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, 2009


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)
            
            13-49226401-3457
            
            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)
            
            35-04104551-6543
            
            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. has submitted
      electronically and posted on its corporate website, if any, every
      Interactive Data File required to be submitted and posted pursuant to Rule
      405 of Regulation S-T (§232.405 of this chapter) during the preceding 12
      months (or for such shorter period that the registrant was required to
      submit and post such files).Yes
                No





Indicate
      by check mark whether Appalachian Power Company, Columbus Southern Power
      Company, Indiana Michigan Power Company, Ohio Power Company, Public
      Service Company of Oklahoma and Southwestern Electric Power Company has
      submitted electronically and posted on its corporate website, if any,
      every Interactive Data File required to be submitted and posted pursuant
      to Rule 405 of Regulation S-T (§232.405 of this chapter) during the
      preceding 12 months (or for such shorter period that the registrant was
      required to submit and post such files).Yes
                No





Indicate
      by check mark whether American Electric Power Company, Inc. is a large
      accelerated filer, an accelerated filer, a non-accelerated filer, or a
      smaller reporting company.  See the definitions of ‘large
      accelerated filer,’ ‘accelerated filer’ and ‘smaller reporting company’ in
      Rule 12b-2 of the Exchange Act.Large
      accelerated filer   X                                      Accelerated
      filer
                
                Non-accelerated
      filer                                         Smaller
      reporting company





Indicate
      by check mark whether Appalachian Power Company, Columbus Southern Power
      Company, Indiana Michigan Power Company, Ohio Power Company, Public
      Service Company of Oklahoma and Southwestern Electric Power Company are
      large accelerated filers, accelerated filers, non-accelerated filers or
      smaller reporting companies.  See the definitions of ‘large
      accelerated filer,’ ‘accelerated filer’ and ‘smaller reporting company’ in
      Rule 12b-2 of the Exchange Act.Large
      accelerated filer                                       Accelerated
      filer
                    
                    Non-accelerated
      filer     X                                      Smaller
      reporting companyIndicate
      by check mark whether the registrants are shell companies (as defined in
      Rule 12b-2 of the Exchange Act)Yes
                  NoX





Columbus
Southern Power Company and Indiana Michigan Power Company 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 of the registrants at
              April
      30, 2009American
      Electric Power Company, Inc.
            
            
            476,760,862($6.50
      par value)Appalachian
      Power Company
            
            
            13,499,500(no
      par value)Columbus
      Southern Power Company
            
            
            16,410,426(no
      par value)Indiana
      Michigan Power Company
            
            
            1,400,000(no
      par value)Ohio
      Power Company
            
            
            27,952,473(no
      par value)Public
      Service Company of Oklahoma
            
            
            9,013,000($15
      par value)Southwestern
      Electric Power Company
            
            
            7,536,640($18
      par value)





AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES


INDEX
TO QUARTERLY REPORTS ON FORM 10-Q


March
31, 2009





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
    ActivitiesCondensed
      Consolidated Financial StatementsIndex
      to Condensed Notes to Condensed Consolidated Financial
      StatementsAppalachian
      Power Company and Subsidiaries:Management’s
      Financial Discussion and AnalysisQuantitative
      and Qualitative Disclosures About Risk Management
    ActivitiesCondensed
      Consolidated Financial StatementsIndex
      to Condensed Notes to Condensed Financial Statements of Registrant
      SubsidiariesColumbus
      Southern Power Company and Subsidiaries:Management’s
      Narrative Financial Discussion and AnalysisQuantitative
      and Qualitative Disclosures About Risk Management
    ActivitiesCondensed
      Consolidated Financial StatementsIndex
      to Condensed Notes to Condensed Financial Statements of Registrant
      SubsidiariesIndiana
      Michigan Power Company and Subsidiaries:Management’s
      Narrative Financial Discussion and AnalysisQuantitative
      and Qualitative Disclosures About Risk Management
    ActivitiesCondensed
      Consolidated Financial StatementsIndex
      to Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries


Ohio
      Power Company Consolidated:Management’s
      Financial Discussion and AnalysisQuantitative
      and Qualitative Disclosures About Risk Management
    ActivitiesCondensed
      Consolidated Financial StatementsIndex
      to Condensed Notes to Condensed Financial Statements of Registrant
      SubsidiariesPublic
      Service Company of Oklahoma:Management’s
      Narrative Financial Discussion and AnalysisQuantitative
      and Qualitative Disclosures About Risk Management
    ActivitiesCondensed
      Financial StatementsIndex
      to Condensed Notes to Condensed Financial Statements of Registrant
      SubsidiariesSouthwestern
      Electric Power Company Consolidated:Management’s
      Financial Discussion and AnalysisQuantitative
      and Qualitative Disclosures About Risk Management
    ActivitiesCondensed
      Consolidated Financial StatementsIndex
      to Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries


Condensed
      Notes to Condensed Financial Statements of Registrant
      SubsidiariesCombined
      Management’s Discussion and Analysis of Registrant
      SubsidiariesControls
      and ProceduresPart
      II.  OTHER INFORMATIONItem
      1.
                              Legal
      ProceedingsItem
      1A.
                              Risk
      FactorsItem
      2.
                              Unregistered
      Sales of Equity Securities and Use of ProceedsItem
      5.
                              Other
      InformationItem
      6.
                              Exhibits:Exhibit
      12Exhibit
      31(a)Exhibit
      31(b)Exhibit
      32(a)Exhibit
      32(b)SIGNATURE





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







GLOSSARY OF TERMS




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





Term
            
            Meaning





AEGCo
              
              AEP
      Generating Company, an AEP electric utility subsidiary.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 electric utility
      companies.AEP
      East companies
              
              APCo,
      CSPCo, I&M, KPCo and OPCo.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.AEPSC
              
              American
      Electric Power Service Corporation, a service subsidiary providing
      management and professional services to AEP and its
      subsidiaries.AEP
      System
              
              American
      Electric Power System, an integrated electric utility system, owned and
      operated by AEP’s electric utility subsidiaries.AEP
      West companies
              
              PSO,
      SWEPCo, TCC and TNC.AFUDC
              
              Allowance
      for Funds Used During Construction.ALJ
              
              Administrative
      Law Judge.AOCI
              
              Accumulated
      Other Comprehensive Income.APB
              
              Accounting
      Principles Board Opinion.APCo
              
              Appalachian
      Power Company, an AEP electric utility subsidiary.APSC
              
              Arkansas
      Public Service Commission.CAA
              
              Clean
      Air Act.CO2
              
              Carbon
      Dioxide.CSPCo
              
              Columbus
      Southern Power Company, an AEP electric utility
  subsidiary.CSW
              
              Central
      and South West Corporation, a subsidiary of AEP (Effective January 21,
      2003, the legal name of Central and South West Corporation was changed to
      AEP Utilities, Inc.).CSW
      Operating Agreement
              
              Agreement,
      dated January 1, 1997, by and among PSO, SWEPCo, TCC and TNC governing
      generating capacity allocation.  This agreement was amended in
      May 2006 to remove TCC and TNC.  AEPSC acts as the
      agent.CTC
              
              Competition
      Transition Charge.CWIP
              
              Construction
      Work in Progress.E&R
              
              Environmental
      compliance and transmission and distribution system
      reliability.EaR
              
              Earnings
      at Risk, a method to quantify risk exposure.EIS
              
              Energy
      Insurance Services, Inc., a protected cell insurance company that AEP
      consolidates under FIN 46R.EITF
              
              Financial
      Accounting Standards Board’s Emerging Issues Task
Force.EITF
      06-10
              
              EITF
      Issue No. 06-10 “Accounting for Collateral Assignment Split-Dollar Life
      Insurance Arrangements.”ENEC
              
              Expanded
      Net Energy Cost.ERCOT
              
              Electric
      Reliability Council of Texas.ERISA
              
              Employee
      Retirement Income Security Act of 1974, as amended.ESP
              
              Electric
      Security Plan.FASB
              
              Financial
      Accounting Standards Board.Federal
      EPA
              
              United
      States Environmental Protection Agency.FERC
              
              Federal
      Energy Regulatory Commission.FIN
              
              FASB
      Interpretation No.FIN
      46R
              
              FIN
      46R, “Consolidation of Variable Interest
  Entities.”


FSP
                  
                  FASB
      Staff Position.FSP
      FIN 39-1
                  
                  FSP
      FIN 39-1, “Amendment of FASB Interpretation No. 39.”GAAP
                  
                  Accounting
      Principles Generally Accepted in the United States of
    America.IGCC
                  
                  Integrated
      Gasification Combined Cycle, technology that turns coal into a
      cleaner-burning gas.Interconnection
      Agreement
                  
                  Agreement,
      dated July 6, 1951, as amended, by and among APCo, CSPCo, I&M, KPCo
      and OPCo, defining the sharing of costs and benefits associated with their
      respective generating plants.IRS
                  
                  Internal
      Revenue Service.IURC
                  
                  Indiana
      Utility Regulatory Commission.I&M
                  
                  Indiana
      Michigan Power Company, an AEP electric utility
  subsidiary.JBR
                  
                  Jet
      Bubbling Reactor.JMG
                  
                  JMG
      Funding LP.KGPCo
                  
                  Kingsport
      Power Company, an AEP electric utility subsidiary.KPCo
                  
                  Kentucky
      Power Company, an AEP electric utility subsidiary.kV
                  
                  Kilovolt.KWH
                  
                  Kilowatthour.LPSC
                  
                  Louisiana
      Public Service Commission.MISO
                  
                  Midwest
      Independent Transmission System Operator.MLR
                  
                  Member
      load ratio, the method used to allocate AEP Power Pool transactions to its
      members.MMBtu
                  
                  Million
      British Thermal Units.MTM
                  
                  Mark-to-Market.MW
                  
                  Megawatt.MWH
                  
                  Megawatthour.NOx
                  
                  Nitrogen
      oxide.Nonutility
      Money Pool
                  
                  AEP
      Consolidated’s Nonutility Money Pool.NSR
                  
                  New
      Source Review.OCC
                  
                  Corporation
      Commission of the State of Oklahoma.OPCo
                  
                  Ohio
      Power Company, an AEP electric utility subsidiary.OPEB
                  
                  Other
      Postretirement Benefit Plans.OTC
                  
                  Over
      the counter.PATH
                  
                  Potomac
      Appalachian Transmission Highline, LLC and its subsidiaries, a joint
      venture with Allegheny Energy Inc. formed to own and operate electric
      transmission facilities in PJM.PJM
                  
                  Pennsylvania
      – New Jersey – Maryland regional transmission
  organization.PSO
                  
                  Public
      Service Company of Oklahoma, an AEP electric utility
      subsidiary.PUCO
                  
                  Public
      Utilities Commission of Ohio.PUCT
                  
                  Public
      Utility Commission of Texas.Registrant
      Subsidiaries
                  
                  AEP
      subsidiaries which are SEC registrants; APCo, CSPCo, I&M, OPCo, PSO
      and SWEPCo.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.RSP
                  
                  Rate
      Stabilization Plan.RTO
                  
                  Regional
      Transmission Organization.S&P
                  
                  Standard
      and Poor’s.SEC
                  
                  United
      States Securities and Exchange
Commission.


SECA
              
              Seams
      Elimination Cost Allocation.SEET
              
              Significant
      Excess Earnings Test.SFAS
              
              Statement
      of Financial Accounting Standards issued by the Financial Accounting
      Standards Board.SFAS
      71
              
              Statement
      of Financial Accounting Standards No. 71, “Accounting for the Effects of
      Certain Types of Regulation.”SFAS
      133
              
              Statement
      of Financial Accounting Standards No. 133, “Accounting for Derivative
      Instruments and Hedging Activities.”SFAS
      157
              
              Statement
      of Financial Accounting Standards No. 157, “Fair Value
      Measurements.”SIA
              
              System
      Integration Agreement.SNF
              
              Spent
      Nuclear Fuel.SO2
              
              Sulfur
      Dioxide.SPP
              
              Southwest
      Power Pool.Stall
      Unit
              
              J.
      Lamar Stall Unit at Arsenal Hill Plant.SWEPCo
              
              Southwestern
      Electric Power Company, an AEP electric utility
  subsidiary.TCC
              
              AEP
      Texas Central Company, an AEP electric utility
  subsidiary.TCRR
              
              Transmission
      Cost Recovery Rider.TEM
              
              SUEZ
      Energy Marketing NA, Inc. (formerly known as Tractebel Energy Marketing,
      Inc.).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 made under the Texas Restructuring Legislation to finalize the
      amount of stranded costs and other true-up items and the recovery of such
      amounts.Turk
      Plant
              
              John
      W. Turk, Jr. Plant.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.WPCo
              
              Wheeling
      Power Company, an AEP electric distribution subsidiary.WVPSC
              
              Public
      Service Commission of West
Virginia.







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:





·
              The
      economic climate and growth in, or contraction within, our service
      territory and changes in market demand and demographic
      patterns.·
              Inflationary
      or deflationary interest rate trends.·
              Volatility
      in the financial markets, particularly developments affecting the
      availability of capital on reasonable terms and developments impairing our
      ability to finance new capital projects and refinance existing debt at
      attractive rates.·
              The
      availability and cost of funds to finance working capital and capital
      needs, particularly during periods when the time lag between incurring
      costs and recovery is long and the costs are material.·
              Electric
      load and customer growth.·
              Weather
      conditions, including storms.·
              Available
      sources and costs of, and transportation for, fuels and the
      creditworthiness and performance of fuel suppliers and
      transporters.·
              Availability
      of generating capacity and the performance of our generating plants
      including our ability to restore Indiana Michigan Power Company’s Donald
      C. Cook Nuclear Plant Unit 1 in a timely manner.·
              Our
      ability to recover regulatory assets and stranded costs in connection with
      deregulation.·
              Our
      ability to recover increases in fuel and other energy costs through
      regulated or competitive electric rates.·
              Our
      ability to build or acquire generating capacity and transmission line
      facilities (including our ability to obtain any necessary regulatory
      approvals and permits) when needed at acceptable prices and terms and to
      recover those costs (including the costs of projects that are cancelled)
      through applicable rate cases or competitive rates.·
              New
      legislation, litigation and government regulation including requirements
      for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or
      particulate matter and other substances.·
              Timing
      and resolution of pending and future rate cases, negotiations and other
      regulatory decisions (including rate or other recovery of new investments
      in generation, distribution and transmission service and environmental
      compliance).·
              Resolution
      of litigation (including disputes arising from the bankruptcy of Enron
      Corp. and related matters).·
              Our
      ability to constrain operation and maintenance costs.·
              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 of the counterparties with whom we have
      contractual arrangements, including participants in the energy trading
      market.·
              Actions
      of rating agencies, including changes in the ratings of
    debt.·
              Volatility
      and changes in markets for electricity, natural gas, coal, nuclear fuel
      and other energy-related commodities.·
              Changes
      in utility regulation, including the implementation of the recently passed
      utility law in Ohio and the allocation of costs within regional
      transmission organizations, including PJM and SPP.·
              Accounting
      pronouncements periodically issued by accounting standard-setting
      bodies.·
              The
      impact of volatility in the capital markets on the value of the
      investments held by our pension, other postretirement benefit plans and
      nuclear decommissioning trust and the impact on future funding
      requirements.·
              Prices
      for power that we generate and sell at wholesale.·
              Changes
      in technology, particularly with respect to new, developing or alternative
      sources of generation.·
              Other
      risks and unforeseen events, including wars, the effects of terrorism
      (including increased security costs), embargoes and other catastrophic
      events.





AEP
      and its Registrant Subsidiaries expressly disclaim any obligation to
      update any forward-looking
information.





AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES


MANAGEMENT’S FINANCIAL
DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS





EXECUTIVE
OVERVIEW





Economic
Slowdown





The
financial struggles of the U.S. economy continue to impact our industrial sales
as well as sales opportunities in the wholesale market.  Industrial
sales in various sections of our service territories are decreasing due to
reduced shifts and suspended operations by some of our large industrial
customers.  Although many sections of our service territories are
experiencing slowdowns in new construction, our residential and commercial
customer base appears to be stable.  As a result of these economic
issues, we are currently monitoring the following:





·
                      Margins from Off-system Sales - Margins
      from off-system sales continue to decrease due to reductions in sales
      volumes and weak market power prices, reflecting reduced overall demand
      for electricity.  We currently forecast that off-system sales
      volumes will decrease by approximately 30% in 2009.  These
      trends will most likely continue until the economy rebounds and
      electricity demand and prices increase.·
                      Industrial KWH Sales - Industrial KWH sales
      for the quarter ended March 31, 2009 were down 15% in comparison to the
      quarter ended March 31, 2008.  Approximately half of this
      decrease was due to cutbacks or closures by six of our large metals
      customers.  We also experienced additional significant decreases
      in KWH sales to customers in the plastics, rubber, auto and paper
      manufacturing industries.  Since our trends for industrial sales
      are usually similar to the nation’s industrial production, these trends
      are likely to continue until industrial production
    improves.·
                      Risk of Loss of Major Customers - We monitor the financial strength and
      viability of each of our major industrial customers
      individually.  We have factored this analysis into our
      operational planning.  Our largest customer, Ormet, an
      industrial customer with a 520 MW load, recently announced that it is in
      dispute with its sole customer which could potentially force Ormet to halt
      production.





Capital
Markets





The
financial markets remain volatile at both a global and domestic
level.  This marketplace distress could impact our access to capital,
liquidity, asset valuations in our trust funds, the creditworthy status of
customers, suppliers and trading partners and our cost of capital.  We
actively manage these factors with oversight from our risk
committee.  We cannot predict the length of time the current credit
market situation will continue or its impact on future operations and our
ability to issue debt at reasonable interest rates.  Despite the
current volatile markets, we were able to issue approximately $1 billion of
long-term debt in the first quarter of 2009 and $1.64 billion (net proceeds) of
AEP common stock in April 2009.





We
believe that we have adequate liquidity to support our planned business
operations and construction program for the remainder of 2009 due to the
following:





·
            As
      of March 31, 2009, we had $2.2 billion in aggregate available liquidity
      under our credit facilities.  These credit facilities include 27
      different banks with no one bank having more than 10% of our total bank
      commitments.  In April 2009, we allowed $350 million of our
      credit facility commitments to expire.  As of March 31, 2009,
      cash and cash equivalents were $710 million.·
            Of
      our $17 billion of long-term debt as of March 31, 2009, approximately $300
      million will mature during the remainder of 2009 (approximately 1.8% of
      our outstanding long-term debt as of March 31, 2009).  The $300
      million of remaining 2009 maturities exclude payments due for
      securitization bonds which we recover directly from
      ratepayers.


·
            In
      April 2009, we issued 69 million shares of common stock at $24.50 per
      share for net proceeds of $1.64 billion.  We used $1.25 billion
      of the proceeds to repay part of the cash drawn under our credit
      facilities.  These transactions improved our debt to capital
      ratio to 58.1% assuming no other changes from our March 31, 2009 balance
      sheet.  With the remaining proceeds, we intend to pay down other
      existing debt.  These actions will help to support our
      investment grade ratings and maintain financial
    flexibility.·
            We
      believe that our projected cash flows from operating activities are
      sufficient to support our ongoing
operations.





Approximately
$1.7 billion of outstanding long-term debt will mature in 2010, excluding
payments due for securitization bonds which we recover directly from
ratepayers.  We intend to refinance or repay our debt
maturities.





We
sponsor several trust funds with significant investments intended to provide for
future payments of pensions, OPEB, nuclear decommissioning and spent nuclear
fuel disposal.  Although all of our trust funds’ investments are
diversified and managed in compliance with all laws and regulations, the value
of the investments in these trusts declined substantially over the past year due
to decreases in domestic and international equity markets.  Although
the asset values are currently lower, this has not affected the funds’ ability
to make their required payments.  The decline in pension asset values
will not require us to make a contribution under ERISA in 2009.  We
estimate that we will need to make minimum contributions to our pension trust of
$475 million in 2010 and $283 million in 2011.  However, estimates may
vary significantly based on market returns, changes in actuarial assumptions and
other factors.





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. Our risk management
organization monitors these exposures on a daily basis to limit our economic and
financial statement impact on a counterparty basis.  At March 31,
2009, our credit exposure net of collateral was approximately $825 million of
which approximately 89% is to investment grade counterparties.  At
March 31, 2009, our exposure to financial institutions was $42 million, which
represents 5% of our total credit exposure net of collateral (all investment
grade).





Regulatory
Activity





In
February 2009, SWEPCo filed an application with the APSC for a base rate
increase of $25 million based on a requested return on equity of
11.5%.  SWEPCo also requested a separate rider to recover financing
costs related to the construction of the Stall and Turk generating
facilities.  These financing costs are currently being capitalized as
AFUDC in Arkansas.  A decision is not expected until the fourth
quarter of 2009 or the first quarter of 2010.





In March
2009, the PUCO issued an order that modified and approved CSPCo’s and OPCo’s ESP
filings.  If accepted by CSPCo and OPCo, the ESPs would be in effect
through 2011.  Among other things, the ESP order authorized capped
increases to revenues during the three-year ESP period and also authorized a
fuel adjustment clause (FAC) which allows CSPCo and OPCo to phase-in and defer
actual fuel costs incurred, along with purchased power and related expenses that
will be trued-up, subject to annual caps and prudency and accounting
reviews.  Deferred phase-in regulatory asset balances for fuel costs
not currently recovered due to the cap are expected to be
material.  The projected revenue increases for CSPCo and OPCo are
listed below:





Projected
      Revenue Increases2009
                  
                  2010
                  
                  2011(in
      millions)CSPCo
                  
                  $
                  116
                  
                  
                  $
                  109
                  
                  
                  $
                  116OPCo
                  
                  
                  130
                  
                  
                  
                  125
                  
                  
                  
                  153





The above
revenues include some incremental cost recoveries.  In addition to the
revenue increases, net income will be positively affected by the material
noncash phase-in deferrals from 2009 through 2011.  These deferrals
will be collected from 2012 through 2018.





For
additional details related to the ESPs, see the “Ohio Electric Security Plan
Filings” section of “Significant Factors.”





In March
2009, the IURC approved the settlement agreement with I&M with modifications
that provides for an annual increase in revenues of $42 million, including a $19
million increase in revenue from base rates and $23 million in additional
tracker revenues for certain incurred costs, subject to true-up.





In March
2009, APCo and WPCo filed an annual ENEC filing with the WVPSC for an increase
of approximately $442 million for incremental fuel, purchased power and
environmental compliance project expenses, to become effective July
2009.  In March 2009, the WVPSC issued an order suspending the rate
increase request until December 2009.  In April 2009, APCo and WPCo
filed a motion for approval of a provisional interim ENEC increase of $156
million, effective July 2009 and subject to refund pending the adjudication of
the ENEC by December 2009.





Capital
Expenditures





Due to
recent capital market instability and the economic slowdown, we reduced our
planned capital expenditures for 2010 from $3.4 billion to $1.8
billion:


2010Capital
      ExpenditureBudget(in
      millions)New
      Generation
                    
                    $
                    251Environmental
                    
                    
                    252Other
      Generation
                    
                    
                    431Transmission
                    
                    
                    290Distribution
                    
                    
                    552Corporate
                    
                    
                    70Total
                    
                    $
                    1,846





We also
reduced our 2011 environmental capital expenditure projection from $892 million
to $246 million.  We intend to keep operation and maintenance expense
relatively flat in 2009 in comparison to 2008.  We do not believe that
these cutbacks will jeopardize the reliability of the AEP System.





Cook
Plant Unit 1 Fire and Shutdown





In
September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine
vibrations, likely caused by blade failure, which resulted in a fire on the
electric generator.  This equipment, located in the turbine building,
is separate and isolated from the nuclear reactor.  Repair of the
property damage and replacement of the turbine rotors and other equipment could
cost up to approximately $330 million.  Management believes that
I&M should recover a significant portion of these costs through the
turbine vendor’s warranty, insurance and the regulatory process.  The
treatment of property damage costs, replacement power costs and insurance
proceeds will be the subject of future regulatory proceedings in Indiana and
Michigan.  I&M is repairing Unit 1 to resume operations as early
as October 2009 at reduced power.  Should post-repair operations prove
unsuccessful, the replacement of parts will extend the outage into
2011.





Fuel
Costs





For 2009,
we expect our coal costs to increase by approximately 12%.  With the
recent ESP orders for CSPCo and OPCo, we now have active fuel cost recovery
mechanisms in all of our jurisdictions.  The deferred fuel balances of
CSPCo and OPCo at the end of the ESP period will be recovered through a
non-bypassable surcharge over the period 2012 through 2018.  As of
March 31, 2009, CSPCo and OPCo had a combined $83 million under-recovered fuel
balance, including carrying costs.  We expect this amount to increase
significantly over the remainder of 2009.  Depending upon certain
variables, including the potential escalation of fuel costs and the timing of
the economic recovery, this amount may continue to increase in 2010 and
2011.





Recent
coal consumption and projected consumption for the remainder of 2009 have
decreased significantly.  As a result, we are in discussions with our
coal suppliers in an effort to better match deliveries with our current
consumption trends and to minimize the impact on fuel inventory
costs.





RESULTS
OF OPERATIONS





Segments





Our
principal operating business segments and their related business activities are
as follows:





Utility
Operations


·
            Generation
      of electricity for sale to U.S. retail and wholesale
      customers.·
            Electricity
      transmission and distribution in the
U.S.





AEP
River Operations


·
            Commercial
      barging operations that annually transport approximately 33 million tons
      of coal and dry bulk commodities primarily on the Ohio, Illinois and lower
      Mississippi Rivers.  Approximately 38% of the barging is for the
      transportation of agricultural products, 30% for coal, 13% for steel and
      19% for other commodities.





Generation
and Marketing


·
            Wind
      farms and marketing and risk management activities primarily in
      ERCOT.





The table
below presents our consolidated Net Income by segment for the three months ended
March 31, 2009 and 2008.




Three
      Months Ended March 31,2009
                      
                      2008(in
      millions)Utility
      Operations
                      
                      $
                      346
                      
                      
                      $
                      413AEP
      River Operations
                      
                      
                      11
                      
                      
                      
                      7Generation
      and Marketing
                      
                      
                      24
                      
                      
                      
                      1All
      Other (a)
                      
                      
                      (18
                      )
                      
                      
                      155Net
      Income
                      
                      $
                      363
                      
                      
                      $
                      576





(a)
            All
      Other includes:·
            Parent’s
      guarantee revenue received from affiliates, investment income, interest
      income and interest expense and other nonallocated
  costs.·
            Forward
      natural gas contracts that were not sold with our natural gas pipeline and
      storage operations in 2004 and 2005.  These contracts are
      financial derivatives which will gradually liquidate and completely expire
      in 2011.·
            The
      first quarter 2008 settlement of a purchase power and sale agreement with
      TEM related to the Plaquemine Cogeneration Facility which was sold in
      2006.·
            Revenue
      sharing related to the Plaquemine Cogeneration
  Facility.





AEP
Consolidated





First Quarter of 2009
Compared to First Quarter of 2008





Net
Income in 2009 decreased $213 million compared to 2008 primarily due to income
of $164 million (net of tax) in 2008 from the cash settlement of a power
purchase and sale agreement with TEM related to the Plaquemine Cogeneration
Facility which was sold in the fourth quarter of 2006 and a decrease in Utility
Operations segment earnings of $67 million.  The decrease in Utility
Operations segment net income primarily relates to lower off-system sales
margins due to lower sales volumes and lower market prices which reflect weak
market demand.





Average
basic shares outstanding increased to 407 million in 2009 from 401 million in
2008 primarily due to the issuance of shares under our incentive compensation
and dividend reinvestment plans.  In 2008, we contributed 1.25 million
shares of common stock held in treasury to the AEP Foundation.  The
AEP Foundation is an AEP charitable organization created in 2005 for charitable
contributions in the communities in which AEP’s subsidiaries
operate.  Actual shares outstanding were 408 million as of March 31,
2009.  In April 2009, we issued 69 million shares of AEP common stock
at $24.50 per share for total net proceeds of $1.64 billion.





Utility
Operations





Our
Utility Operations segment includes primarily regulated revenues with direct and
variable offsetting expenses and net reported commodity trading
operations.  We believe that a discussion of the results from our
Utility Operations segment on a gross margin basis is most appropriate in order
to further understand the key drivers of the segment.  Gross margin
represents utility operating revenues less the related direct cost of fuel,
including consumption of chemicals and emissions allowances and purchased
power.





Three
      Months EndedMarch
      31,2009
                  
                  
                  2008(in
      millions)Revenues
                  
                  $
                  3,267
                  
                  
                  $
                  3,294Fuel
      and Purchased Power
                  
                  
                  1,196
                  
                  
                  
                  1,213Gross
      Margin
                  
                  
                  2,071
                  
                  
                  
                  2,081Depreciation
      and Amortization
                  
                  
                  373
                  
                  
                  
                  355Other
      Operating Expenses
                  
                  
                  994
                  
                  
                  
                  941Operating
      Income
                  
                  
                  704
                  
                  
                  
                  785Other
      Income, Net
                  
                  
                  30
                  
                  
                  
                  43Interest
      Charges
                  
                  
                  220
                  
                  
                  
                  208Income
      Tax Expense
                  
                  
                  168
                  
                  
                  
                  207Net
      Income
                  
                  $
                  346
                  
                  
                  $
                  413





Summary
of Selected Sales and Weather Data


For
Utility Operations


For
the Three Months Ended March 31, 2009 and 2008





2009
                  
                  
                  2008Energy
      Summary
                  
                  (in
      millions of KWH)Retail:Residential
                  
                  
                  14,368
                  
                  
                  
                  14,500Commercial
                  
                  
                  9,395
                  
                  
                  
                  9,547Industrial
                  
                  
                  12,126
                  
                  
                  
                  14,350Miscellaneous
                  
                  
                  576
                  
                  
                  
                  609Total
      Retail
                  
                  
                  36,465
                  
                  
                  
                  39,006Wholesale
                  
                  
                  6,777
                  
                  
                  
                  11,742Texas
      Wires – Energy Delivered to Customers Served by TNC and TCC in
      ERCOT
                  
                  
                  5,738
                  
                  
                  
                  5,823Total
      KWHs
                  
                  
                  48,980
                  
                  
                  
                  56,571





Cooling
degree days and heating degree days are metrics commonly used in the utility
industry as a measure of the impact of weather on net income.  In
general, degree day changes in our eastern region have a larger effect on net
income than changes in our western region due to the relative size of the two
regions and the associated number of customers within each.  Cooling
degree days and heating degree days in our service territory for the three
months ended March 31, 2009 and 2008 were as follows:





2009
                      
                      
                      2008Weather
      Summary
                      
                      (in
      degree days)Eastern RegionActual
      – Heating (a)
                      
                      
                      1,900
                      
                      
                      
                      1,830Normal
      – Heating (b)
                      
                      
                      1,791
                      
                      
                      
                      1,767Actual
      – Cooling (c)
                      
                      
                      5
                      
                      
                      
                      -Normal
      – Cooling (b)
                      
                      
                      3
                      
                      
                      
                      3Western Region
      (d)Actual
      – Heating (a)
                      
                      
                      854
                      
                      
                      
                      941Normal
      – Heating (b)
                      
                      
                      905
                      
                      
                      
                      931Actual
      – Cooling (c)
                      
                      
                      38
                      
                      
                      
                      26Normal
      – Cooling (b)
                      
                      
                      20
                      
                      
                      
                      20





(a)
              Eastern
      region and western region heating degree days are calculated on a 55
      degree temperature base.(b)
              Normal
      Heating/Cooling represents the thirty-year average of degree
      days.(c)
              Eastern
      region and western region cooling degree days are calculated on a 65
      degree temperature base.(d)
              Western
      region statistics represent PSO/SWEPCo customer base
  only.





First Quarter of 2009
Compared to First Quarter of 2008





Reconciliation
of First Quarter of 2008 to First Quarter of 2009


Net
Income from Utility Operations


(in
millions)





First
      Quarter of 2008
                    
                    
                    
                    
                    $
                    413Changes
      in Gross Margin:Retail
      Margins
                    
                    
                    61Off-system
      Sales
                    
                    
                    (136
                    )Transmission
      Revenues
                    
                    
                    4Other
      Revenues
                    
                    
                    61Total
      Change in Gross Margin
                    
                    
                    
                    
                    
                    
                    (10
                    )Changes
      in Operating Expenses and Other:Other
      Operation and Maintenance
                    
                    
                    (56
                    )Gain
      on Dispositions of Assets, Net
                    
                    
                    3Depreciation
      and Amortization
                    
                    
                    (18
                    )Interest
      Income
                    
                    
                    (10
                    )Carrying
      Costs Income
                    
                    
                    (8
                    )Other
      Income, Net
                    
                    
                    5Interest
      Expense
                    
                    
                    (12
                    )Total
      Change in Operating Expenses and Other
                    
                    
                    
                    
                    
                    
                    (96
                    )Income
      Tax Expense
                    
                    
                    
                    
                    
                    
                    39First
      Quarter of 2009
                    
                    
                    
                    
                    
                    $
                    346





Net
Income from Utility Operations decreased $67 million to $346 million in
2009.  The key drivers of the decrease were a $10 million decrease in
Gross Margin and a $96 million increase in Operating Expenses and Other,
partially offset by a $39 million decrease in Income Tax Expense.





The major
components of the net decrease in Gross Margin were as follows:





·
            Retail
      Margins increased $61 million primarily due to the
    following:·
            A
      $58 million increase related to base rates and recovery of E&R costs
      in Virginia and construction financing costs in West Virginia, a $17
      million increase in base rates in Oklahoma, a $13 million increase related
      to the net increases in Ohio as a result of the PUCO’s approval of our
      Ohio ESPs and a $5 million net rate increase for
  I&M.·
            A
      $54 million increase resulting from reduced sharing of off-system sales
      margins with retail customers in our eastern service territory due to a
      decrease in total off-system sales.·
            A
      $6 million increase in fuel margins in Ohio due to the deferral of fuel
      costs by CSPCo and OPCo in 2009.  The PUCO’s March 2009 approval
      of CSPCo’s and OPCo’s ESPs allows for the recovery of fuel and related
      costs during the ESP period.  See “Ohio Electric Security Plan
      Filings” section of Note 3.These
      increases were partially offset by:·
            A
      $58 million decrease in fuel margins related to an OPCo coal contract
      amendment recorded in 2008 which reduced future deliveries to OPCo in
      exchange for consideration received.·
            A
      $32 million decrease in margins from industrial sales due to reduced
      shifts and suspended operations by some of the large industrial customers
      in our service territories.·
            A
      $20 million decrease in fuel margins due to higher fuel and purchased
      power costs related to the Cook Plant Unit 1 shutdown.  This
      decrease in fuel margins was offset by a corresponding increase in Other
      Revenues as discussed below.·
            Margins
      from Off-system Sales decreased $136 million primarily due to lower
      physical sales volumes and lower margins in our eastern service territory
      reflecting lower market prices, partially offset by higher trading
      margins.·
            Other
      Revenues increased $61 million primarily due to Cook Plant accidental
      outage insurance policy proceeds of $54 million.  Of these
      insurance proceeds, $20 million were used to offset fuel costs associated
      with the Cook Plant Unit 1 shutdown.  This increase in revenues
      was offset by a corresponding decrease in Retail Margins as discussed
      above.  See “Cook Plant Unit 1 Fire and Shutdown” section of
      Note 4.





Utility
Operating Expenses and Other and Income Taxes changed between years as
follows:





·
            Other
      Operation and Maintenance expenses increased $56 million primarily due to
      the following:·
            An
      $80 million increase related to the deferral of Oklahoma ice storm costs
      in 2008 resulting from an OCC order approving recovery of January and
      December 2007 ice storm expenses.·
            A
      $38 million increase related to storm restoration expenses, primarily in
      our eastern service territory.·
            A
      $15 million increase related to an obligation to contribute to the
      “Partnership with Ohio” fund for low income, at-risk customers ordered by
      the PUCO’s March 2009 approval of CSPCo’s and OPCo’s ESPs.  See
      “Ohio Electric Security Plan Filings” section of Note
3.These
      increases were partially offset by:·
            A
      $34 million decrease in employee-related expenses.·
            A
      $14 million decrease in plant outage and other maintenance
      expenses.·
            A
      $13 million decrease in tree trimming, reliability and other transmission
      and distribution expenses.·
            A
      $10 million decrease related to the write-off of the unrecoverable
      pre-construction costs for PSO’s cancelled Red Rock Generating Facility in
      the first quarter of 2008.·
            Depreciation
      and Amortization increased $18 million primarily due to higher depreciable
      property balances as the result of environmental improvements placed in
      service at OPCo and various other property additions and higher
      depreciation rates for OPCo related to shortened depreciable lives for
      certain generating facilities.·
            Interest
      Income decreased $10 million primarily due to the 2008 favorable effect of
      claims for refund filed with the IRS.·
            Carrying
      Costs Income decreased $8 million primarily due to the completion of
      reliability deferrals in Virginia in December 2008 and the decrease of
      environmental deferrals in Virginia in 2009.·
            Interest
      Expense increased $12 million primarily due to increased long-term debt
      and higher interest rates on variable rate debt.·
            Income
      Tax Expense decreased $39 million due to a decrease in pretax
      income.





AEP River
Operations





First Quarter of 2009
Compared to First Quarter of 2008





Net
Income from our AEP River Operations segment increased from $7 million in 2008
to $11 million in 2009 primarily due to lower fuel costs and gains on the sale
of two older towboats.  These increases were partially offset by lower
revenues due to reduced import volumes and lower freight rates.





Generation and
Marketing





First Quarter of 2009
Compared to First Quarter of 2008





Net
Income from our Generation and Marketing segment increased from $1 million in
2008 to $24 million in 2009 primarily due to higher gross margins from marketing
activities.





All
Other





First Quarter of 2009
Compared to First Quarter of 2008





Net
Income from All Other decreased from income of $155 million in 2008 to a loss of
$18 million in 2009.  In 2008, we had after-tax income of $164 million
from a litigation settlement of a power purchase and sale agreement with TEM
related to the Plaquemine Cogeneration Facility which was sold in the fourth
quarter of 2006.  The settlement was recorded as a pretax credit to
Asset Impairments and Other Related Charges of $255 million in the accompanying
Condensed Consolidated Statements of Income.





AEP System Income
Taxes





Income
Tax Expense decreased $114 million in the first quarter of 2009 compared to the
first quarter of 2008 primarily due to a decrease in pretax book
income.





FINANCIAL
CONDITION





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





Debt and Equity
    CapitalizationMarch
      31, 2009
                                    
                                    December
      31, 2008($
      in millions)Long-term
      Debt, including amounts due within one year
                                    
                                    $
                                    16,843
                                    
                                    56.5%
                                    
                                    $
                                    15,983
                                    
                                    55.6%Short-term
      Debt
                                    
                                    
                                    1,976
                                    
                                    6.6
                                    
                                    
                                    1,976
                                    
                                    6.9Total
      Debt
                                    
                                    
                                    18,819
                                    
                                    63.1
                                    
                                    
                                    17,959
                                    
                                    62.5Preferred
      Stock of Subsidiaries
                                    
                                    
                                    61
                                    
                                    0.2
                                    
                                    
                                    61
                                    
                                    0.2AEP
      Common Equity
                                    
                                    
                                    10,940
                                    
                                    36.6
                                    
                                    
                                    10,693
                                    
                                    37.2Noncontrolling
      Interests
                                    
                                    
                                    18
                                    
                                    0.1
                                    
                                    
                                    17
                                    
                                    0.1Total
      Debt and Equity Capitalization
                                    
                                    $
                                    29,838
                                    
                                    100.0%
                                    
                                    $
                                    28,730
                                    
                                    100.0%





As of
March 31, 2009, our ratio of debt-to-total capital was 63.1%.  After
the issuance of 69 million new common shares and the application of the net
proceeds of $1.64 billion to reduce debt, our pro forma ratio of debt-to-capital
as of the date of issuance would have been 57.6%.





Liquidity





Liquidity,
or access to cash, is an important factor in determining our financial
stability.  We are committed to maintaining adequate
liquidity.  We generally use short-term borrowings to fund working
capital needs, property acquisitions and construction until long-term funding is
arranged.  Sources of long-term funding include issuance
of  long-term debt, sale-leaseback or leasing agreements or common
stock.





Capital
Markets





In 2008,
the domestic and world economies experienced significant
slowdowns.  The financial markets remain volatile at both a global and
domestic level.  This marketplace distress could impact our access to
capital, liquidity and cost of capital.  The uncertainties in the
capital markets could have significant implications since we rely on continuing
access to capital to fund operations and capital expenditures.  We
cannot predict the length of time the credit situation will continue or its
impact on future operations and our ability to issue debt at reasonable interest
rates.





We
believe we have adequate liquidity through 2009 under our existing credit
facilities.  However, the current credit markets could constrain our
ability to issue commercial paper.  Approximately $300 million
(excluding payments due for securitization bonds which we recover directly from
ratepayers) of our $17 billion of long-term debt as of March 31, 2009 will
mature during the remainder of 2009.  We intend to refinance debt
maturities.  At March 31, 2009, we had $3.9 billion ($3.6 billion
after an April expiration of one facility) in aggregate credit facility
commitments to support our operations.  These commitments include 27
different banks with no one bank having more than 10% of our total bank
commitments.





During
the first quarter of 2009, we issued $475 million of 7% senior notes due 2019,
$350 million of 7.95% senior notes due 2020, $100 million of 6.25% Pollution
Control Bonds due 2025 and $34 million of 5.25% Pollution Control Bonds due
2014.





During
2008, we chose to begin eliminating our auction-rate debt position due to market
conditions.  As of March 31, 2009, $272 million of our auction-rate
tax-exempt long-term debt (rates range between 1.676% and 13%) remained
outstanding with rates reset every 35 days.  The instruments under
which the bonds are issued allow us to convert to other short-term variable-rate
structures, term-put structures and fixed-rate
structures.  Approximately $218 million of the $272 million of
outstanding auction-rate debt relates to a lease structure with JMG that we are
unable to refinance without JMG’s consent.  The rates for this debt
are at contractual maximum rates of 13%.  The initial term for the JMG
lease structure matures on March 31, 2010.  We are evaluating whether
to terminate this facility prior to maturity.  Termination of this
facility requires approval from the PUCO.





Credit
Facilities





We manage
our liquidity by maintaining adequate external financing
commitments.  At March 31, 2009, our available liquidity was
approximately $2.2 billion as illustrated in the table below:


Amount
                          
                          
                          Maturity(in
      millions)Commercial
      Paper Backup:Revolving
      Credit Facility
                          
                          $
                          1,500
                          
                          
                          March
      2011Revolving
      Credit Facility
                          
                          
                          1,454
                          
                          (a)
                          April
      2012Revolving
      Credit Facility
                          
                          
                          627
                          
                          (a)
                          April
      2011Revolving
      Credit Facility
                          
                          
                          338
                          
                          (a)(b)
                          April
      2009Total
                          
                          
                          3,919Cash
      and Cash Equivalents
                          
                          
                          710Total
      Liquidity Sources
                          
                          
                          4,629Less:  Cash
      Drawn on Credit Facilities
                          
                          
                          1,969
                          
                          (c)Letters
      of Credit Issued
                          
                          
                          492Net
      Available Liquidity
                          
                          $
                          2,168





(a)
              Reduced
      by Lehman Brothers Holdings Inc.’s commitment amount of $81 million
      following its bankruptcy.(b)
              Expired
      in April 2009.(c)
              Paid
      $1.25 billion with proceeds from the equity issuance in April
      2009.





The
revolving credit facilities for commercial paper backup were structured as two
$1.5 billion credit facilities which were reduced by Lehman Brothers Holdings
Inc.’s commitment amount of $46 million following its bankruptcy.  The
credit facilities allow for the issuance of up to $750 million as letters of
credit under each credit facility.





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 other
subsidiaries that are not participants in either money pool for regulatory or
operational reasons.  As of March 31, 2009, we had credit facilities
totaling $3 billion to support our commercial paper program.  In 2008,
we borrowed $2 billion under these credit facilities at a LIBOR
rate.  In April 2009, we repaid $1.25 billion of the $2 billion
borrowed under the credit facilities.  The maximum amount of
commercial paper outstanding during 2009 was $308 million.  The
weighted-average interest rate for our commercial paper during 2009 was
1.22%.  No commercial paper was outstanding at March 31,
2009.





As of
March 31, 2009, under the $650 million 3-year credit agreement reduced by Lehman
Brothers Holdings Inc.’s commitment amount of $23 million following its
bankruptcy, letters of credit of $372 million were issued to support variable
rate Pollution Control Bonds.





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, 2009, this contractually-defined
percentage was 59.1%.  Nonperformance of these covenants could result
in an event of default under these credit agreements.  At March 31,
2009, we complied with all of the covenants contained in these credit
agreements.  In addition, the acceleration of our payment obligations,
or the obligations of certain of our major 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 outstanding amounts payable.





The
revolving credit facilities do not permit the lenders to refuse a draw on either
facility if a material adverse change occurs.





Utility
Money Pool borrowings and external borrowings may not exceed amounts authorized
by regulatory orders.  At March 31, 2009, we had not exceeded those
authorized limits.





Dividend
Policy and Restrictions





We have
declared common stock dividends payable in cash in each quarter since July 1910,
representing 396 consecutive quarters.  The Board of Directors
declared a quarterly dividend of $0.41 per share in April
2009.  Future dividends may vary depending upon our profit levels,
operating cash flow levels and capital requirements, as well as financial and
other business conditions existing at the time.  We have the option to
defer interest payments on the AEP Junior Subordinated Debentures issued in
March 2008 for one or more periods of up to 10 consecutive years per
period.  During any period in which we defer interest payments, we may
not declare or pay any dividends or distributions on, or redeem, repurchase or
acquire, our common stock.  We believe that these restrictions will
not have a material effect on our cash flows, financial condition or limit any
dividend payments in the foreseeable future.





Credit
Ratings





Our
credit ratings as of March 31, 2009 were as follows:




Moody’s
                        
                        
                        S&P
                        
                        
                        FitchAEP
      Short-term Debt
                        
                        P-2
                        
                        
                        A-2
                        
                        
                        F-2AEP
      Senior Unsecured Debt
                        
                        Baa2
                        
                        
                        BBB
                        
                        
                        BBB





In 2009,
Moody’s:





·
            Placed
      AEP on negative outlook due to concern about overall credit worthiness,
      pending rate cases and recessionary pressures.·
            Placed
      OPCo, SWEPCo, TCC and TNC on review for possible downgrade due to concerns
      about financial metrics and pending cost and construction
      recoveries.·
            Affirmed
      the stable rating outlooks for CSPCo, I&M, KPCo and
    PSO.·
            Changed
      the rating outlook for APCo from negative to stable due to recent rate
      recoveries in Virginia and West
Virginia.





In 2009,
Fitch:





·
            Affirmed
      its stable rating outlook for I&M, PSO and TNC.·
            Changed
      its rating outlook for TCC from stable to
  negative.





If we
receive a downgrade in our credit ratings by any of the rating agencies, our
borrowing costs could increase and access to borrowed funds could be negatively
affected.





Cash
Flow





Managing
our cash flows is a major factor in maintaining our liquidity
strength.


Three
      Months EndedMarch
      31,2009
                      
                      2008(in
      millions)Cash
      and Cash Equivalents at Beginning of Period
                      
                      $
                      411
                      
                      
                      $
                      178Net
      Cash Flows from Operating Activities
                      
                      
                      317
                      
                      
                      
                      631Net
      Cash Flows Used for Investing Activities
                      
                      
                      (727
                      )
                      
                      
                      (894
                      )Net
      Cash Flows from Financing Activities
                      
                      
                      709
                      
                      
                      
                      240Net
      Increase (Decrease) in Cash and Cash Equivalents
                      
                      
                      299
                      
                      
                      
                      (23
                      )Cash
      and Cash Equivalents at End of Period
                      
                      $
                      710
                      
                      
                      $
                      155





Cash from
operations, combined with a bank-sponsored receivables purchase agreement and
short-term borrowings, provides working capital and allows us to meet other
short-term cash needs.





Operating
Activities


Three
      Months EndedMarch
      31,2009
                  
                  2008(in
      millions)Net
      Income
                  
                  $
                  363
                  
                  
                  $
                  576Depreciation
      and Amortization
                  
                  
                  382
                  
                  
                  
                  363Other
                  
                  
                  (428
                  )
                  
                  
                  (308
                  )Net
      Cash Flows from Operating Activities
                  
                  $
                  317
                  
                  
                  $
                  631





Net Cash
Flows from Operating Activities decreased in 2009 primarily due to a decline in
net income and an increase in fuel inventory.





Net Cash
Flows from Operating Activities were $317 million in 2009 consisting primarily
of Net Income of $363 million and $382 million of noncash depreciation and
amortization.  Other represents 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.  Significant changes in other items resulted in lower
cash from operations due to an increase in coal inventory from December 31,
2008.





Net Cash
Flows from Operating Activities were $631 million in 2008 consisting primarily
of Net Income of $576 million and $363 million of noncash depreciation and
amortization.  Other represents 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.  Significant changes in other items resulted in lower
cash from operations due to payment of items accrued at December 31,
2007.





Investing
Activities


Three
      Months EndedMarch
      31,2009
                      
                      2008(in
      millions)Construction
      Expenditures
                      
                      $
                      (897
                      )
                      
                      $
                      (778
                      )Proceeds
      from Sales of Assets
                      
                      
                      172
                      
                      
                      
                      18Other
                      
                      
                      (2
                      )
                      
                      
                      (134
                      )Net
      Cash Flows Used for Investing Activities
                      
                      $
                      (727
                      )
                      
                      $
                      (894
                      )





Net Cash
Flows Used for Investing Activities were $727 million in 2009 and $894 million
in 2008 primarily due to Construction Expenditures for our new generation,
environmental and distribution investment plan.  Construction
Expenditures increased compared to 2008 due to expenditures for new generation
during 2009.  Proceeds from Sales of Assets in 2009 primarily includes
$104 million in progress payments for Turk Plant construction from the joint
owners.





In our
normal course of business, we purchase investment securities including variable
rate demand notes with cash available for short-term investments and purchase
and sell securities within our nuclear trusts.  The net amount of
these activities is included in Other.





We
forecast approximately $2.6 billion of construction expenditures for all of
2009, excluding AFUDC.  Estimated construction expenditures are
subject to periodic review and modification and may vary based on the ongoing
effects of regulatory constraints, environmental regulations, business
opportunities, market volatility, economic trends, weather, legal reviews and
the ability to access capital.  These construction expenditures will
be funded through net income and financing activities.





Financing
Activities


Three
      Months EndedMarch
      31,2009
                  
                  2008(in
      millions)Issuance
      of Common Stock
                  
                  $
                  48
                  
                  
                  $
                  45Issuance/Retirement
      of Debt, Net
                  
                  
                  854
                  
                  
                  
                  376Dividends
      Paid on Common Stock
                  
                  
                  (169
                  )
                  
                  
                  (167
                  )Other
                  
                  
                  (24
                  )
                  
                  
                  (14
                  )Net
      Cash Flows from Financing Activities
                  
                  $
                  709
                  
                  
                  $
                  240





Net Cash
Flows from Financing Activities in 2009 were $709 million primarily due to the
issuance of $825 million of senior unsecured notes and $134 million of pollution
control bonds.  See Note 9 – Financing Activities for a complete
discussion of long-term debt issuances and retirements.





Net Cash
Flows from Financing Activities in 2008 were $240 million primarily due to the
issuance of $315 million of junior subordinated debentures and $500 million of
senior unsecured notes, partially offset by the retirement of $95 million of
pollution control bonds, $52 million of senior unsecured notes and $34 million
of mortgage notes and the reduction of our short-term commercial paper
outstanding by $251 million.





Our
capital investment plans for the remainder of 2009 will require additional
funding from the capital markets.





Off-balance Sheet
Arrangements





Under a
limited set of circumstances, we enter into off-balance sheet arrangements to
accelerate cash collections, reduce operational expenses and spread risk of loss
to third parties.  Our current guidelines restrict the use of
off-balance sheet financing entities or structures to traditional operating
lease arrangements and sales of customer accounts receivable that we enter in
the normal course of business.  Our significant off-balance sheet
arrangements  are as follows:


March
      31,
                      2009
                    
                    December
      31,
                      2008(in
      millions)AEP
      Credit Accounts Receivable Purchase Commitments
                    
                    $
                    578
                    
                    
                    $
                    650Rockport
      Plant Unit 2 Future Minimum Lease Payments
                    
                    
                    2,070
                    
                    
                    
                    2,070Railcars
      Maximum Potential Loss From Lease Agreement
                    
                    
                    25
                    
                    
                    
                    25





For
complete information on each of these off-balance sheet arrangements see the
“Off-balance Sheet Arrangements” section of “Management’s Financial Discussion
and Analysis of Results of Operations” in the 2008 Annual Report.





Summary Obligation
Information





A summary
of our contractual obligations is included in our 2008 Annual Report and has not
changed significantly from year-end other than the debt issuances and
retirements discussed in “Cash Flow” above and the drawdowns and standby letters
of credit discussed in “Liquidity” above.





SIGNIFICANT
FACTORS





We
continue to be involved in various matters described in the “Significant
Factors” section of “Management’s Financial Discussion and Analysis of Results
of Operations” in our 2008 Annual Report.  The 2008 Annual Report
should be read in conjunction with this report in order to understand
significant factors which have not materially changed in status since the
issuance of our 2008 Annual Report, but may have a material impact on our future
net income, cash flows and financial condition.





Ohio Electric Security Plan
Filings





In March
2009, the PUCO issued an order that modified and approved CSPCo’s and OPCo’s
ESPs which will be in effect through 2011.  The ESP order authorized
increases to revenues during the ESP period and capped the overall revenue
increases through a phase-in of the fuel adjustment clause (FAC).  The
ordered increases for CSPCo are 7% in 2009, 6% in 2010 and 6% in 2011 and for
OPCo are 8% in 2009, 7% in 2010 and 8% in 2011.  After final PUCO
review and approval of conforming rate schedules, CSPCo and OPCo implemented
rates for the April 2009 billing cycle.  CSPCo and OPCo will collect
the 2009 annualized revenue increase over the remainder of 2009.





The order
provides a FAC for the three-year period of the ESP.  The FAC increase
will be phased in to meet the ordered annual caps described
above.  The FAC increase before phase-in will be subject to quarterly
true-ups to actual recoverable FAC costs and to annual accounting audits and
prudency reviews.  The order allows CSPCo and OPCo to defer
unrecovered FAC costs resulting from the annual caps/phase-in plan and to accrue
carrying charges on such deferrals at CSPCo’s and OPCo’s weighted average cost
of capital.  The deferred FAC balance at the end of the ESP period
will be recovered through a non-bypassable surcharge over the period 2012
through 2018.  As of March 31, 2009, the FAC deferral balances were
$17 million and $66 million for CSPCo and OPCo, respectively, including carrying
charges.  The PUCO rejected a proposal by several intervenors to
offset the FAC costs with a credit for off-system sales margins.  As a
result, CSPCo and OPCo will retain the benefit of their share of  the
AEP System’s off-system sales.  In addition, the ESP order provided
for both the FAC deferral credits and the off-system sales margins to be
excluded from the methodology for the Significantly Excessive Earnings Test
(SEET).  The SEET is discussed below.





Additionally,
the order addressed several other items, including:





·
            The
      approval of new distribution riders, subject to true-up for recovery of
      costs for enhanced vegetation management programs for CSPCo and OPCo and
      the proposed gridSMART advanced metering initial program roll out in a
      portion of CSPCo’s service territory.  The PUCO proposed that
      CSPCo mitigate the costs of gridSMART by seeking matching funds under the
      American Recovery and Reinvestment Act of 2009.  As a result, a
      rider was established to recover 50% or $32 million of the projected $64
      million revenue requirement related to gridSMART costs.  The
      PUCO denied the other distribution system reliability programs proposed by
      CSPCo and OPCo as part of their ESP filings.  The PUCO decided
      that those requests should be examined in the context of a complete
      distribution base rate case.  The order did not require CSPCo
      and/or OPCo to file a distribution base rate
  case.





·
            The
      approval of CSPCo’s and OPCo’s request to recover the incremental carrying
      costs related to environmental investments made from 2001 through 2008
      that are not reflected in existing rates.  Future recovery
      during the ESP period of incremental carrying charges on environmental
      expenditures incurred beginning in 2009 may be requested in annual
      filings.





·
            The
      approval of a $97 million and $55 million increase in CSPCo’s and OPCo’s
      Provider of Last Resort charges, respectively, to compensate for the risk
      of customers changing electric suppliers during the ESP
      period.





·
            The
      requirement that CSPCo’s and OPCo’s shareholders fund a combined minimum
      of $15 million in costs over the ESP period for low-income, at-risk
      customer programs.  This funding obligation was recognized as a
      liability and an unfavorable adjustment to Other Operation and Maintenance
      expense for the three-month period ending March 31,
  2009.





·
            The
      deferral of CSPCo’s and OPCo’s request to recover certain existing
      regulatory assets, including customer choice implementation and line
      extension carrying costs as part of the ESPs.  The PUCO decided
      it would be more appropriate to consider this request in the context of
      CSPCo’s and OPCo’s next distribution base rate case.  These
      regulatory assets, which were approved by prior PUCO orders, total $58
      million for CSPCo and $40 million for OPCo as of March 31,
      2009.  In addition, CSPCo and OPCo would recover and recognize
      as income, when collected, $35 million and $26 million, respectively, of
      related unrecorded equity carrying costs incurred through March
      2009.





Finally,
consistent with its decisions on ESP orders of other companies, the PUCO ordered
its staff to convene a workshop to determine the methodology for the SEET that
will be applicable to all electric utilities in Ohio.  The SEET
requires the PUCO to determine, following the end of each year of the ESP, if
any rate adjustments included in the ESP resulted in excessive earnings as
measured by whether the earned return on common equity of CSPCo and OPCo is
significantly in excess of the return on common equity that was earned during
the same period by publicly traded companies, including utilities, that have
comparable business and financial risk.  If the rate adjustments, in
the aggregate, result in significantly excessive earnings in comparison, the
PUCO must require that the amount of the excess be returned to
customers.  The PUCO’s decision on the SEET review of CSPCo’s and
OPCo’s 2009 earnings is not expected to be finalized until the second or third
quarter of 2010.





In March
2009, intervenors filed a motion to stay a portion of the ESP rates or
alternately make that portion subject to refund because the intervenors believed
that the ordered ESP rates for 2009 were retroactive and therefore
unlawful.  In March 2009, the PUCO approved CSPCo’s and OPCo’s tariffs
effective with the April 2009 billing cycle and rejected the intervenors’
motion.  The PUCO also clarified that the reference in its earlier
order to the January 1, 2009 date related to the term of the ESP, not to the
effective date of tariffs and clarified the tariffs were not
retroactive.  In March 2009, CSPCo and OPCo implemented the new ESP
tariffs effective with the start of the April 2009 billing cycle.  In
April 2009, CSPCo and OPCo filed a motion requesting rehearing of several
issues.  In April 2009, several intervenors filed motions requesting
rehearing of issues underlying the PUCO’s authorized rate increases and one
intervenor filed a motion requesting the PUCO to direct CSPCo and OPCo to cease
collecting rates under the order.  Certain intervenors also filed a
complaint for writ of prohibition with the Ohio Supreme Court to halt any
further collection from customers of what the intervenors claim is unlawful
retroactive rate increases.





Management
will evaluate whether it will withdraw the ESP applications after a final order,
thereby terminating the ESP proceedings.  If CSPCo and/or OPCo
withdraw the ESP applications, CSPCo and/or OPCo may file a Market Rate Offer
(MRO) or another ESP as permitted by the law.  The revenues collected
and recorded in 2009 under this PUCO order are subject to possible refund
through the SEET process.  Management is unable, due to the decision
of the PUCO to defer guidance on the SEET methodology to a future generic SEET
proceeding, to estimate the amount, if any, of a possible refund that could
result from the SEET process in 2010.





Cook Plant Unit 1 Fire and
Shutdown





In
September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine
vibrations, likely caused by blade failure, which resulted in a fire on the
electric generator.  This equipment, located in the turbine building,
is separate and isolated from the nuclear reactor.  The turbine rotors
that caused the vibration were installed in 2006 and are within the vendor’s
warranty period.  The warranty provides for the repair or replacement
of the turbine rotors if the damage was caused by a defect in materials or
workmanship.  I&M is working with its insurance company, Nuclear
Electric Insurance Limited (NEIL), and its turbine vendor, Siemens, to evaluate
the extent of the damage resulting from the incident and facilitate repairs to
return the unit to service.  Repair of the property damage and
replacement of the turbine rotors and other equipment could cost up to
approximately $330 million.  Management believes that I&M should
recover a significant portion of these costs through the turbine vendor’s
warranty, insurance and the regulatory process.  The treatment of
property damage costs, replacement power costs and insurance proceeds will be
the subject of future regulatory proceedings in Indiana and
Michigan.  I&M is repairing Unit 1 to resume operations as early
as October 2009 at reduced power.  Should post-repair operations prove
unsuccessful, the replacement of parts will extend the outage into
2011.





I&M
maintains property insurance through NEIL with a $1 million
deductible.  As of March 31, 2009, we recorded $34 million in
Prepayments and Other on our Condensed Consolidated Balance Sheets representing
recoverable amounts under the property insurance policy.  I&M
received partial reimbursements from NEIL for the cost incurred to date to
repair the property damage.  I&M also maintains a separate
accidental outage policy with NEIL whereby, after a 12-week deductible period,
I&M is entitled to weekly payments of $3.5 million for the first 52 weeks
following the deductible period.  After the initial 52 weeks of
indemnity, the policy pays $2.8 million per week for up to an additional 110
weeks.  I&M began receiving payments under the accidental outage
policy in December 2008.  In the first quarter of 2009, I&M
recorded $54 million in revenues, including $9 million in revenues that were
deferred at December 31, 2008, related to the accidental outage
policy.  In order to hold customers harmless, in the first quarter of
2009, I&M applied $20 million of the accidental outage insurance proceeds to
reduce fuel underrecoveries reflecting recoverable fuel costs as if Unit 1 were
operating.  If the ultimate costs of the incident are not covered by
warranty, insurance or through the regulatory process or if the unit is not
returned to service in a reasonable period of time, it could have an adverse
impact on net income, cash flows and financial condition.





Texas Restructuring
Appeals





Pursuant
to PUCT orders, TCC securitized net recoverable stranded generation costs of
$2.5 billion and is recovering the principal and interest on the securitization
bonds through the end of 2020.  TCC refunded net other true-up
regulatory liabilities of $375 million during the period October 2006 through
June 2008 via a CTC credit rate rider.  Although earnings were not
affected by this CTC refund, cash flow was adversely impacted for 2008, 2007 and
2006 by $75 million, $238 million and $69 million, respectively.  TCC
appealed the PUCT stranded costs true-up and related orders seeking relief in
both state and federal court on the grounds that certain aspects of the orders
are contrary to the Texas Restructuring Legislation, PUCT rulemakings and
federal law and fail to fully compensate TCC for its net stranded cost and other
true-up items.  Municipal customers and other intervenors also
appealed the PUCT true-up orders seeking to further reduce TCC’s true-up
recoveries.





In March
2007, the Texas District Court judge hearing the appeals of the true-up order
affirmed the PUCT’s April 2006 final true-up order for TCC with two significant
exceptions.  The judge determined that the PUCT erred by applying an
invalid rule to determine the carrying cost rate for the true-up of stranded
costs and remanded this matter to the PUCT for further
consideration.  This remand could potentially have an adverse effect
on TCC’s future net income and cash flows if upheld on appeal.  The
District Court judge also determined that the PUCT improperly reduced TCC’s net
stranded plant costs for commercial unreasonableness which could have a
favorable effect on TCC’s future net income and cash flows.





TCC, the
PUCT and intervenors appealed the District Court decision to the Texas Court of
Appeals.  In May 2008, the Texas Court of Appeals affirmed the
District Court decision in all but two major respects.  It reversed
the District Court’s unfavorable decision which found that the PUCT erred by
applying an invalid rule to determine the carrying cost rate.  It also
determined that the PUCT erred by not reducing stranded costs by the “excess
earnings” that had already been refunded to affiliated
REPs.  Management does not believe that TCC will be adversely affected
by the Court of Appeals ruling on excess earnings based upon the reasons
discussed in the “TCC Excess Earnings” section below.  The favorable
commercial unreasonableness judgment entered by the District Court was not
reversed.  The Texas Court of Appeals denied intervenors’ motion for
rehearing.  In May 2008, TCC, the PUCT and intervenors filed petitions
for review with the Texas Supreme Court.  Review is discretionary and
the Texas Supreme Court has not determined if it will grant
review.  In January 2009, the Texas Supreme Court requested full
briefing of the proceedings.





TNC
received its final true-up order in May 2005 that resulted in refunds via a CTC
which have been completed.  The appeal brought by TNC of the final
true-up order remains pending in state court.





Management
cannot predict the outcome of these court proceedings and PUCT remand
decisions.  If TCC and/or TNC ultimately succeed in their appeals, it
could have a material favorable effect on future net income, cash flows and
financial condition.  If municipal customers and other intervenors
succeed in their appeals, it could have a material adverse effect on future net
income, cash flows and possibly financial condition.





New Generation/Purchase
Power Agreement





In 2009,
AEP is in various stages of construction of the following generation
facilities:


CommercialTotal
              
              
              
              
              
              
              
              
              Nominal
              
              OperationOperating
              
              Project
              
              
              
              Projected
              
              
              
              
              
              
              
              
              MW
              
              DateCompany
              
              Name
              
              Location
              
              Cost
      (a)
              
              CWIP
      (b)
              
              Fuel
      Type
              
              Plant
      Type
              
              Capacity
              
              (Projected)(in
      millions)
              
              (in
      millions)AEGCo
              
              Dresden
              (c)
              Ohio
              
              $
              322
              
              $
              189
              
              Gas
              
              Combined-cycle
              
              580
              
              2013SWEPCo
              
              Stall
              
              Louisiana
              
              
              385
              
              
              291
              
              Gas
              
              Combined-cycle
              
              500
              
              2010SWEPCo
              
              Turk
              (d)
              Arkansas
              
              
              1,628
              (d)
              
              480
              
              Coal
              
              Ultra-supercritical
              
              600
              (d)
              2012APCo
              
              Mountaineer
              (e)
              West
      Virginia
              
              
              
              (e)
              
              
              
              Coal
              
              IGCC
              
              629
              
              (e)CSPCo/OPCo
              
              Great
      Bend
              (e)
              Ohio
              
              
              
              (e)
              
              
              
              Coal
              
              IGCC
              
              629
              
              (e)





(a)
            Amount
      excludes AFUDC.(b)
            Amount
      includes AFUDC.(c)
            In
      September 2007, AEGCo purchased the partially completed Dresden plant from
      Dresden Energy LLC, a subsidiary of Dominion Resources, Inc., for $85
      million, which is included in the “Total Projected Cost” section
      above.(d)
            SWEPCo
      plans to own approximately 73%, or 440 MW, totaling $1.2 billion in
      capital investment.  See “Turk Plant” section
    below.(e)
            Construction
      of IGCC plants is subject to regulatory approvals.  See “IGCC
      Plants” section below.





Turk
Plant





In
November 2007, the APSC granted approval to build the Turk
Plant.  Certain landowners have appealed the APSC’s decision to the
Arkansas State Court of Appeals.  In March 2008, the LPSC approved the
application to construct the Turk Plant.





In August
2008, the PUCT issued an order approving the Turk Plant with the following four
conditions: (a) the capping of capital costs for the Turk Plant at the
previously estimated $1.522 billion projected construction cost, excluding
AFUDC, (b) capping CO2 emission
costs at $28 per ton through the year 2030, (c) holding Texas ratepayers
financially harmless from any adverse impact related to the Turk Plant not being
fully subscribed to by other utilities or wholesale customers and (d) providing
the PUCT all updates, studies, reviews, reports and analyses as previously
required under the Louisiana and Arkansas orders.  In October 2008,
SWEPCo appealed the PUCT’s order regarding the two cost cap
restrictions.  If the cost cap restrictions are upheld and
construction or emission costs exceed the restrictions, it could have a material
adverse effect on future net income and cash flows.  In October 2008,
an intervenor filed an appeal contending that the PUCT’s grant of a conditional
Certificate of Public Convenience and Necessity for the Turk Plant was not
necessary to serve retail customers.





A request
to stop pre-construction activities at the site was filed in federal court by
Arkansas landowners.  In July 2008, the federal court denied the
request and the Arkansas landowners appealed the denial to the U.S. Court of
Appeals.  In January 2009, SWEPCo filed a motion to dismiss the
appeal.  In March 2009, the motion was granted.





In
November 2008, SWEPCo received the required air permit approval from the
Arkansas Department of Environmental Quality and commenced
construction.  In December 2008, Arkansas landowners filed an appeal
with the Arkansas Pollution Control and Ecology Commission (APCEC) which caused
construction of the Turk Plant to halt until the APCEC took further
action.  In December 2008, SWEPCo filed a request with the APCEC to
continue construction of the Turk Plant and the APCEC ruled to allow
construction to continue while an appeal of the Turk Plant’s permit is
heard.  Hearings on the air permit appeal are scheduled for June
2009.  SWEPCo is also working with the U.S. Army Corps of Engineers
for the approval of a wetlands and stream impact permit.  In March
2009, SWEPCo reported to the U.S. Army Corps of Engineers a potential wetlands
impact on approximately 2.5 acres at the Turk Plant.  The U.S. Army
Corps of Engineers directed SWEPCo to cease further work impacting the wetland
areas.  Construction has continued on other areas of the Turk
Plant.  The impact on the construction schedule and workforce is
currently being evaluated by management.





In
January and July 2008, SWEPCo filed Certificate of Environmental Compatibility
and Public Need (CECPN) applications with the APSC to construct transmission
lines necessary for service from the Turk Plant.  Several landowners
filed for intervention status and one landowner also contended he should be
permitted to re-litigate Turk Plant issues, including the need for the
generation.  The APSC granted their intervention but denied the
request to re-litigate the Turk Plant issues.  In June 2008, the
landowner filed an appeal to the Arkansas State Court of Appeals requesting to
re-litigate Turk Plant issues.  SWEPCo responded and the appeal was
dismissed.  In January 2009, the APSC approved the CECPN
applications.





The
Arkansas Governor’s Commission on Global Warming issued its final report to the
governor in October 2008.  The Commission was established to set a
global warming pollution reduction goal together with a strategic plan for
implementation in Arkansas.  The Commission’s final report included a
recommendation that the Turk Plant employ post combustion carbon capture and
storage measures as soon as it starts operating.  If legislation is
passed as a result of the findings in the Commission’s report, it could impact
SWEPCo’s proposal to build and operate the Turk Plant.





If SWEPCo
does not receive appropriate authorizations and permits to build the Turk Plant,
SWEPCo could incur significant cancellation fees to terminate its commitments
and would be responsible to reimburse OMPA, AECC and ETEC for their share of
costs incurred plus related shutdown costs.  If that occurred, SWEPCo
would seek recovery of its capitalized costs including any cancellation fees and
joint owner reimbursements.  As of March 31, 2009, SWEPCo has
capitalized approximately $480 million of expenditures (including AFUDC) and has
contractual construction commitments for an additional $655
million.  As of March 31, 2009, if the plant had been cancelled,
SWEPCo would have incurred cancellation fees of $100 million.  If the
Turk Plant does not receive all necessary approvals on reasonable terms and
SWEPCo cannot recover its capitalized costs, including any cancellation fees, it
would have an adverse effect on future net income, cash flows and possibly
financial condition.





IGCC
Plants





The
construction of the West Virginia and Ohio IGCC plants are pending regulatory
approvals.  In April 2008, the Virginia SCC issued an order denying
APCo’s request to recover initial costs associated with a proposed IGCC plant in
West Virginia.  In July 2008, the WVPSC issued a notice seeking
comments from parties on how the WVPSC should proceed regarding its earlier
approval of the IGCC plant.  Comments were filed by various parties,
including APCo, but the WVPSC has not taken any action.  In July 2008,
the IRS allocated $134 million in future tax credits to APCo for the planned
IGCC plant contingent upon the commencement of construction, qualifying expenses
being incurred and certification of the IGCC plant prior to July
2010.  Through March 2009, APCo deferred for future recovery
preconstruction IGCC costs of $20 million.  If the West Virginia IGCC
plant is cancelled, APCo plans to seek recovery of its prudently incurred
deferred pre-construction costs.  If the plant is cancelled and if the
deferred costs are not recoverable, it would have an adverse effect on future
net income and cash flows.





In Ohio,
neither CSPCo nor OPCo are engaged in a continuous course of construction on the
IGCC plant.  However, CSPCo and OPCo continue to pursue the ultimate
construction of the IGCC plant.  In September 2008, the Ohio
Consumers’ Counsel filed a motion with the PUCO requesting all pre-construction
cost recoveries be refunded to Ohio ratepayers with interest.  CSPCo
and OPCo filed a response with the PUCO that argued the Ohio Consumers’
Counsel’s motion was without legal merit and contrary to past
precedent.  If CSPCo and OPCo were required to refund some or all of
the $24 million collected for IGCC pre-construction costs and those costs were
not recoverable in another jurisdiction in connection with the construction of
an IGCC plant, it would have an adverse effect on future net income and cash
flows.





PSO
Purchase Power Agreement





PSO and
Exelon Generation Company LLC, a subsidiary of Exelon Corporation, executed a
long-term purchase power agreement (PPA) for which an application seeking its
approval is expected to be filed with the OCC.  The PPA is for the
purchase of up to 520 MW of electric generation from the 795 MW natural
gas-fired Green Country Generating Station, located in Jenks,
Oklahoma.  The agreement is the result of PSO’s 2008 Request for
Proposals following a December 2007 OCC order that found PSO had a need for new
baseload generation by 2012.





Litigation





In the
ordinary course of business, we are involved in employment, commercial,
environmental and regulatory litigation.  Since it is difficult to
predict the outcome of these proceedings, we cannot state what the eventual
outcome will be, or what the timing of the amount of any loss, fine or penalty
may be.  Management assesses the probability of loss for each
contingency and accrues a liability for cases that have a probable likelihood of
loss if the loss amount can be estimated.  For details on our
regulatory proceedings and pending litigation see Note 4 – Rate Matters, Note 6
– Commitments, Guarantees and Contingencies and the “Litigation” section of
“Management’s Financial Discussion and Analysis of Results of Operations” in the
2008 Annual Report.  Additionally, see Note 3 – Rate Matters and Note
4 – Commitments, Guarantees and Contingencies included
herein.  Adverse results in these proceedings have the potential to
materially affect our net income and cash flows.





Environmental
Litigation





New Source Review (NSR)
Litigation:  The Federal EPA, a number of states and certain
special interest groups filed complaints alleging that CSPCo, Dayton Power and
Light Company (DP&L) and Duke Energy Ohio, Inc. (Duke) modified certain
units at coal-fired generating plants in violation of the NSR requirements of
the CAA.





Litigation
continues against Beckjord, a plant jointly-owned by CSPCo, Duke and DP&L,
which Duke operates.  A jury trial returned a verdict of no liability
at the Beckjord unit.  In December 2008, however, the court ordered a
new trial in the Beckjord case.  We are unable to predict the outcome
of this case.  We believe we can recover any capital and operating
costs of additional pollution control equipment that may be required through
future regulated rates or market prices for electricity.  If we are
unable to recover such costs or if material penalties are imposed, it would
adversely affect future net income and cash flows.





Environmental
Matters





We are
implementing a substantial capital investment program and incurring additional
operational costs to comply with new environmental control
requirements.  The sources of these requirements include:





·
            Requirements
      under CAA to reduce emissions of SO2,
      NOx,
      particulate matter (PM) and mercury from fossil fuel-fired power plants;
      and·
            Requirements
      under the Clean Water Act (CWA) to reduce the impacts of water intake
      structures on aquatic species at certain of our power
    plants.





In
addition, we are engaged in litigation with respect to certain environmental
matters, have been notified of potential responsibility for the clean-up of
contaminated sites and incur costs for disposal of spent nuclear fuel and future
decommissioning of our nuclear units.  We are also involved in the
development of possible future requirements to reduce CO2and other
greenhouse gases (GHG) emissions to address concerns about global climate
change.  All of these matters are discussed in the “Environmental
Matters” section of “Management’s Financial Discussion and Analysis of Results
of Operations” in the 2008 Annual Report.





Clean
Water Act Regulations





In 2004,
the Federal EPA issued a final rule requiring all large existing power plants
with once-through cooling water systems to meet certain standards to reduce
mortality of aquatic organisms pinned against the plant’s cooling water intake
screen or entrained in the cooling water.  The standards vary based on
the water bodies from which the plants draw their cooling water.  We
expected additional capital and operating expenses, which the Federal EPA
estimated could be $193 million for our plants.  We undertook
site-specific studies and have been evaluating site-specific compliance or
mitigation measures that could significantly change these cost
estimates.





In 2007,
the Federal EPA suspended the 2004 rule, except for the requirement that
permitting agencies develop best professional judgment (BPJ) controls for
existing facility cooling water intake structures that reflect the best
technology available for minimizing adverse environmental impact.  The
result is that the BPJ control standard for cooling water intake structures in
effect prior to the 2004 rule is the applicable standard for permitting agencies
pending finalization of revised rules by the Federal EPA.  We sought
further review and filed for relief from the schedules included in our
permits.





In April
2009, the U.S. Supreme Court issued a decision that allows the Federal EPA the
discretion to rely on cost-benefit analysis in setting national performance
standards and in providing for cost-benefit variances from those standards as
part of the regulations.  We cannot predict if or how the Federal EPA
will apply this decision to any revision of the regulations or what effect it
may have on similar requirements adopted by the states.





Potential
Regulation of CO2 and Other
GHG Emissions





As
discussed in the 2008 Annual Report, CO2 and other
GHG are alleged to contribute to climate change.  In April 2009, the
Federal EPA issued a proposed endangerment finding under the CAA regarding GHG
emissions from motor vehicles.  The proposed endangerment finding is
subject to public comment.  This finding could lead to regulation of
CO2
and other gases under existing laws.  Congress continues to discuss
new legislation related to the control of these emissions.  Some
policy approaches being discussed would have significant and widespread negative
consequences for the national economy and major U.S. industrial enterprises,
including us.  Because of these adverse consequences, management
believes that these more extreme policies will not ultimately be
adopted.  Even if reasonable CO2 and other
GHG emission standards are imposed, they will still require us to make material
expenditures.  Management believes that costs of complying with new
CO2
and other GHG emission standards will be treated like all other reasonable costs
of serving customers, and should be recoverable from customers as costs of doing
business including capital investments with a return on investment.





Critical Accounting
Estimates





See the
“Critical Accounting Estimates” section of “Management’s Financial Discussion
and Analysis of Results of Operations” in the 2008 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.





Adoption of New Accounting
Pronouncements





The FASB
issued SFAS 141R (revised “Business Combinations” 2007) improving financial
reporting about business combinations and their effects.  SFAS 141R
can affect tax positions on previous acquisitions.  We do not have any
such tax positions that result in adjustments.  We adopted SFAS 141R
effective January 1, 2009.  We will apply it to any future business
combinations.





The FASB
issued SFAS 160 “Noncontrolling Interest in Consolidated Financial Statements”
(SFAS 160), modifying reporting for noncontrolling interest (minority interest)
in consolidated financial statements.  The statement requires
noncontrolling interest be reported in equity and establishes a new framework
for recognizing net income or loss and comprehensive income by the controlling
interest.  We adopted SFAS 160 effective January 1, 2009 and
retrospectively applied the standard to prior periods.  See Note
2.





The FASB
issued SFAS 161 “Disclosures about Derivative Instruments and Hedging
Activities” (SFAS 161), enhancing disclosure requirements for derivative
instruments and hedging activities.  The standard requires that
objectives for using derivative instruments be disclosed in terms of underlying
risk and accounting designation.  This standard increased our
disclosure requirements related to derivative instruments and hedging
activities.  We adopted SFAS 161 effective January 1,
2009.





The FASB
ratified EITF Issue No. 08-5 “Issuer’s Accounting for Liabilities Measured at
Fair Value with a Third-Party Credit Enhancement” (EITF 08-5) a consensus on
liabilities with third-party credit enhancements when the liability is measured
and disclosed at fair value.  The consensus treats the liability and
the credit enhancement as two units of accounting.  We adopted EITF
08-5 effective January 1, 2009.  It will be applied prospectively with
the effect of initial application included as a change in fair value of the
liability.





The FASB
ratified EITF Issue No. 08-6 “Equity Method Investment Accounting
Considerations” (EITF 08-6), a consensus on equity method investment accounting
including initial and allocated carrying values and subsequent
measurements.  We prospectively adopted EITF 08-6 effective January 1,
2009 with no impact on our financial statements.





We
adopted FSP EITF 03-6-1 “Determining Whether Instruments Granted in Share-Based
Payment Transactions Are Participating Securities” (EITF 03-6-1) effective
January 1, 2009.  The rule addressed whether instruments granted in
share-based payment transactions are participating securities prior to vesting
and determined that the instruments need to be included in earnings allocation
in computing EPS under the two-class method.  The adoption of this
standard had an immaterial impact on our financial statements.





The FASB
issued FSP SFAS 142-3 “Determination of the Useful Life of Intangible
Assets”amending
factors that should be considered in developing renewal or extension assumptions
used to determine the useful life of a recognized intangible
asset.  We adopted the rule effective January 1, 2009.  The
guidance is prospectively applied to intangible assets acquired after the
effective date.  The standard’s disclosure requirements are applied
prospectively to all intangible assets as of January 1, 2009.  The
adoption of this standard had no impact on our financial
statements.





The FASB
issued SFAS 157-2 which delays the effective date of SFAS 157 to fiscal years
beginning after November 15, 2008 for all nonfinancial assets and nonfinancial
liabilities, except those that are recognized or disclosed at fair value in the
financial statements on a recurring basis (at least annually).  As
defined in SFAS 157, fair value is the price that would be received to sell an
asset or paid to transfer a liability in an orderly transaction between market
participants at the measurement date.  The fair value hierarchy gives
the highest priority to unadjusted quoted prices in active markets for identical
assets or liabilities and the lowest priority to unobservable
inputs.  In the absence of quoted prices for identical or similar
assets or investments in active markets, fair value is estimated using various
internal and external valuation methods including cash flow analysis and
appraisals.  We adopted SFAS 157-2 effective January 1,
2009.  We will apply these requirements to applicable fair value
measurements which include new asset retirement obligations and impairment
analysis related to long-lived assets, equity investments, goodwill and
intangibles.  We did not record any fair value measurements for
nonrecurring nonfinancial assets and liabilities in the first quarter of
2009.





QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES





Market
Risks





Our
Utility Operations segment is exposed to certain market risks as a major power
producer and marketer of wholesale electricity, coal and emission
allowances.  These risks include commodity price risk, interest rate
risk and credit risk.  In addition, we may be exposed to foreign
currency exchange risk because occasionally we procure various services and
materials used in our energy business from foreign suppliers.  These
risks represent the risk of loss that may impact us due to changes in the
underlying market prices or rates.





Our
Generation and Marketing segment, operating primarily within ERCOT, transacts in
wholesale energy trading and marketing contracts.  This segment is
exposed to certain market risks as a marketer of wholesale
electricity.  These risks include commodity price risk, interest rate
risk and credit risk.  These risks represent the risk of loss that may
impact us due to changes in the underlying market prices or rates.





All Other
includes natural gas operations which holds forward natural gas contracts that
were not sold with the natural gas pipeline and storage assets.  These
contracts are financial derivatives, which will gradually settle and completely
expire in 2011.  Our risk objective is to keep these positions
generally risk neutral through maturity.





We employ
risk management contracts including physical forward purchase and sale contracts
and financial forward purchase and sale contracts.  We engage in risk
management of electricity, coal, natural gas and emission allowances and to a
lesser degree other commodities associated with our energy
business.  As a result, we are subject to price risk.  The
amount of risk taken is determined by the commercial operations group in
accordance with the market risk policy approved by the Finance Committee of our
Board of Directors.  Our market risk oversight staff independently
monitors our risk policies, procedures and risk levels and provides members of
the Commercial Operations Risk Committee (CORC) various daily, weekly and/or
monthly reports regarding compliance with policies, limits and
procedures.  The CORC consists of our President – AEP Utilities, Chief
Financial Officer, Senior Vice President of Commercial Operations and Chief Risk
Officer.  When commercial activities exceed predetermined limits, we
modify the positions to reduce the risk to be within the limits unless
specifically approved by the CORC.





The
Committee of Chief Risk Officers (CCRO) adopted disclosure standards for risk
management contracts to improve clarity, understanding and consistency of
information reported.  The following tables provide information on our
risk management activities.





Mark-to-Market Risk
Management Contract Net Assets (Liabilities)





The
following two tables summarize the various mark-to-market (MTM) positions
included on our balance sheet as of March 31, 2009 and the reasons for changes
in our total MTM value included on our balance sheet as compared to December 31,
2008.





Reconciliation
of MTM Risk Management Contracts to


Condensed
Consolidated Balance Sheet


March
31, 2009


(in
millions)





Utility
      Operations
                            
                            
                            Generation
      and
                              Marketing
                            
                            
                            All
      Other
                            
                            
                            Sub-Total
                              MTM
      Risk Management Contracts
                            
                            
                            Cash
      Flow Hedge Contracts
                            
                            
                            Collateral
                              Deposits
                            
                            
                            TotalCurrent
      Assets
                            
                            $
                            256
                            
                            
                            $
                            27
                            
                            
                            $
                            4
                            
                            
                            $
                            287
                            
                            
                            $
                            40
                            
                            
                            $
                            (34
                            )
                            
                            $
                            293Noncurrent
      Assets
                            
                            
                            228
                            
                            
                            
                            221
                            
                            
                            
                            7
                            
                            
                            
                            456
                            
                            
                            
                            1
                            
                            
                            
                            (40
                            )
                            
                            
                            417Total
      Assets
                            
                            
                            484
                            
                            
                            
                            248
                            
                            
                            
                            11
                            
                            
                            
                            743
                            
                            
                            
                            41
                            
                            
                            
                            (74
                            )
                            
                            
                            710Current
      Liabilities
                            
                            
                            (153
                            )
                            
                            
                            (23
                            )
                            
                            
                            (9
                            )
                            
                            
                            (185
                            )
                            
                            
                            (31
                            )
                            
                            
                            37
                            
                            
                            
                            (179
                            )Noncurrent
      Liabilities
                            
                            
                            (155
                            )
                            
                            
                            (85
                            )
                            
                            
                            (10
                            )
                            
                            
                            (250
                            )
                            
                            
                            (4
                            )
                            
                            
                            80
                            
                            
                            
                            (174
                            )Total
      Liabilities
                            
                            
                            (308
                            )
                            
                            
                            (108
                            )
                            
                            
                            (19
                            )
                            
                            
                            (435
                            )
                            
                            
                            (35
                            )
                            
                            
                            117
                            
                            
                            
                            (353
                            )Total MTM Derivative Contract Net Assets
      (Liabilities)
                            
                            $
                            176
                            
                            
                            $
                            140
                            
                            
                            $
                            (8
                            )
                            
                            $
                            308
                            
                            
                            $
                            6
                            
                            
                            $
                            43
                            
                            
                            $
                            357





MTM
Risk Management Contract Net Assets (Liabilities)


Three
Months Ended March 31, 2009


(in
millions)




Utility
      Operations
                  
                  
                  Generation
                    and
                    Marketing
                  
                  
                  All
      Other
                  
                  
                  TotalTotal
      MTM Risk Management Contract Net Assets (Liabilities) at December 31,
      2008
                  
                  $
                  175
                  
                  
                  $
                  104
                  
                  
                  $
                  (7
                  )
                  
                  $
                  272(Gain)
      Loss from Contracts Realized/Settled During the Period and Entered in a
      Prior Period
                  
                  
                  (27
                  )
                  
                  
                  (3
                  )
                  
                  
                  1
                  
                  
                  
                  (29
                  )Fair
      Value of New Contracts at Inception When Entered During the Period
      (a)
                  
                  
                  2
                  
                  
                  
                  51
                  
                  
                  
                  -
                  
                  
                  
                  53Net
      Option Premiums Paid (Received) for Unexercised or Unexpired Option
      Contracts Entered During the Period
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -Changes
      in Fair Value Due to Valuation Methodology Changes on Forward
      Contracts
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -Changes
      in Fair Value Due to Market Fluctuations During the
      Period (b)
                  
                  
                  7
                  
                  
                  
                  (12
                  )
                  
                  
                  (2
                  )
                  
                  
                  (7
                  )Changes
      in Fair Value Allocated to Regulated Jurisdictions
(c)
                  
                  
                  19
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  19Total
      MTM Risk Management Contract Net Assets (Liabilities) at March
      31, 2009
                  
                  $
                  176
                  
                  
                  $
                  140
                  
                  
                  $
                  (8
                  )
                  
                  
                  308Cash
      Flow HedgeContracts
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  6Collateral
      Deposits
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  43Ending
      Net Risk Management Assets at March 31, 2009
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  $
                  357





(a)
            Reflects
      fair value on long-term structured contracts which are typically with
      customers that seek fixed pricing to limit their risk against fluctuating
      energy prices.  The contract prices are valued against market
      curves associated with the delivery location and delivery
      term.  A significant portion of the total volumetric position
      has been economically hedged.(b)
            Market
      fluctuations are attributable to various factors such as supply/demand,
      weather, etc.(c)
            “Change
      in Fair Value Allocated to Regulated Jurisdictions” relates to the net
      gains (losses) of those contracts that are not reflected on the Condensed
      Consolidated Statements of Income.  These net gains (losses) are
      recorded as regulatory
liabilities/assets.





Maturity and Source of Fair
Value of MTM Risk Management Contract Net Assets
(Liabilities)





The
following table presents the maturity, by year, of our net assets/liabilities,
to give 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, 2009


(in
millions)





Remainder
                    2009
                  
                  
                  2010
                  
                  
                  2011
                  
                  
                  2012
                  
                  
                  2013
                  
                  
                  After
                    2013
      (f)
                  
                  
                  TotalUtility
      OperationsLevel
      1 (a)
                  
                  $
                  (6
                  )
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  (6
                  )Level
      2 (b)
                  
                  
                  62
                  
                  
                  
                  34
                  
                  
                  
                  17
                  
                  
                  
                  (1
                  )
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  112Level
      3 (c)
                  
                  
                  16
                  
                  
                  
                  8
                  
                  
                  
                  5
                  
                  
                  
                  5
                  
                  
                  
                  1
                  
                  
                  
                  -
                  
                  
                  
                  35Total
                  
                  
                  72
                  
                  
                  
                  42
                  
                  
                  
                  22
                  
                  
                  
                  4
                  
                  
                  
                  1
                  
                  
                  
                  -
                  
                  
                  
                  141Generation
      and MarketingLevel
      1 (a)
                  
                  
                  (8
                  )
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  (8
                  )Level
      2 (b)
                  
                  
                  7
                  
                  
                  
                  15
                  
                  
                  
                  16
                  
                  
                  
                  16
                  
                  
                  
                  18
                  
                  
                  
                  25
                  
                  
                  
                  97Level
      3 (c)
                  
                  
                  1
                  
                  
                  
                  1
                  
                  
                  
                  2
                  
                  
                  
                  1
                  
                  
                  
                  3
                  
                  
                  
                  43
                  
                  
                  
                  51Total
                  
                  
                  -
                  
                  
                  
                  16
                  
                  
                  
                  18
                  
                  
                  
                  17
                  
                  
                  
                  21
                  
                  
                  
                  68
                  
                  
                  
                  140All
      OtherLevel
      1 (a)
                  
                  
                  -
                  
                  
                  
                  (1
                  )
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  (1
                  )Level
      2 (b)
                  
                  
                  (4
                  )
                  
                  
                  (5
                  )
                  
                  
                  2
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  (7
                  )Level
      3 (c)
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -Total
                  
                  
                  (4
                  )
                  
                  
                  (6
                  )
                  
                  
                  2
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  (8
                  )TotalLevel
      1 (a)
                  
                  
                  (14
                  )
                  
                  
                  (1
                  )
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  (15
                  )Level
      2 (b)
                  
                  
                  65
                  
                  
                  
                  44
                  
                  
                  
                  35
                  
                  
                  
                  15
                  
                  
                  
                  18
                  
                  
                  
                  25
                  
                  
                  
                  202Level
      3 (c) (d)
                  
                  
                  17
                  
                  
                  
                  9
                  
                  
                  
                  7
                  
                  
                  
                  6
                  
                  
                  
                  4
                  
                  
                  
                  43
                  
                  
                  
                  86Total
                  
                  
                  68
                  
                  
                  
                  52
                  
                  
                  
                  42
                  
                  
                  
                  21
                  
                  
                  
                  22
                  
                  
                  
                  68
                  
                  
                  
                  273Dedesignated
      Risk Management Contracts (e)
                  
                  
                  10
                  
                  
                  
                  14
                  
                  
                  
                  6
                  
                  
                  
                  5
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  35Total
      MTM Risk Management Contract Net Assets (Liabilities)
                  
                  $
                  78
                  
                  
                  $
                  66
                  
                  
                  $
                  48
                  
                  
                  $
                  26
                  
                  
                  $
                  22
                  
                  
                  $
                  68
                  
                  
                  $
                  308




(a)
            Level
      1 inputs are quoted prices (unadjusted) in active markets for identical
      assets or liabilities that the reporting entity has the ability to access
      at the measurement date.  Level 1 inputs primarily consist of
      exchange traded contracts that exhibit sufficient frequency and volume to
      provide pricing information on an ongoing basis.(b)
            Level
      2 inputs are inputs other than quoted prices included within Level 1 that
      are observable for the asset or liability, either directly or
      indirectly.  If the asset or liability has a specified
      (contractual) term, a Level 2 input must be observable for substantially
      the full term of the asset or liability.  Level 2 inputs
      primarily consist of OTC broker quotes in moderately active or less active
      markets, exchange traded contracts where there was not sufficient market
      activity to warrant inclusion in Level 1 and OTC broker quotes that are
      corroborated by the same or similar transactions that have occurred in the
      market.(c)
            Level
      3 inputs are unobservable inputs for the asset or
      liability.  Unobservable inputs shall be used to measure fair
      value to the extent that the observable inputs are not available, thereby
      allowing for situations in which there is little, if any, market activity
      for the asset or liability at the measurement date.  Level 3
      inputs primarily consist of unobservable market data or are valued based
      on models and/or assumptions.(d)
            A
      significant portion of the total volumetric position within the
      consolidated Level 3 balance has been economically
  hedged.(e)
            Dedesignated
      Risk Management Contracts are contracts that were originally MTM but were
      subsequently elected as normal under SFAS 133.  At the time of
      the normal election, the MTM value was frozen and no longer fair
      valued.  This will be amortized within Utility Operations
      Revenues over the remaining life of the contracts.(f)
            There
      is mark-to-market value of $68 million in individual periods beyond
      2014.  $46 million of this mark-to-market value is in periods
      2014-2018, $15 million is in periods 2019-2023 and $7 million is in
      periods 2024-2028.


Credit
Risk





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, 2009,
our credit exposure net of collateral to sub investment grade counterparties was
approximately 10.6%, expressed in terms of net MTM assets, net receivables and
the net open positions for contracts not subject to MTM (representing economic
risk even though there may not be risk of accounting loss).  As of
March 31, 2009, the following table approximates our counterparty credit quality
and exposure based on netting across commodities, instruments and legal entities
where applicable:





Exposure
      Before Credit Collateral
                
                
                Credit
      Collateral
                
                
                Net
      Exposure
                
                
                Number
      of Counterparties >10% of
                  Net
      Exposure
                
                
                Net
      Exposure
                  of
      Counterparties >10%Counterparty
      Credit Quality
                
                (in
      millions, except number of counterparties)Investment
      Grade
                
                $
                670
                
                
                $
                89
                
                
                $
                581
                
                
                
                1
                
                
                $
                133Split
      Rating
                
                
                8
                
                
                
                1
                
                
                
                7
                
                
                
                2
                
                
                
                7Noninvestment
      Grade
                
                
                14
                
                
                
                -
                
                
                
                14
                
                
                
                1
                
                
                
                13No
      External Ratings:Internal
      Investment Grade
                
                
                166
                
                
                
                16
                
                
                
                150
                
                
                
                4
                
                
                
                87Internal
      Noninvestment Grade
                
                
                83
                
                
                
                10
                
                
                
                73
                
                
                
                2
                
                
                
                55Total
      as of March 31, 2009
                
                $
                941
                
                
                $
                116
                
                
                $
                825
                
                
                
                10
                
                
                $
                295Total
      as of December 31, 2008
                
                $
                793
                
                
                $
                29
                
                
                $
                764
                
                
                
                9
                
                
                $
                284





See Note
7 for further information regarding MTM risk management contracts, cash flow
hedging, accumulated other comprehensive income, credit risk and collateral
triggering events.





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, 2009 a near term
typical change in commodity prices is not expected to have a material effect on
our net income, cash flows or financial condition.





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





VaR
Model





Three
      Months Ended
              
              
              
              
              Twelve
      Months EndedMarch
      31, 2009
              
              
              
              
              December
      31, 2008(in
      millions)
              
              
              
              
              (in
      millions)End
              
              High
              
              Average
              
              Low
              
              
              
              
              End
              
              High
              
              Average
              
              Low$1
              
              $1
              
              $1
              
              $-
              
              
              
              
              $-
              
              $3
              
              $1
              
              $-





We
back-test our VaR results against performance due to actual price
moves.  Based on the assumed 95% confidence interval, the performance
due to actual price moves would be expected to exceed the VaR at least once
every 20 trading days.  Our backtesting results show that our actual
performance exceeded VaR far fewer than once every 20 trading
days.  As a result, we believe our VaR calculation is
conservative.





As our
VaR calculation captures recent price moves, we also perform regular stress
testing of the portfolio to understand our exposure to extreme price
moves.  We employ a historical-based method whereby the current
portfolio is subjected to actual, observed price moves from the last three years
in order to ascertain which historical price moves translated into the largest
potential MTM loss.  We then research the underlying positions, price
moves and market events that created the most significant exposure.





Interest Rate
Risk





We
utilize an Earnings at Risk (EaR) model to measure interest rate market risk
exposure. EaR statistically quantifies the extent to which AEP’s interest
expense could vary over the next twelve months and gives a probabilistic
estimate of different levels of interest expense.  The resulting EaR
is interpreted as the dollar amount by which actual interest expense for the
next twelve months could exceed expected interest expense with a one-in-twenty
chance of occurrence.  The primary drivers of EaR are from the
existing floating rate debt (including short-term debt) as well as long-term
debt issuances in the next twelve months.  The estimated EaR on our
debt portfolio was $19 million.  This amount includes the estimated
impact of the April 2009 issuance of AEP common stock.







AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY
COMPANIES


CONDENSED
CONSOLIDATED STATEMENTS OF INCOME


For
the Three Months Ended March 31, 2009 and 2008


(in
millions, except per-share and share amounts)


(Unaudited)





REVENUES
                
                2009
                
                
                2008Utility
      Operations
                
                $
                3,267
                
                
                $
                3,010Other
                
                
                191
                
                
                
                457TOTAL
                
                
                3,458
                
                
                
                3,467EXPENSESFuel
      and Other Consumables Used for Electric Generation
                
                
                929
                
                
                
                980Purchased
      Electricity for Resale
                
                
                295
                
                
                
                263Other
      Operation and Maintenance
                
                
                914
                
                
                
                878Gain
      on Disposition of Assets, Net
                
                
                (9
                )
                
                
                (3
                )Asset
      Impairments and Other Related Charges
                
                
                -
                
                
                
                (255
                )Depreciation
      and Amortization
                
                
                382
                
                
                
                363Taxes
      Other Than Income Taxes
                
                
                197
                
                
                
                198TOTAL
                
                
                2,708
                
                
                
                2,424OPERATING
      INCOME
                
                
                750
                
                
                
                1,043Other
      Income (Expense):Interest
      and Investment Income
                
                
                5
                
                
                
                16Carrying
      Costs Income
                
                
                9
                
                
                
                17Allowance
      for Equity Funds Used During Construction
                
                
                16
                
                
                
                10Interest
      Expense
                
                
                (238
                )
                
                
                (219
                )INCOME
      BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS
                
                
                542
                
                
                
                867Income
      Tax Expense
                
                
                179
                
                
                
                293Equity
      Earnings of Unconsolidated Subsidiaries
                
                
                -
                
                
                
                2NET
      INCOME
                
                
                363
                
                
                
                576Less:  Net
      Income Attributable to Noncontrolling Interests
                
                
                2
                
                
                
                2NET
      INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS
                
                
                361
                
                
                
                574Less:
      Preferred Stock Dividend Requirements of Subsidiaries
                
                
                1
                
                
                
                1EARNINGS
      ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
                
                $
                360
                
                
                $
                573WEIGHTED
      AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING
                
                
                406,826,606
                
                
                
                400,797,993TOTAL
      BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
      SHAREHOLDERS
                
                $
                0.89
                
                
                $
                1.43WEIGHTED
      AVERAGE NUMBER OF DILUTED AEP COMMON SHARES
    OUTSTANDING
                
                
                407,381,954
                
                
                
                402,072,098TOTAL
      DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
      SHAREHOLDERS
                
                $
                0.89
                
                
                $
                1.43CASH
      DIVIDENDS PAID PER SHARE
                
                $
                0.41
                
                
                $
                0.41





See
      Condensed Notes to Condensed Consolidated Financial
      Statements.





AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES


CONDENSED
CONSOLIDATED BALANCE SHEETS


ASSETS


March
31, 2009 and December 31, 2008


(in
millions)


(Unaudited)





2009
                    
                    
                    2008CURRENT
      ASSETSCash
      and Cash Equivalents
                    
                    $
                    710
                    
                    
                    $
                    411Other
      Temporary Investments
                    
                    
                    215
                    
                    
                    
                    327Accounts
      Receivable:Customers
                    
                    
                    555
                    
                    
                    
                    569Accrued
      Unbilled Revenues
                    
                    
                    378
                    
                    
                    
                    449Miscellaneous
                    
                    
                    70
                    
                    
                    
                    90Allowance
      for Uncollectible Accounts
                    
                    
                    (41
                    )
                    
                    
                    (42
                    )Total
      Accounts Receivable
                    
                    
                    962
                    
                    
                    
                    1,066Fuel
                    
                    
                    740
                    
                    
                    
                    634Materials
      and Supplies
                    
                    
                    550
                    
                    
                    
                    539Risk
      Management Assets
                    
                    
                    293
                    
                    
                    
                    256Regulatory
      Asset for Under-Recovered Fuel Costs
                    
                    
                    320
                    
                    
                    
                    284Margin
      Deposits
                    
                    
                    125
                    
                    
                    
                    86Prepayments
      and Other
                    
                    
                    203
                    
                    
                    
                    172TOTAL
                    
                    
                    4,118
                    
                    
                    
                    3,775PROPERTY,
      PLANT AND EQUIPMENTElectric:Production
                    
                    
                    22,300
                    
                    
                    
                    21,242Transmission
                    
                    
                    7,955
                    
                    
                    
                    7,938Distribution
                    
                    
                    12,990
                    
                    
                    
                    12,816Other
      (including coal mining and nuclear fuel)
                    
                    
                    3,772
                    
                    
                    
                    3,741Construction
      Work in Progress
                    
                    
                    3,147
                    
                    
                    
                    3,973Total
                    
                    
                    50,164
                    
                    
                    
                    49,710Accumulated
      Depreciation and Amortization
                    
                    
                    16,913
                    
                    
                    
                    16,723TOTAL
      - NET
                    
                    
                    33,251
                    
                    
                    
                    32,987OTHER
      NONCURRENT ASSETSRegulatory
      Assets
                    
                    
                    3,837
                    
                    
                    
                    3,783Securitized
      Transition Assets
                    
                    
                    2,011
                    
                    
                    
                    2,040Spent
      Nuclear Fuel and Decommissioning Trusts
                    
                    
                    1,207
                    
                    
                    
                    1,260Goodwill
                    
                    
                    76
                    
                    
                    
                    76Long-term
      Risk Management Assets
                    
                    
                    417
                    
                    
                    
                    355Deferred
      Charges and Other
                    
                    
                    948
                    
                    
                    
                    879TOTAL
                    
                    
                    8,496
                    
                    
                    
                    8,393TOTAL
      ASSETS
                    
                    $
                    45,865
                    
                    
                    $
                    45,155





See
      Condensed Notes to Condensed Consolidated Financial
      Statements.







AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES


CONDENSED
CONSOLIDATED BALANCE SHEETS


LIABILITIES
AND EQUITY


March
31, 2009 and December 31, 2008


(Unaudited)





2009
                      
                      2008CURRENT
      LIABILITIES
                      
                      
                      (in
      millions)Accounts
      Payable
                      
                      
                      $
                      1,126
                      
                      $
                      1,297Short-term
      Debt
                      
                      
                      
                      1,976
                      
                      
                      1,976Long-term
      Debt Due Within One Year
                      
                      
                      
                      939
                      
                      
                      447Risk
      Management Liabilities
                      
                      
                      
                      179
                      
                      
                      134Customer
      Deposits
                      
                      
                      
                      266
                      
                      
                      254Accrued
      Taxes
                      
                      
                      
                      614
                      
                      
                      634Accrued
      Interest
                      
                      
                      
                      226
                      
                      
                      270Regulatory
      Liability for Over-Recovered Fuel Costs
                      
                      
                      
                      155
                      
                      
                      66Other
                      
                      
                      
                      930
                      
                      
                      1,219TOTAL
                      
                      
                      
                      6,411
                      
                      
                      6,297NONCURRENT
      LIABILITIESLong-term
      Debt
                      
                      
                      
                      15,904
                      
                      
                      15,536Long-term
      Risk Management Liabilities
                      
                      
                      
                      174
                      
                      
                      170Deferred
      Income Taxes
                      
                      
                      
                      5,255
                      
                      
                      5,128Regulatory
      Liabilities and Deferred Investment Tax Credits
                      
                      
                      
                      2,652
                      
                      
                      2,789Asset
      Retirement Obligations
                      
                      
                      
                      1,166
                      
                      
                      1,154Employee
      Benefits and Pension Obligations
                      
                      
                      
                      2,162
                      
                      
                      2,184Deferred
      Credits and Other
                      
                      
                      
                      1,122
                      
                      
                      1,126TOTAL
                      
                      
                      
                      28,435
                      
                      
                      28,087TOTAL
      LIABILITIES
                      
                      
                      
                      34,846
                      
                      
                      34,384Cumulative
      Preferred Stock Not Subject to Mandatory Redemption
                      
                      
                      
                      61
                      
                      
                      61Commitments
      and Contingencies (Note 4)EQUITYCommon
      Stock Par Value $6.50:2009
                      
                      2008Shares
      Authorized
                      600,000,000
                      
                      600,000,000Shares
      Issued
                      428,010,854
                      
                      426,321,248(20,249,992
      shares were held in treasury at March 31, 2009 and December 31,
      2008)
                      
                      
                      
                      2,782
                      
                      
                      2,771Paid-in
      Capital
                      
                      
                      
                      4,564
                      
                      
                      4,527Retained
      Earnings
                      
                      
                      
                      4,040
                      
                      
                      3,847Accumulated
      Other Comprehensive Income (Loss)
                      
                      
                      
                      (446)
                      
                      
                      (452)TOTAL
      AEP COMMON SHAREHOLDERS’ EQUITY
                      
                      
                      
                      10,940
                      
                      
                      10,693Noncontrolling
      Interests
                      
                      
                      
                      18
                      
                      
                      17TOTAL
      EQUITY
                      
                      
                      
                      10,958
                      
                      
                      10,710TOTAL
      LIABILITIES AND EQUITY
                      
                      
                      $
                      45,865
                      
                      $
                      45,155





See
      Condensed Notes to Condensed Consolidated Financial
      Statements.







AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES


CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS


For
the Three Months Ended March 31, 2009 and 2008


(in
millions)


(Unaudited)





2009
                    
                    
                    2008OPERATING
      ACTIVITIESNet
      Income
                    
                    $
                    363
                    
                    
                    $
                    576Adjustments
      to Reconcile Net Income to Net Cash Flows from Operating
      Activities:Depreciation
      and Amortization
                    
                    
                    382
                    
                    
                    
                    363Deferred
      Income Taxes
                    
                    
                    217
                    
                    
                    
                    111Carrying
      Costs Income
                    
                    
                    (9
                    )
                    
                    
                    (17
                    )Allowance
      for Equity Funds Used During Construction
                    
                    
                    (16
                    )
                    
                    
                    (10
                    )Mark-to-Market
      of Risk Management Contracts
                    
                    
                    (46
                    )
                    
                    
                    (26
                    )Amortization
      of Nuclear Fuel
                    
                    
                    13
                    
                    
                    
                    22Deferred
      Property Taxes
                    
                    
                    (64
                    )
                    
                    
                    (64
                    )Fuel
      Over/Under-Recovery, Net
                    
                    
                    (95
                    )
                    
                    
                    (57
                    )Gain
      on Sales of Assets
                    
                    
                    (9
                    )
                    
                    
                    (3
                    )Change
      in Other Noncurrent Assets
                    
                    
                    32
                    
                    
                    
                    (119
                    )Change
      in Other Noncurrent Liabilities
                    
                    
                    18
                    
                    
                    
                    (71
                    )Changes
      in Certain Components of Working Capital:Accounts
      Receivable, Net
                    
                    
                    102
                    
                    
                    
                    61Fuel,
      Materials and Supplies
                    
                    
                    (118
                    )
                    
                    
                    20Margin
      Deposits
                    
                    
                    (39
                    )
                    
                    
                    (4
                    )Accounts
      Payable
                    
                    
                    3
                    
                    
                    
                    (7
                    )Customer
      Deposits
                    
                    
                    12
                    
                    
                    
                    6Accrued
      Taxes, Net
                    
                    
                    (57
                    )
                    
                    
                    149Accrued
      Interest
                    
                    
                    (44
                    )
                    
                    
                    (44
                    )Other
      Current Assets
                    
                    
                    (7
                    )
                    
                    
                    (21
                    )Other
      Current Liabilities
                    
                    
                    (321
                    )
                    
                    
                    (234
                    )Net
      Cash Flows from Operating Activities
                    
                    
                    317
                    
                    
                    
                    631INVESTING
      ACTIVITIESConstruction
      Expenditures
                    
                    
                    (897
                    )
                    
                    
                    (778
                    )Change
      in Other Temporary Investments, Net
                    
                    
                    111
                    
                    
                    
                    (26
                    )Purchases
      of Investment Securities
                    
                    
                    (179
                    )
                    
                    
                    (491
                    )Sales
      of Investment Securities
                    
                    
                    158
                    
                    
                    
                    500Acquisition
      of Nuclear Fuel
                    
                    
                    (76
                    )
                    
                    
                    (98
                    )Proceeds
      from Sales of Assets
                    
                    
                    172
                    
                    
                    
                    18Other
                    
                    
                    (16
                    )
                    
                    
                    (19
                    )Net
      Cash Flows Used for Investing Activities
                    
                    
                    (727
                    )
                    
                    
                    (894
                    )FINANCING
      ACTIVITIESIssuance
      of Common Stock
                    
                    
                    48
                    
                    
                    
                    45Change
      in Short-term Debt, Net
                    
                    
                    -
                    
                    
                    
                    (251
                    )Issuance
      of Long-term Debt
                    
                    
                    947
                    
                    
                    
                    916Retirement
      of Long-term Debt
                    
                    
                    (93
                    )
                    
                    
                    (289
                    )Principal
      Payments for Capital Lease Obligations
                    
                    
                    (23
                    )
                    
                    
                    (23
                    )Dividends
      Paid on Common Stock
                    
                    
                    (169
                    )
                    
                    
                    (167
                    )Dividends
      Paid on Cumulative Preferred Stock
                    
                    
                    (1
                    )
                    
                    
                    (1
                    )Other
                    
                    
                    -
                    
                    
                    
                    10Net
      Cash Flows from Financing Activities
                    
                    
                    709
                    
                    
                    
                    240Net
      Increase (Decrease) in Cash and Cash Equivalents
                    
                    
                    299
                    
                    
                    
                    (23
                    )Cash
      and Cash Equivalents at Beginning of Period
                    
                    
                    411
                    
                    
                    
                    178Cash
      and Cash Equivalents at End of Period
                    
                    $
                    710
                    
                    
                    $
                    155SUPPLEMENTARY
      INFORMATIONCash
      Paid for Interest, Net of Capitalized Amounts
                    
                    $
                    314
                    
                    
                    $
                    252Net
      Cash Paid for Income Taxes
                    
                    
                    2
                    
                    
                    
                    36Noncash
      Acquisitions Under Capital Leases
                    
                    
                    6
                    
                    
                    
                    19Noncash
      Acquisition of Land/Mineral Rights
                    
                    
                    -
                    
                    
                    
                    42Construction
      Expenditures Included in Accounts Payable at March 31,
                    
                    
                    294
                    
                    
                    
                    284Acquisition
      of Nuclear Fuel Included in Accounts Payable at March 31,
                    
                    
                    17
                    
                    
                    
                    -





See
      Condensed Notes to Condensed Consolidated Financial
      Statements.





AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES


CONDENSED
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY AND


COMPREHENSIVE
INCOME (LOSS)


For
the Three Months Ended March 31, 2009 and 2008


(in
millions)


(Unaudited)





AEP
      Common ShareholdersCommon
      Stock
                                      
                                      
                                      
                                      
                                      
                                      AccumulatedOtherPaid-in
                                      
                                      Retained
                                      
                                      Comprehensive
                                      
                                      NoncontrollingShares
                                      
                                      Amount
                                      
                                      Capital
                                      
                                      Earnings
                                      
                                      Income
      (Loss)
                                      
                                      Interests
                                      
                                      TotalDECEMBER
      31, 2007
                                      
                                      422
                                      
                                      $
                                      2,743
                                      
                                      $
                                      4,352
                                      
                                      $
                                      3,138
                                      
                                      $
                                      (154)
                                      
                                      $
                                      18
                                      
                                      $
                                      10,097EITF
      06-10 Adoption, Net of Tax of $6
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      (10)
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      (10)SFAS
      157 Adoption, Net of Tax of $0
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      (1)
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      (1)Issuance
      of Common Stock
                                      
                                      1
                                      
                                      
                                      7
                                      
                                      
                                      38
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      45Common
      Stock Dividends
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      (165)
                                      
                                      
                                      
                                      
                                      
                                      (2)
                                      
                                      
                                      (167)Preferred
      Stock Dividends
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      (1)
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      (1)Other
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      1
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      2
                                      
                                      
                                      3TOTAL
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      9,966COMPREHENSIVE
      INCOMEOther
      Comprehensive Income (Loss), Net of Taxes:Cash
      Flow Hedges, Net of Tax of $17
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      (30)
                                      
                                      
                                      
                                      
                                      
                                      (30)Securities
      Available for Sale, Net of Tax of $3
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      (6)
                                      
                                      
                                      
                                      
                                      
                                      (6)Amortization
      of Pension and OPEB Deferred Costs, Net of Tax of $2
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      3
                                      
                                      
                                      
                                      
                                      
                                      3NET
      INCOME
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      574
                                      
                                      
                                      
                                      
                                      
                                      2
                                      
                                      
                                      576TOTAL
      COMPREHENSIVE INCOME
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      543MARCH
      31, 2008
                                      
                                      423
                                      
                                      $
                                      2,750
                                      
                                      $
                                      4,391
                                      
                                      $
                                      3,535
                                      
                                      $
                                      (187)
                                      
                                      $
                                      20
                                      
                                      $
                                      10,509DECEMBER
      31, 2008
                                      
                                      426
                                      
                                      $
                                      2,771
                                      
                                      $
                                      4,527
                                      
                                      $
                                      3,847
                                      
                                      $
                                      (452)
                                      
                                      $
                                      17
                                      
                                      $
                                      10,710Issuance
      of Common Stock
                                      
                                      2
                                      
                                      
                                      11
                                      
                                      
                                      37
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      48Common
      Stock Dividends
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      (167)
                                      
                                      
                                      
                                      
                                      
                                      (2)
                                      
                                      
                                      (169)Preferred
      Stock Dividends
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      (1)
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      (1)Other
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      1
                                      
                                      
                                      1TOTAL
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      10,589COMPREHENSIVE
      INCOMEOther
      Comprehensive Income (Loss), Net of Taxes:Cash
      Flow Hedges, Net of Tax of $1
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      3
                                      
                                      
                                      
                                      
                                      
                                      3Securities
      Available for Sale, Net of Tax of $1
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      (2)
                                      
                                      
                                      
                                      
                                      
                                      (2)Amortization
      of Pension and OPEB Deferred Costs, Net of Tax of $3
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      5
                                      
                                      
                                      
                                      
                                      
                                      5NET
      INCOME
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      361
                                      
                                      
                                      
                                      
                                      
                                      2
                                      
                                      
                                      363TOTAL
      COMPREHENSIVE INCOME
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      
                                      369MARCH
      31, 2009
                                      
                                      428
                                      
                                      $
                                      2,782
                                      
                                      $
                                      4,564
                                      
                                      $
                                      4,040
                                      
                                      $
                                      (446)
                                      
                                      $
                                      18
                                      
                                      $
                                      10,958





See
      Condensed Notes to Condensed Consolidated Financial
    Statements







AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES


INDEX
TO CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS





1.
                                Significant
      Accounting Matters2.
                                New
      Accounting Pronouncements3.
                                Rate
      Matters4.
                                Commitments,
      Guarantees and Contingencies5.
                                Benefit
      Plans6.
                                Business
      Segments7.
                                Derivatives,
      Hedging and Fair Value Measurements8.
                                Income
      Taxes9.
                                Financing
      Activities





AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES


CONDENSED
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS








1.
            SIGNIFICANT ACCOUNTING
      MATTERS





General





The
accompanying unaudited condensed consolidated financial statements and footnotes
were prepared in accordance with GAAP for interim financial information and with
the instructions to Form 10-Q and Article 10 of Regulation S-X of the
SEC.  Accordingly, they do not include all of the information and
footnotes required by GAAP for complete annual financial
statements.





In the
opinion of management, the unaudited interim financial statements reflect all
normal and recurring accruals and adjustments necessary for a fair presentation
of our net income, financial position and cash flows for the interim
periods.  The net income for the three months ended March 31, 2009 is
not necessarily indicative of results that may be expected for the year ending
December 31, 2009.  The accompanying condensed consolidated financial
statements are unaudited and should be read in conjunction with the audited 2008
consolidated financial statements and notes thereto, which are included in our
Annual Report on Form 10-K for the year ended December 31, 2008 as filed with
the SEC on February 27, 2009.





Earnings
Per Share (EPS)





The
following table presents our basic and diluted EPS calculations included on our
Condensed Consolidated Statements of Income:





Three
      Months Ended March 31,2009
                          
                          
                          2008(in
      millions, except per share data)$/share
                          
                          
                          
                          
                          
                          $/shareEarnings
      Applicable to AEP Common Shareholders
                          
                          $
                          360
                          
                          
                          
                          
                          
                          $
                          573Weighted
      Average Number of Basic Shares Outstanding
                          
                          
                          406.8
                          
                          
                          $
                          0.89
                          
                          
                          
                          400.8
                          
                          
                          $
                          1.43Weighted
      Average Dilutive Effect of:Performance
      Share Units
                          
                          
                          0.5
                          
                          
                          
                          -
                          
                          
                          
                          0.9
                          
                          
                          
                          -Stock
      Options
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          0.2
                          
                          
                          
                          -Restricted
      Stock Units
                          
                          
                          0.1
                          
                          
                          
                          -
                          
                          
                          
                          0.1
                          
                          
                          
                          -Restricted
      Shares
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          0.1
                          
                          
                          
                          -Weighted
      Average Number of Diluted Shares Outstanding
                          
                          
                          407.4
                          
                          
                          $
                          0.89
                          
                          
                          
                          402.1
                          
                          
                          $
                          1.43





The
assumed conversion of our share-based compensation does not affect net earnings
for purposes of calculating diluted earnings per share.





Options
to purchase 618,916 and 146,900 shares of common stock were outstanding at March
31, 2009 and 2008, respectively, but were not included in the computation of
diluted earnings per share because the options’ exercise prices were greater
than the quarter-end market price of the common shares and, therefore, the
effect would be antidilutive.





Variable
Interest Entities




FIN 46R
is a consolidation model that considers risk absorption of a variable interest
entity (VIE), also referred to as variability.  Entities are required
to consolidate a VIE when it is determined that they are the primary beneficiary
of that VIE, as defined by FIN 46R.  In determining whether we are the
primary beneficiary of a VIE, we consider factors such as equity at risk, the
amount of the VIE’s variability we absorb, guarantees of indebtedness, voting
rights including kick-out rights, power to direct the VIE and other
factors.  We believe that significant assumptions and judgments have
been consistently applied and that there are no other reasonable judgments or
assumptions that would have resulted in a different conclusion.





We are
the primary beneficiary of Sabine, DHLC, JMG and a protected cell of
EIS.  We hold a variable interest in Potomac-Appalachian Transmission
Highline, LLC West Virginia Series (West Virginia Series).  In
addition, we have not provided financial or other support to any VIE that was
not previously contractually required.





Sabine is
a mining operator providing mining services to SWEPCo.  SWEPCo has no
equity investment in Sabine but is Sabine’s only customer.  SWEPCo has
guaranteed the debt obligations and lease obligations of
Sabine.  Under the terms of the note agreements, substantially all
assets are pledged and all rights under the lignite mining agreement are
assigned to SWEPCo.  The creditors of Sabine have no recourse to any
AEP entity other than SWEPCo.  Under the provisions of the mining
agreement, SWEPCo is required to pay, as a part of the cost of lignite
delivered, an amount equal to mining costs plus a management fee which is
included in Fuel and Other Consumables Used for Electric Generation on our
Condensed Consolidated Statements of Income.  Based on these facts,
management has concluded SWEPCo is the primary beneficiary and is required to
consolidate Sabine.  SWEPCo’s total billings from Sabine for the three
months ended March 31, 2009 and 2008 were $35 million and $20 million,
respectively.  See the tables below for the classification of Sabine’s
assets and liabilities on our Condensed Consolidated Balance
Sheets.





DHLC is a
wholly-owned subsidiary of SWEPCo.  DHLC is a mining operator who
sells 50% of the lignite produced to SWEPCo and 50% to Cleco Corporation, a
nonaffiliated company.  SWEPCo and Cleco Corporation share half of the
executive board seats, with equal voting rights and each entity guarantees a 50%
share of DHLC’s debt.  The creditors of DHLC have no recourse to any
AEP entity other than SWEPCo.  Based on the structure and equity
ownership, management has concluded that SWEPCo is the primary beneficiary and
is required to consolidate DHLC.  SWEPCo’s total billings from DHLC
for the three months ended March 31, 2009 and 2008 were $11 million and $12
million, respectively.  These billings are included in Fuel and Other
Consumables Used for Electric Generation on our Condensed Consolidated
Statements of Income.  See the tables below for the classification of
DHLC assets and liabilities on our Condensed Consolidated Balance
Sheets.





OPCo has
a lease agreement with JMG to finance OPCo’s Flue Gas Desulfurization (FGD)
system installed on OPCo’s Gavin Plant.  The PUCO approved the
original lease agreement between OPCo and JMG.  JMG has a capital
structure of substantially all debt from pollution control bonds and other
debt.  JMG owns and leases the FGD to OPCo.  JMG is
considered a single-lessee leasing arrangement with only one
asset.  OPCo’s lease payments are the only form of repayment
associated with JMG’s debt obligations even though OPCo does not guarantee JMG’s
debt.  The creditors of JMG have no recourse to any AEP entity other
than OPCo for the lease payment.  OPCo does not have any ownership
interest in JMG.  Based on the structure of the entity, management has
concluded OPCo is the primary beneficiary and is required to consolidate
JMG.  OPCo’s total billings from JMG for the three months ended March
31, 2009 and 2008 were $17 million and $12 million, respectively.  See
the tables below for the classification of JMG’s assets and liabilities on our
Condensed Consolidated Balance Sheets.





EIS is a
captive insurance company with multiple protected cells in which our
subsidiaries participate in one protected cell for approximately ten lines of
insurance.  Neither AEP nor its subsidiaries have an equity investment
in EIS.  The AEP system is essentially this EIS cell’s only
participant, but allows certain third parties access to this
insurance.  Our subsidiaries and any allowed third parties share in
the insurance coverage, premiums and risk of loss from claims.  Based
on the structure of the protected cell, management has concluded that we are the
primary beneficiary and that we are required to consolidate the protected
cell.  Our insurance premium payments to EIS for the three months
ended March 31, 2009 and 2008 were $17 million in both periods.  See
the tables below for the classification of EIS’s assets and liabilities on our
Condensed Consolidated Balance Sheets.





The
balances below represent the assets and liabilities of the VIEs that are
consolidated.  These balances include intercompany transactions that
would be eliminated upon consolidation.





AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES


VARIABLE
INTEREST ENTITIES


March
31, 2009


(in
millions)





SWEPCo
                          Sabine
                        
                        
                        SWEPCo
                          DHLC
                        
                        
                        OPCo
                          JMG
                        
                        
                        EISASSETSCurrent
      Assets
                        
                        $
                        34
                        
                        
                        $
                        18
                        
                        
                        $
                        13
                        
                        
                        $
                        118Net
      Property, Plant and Equipment
                        
                        
                        122
                        
                        
                        
                        32
                        
                        
                        
                        417
                        
                        
                        
                        -Other
      Noncurrent Assets
                        
                        
                        30
                        
                        
                        
                        11
                        
                        
                        
                        1
                        
                        
                        
                        1Total
      Assets
                        
                        $
                        186
                        
                        
                        $
                        61
                        
                        
                        $
                        431
                        
                        
                        $
                        119LIABILITIES
      AND EQUITYCurrent
      Liabilities
                        
                        $
                        34
                        
                        
                        $
                        12
                        
                        
                        $
                        156
                        
                        
                        $
                        41Noncurrent
      Liabilities
                        
                        
                        152
                        
                        
                        
                        45
                        
                        
                        
                        257
                        
                        
                        
                        64Equity
                        
                        
                        -
                        
                        
                        
                        4
                        
                        
                        
                        18
                        
                        
                        
                        14Total
      Liabilities and Equity
                        
                        $
                        186
                        
                        
                        $
                        61
                        
                        
                        $
                        431
                        
                        
                        $
                        119





AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES


VARIABLE
INTEREST ENTITIES


December
31, 2008


(in
millions)





SWEPCo
                          Sabine
                        
                        
                        SWEPCo
                          DHLC
                        
                        
                        OPCo
                          JMG
                        
                        
                        EISASSETSCurrent
      Assets
                        
                        $
                        33
                        
                        
                        $
                        22
                        
                        
                        $
                        11
                        
                        
                        $
                        107Net
      Property, Plant and Equipment
                        
                        
                        117
                        
                        
                        
                        33
                        
                        
                        
                        423
                        
                        
                        
                        -Other
      Noncurrent Assets
                        
                        
                        24
                        
                        
                        
                        11
                        
                        
                        
                        1
                        
                        
                        
                        2Total
      Assets
                        
                        $
                        174
                        
                        
                        $
                        66
                        
                        
                        $
                        435
                        
                        
                        $
                        109LIABILITIES
      AND EQUITYCurrent
      Liabilities
                        
                        $
                        32
                        
                        
                        $
                        18
                        
                        
                        $
                        161
                        
                        
                        $
                        30Noncurrent
      Liabilities
                        
                        
                        142
                        
                        
                        
                        44
                        
                        
                        
                        257
                        
                        
                        
                        60Equity
                        
                        
                        -
                        
                        
                        
                        4
                        
                        
                        
                        17
                        
                        
                        
                        19Total
      Liabilities and Equity
                        
                        $
                        174
                        
                        
                        $
                        66
                        
                        
                        $
                        435
                        
                        
                        $
                        109





In
September 2007, we and Allegheny Energy Inc. (AYE) formed a joint venture by
creating Potomac-Appalachian Transmission Highline, LLC (PATH).  PATH
is a series limited liability company and was created to construct a
high-voltage transmission line project in the PJM region.  PATH
consists of the “Ohio Series,” the “West Virginia Series (PATH-WV),” both owned
equally by AYE and us and the “Allegheny Series” which is 100% owned by
AYE.  Provisions exist within the PATH-WV agreement that make it a
VIE.  The “Ohio Series” does not include the same provisions that make
PATH-WV a VIE.  The other series are not considered
VIEs.  We are not required to consolidate PATH-WV as we are not the
primary beneficiary, although we hold a significant interest in
PATH-WV.  Our equity investment in PATH-WV is included in Deferred
Charges and Other on our Condensed Consolidated Balance Sheets.  We
and AYE share the returns and losses equally in PATH-WV.  Our
subsidiaries and AYE’s subsidiaries provide services to the PATH companies
through service agreements. At the current time, PATH-WV has no debt
outstanding.  However, when debt is issued, the debt to equity ratio
in each series will be consistent with other regulated utilities and the
entities are designed to maintain this financing structure.  The
entities recover costs through regulated rates.





Given the
structure of the entity, we may be required to provide future financial support
to PATH-WV in the form of a capital call.  This would be considered an
increase to our investment in the entity.  Our maximum exposure to
loss is to the extent of our investment.  Currently the entity has no
debt financing.  The likelihood of such a loss is remote since the
FERC approved PATH-WV’s request for regulatory recovery of cost and a return on
the equity invested.





Our
investment in PATH-WV was:





March
      31, 2009
                            
                            December
      31, 2008As
      Reported on the Consolidated
                              Balance
      Sheet
                            
                            
                            Maximum
                              Exposure
                            
                            As
      Reported on the Consolidated
                              Balance
      Sheet
                            
                            
                            Maximum
                              Exposure(in
      millions)Capital
      Contribution from Parent
                            
                            $
                            4
                            
                            
                            $
                            4
                            
                            
                            $
                            4
                            
                            
                            $
                            4Retained
      Earnings
                            
                            
                            1
                            
                            
                            
                            1
                            
                            
                            
                            2
                            
                            
                            
                            2Total
      Investment in PATH-WV
                            
                            $
                            5
                            
                            
                            $
                            5
                            
                            
                            $
                            6
                            
                            
                            $
                            6





Revenue
Recognition – Traditional Electricity Supply and Demand





Revenues
are recognized from retail and wholesale electricity sales and electricity
transmission and distribution delivery services.  We recognize the
revenues on our Condensed Consolidated Statements of Income upon delivery of the
energy to the customer and include unbilled as well as billed
amounts.





Most of
the power produced at the generation plants of the AEP East companies is sold to
PJM, the RTO operating in the east service territory.  We then
purchase power from PJM to supply our customers.  Generally, these
power sales and purchases are reported on a net basis as revenues on our
Condensed Consolidated Statements of Income.  However, in the first
quarter of 2009, there were times when we were a purchaser of power from PJM to
serve retail load.  These purchases were recorded gross as Purchased
Electricity for Resale on our Condensed Consolidated Statements of
Income.  Other RTOs in which we operate do not function in the same
manner as PJM. They function as balancing organizations and not as
exchanges.





Physical
energy purchases, including those from RTOs, that are identified as non-trading,
are accounted for on a gross basis in Purchased Electricity for Resale on our
Condensed Consolidated Statements of Income.




CSPCo
and OPCo Revised Depreciation Rates
 
 Effective
January 1, 2009, we revised book depreciation rates for CSPCo and OPCo
generating plants consistent with a recently completed depreciation
study.  OPCo’s overall higher depreciation rates primarily related to
shortened depreciable lives for certain OPCo generating
facilities.  The impact of the change in depreciation rates was an
increase in OPCo’s depreciation expense of $17 million and a decrease in CSPCo’s
depreciation expense of $4 million when comparing the three months ended March
31, 2009 and 2008.
 
 Acquisition
– Oxbow Mine Lignite (Utility Operations segment)
 
 In April
2009, SWEPCo and its wholly-owned lignite mining subsidiary, Dolet Hills Mining
Company, LLC (DHLC), agreed to purchase 50% of the Oxbow Mine lignite reserves
and 100% of all associated mining equipment and assets from The North American
Coal Corporation and its affiliates, Red River Mining Company and Oxbow Property
Company, LLC for $42 million.  Cleco Power LLC (Cleco) will acquire
the remaining 50% of the lignite reserves.  Consummation of the
transaction is subject to regulatory approval by the LPSC and the APSC and the
transfer of other regulatory instruments.  If approved, DHLC will
acquire and own the Oxbow Mine mining equipment and related assets and it will
operate the Oxbow Mine.  The Oxbow Mine is located near Coushatta,
Louisiana and will be used as one of the fuel sources for SWEPCo’s and Cleco’s
jointly-owned Dolet Hills Generating Station.





Supplementary
Information





Three
      Months Ended March 31,2009
                
                
                2008Related
      Party Transactions
                
                (in
      millions)AEP
      Consolidated Revenues – Utility Operations:Power
      Pool Purchases – Ohio Valley Electric Corporation (43.47% owned)
      (a)
                
                $
                -
                
                
                $
                (13
                )AEP
      Consolidated Revenues – Other:Ohio
      Valley Electric Corporation – Barging and Other Transportation
      Services (43.47% Owned)
                
                
                9
                
                
                
                9AEP
      Consolidated Expenses – Purchased Electricity for Resale:Ohio
      Valley Electric Corporation (43.47% Owned)
                
                
                70
                
                
                
                63





(a)
            In
      2006, the AEP Power Pool began purchasing power from OVEC as part of risk
      management activities.  The agreement expired in May 2008 and
      subsequently ended in December
2008.





2.
            NEW ACCOUNTING
      PRONOUNCEMENTS





Upon
issuance of final pronouncements, we review the new accounting literature to
determine its relevance, if any, to our business.  The following
represents a summary of final pronouncements issued or implemented in 2009 and
standards issued but not implemented that we have determined relate to our
operations.





Pronouncements Adopted
During the First Quarter of 2009





The
following standards were effective during the first quarter of
2009.  Consequently, the financial statements and footnotes reflect
their impact.





SFAS
141 (revised 2007) “Business Combinations” (SFAS 141R)





In
December 2007, the FASB issued SFAS 141R, improving financial reporting about
business combinations and their effects.  It established how the
acquiring entity recognizes and measures the identifiable assets acquired,
liabilities assumed, goodwill acquired, any gain on bargain purchases and any
noncontrolling interest in the acquired entity.  SFAS 141R no longer
allows acquisition-related costs to be included in the cost of the business
combination, but rather expensed in the periods they are incurred, with the
exception of the costs to issue debt or equity securities which shall be
recognized in accordance with other applicable GAAP.  The standard
requires disclosure of information for a business combination that occurs during
the accounting period or prior to the issuance of the financial statements for
the accounting period.  SFAS 141R can affect tax positions on previous
acquisitions.  We do not have any such tax positions that result in
adjustments.





In April
2009, the FASB issued FSP SFAS 141(R)-1 “Accounting for Assets Acquired and
Liabilities Assumed in a Business Combination That Arise from
Contingencies.”  The standard clarifies accounting and disclosure for
contingencies arising in business combinations.  It was effective
January 1, 2009.





We
adopted SFAS 141R, including the FSP, effective January 1, 2009.  It
is effective prospectively for business combinations with an acquisition date on
or after January 1, 2009.  We will apply it to any future business
combinations.





SFAS
160 “Noncontrolling Interest in Consolidated Financial Statements” (SFAS
160)





In
December 2007, the FASB issued SFAS 160, modifying reporting for noncontrolling
interest (minority interest) in consolidated financial
statements.  The statement requires noncontrolling interest be
reported in equity and establishes a new framework for recognizing net income or
loss and comprehensive income by the controlling interest.  Upon
deconsolidation due to loss of control over a subsidiary, the standard requires
a fair value remeasurement of any remaining noncontrolling equity investment to
be used to properly recognize the gain or loss.  SFAS 160 requires
specific disclosures regarding changes in equity interest of both the
controlling and noncontrolling parties and presentation of the noncontrolling
equity balance and income or loss for all periods presented.





We
adopted SFAS 160 effective January 1, 2009 and retrospectively applied the
standard to prior periods. The retrospective application of this
standard:





·
            Reclassifies
      Minority Interest Expense of $1 million and Interest Expense of $1 million
      for the three months ended March 31, 2008 as Net Income Attributable to
      Noncontrolling Interest below Net Income in the presentation of Earnings
      Attributable to AEP Common Shareholders in our Condensed Consolidated
      Statements of Income.·
            Repositions
      Preferred Stock Dividend Requirements of Subsidiaries of $1 million for
      the three months ended March 31, 2008 below Net Income in the presentation
      of Earnings Attributable to AEP Common Shareholders in our Condensed
      Consolidated Statements of Income.·
            Reclassifies
      minority interest of $17 million as of December 31, 2008 previously
      included in Deferred Credits and Other and Total Liabilities as
      Noncontrolling Interest in Total Equity on our Consolidated Balance
      Sheets.·
            Separately
      reflects changes in Noncontrolling Interest in the Statements of Changes
      in Equity and Comprehensive Income (Loss).·
            Reclassifies
      dividends paid to noncontrolling interests of $2 million for the three
      months ended March 31, 2008 from Operating Activities to Financing
      Activities in our Condensed Consolidated Statements of Cash
      Flows.





SFAS
161 “Disclosures about Derivative Instruments and Hedging Activities” (SFAS
161)





In March
2008, the FASB issued SFAS 161, enhancing disclosure requirements for derivative
instruments and hedging activities.  Affected entities are required to
provide enhanced disclosures about (a) how and why an entity uses derivative
instruments, (b) how an entity accounts for derivative instruments and related
hedged items and (c) how derivative instruments and related hedged items affect
an entity’s financial position, financial performance and cash
flows.  The standard requires that objectives for using derivative
instruments be disclosed in terms of the primary underlying risk and accounting
designation.





We
adopted SFAS 161 effective January 1, 2009.  This standard increased
our disclosures related to derivative instruments and hedging
activities.  See “Derivatives and Hedging ” section of Note 7 for
further information.





EITF
      Issue No. 08-5 “Issuer’s Accounting for Liabilities Measured at Fair Value
      with a Third-Party Credit Enhancement” (EITF
  08-5)





In
September 2008, the FASB ratified the consensus on liabilities with third-party
credit enhancements when the liability is measured and disclosed at fair
value.  The consensus treats the liability and the credit enhancement
as two units of accounting.  Under the consensus, the fair value
measurement of the liability does not include the effect of the third-party
credit enhancement.  Consequently, changes in the issuer’s credit
standing without the support of the credit enhancement affect the fair value
measurement of the issuer’s liability.  Entities will need to provide
disclosures about the existence of any third-party credit enhancements related
to their liabilities.  In the period of adoption, entities must
disclose the valuation method(s) used to measure the fair value of liabilities
within its scope and any change in the fair value measurement method that occurs
as a result of its initial application.





We
adopted EITF 08-5 effective January 1, 2009.  It will be applied
prospectively with the effect of initial application included as a change in
fair value of the liability.





EITF
Issue No. 08-6 “Equity Method Investment Accounting Considerations” (EITF
08-6)





In
November 2008, the FASB ratified the consensus on equity method investment
accounting including initial and allocated carrying values and subsequent
measurements.  It requires initial carrying value be determined using
the SFAS 141R cost allocation method.  When an investee issues shares,
the equity method investor should treat the transaction as if the investor sold
part of its interest.





We
adopted EITF 08-6 effective January 1, 2009 with no impact on our financial
statements.  It was applied prospectively.




FSP
EITF 03-6-1 “Determining Whether Instruments Granted in Share-Based Payment
Transactions Are Participating Securities”
(EITF  03-6-1)








In June
2008, the FASB addressed whether instruments granted in share-based payment
transactions are participating securities prior to vesting and determined that
the instruments need to be included in earnings allocation in computing EPS
under the two-class method described in SFAS 128 “Earnings per
Share.”





We
adopted EITF 03-6-1 effective January 1, 2009.  The adoption of this
standard had an immaterial impact on our financial statements.





FSP
SFAS 142-3 “Determination of the Useful Life of Intangible Assets” (SFAS
142-3)





In April
2008, the FASB issued SFAS 142-3 amending factors that should be considered in
developing renewal or extension assumptions used to determine the useful life of
a recognized intangible asset.  The standard is expected to improve
consistency between the useful life of a recognized intangible asset and the
period of expected cash flows used to measure its fair value.





We
adopted SFAS 142-3 effective January 1, 2009.  The guidance is
prospectively applied to intangible assets acquired after the effective
date.  The standard’s disclosure requirements are applied
prospectively to all intangible assets as of January 1, 2009.  The
adoption of this standard had no impact on our financial
statements.





FSP
SFAS 157-2 “Effective Date of FASB Statement No. 157” (SFAS 157-2)





In
February 2008, the FASB issued SFAS 157-2 which delays the effective date of
SFAS 157 to fiscal years beginning after November 15, 2008 for all nonfinancial
assets and nonfinancial liabilities, except those that are recognized or
disclosed at fair value in the financial statements on a recurring basis (at
least annually).  As defined in SFAS 157, fair value is the price that
would be received to sell an asset or paid to transfer a liability in an orderly
transaction between market participants at the measurement date.  The
fair value hierarchy gives the highest priority to unadjusted quoted prices in
active markets for identical assets or liabilities and the lowest priority to
unobservable inputs.  In the absence of quoted prices for identical or
similar assets or investments in active markets, fair value is estimated using
various internal and external valuation methods including cash flow analysis and
appraisals.





We
adopted SFAS 157-2 effective January 1, 2009.  We will apply these
requirements to applicable fair value measurements which include new asset
retirement obligations and impairment analysis related to long-lived assets,
equity investments, goodwill and intangibles.  We did not record any
fair value measurements for nonrecurring nonfinancial assets and liabilities in
the first quarter of 2009.





Pronouncements Effective in
the Future





The
following standards will be effective in the future and their impacts disclosed
at that time.





FSP
      SFAS 107-1 and APB 28-1 “Interim Disclosures about Fair Value of Financial
      Instruments” (FSP SFAS 107-1 and APB
28-1)





In April
2009, the FASB issued FSP SFAS 107-1 and APB 28-1 requiring disclosure about the
fair value of financial instruments in all interim reporting
periods.  The standard requires disclosure of the method and
significant assumptions used to determine the fair value of financial
instruments.





This
standard is effective for interim periods ending after June 15,
2009.  Management expects this standard to increase the disclosure
requirements related to financial instruments.  We will adopt the
standard effective second quarter of 2009.




FSP
SFAS 115-2 and SFAS 124-2 “Recognition and Presentation of Other-Than-Temporary
Impairments” (FSP SFAS 115-2 and SFAS 124-2)




In April
2009, the FASB issued FSP SFAS 115-2 and SFAS 124-2 amending the
other-than-temporary impairment (OTTI) recognition and measurement guidance for
debt securities.  For both debt and equity securities, the standard
requires disclosure for each interim reporting period of information by security
class similar to previous annual disclosure requirements.





This
standard is effective for interim periods ending after June 15,
2009.  Management does not expect a material impact as a result of the
new OTTI evaluation method for debt securities, but expects this standard to
increase the disclosure requirements related to financial
instruments.  We will adopt the standard effective second quarter of
2009.





FSP
SFAS 132R-1 “Employers’ Disclosures about Postretirement Benefit Plan Assets”
(FSP SFAS 132R-1)





In
December 2008, the FASB issued FSP SFAS 132R-1 providing additional disclosure
guidance for pension and OPEB plan assets.  The rule requires
disclosure of investment policy including target allocations by investment
class, investment goals, risk management policies and permitted or prohibited
investments.  It specifies a minimum of investment classes by further
dividing equity and debt securities by issuer grouping.  The standard
adds disclosure requirements including hierarchical classes for fair value and
concentration of risk.





This
standard is effective for fiscal years ending after December 15,
2009.  Management expects this standard to increase the disclosure
requirements related to our benefit plans.  We will adopt the standard
effective for the 2009 Annual Report.




FSP
SFAS 157-4 “Determining Fair Value When the Volume and Level of Activity for the
Asset or Liability Have Significantly Decreased and Identifying Transactions
That Are Not Orderly” (FSP SFAS 157-4)




In April
2009, the FASB issued FSP SFAS 157-4 providing additional guidance on estimating
fair value when the volume and level of activity for an asset or liability has
significantly decreased, including guidance on identifying circumstances
indicating when a transaction is not orderly.  Fair value measurements
shall be based on the price that would be received to sell an asset or paid to
transfer a liability in an orderly (not a distressed sale or forced liquidation)
transaction between market participants at the measurement date under current
market conditions.  The standard also requires disclosures of the
inputs and valuation techniques used to measure fair value and a discussion of
changes in valuation techniques and related inputs, if any, for both interim and
annual periods.





This
standard is effective for interim and annual periods ending after June 15,
2009.  Management expects this standard to have no impact on our
financial statement but will increase our disclosure requirements.  We
will adopt the standard effective second quarter of 2009.





Future
Accounting Changes





The
FASB’s standard-setting process is ongoing and until new standards have been
finalized and issued by the FASB, we cannot determine the impact on the
reporting of our operations and financial position that may result from any such
future changes.  The FASB is currently working on several projects
including revenue recognition, contingencies, liabilities and equity, emission
allowances, earnings per share calculations, leases, insurance, hedge
accounting, consolidation policy, discontinued operations, trading inventory and
related tax impacts.  We also expect to see more FASB projects as a
result of its desire to converge International Accounting Standards with
GAAP.  The ultimate pronouncements resulting from these and future
projects could have an impact on our future net income and financial
position.





3.
            RATE
      MATTERS





As
discussed in the 2008 Annual Report, our subsidiaries are involved in rate and
regulatory proceedings at the FERC and their state commissions.  The
Rate Matters note within our 2008 Annual Report should be read in conjunction
with this report to gain a complete understanding of material rate matters still
pending that could impact net income, cash flows and possibly financial
condition.  The following discusses ratemaking developments in 2009
and updates the 2008 Annual Report.





Ohio Rate
Matters





Ohio
Electric Security Plan Filings





In July
2008, as required by the 2008 amendments to the Ohio restructuring legislation,
CSPCo and OPCo filed ESPs with the PUCO to establish standard service offer
rates.  CSPCo and OPCo did not file an optional Market Rate Offer
(MRO).  CSPCo’s and OPCo’s ESP filings requested an annual rate
increase for 2009 through 2011 that would not exceed approximately 15% per
year.  A significant portion of the requested ESP increases resulted
from the implementation of a fuel adjustment clause (FAC) that includes fuel
costs, purchased power costs, consumables such as urea, gains and losses on
sales of emission allowances and most other variable production
costs.  FAC costs were proposed to be phased into customer bills over
the three-year period from 2009 through 2011 with unrecovered FAC costs to be
recorded as a FAC phase-in regulatory asset.  The phase-in regulatory
asset deferral along with a deferred weighted average cost of capital carrying
cost was proposed to be recovered over seven years from 2012 through
2018.





In March
2009, the PUCO issued an order that modified and approved CSPCo’s and OPCo’s
ESPs.  The ESPs will be in effect through 2011.  The ESP
order authorized increases to revenues during the ESP period and capped the
overall revenue increases through a phase-in of the FAC.  The ordered
increases for CSPCo are 7% in 2009, 6% in 2010 and 6% in 2011 and for OPCo are
8% in 2009, 7% in 2010 and 8% in 2011.  After final PUCO review and
approval of conforming rate schedules, CSPCo and OPCo implemented rates for the
April 2009 billing cycle.  CSPCo and OPCo will collect the 2009
annualized revenue increase over the remainder of 2009.





The order
provides a FAC for the three-year period of the ESP.  The FAC increase
will be phased in to meet the ordered annual caps described
above.  The FAC increase before phase-in will be subject to quarterly
true-ups to actual recoverable FAC costs and to annual accounting audits and
prudency reviews.  The order allows CSPCo and OPCo to defer
unrecovered FAC costs resulting from the annual caps/phase-in plan and to accrue
carrying charges on such deferrals at CSPCo’s and OPCo’s weighted average cost
of capital.  The deferred FAC balance at the end of the ESP period
will be recovered through a non-bypassable surcharge over the period 2012
through 2018.  As of March 31, 2009, the FAC deferral balances were
$17 million and $66 million for CSPCo and OPCo, respectively, including carrying
charges.  The PUCO rejected a proposal by several intervenors to
offset the FAC costs with a credit for off-system sales margins.  As a
result, CSPCo and OPCo will retain the benefit of their share of the AEP
System’s off-system sales.  In addition, the ESP order provided for
both the FAC deferral credits and the off-system sales margins to be excluded
from the methodology for the Significantly Excessive Earnings Test
(SEET).  The SEET is discussed below.





Additionally,
the order addressed several other items, including:





·
            The
      approval of new distribution riders, subject to true-up for recovery of
      costs for enhanced vegetation management programs, for CSPCo and OPCo and
      the proposed gridSMART advanced metering initial program roll out in a
      portion of CSPCo’s service territory.  The PUCO proposed that
      CSPCo mitigate the costs of gridSMART by seeking matching funds under the
      American Recovery and Reinvestment Act of 2009.  As a result, a
      rider was established to recover 50% or $32 million of the projected $64
      million revenue requirement related to gridSMART costs.  The
      PUCO denied the other distribution system reliability programs proposed by
      CSPCo and OPCo as part of their ESP filings.  The PUCO decided
      that those requests should be examined in the context of a complete
      distribution base rate case.  The order did not require CSPCo
      and/or OPCo to file a distribution base rate
  case.





·
            The
      approval of CSPCo’s and OPCo’s request to recover the incremental carrying
      costs related to environmental investments made from 2001 through 2008
      that are not reflected in existing rates.  Future recovery
      during the ESP period of incremental carrying charges on environmental
      expenditures incurred beginning in 2009 may be requested in annual
      filings.





·
            The
      approval of a $97 million and $55 million increase in CSPCo’s and OPCo’s
      Provider of Last Resort charges, respectively, to compensate for the risk
      of customers changing electric suppliers during the ESP
      period.





·
            The
      requirement that CSPCo’s and OPCo’s shareholders fund a combined minimum
      of $15 million in costs over the ESP period for low-income, at-risk
      customer programs.  This funding obligation was recognized as a
      liability and an unfavorable adjustment to Other Operation and Maintenance
      expense for the three-month period ending March 31,
  2009.





·
            The
      deferral of CSPCo’s and OPCo’s request to recover certain existing
      regulatory assets, including customer choice implementation and line
      extension carrying costs as part of the ESPs.  The PUCO decided
      it would be more appropriate to consider this request in the context of
      CSPCo’s and OPCo’s next distribution base rate case.  These
      regulatory assets, which were approved by prior PUCO orders, total $58
      million for CSPCo and $40 million for OPCo as of March 31,
      2009.  In addition, CSPCo and OPCo would recover and recognize
      as income, when collected, $35 million and $26 million, respectively, of
      related unrecorded equity carrying costs incurred through March
      2009.





Finally,
consistent with its decisions on ESP orders of other companies, the PUCO ordered
its staff to convene a workshop to determine the methodology for the SEET that
will be applicable to all electric utilities in Ohio.  The SEET
requires the PUCO to determine, following the end of each year of the ESP, if
any rate adjustments included in the ESP resulted in excessive earnings as
measured by whether the earned return on common equity of CSPCo and OPCo is
significantly in excess of the return on common equity that was earned during
the same period by publicly traded companies, including utilities, that have
comparable business and financial risk.  If the rate adjustments, in
the aggregate, result in significantly excessive earnings in comparison, the
PUCO must require that the amount of the excess be returned to
customers.  The PUCO’s decision on the SEET review of CSPCo’s and
OPCo’s 2009 earnings is not expected to be finalized until the second or third
quarter of 2010.





In March
2009, intervenors filed a motion to stay a portion of the ESP rates or
alternately make that portion subject to refund because the intervenors believed
that the ordered ESP rates for 2009 were retroactive and therefore
unlawful.  In March 2009, the PUCO approved CSPCo’s and OPCo’s tariffs
effective with the April 2009 billing cycle and rejected the intervenors’
motion.  The PUCO also clarified that the reference in its earlier
order to the January 1, 2009 date related to the term of the ESP, not to the
effective date of tariffs and clarified the tariffs were not
retroactive.  In March 2009, CSPCo and OPCo implemented the new ESP
tariffs effective with the start of the April 2009 billing cycle.  In
April 2009, CSPCo and OPCo filed a motion requesting rehearing of several
issues.  In April 2009, several intervenors filed motions requesting
rehearing of issues underlying the PUCO’s authorized rate increases and one
intervenor filed a motion requesting the PUCO to direct CSPCo and OPCo to cease
collecting rates under the order.  Certain intervenors also filed a
complaint for writ of prohibition with the Ohio Supreme Court to halt any
further collection from customers of what the intervenors claim is unlawful
retroactive rate increases.





Management
will evaluate whether it will withdraw the ESP applications after a final order,
thereby terminating the ESP proceedings.  If CSPCo and/or OPCo
withdraw the ESP applications, CSPCo and/or OPCo may file an MRO or another ESP
as permitted by the law.  The revenues collected and recorded in 2009
under this PUCO order are subject to possible refund through the SEET
process.  Management is unable, due to the decision of the PUCO to
defer guidance on the SEET methodology to a future generic SEET proceeding, to
estimate the amount, if any, of a possible refund that could result from the
SEET process in 2010.





Ohio
IGCC Plant





In March
2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority
to recover costs related to building and operating a 629 MW IGCC power plant
using clean-coal technology.  In June 2006, the PUCO issued an order
approving a tariff to allow CSPCo and OPCo to recover pre-construction costs
over a period of no more than twelve months effective July 1,
2006.  During that period, CSPCo and OPCo each collected $12 million
in pre-construction costs and incurred $11 million in pre-construction
costs.  As a result, CSPCo and OPCo each established a net regulatory
liability of approximately $1 million.





The order
also provided that if CSPCo and OPCo have not commenced a continuous course of
construction of the proposed IGCC plant within five years of the June 2006 PUCO
order, all pre-construction cost recoveries associated with items that may be
utilized in projects at other sites must be refunded to Ohio ratepayers with
interest.





In
September 2008, the Ohio Consumers’ Counsel filed a motion with the PUCO
requesting all pre-construction costs be refunded to Ohio ratepayers with
interest.  In October 2008, CSPCo and OPCo filed a motion with the
PUCO that argued the Ohio Consumers’ Counsel’s motion was without legal merit
and contrary to past precedent.





In
January 2009, a PUCO Attorney Examiner issued an order that CSPCo and OPCo file
a detailed statement outlining the status of the construction of the IGCC plant,
including whether CSPCo and OPCo are engaged in a continuous course of
construction on the IGCC plant.  In February 2009, CSPCo and OPCo
filed a statement that CSPCo and OPCo have not commenced construction of the
IGCC plant and believe there exist real statutory barriers to the construction
of any new base load generation in Ohio, including IGCC plants.  The
statement also indicated that while construction on the IGCC plant might not
begin by June 2011, changes in circumstances could result in the commencement of
construction on a continuous course by that time.





Management
continues to pursue the ultimate construction of the IGCC
plant.  However, CSPCo and OPCo will not start construction of the
IGCC plant until sufficient assurance of regulatory cost recovery
exists.  If CSPCo and OPCo were required to refund the $24 million
collected and those costs were not recoverable in another jurisdiction in
connection with the construction of an IGCC plant, it would have an adverse
effect on future net income and cash flows.  Management cannot predict
the outcome of the cost recovery litigation concerning the Ohio IGCC plant or
what, if any effect, the litigation will have on future net income and cash
flows.





Ormet





In
December 2008, CSPCo, OPCo and Ormet, a large aluminum company with a load of
520 MW, filed an application with the PUCO for approval of an interim
arrangement governing the provision of generation service to
Ormet.  The arrangement would be effective January 1, 2009 and remain
in effect and expire upon the effective date of CSPCo’s and OPCo’s new ESP rates
and the effective date of a new arrangement between Ormet and CSPCo/OPCo as
approved by the PUCO.  Under the interim arrangement, Ormet would pay
the then-current applicable generation tariff rates and riders.  CSPCo
and OPCo sought to defer as a regulatory asset beginning in 2009 the difference
between the PUCO approved 2008 market price of $53.03 per MWH and the applicable
generation tariff rates and riders.  CSPCo and OPCo proposed to
recover the deferral through the fuel adjustment clause mechanism they proposed
in the ESP proceeding.  In January 2009, the PUCO approved the
application as an interim arrangement.  In February 2009, an
intervenor filed an application for rehearing of the PUCO’s interim arrangement
approval.  In March 2009, the PUCO granted that application for
further consideration of the matters specified in the rehearing
application.





In
February 2009, as amended in April 2009, Ormet filed an application with the
PUCO for approval of a proposed Ormet power contract for 2009 through
2018.  Ormet proposed to pay varying amounts based on certain
conditions, including the price of aluminum and the level of
production.  The difference between the amounts paid by Ormet and the
otherwise applicable PUCO ESP tariff rate would be either collected from or
refunded to CSPCo’s and OPCo’s retail customers.





In March
2009, the PUCO issued an order in the ESP filings which included approval of a
FAC for the ESP period.  The approval of an ESP FAC, together with the
January 2009 PUCO approval of the Ormet interim arrangement, provided the basis
to record regulatory assets of $10 million and $9 million for CSPCo and OPCo,
respectively, for the differential in the approved market price of $53.03 versus
the rate paid by Ormet during the first quarter of 2009.  These
amounts are included in CSPCo’s and OPCo’s FAC phase-in deferral balance of $17
million and $66 million, respectively.  See “Ohio Electric Security
Plan Filings” section above.





The
pricing and deferral authority under the PUCO’s January 2009 approval of the
interim arrangement will continue until the 2009-2018 power contract becomes
effective.  Management cannot predict when or if the PUCO will
approve the new power contract.





Hurricane
Ike





In
September 2008, the service territories of CSPCo and OPCo were impacted by
strong winds from the remnants of Hurricane Ike.  Under the RSP, which
was effective in 2008, CSPCo and OPCo could seek a distribution rate adjustment
to recover incremental distribution expenses related to major storm service
restoration efforts.  In September 2008, CSPCo and OPCo established
regulatory assets of $17 million and $10 million, respectively, for the expected
recovery of the storm restoration costs.  In December 2008, CSPCo and
OPCo filed with the PUCO a request to establish the regulatory assets under the
terms of the RSP, plus accrue carrying costs on the unrecovered balance using
CSPCo’s and OPCo’s weighted average cost of capital carrying charge
rates.  In December 2008, the PUCO subsequently approved the
establishment of the regulatory assets but authorized CSPCo and OPCo to record a
long-term debt only carrying cost on the regulatory asset.  In its
order approving the deferrals, the PUCO stated that the mechanism for recovery
would be determined in CSPCo’s and OPCo’s next distribution rate
filing.





In
December 2008, the Consumers for Reliable Electricity in Ohio filed a request
with the PUCO asking for an investigation into the service reliability of Ohio’s
investor-owned electric utilities, including CSPCo and OPCo.  The
investigation request included the widespread outages caused by the September
2008 wind storm.  CSPCo and OPCo filed a response asking the PUCO to
deny the request.





As a
result of the past favorable treatment of storm restoration costs under the RSP
and the RSP recovery provisions, which were in effect when the storm occurred
and the filings made, management believes the recovery of the regulatory assets
is probable.  However, if these regulatory assets are not recovered,
it would have an adverse effect on future net income and cash
flows.





Texas Rate
Matters





TEXAS
RESTRUCTURING





Texas
Restructuring Appeals





Pursuant
to PUCT orders, TCC securitized net recoverable stranded generation costs of
$2.5 billion and is recovering the principal and interest on the securitization
bonds through the end of 2020.  TCC refunded net other true-up
regulatory liabilities of $375 million during the period October 2006 through
June 2008 via a CTC credit rate rider.  Although earnings were not
affected by this CTC refund, cash flow was adversely impacted for 2008, 2007 and
2006 by $75 million, $238 million and $69 million, respectively. TCC
appealed the PUCT stranded costs true-up and related orders seeking relief in
both state and federal court on the grounds that certain aspects of the orders
are contrary to the Texas Restructuring Legislation, PUCT rulemakings and
federal law and fail to fully compensate TCC for its net stranded cost and other
true-up items.  The significant items appealed by TCC
were:





·
            The
      PUCT ruling that TCC did not comply with the Texas Restructuring
      Legislation and PUCT rules regarding the required auction of 15% of its
      Texas jurisdictional installed capacity, which led to a significant
      disallowance of capacity auction true-up revenues.·
            The
      PUCT ruling that TCC acted in a manner that was commercially unreasonable,
      because TCC failed to determine a minimum price at which it would reject
      bids for the sale of its nuclear generating plant and TCC bundled
      out-of-the-money gas units with the sale of its coal unit, which led to
      the disallowance of a significant portion of TCC’s net stranded generation
      plant costs.·
            Two
      federal matters regarding the allocation of off-system sales related to
      fuel recoveries and a potential tax normalization
    violation.





Municipal
customers and other intervenors also appealed the PUCT true-up orders seeking to
further reduce TCC’s true-up recoveries.





In March
2007, the Texas District Court judge hearing the appeals of the true-up order
affirmed the PUCT’s April 2006 final true-up order for TCC with two significant
exceptions.  The judge determined that the PUCT erred by applying an
invalid rule to determine the carrying cost rate for the true-up of stranded
costs and remanded this matter to the PUCT for further
consideration.  This remand could potentially have an adverse effect
on TCC’s future net income and cash flows if upheld on appeal.  The
District Court judge also determined that the PUCT improperly reduced TCC’s net
stranded plant costs for commercial unreasonableness which could have a
favorable effect on TCC’s future net income and cash flows.





TCC, the
PUCT and intervenors appealed the District Court decision to the Texas Court of
Appeals.  In May 2008, the Texas Court of Appeals affirmed the
District Court decision in all but two major respects.  It reversed
the District Court’s unfavorable decision which found that the PUCT erred by
applying an invalid rule to determine the carrying cost rate.  It also
determined that the PUCT erred by not reducing stranded costs by the “excess
earnings” that had already been refunded to affiliated
REPs.  Management does not believe that TCC will be adversely affected
by the Court of Appeals ruling on excess earnings based upon the reasons
discussed in the “TCC Excess Earnings” section below.  The favorable
commercial unreasonableness judgment entered by the District Court was not
reversed.  The Texas Court of Appeals denied intervenors’ motion for
rehearing.  In May 2008, TCC, the PUCT and intervenors filed petitions
for review with the Texas Supreme Court.  Review is discretionary and
the Texas Supreme Court has not determined if it will grant
review.  In January 2009, the Texas Supreme Court requested full
briefing of the proceedings.





TNC
received its final true-up order in May 2005 that resulted in refunds via a CTC
which have been completed.  The appeal brought by TNC of the final
true-up order remains pending in state court.





Management
cannot predict the outcome of these court proceedings and PUCT remand
decisions.  If TCC and/or TNC ultimately succeed in their appeals, it
could have a material favorable effect on future net income, cash flows and
financial condition.  If municipal customers and other intervenors
succeed in their appeals, it could have a material adverse effect on future net
income, cash flows and possibly financial condition.





TCC
Deferred Investment Tax Credits and Excess Deferred Federal Income
Taxes





TCC’s
appeal remains outstanding related to the stranded costs true-up and related
orders regarding whether the PUCT may require TCC to refund certain tax benefits
to customers.  Subsequent to the PUCT’s ordered reduction to TCC’s
securitized stranded costs by certain tax benefits, the PUCT, reacting to
possible IRS normalization violations, allowed TCC to defer $103 million of
ordered CTC refunds for other true-up items to negate the securitization
reduction.  Of the $103 million, $61 million relates to the present
value of certain tax benefits applied to reduce the securitization stranded
generating assets and $42 million for related carrying costs.  The
deferral of the CTC refunds is pending resolution on whether the PUCT’s
securitization refund is an IRS normalization violation.





Evidence
supporting a possible IRS normalization violation includes a March 2008 IRS
issuance of final regulations addressing the normalization requirements for the
treatment of Accumulated Deferred Investment Tax Credit (ADITC) and Excess
Deferred Federal Income Tax (EDFIT) in a stranded cost
determination.  Consistent with a Private Letter Ruling TCC received
in 2006, the final regulations clearly state that TCC will sustain a
normalization violation if the PUCT orders TCC to flow the tax benefits to
customers as part of the stranded cost true-up.  TCC notified the PUCT
that the final regulations were issued.  The PUCT made a request to
the Texas Court of Appeals for the matter to be remanded back to the PUCT for
further action.  In May 2008, as requested by the PUCT, the Texas
Court of Appeals ordered a remand of the tax normalization issue for the
consideration of this additional evidence.





TCC
expects that the PUCT will allow TCC to retain these amounts.  This
will have a favorable effect on future net income and cash flows as TCC will be
free to amortize the deferred ADITC and EDFIT tax benefits to income due to the
sale of the generating plants that generated the tax benefits.  Since
management expects that the PUCT will allow TCC to retain the deferred CTC
refund amounts in order to avoid an IRS normalization violation, management has
not accrued any related interest expense for refunds of these
amounts.  If accrued, management estimates interest expense would have
been approximately $6 million higher for the period July 2008 through March 2009
based on a CTC interest rate of 7.5% with $4 million relating to
2008.





If the
PUCT orders TCC to return the tax benefits to customers, thereby causing a
violation of the IRS normalization regulations, the violation could result in
TCC’s repayment to the IRS, under the normalization rules, of ADITC on all
property, including transmission and distribution property.  This
amount approximates $103 million as of March 31, 2009.  It could also
lead to a loss of TCC’s right to claim accelerated tax depreciation in future
tax returns.  If TCC is required to repay to the IRS its ADITC and is
also required to refund ADITC to customers, it would have an unfavorable effect
on future net income and cash flows.  Tax counsel advised management
that a normalization violation should not occur until all remedies under law
have been exhausted and the tax benefits are actually returned to ratepayers
under a nonappealable order.  Management intends to continue to work
with the PUCT to favorably resolve the issue and avoid the adverse effects of a
normalization violation on future net income, cash flows and financial
condition.





TCC
Excess Earnings





In 2005,
a Texas appellate court issued a decision finding that a PUCT order requiring
TCC to refund to the REPs excess earnings prior to and outside of the true-up
process was unlawful under the Texas Restructuring Legislation.  From
2002 to 2005, TCC refunded $55 million of excess earnings, including interest,
under the overturned PUCT order.  On remand, the PUCT must determine
how to implement the Court of Appeals decision given that the unauthorized
refunds were made to the REPs in lieu of reducing stranded cost recoveries from
REPs in the True-up Proceeding.  It is possible that TCC’s stranded
cost recovery, which is currently on appeal, may be affected by a PUCT
remedy.





In May
2008, the Texas Court of Appeals issued a decision in TCC’s True-up Proceeding
determining that even though excess earnings had been previously refunded to
REPs, TCC still must reduce stranded cost recoveries in its True-up
Proceeding.  In 2005, TCC reflected the obligation to refund excess
earnings to customers through the true-up process and recorded a regulatory
asset of $55 million representing a receivable from the REPs for prior excess
earnings refunds made to them by TCC.  However, certain parties have
taken positions that, if adopted, could result in TCC being required to refund
additional amounts of excess earnings or interest through the true-up process
without receiving a refund from the REPs.  If this were to occur, it
would have an adverse effect on future net income and cash flows.  AEP
sold its affiliate REPs in December 2002.  While AEP owned the
affiliate REPs, TCC refunded $11 million of excess earnings to the affiliate
REPs.  Management cannot predict the outcome of the excess earnings
remand and whether it would have an adverse effect on future net income and cash
flows.





Texas
Restructuring – SPP





In August
2006, the PUCT adopted a rule extending the delay in implementation of customer
choice in SWEPCo’s SPP area of Texas until no sooner than January 1,
2011.  In April 2009, the Texas Senate passed a bill related to
SWEPCo’s SPP area of Texas that requires cost of service regulation until
certain stages have been completed and approved by the PUCT such that fair
competition is available to all retail customer classes.  The bill is
expected to be reviewed by the Texas House of Representatives which, if passed,
would be sent to the governor of Texas for approval.  If the bill is
signed, management may be required to re-apply SFAS 71 for the generation
portion of SWEPCo’s Texas jurisdiction.  The initial reapplication of
SFAS 71 regulatory accounting would likely result in an extraordinary
loss.





OTHER
TEXAS RATE MATTERS





Hurricanes
Dolly and Ike





In July
and September 2008, TCC’s service territory in south Texas was hit by Hurricanes
Dolly and Ike, respectively.  TCC incurred $23 million and $2 million
in incremental maintenance costs related to service restoration efforts for
Hurricanes Dolly and Ike, respectively.  TCC has a PUCT-approved
catastrophe reserve which permits TCC to collect $1.3 million annually with
authority to continue the collection until the catastrophe reserve reaches $13
million.  Any incremental storm-related maintenance costs can be
charged against the catastrophe reserve if the total incremental maintenance
costs for a storm exceed $500 thousand.  In June 2008, prior to these
hurricanes, TCC had approximately $2 million recorded in the catastrophe reserve
account.  Therefore, TCC established a net regulatory asset for $23
million.





Under
Texas law and as previously approved by the PUCT in prior base rate cases, the
regulatory asset will be included in rate base in the next base rate
filing.  At that time, TCC will evaluate the existing catastrophe
reserve amounts and review potential future events to determine the appropriate
funding level to request to both recover the regulatory asset and adequately
fund a reserve for future storms in a reasonable time period.





2008
Interim Transmission Rates





In March
2008, TCC and TNC filed applications with the PUCT for an interim update of
wholesale-transmission rates.  The PUCT issued an order in May 2008
that provided for increased interim transmission rates for TCC and TNC, subject
to review during the next TCC and TNC base rate case.  This review
could result in a refund if the PUCT finds that TCC and TNC have not prudently
incurred the transmission investment.  The FERC approved the new
interim transmission rates in May 2008 which increased annual transmission
revenues by $9 million and $4 million for TCC and TNC, respectively. TCC and TNC
have not recorded any provision for refund regarding the interim transmission
rates because management believes these new rates are reasonable and necessary
to recover costs associated with new transmission plant.  Management
cannot predict the outcome of future proceedings related to the interim
transmission rates.  A refund of the interim transmission rates would
have an adverse impact on net income and cash flows.





2009
Interim Transmission Rates





In
February 2009, TCC and TNC filed applications with the PUCT for an interim
update of wholesale-transmission rates.  The proposed new interim
transmission rates are estimated to increase annual transmission revenues by $8
million and $9 million for TCC and TNC, respectively.  In April 2009,
the PUCT staff recommended the applications be approved as filed.  A
decision is expected from the PUCT during the second quarter of 2009 with rates
increasing shortly thereafter upon the FERC’s concurrence.  Management
cannot predict the outcome of the interim transmission rates
proceeding.





Advanced
Metering System





In 2007,
the governor of Texas signed legislation directing the PUCT to establish a
surcharge for electric utilities relating to advanced meters.  In
April 2009, TCC and TNC filed their Advanced Metering System (AMS)
with the PUCT proposing to invest approximately $223 million and $61 million,
respectively, to be recovered through customer surcharges beginning in October
2009.  The TCC and TNC filing is modeled on similar filings by other
Texas ERCOT Investor Owned Utilities who have already received PUCT approval for
their plans.  In the filing TCC and TNC propose to apply customer
refunds related to the FERC SIA ruling to reduce the AMS investment and
associated customer surcharge.  As of March 31, 2009, TCC and TNC has
$2.8 million and $0.5 million recorded on their balance sheets related to
advanced meters.





Texas
Rate Filing





In
November 2006, TCC filed a base rate case seeking to increase transmission and
distribution energy delivery services (wires) base rate in
Texas.  TCC’s revised requested increase in annual base rates was $70
million based on a requested return on common equity of 10.75%.





TCC
implemented the rate change in June 2007, subject to refund.  In March
2008, the PUCT issued an order  approving rates to collect a $20
million base rate increase based on a return on common equity of 9.96% and an
additional $20 million increase in revenues related to the expiration of TCC’s
merger credits.  In addition, depreciation expense was decreased by $7
million and discretionary fee revenues were increased by $3
million.  TCC estimates the order will increase TCC’s annual pretax
income by $50 million.  Various parties appealed the PUCT
decision.





In
February 2009, the Texas District Court affirmed the PUCT in most
respects.  However, it also ruled that the PUCT improperly denied TCC
an AFUDC return on the prepaid pension asset that the PUCT ruled to be
CWIP.  In March 2009, various intervenors appealed the Texas District
Court decision to the Texas Court of Appeals.  Management is unable to
predict the outcome of these proceedings.  If the appeals are
successful, it could have an adverse effect on future net income and cash
flows.





ETT





In
December 2007, TCC contributed $70 million of transmission facilities to ETT, an
AEP joint venture accounted for using the equity method.  The PUCT approved
ETT's initial rates, a request for a transfer of facilities and a certificate of
convenience and necessity to operate as a stand alone transmission utility in
the ERCOT region.  ETT was allowed a 9.96% after tax return on equity
rate in those approvals.  In 2008, intervenors filed a notice of
appeal to the Travis County District Court.  In October 2008, the
court ruled that the PUCT exceeded its authority by approving ETT’s application
as a stand alone transmission utility without a service area under the wrong
section of the statute.  Management believes that ruling is
incorrect.  Moreover, ETT provided evidence in its application that
ETT complied with what the court determined was the proper section of the
statute.  In January 2009, ETT and the PUCT filed appeals to the Texas
Court of Appeals.  In January and April 2009, TCC sold $60 million and
$30 million, respectively, of additional transmission facilities to
ETT.   As of March 31, 2009, AEP’s net investment in ETT was $36
million.  Depending upon the ultimate outcome of the appeals and any
resulting remands, TCC may be required to reacquire transferred assets and
projects under construction by ETT.





ETT, TCC
and TNC are involved in transactions relating to the transfer to ETT of other
transmission assets, which are in various stages of review and
approval.  In September 2008, ETT and a group of other Texas
transmission providers filed a comprehensive plan with the PUCT for completion
of the Competitive Renewable Energy Zone (CREZ) initiative.  The CREZ
initiative is the development of 2,400 miles of new transmission lines to
transport electricity from 18,000 MWs of planned wind farm capacity in west
Texas to rapidly growing cities in eastern Texas.  In March 2009, the
PUCT issued an order pursuant to a January 2009 decision that authorized ETT to
pursue the construction of $841 million of new CREZ transmission
assets.





Stall
Unit





See
“Stall Unit” section within “Louisiana Rate Matters” for
disclosure.





Turk
Plant





See “Turk
Plant” section within “Arkansas Rate Matters” for disclosure.





Virginia Rate
Matters





Virginia
E&R Costs Recovery Filing





Due to
the recovery provisions in Virginia law, APCo has been deferring incremental
E&R costs as incurred, excluding the equity return on non-CWIP capital
investments, pending future recovery.  In October 2008, the Virginia
SCC approved a stipulation agreement to recover $61 million of incremental
E&R costs incurred from October 2006 to December 2007 through a surcharge in
2009 which will have a favorable effect on cash flows of $61 million and on net
income for the previously unrecognized equity portion of the carrying costs of
approximately $11 million.





The
Virginia E&R cost recovery mechanism under Virginia law ceased effective
with costs incurred through December 2008.  However, the 2007
amendments to Virginia’s electric utility restructuring law provide for a rate
adjustment clause to be requested in 2009 to recover incremental E&R costs
incurred through December 2008.  Under this amendment, APCo will
request recovery of its 2008 unrecovered incremental E&R costs in a planned
May 2009 filing.  As of March 31, 2009, APCo has $109 million of
deferred Virginia incremental E&R costs (excluding $22 million of
unrecognized equity carrying costs).  The $109 million consists of $6
million of over recovery of costs collected from the 2008 surcharge, $36 million
approved by the Virginia SCC related to the 2009 surcharge and $79 million,
representing costs deferred during 2008, to be included in the 2009 E&R
filing, for collection in 2010.





If the
Virginia SCC were to disallow a material portion of APCo’s 2008 deferred
incremental E&R costs, it would have an adverse effect on future net income
and cash flows.





APCo’s
Filings for an IGCC Plant





In
January 2006, APCo filed a petition from the WVPSC requesting approval of a
Certificate of Public Convenience and Necessity (CPCN) to construct a 629 MW
IGCC plant adjacent to APCo’s existing Mountaineer Generating Station in Mason
County, West Virginia.





In June
2007, APCo sought pre-approval from the WVPSC for a surcharge rate mechanism to
provide for the timely recovery of pre-construction costs and the ongoing
finance costs of the project during the construction period, as well as the
capital costs, operating costs and a return on equity once the facility is
placed into commercial operation.  In March 2008, the WVPSC granted
APCo the CPCN to build the plant and approved the requested cost
recovery.  In March 2008, various intervenors filed petitions with the
WVPSC to reconsider the order.  No action has been taken on the
requests for rehearing.





In July
2007, APCo filed a request with the Virginia SCC for a rate adjustment clause to
recover initial costs associated with a proposed IGCC plant.  The
filing requested recovery of an estimated $45 million over twelve months
beginning January 1, 2009.  The $45 million included a return on
projected CWIP and development, design and planning pre-construction costs
incurred from July 1, 2007 through December 31, 2009.  APCo also
requested authorization to defer a carrying cost on deferred pre-construction
costs incurred beginning July 1, 2007 until such costs are
recovered.





The
Virginia SCC issued an order in April 2008 denying APCo’s requests, in part,
upon its finding that the estimated cost of the plant was uncertain and may
escalate.  The Virginia SCC also expressed concern that the $2.2
billion estimated cost did not include a retrofitting of carbon capture and
sequestration facilities.  In July 2008, based on the unfavorable
order received in Virginia, the WVPSC issued a notice seeking comments from
parties on how the WVPSC should proceed.  Various parties, including
APCo, filed comments but the WVPSC has not taken any action.





Through
March 31, 2009, APCo deferred for future recovery pre-construction IGCC costs of
approximately $9 million applicable to its West Virginia jurisdiction,
approximately $2 million applicable to its FERC jurisdiction and approximately
$9 million allocated to its Virginia jurisdiction.





In July
2008, the IRS allocated $134 million in future tax credits to APCo for the
planned IGCC plant contingent upon the commencement of construction, qualifying
expenses being incurred and certification of the IGCC plant prior to July
2010.





Although
management continues to pursue the construction of the IGCC plant, APCo will not
start construction of the IGCC plant until sufficient assurance of cost recovery
exists.  If the plant is cancelled, APCo plans to seek recovery of its
prudently incurred deferred pre-construction costs.  If the plant is
cancelled and if the deferred costs are not recoverable, it would have an
adverse effect on future net income and cash flows.





Mountaineer
Carbon Capture Project





In
January 2008, APCo and ALSTOM Power Inc. (Alstom), an unrelated third party,
entered into an agreement to jointly construct a CO2 capture
demonstration facility.  APCo and Alstom will each own part of the
CO2
capture facility.  APCo will also construct and own the necessary
facilities to store the CO2.  RWE
AG, a German electric power and natural gas public utility, is participating in
the project and is providing some funding to offset APCo's
costs.  APCo’s estimated cost for its share of the facilities is $73
million.  Through March 31, 2009, APCo incurred $45 million in
capitalized project costs which are included in Regulatory
Assets.  APCo earns a return on the capitalized project costs incurred
through June 30, 2008, as a result of the base rate case settlement approved by
the Virginia SCC in November 2008.  APCo plans to seek recovery for
the CO2 capture
and storage project costs including a return on the additional investment since
June 2008 in its next Virginia and West Virginia base rate filings which are
expected to be filed in 2009.  If a significant portion of the
deferred project costs are excluded from base rates and ultimately disallowed in
future Virginia or West Virginia rate proceedings, it could have an adverse
effect on future net income and cash flows.





West Virginia Rate
Matters





APCo’s
and WPCo’s 2009 Expanded Net Energy Cost (ENEC) Filing





In March
2009, APCo and WPCo filed an annual ENEC filing with the WVPSC for an increase
of approximately $442 million for incremental fuel, purchased power and
environmental compliance project expenses, to become effective July
2009.  Within the filing, APCo and WPCo requested the WVPSC to allow
APCo and WPCo to temporarily adopt a modified ENEC mechanism due to the
distressed economy.  The proposed modified ENEC mechanism provides
that all deferred ENEC amounts as of June 30, 2009 be recovered over a five-year
period beginning in July 2009.  The mechanism also extends cost
projections out for a period of three years through June 30, 2012 and provides
for three annual increases to recover projected future ENEC cost
increases.  APCo and WPCo are also requesting all deferred amounts
that exceed the deferred amounts that would have existed under the traditional
ENEC mechanism be subject to a carrying charge based upon APCo’s and WPCo’s
weighted average cost of capital.  As filed, the modified ENEC
mechanism would produce three annual increases, including carrying charges, of
$189 million, $166 million and $172 million, effective July 2009, 2010 and 2011,
respectively.





In March
2009, the WVPSC issued an order suspending the rate increase request until
December 2009.  In April 2009, APCo and WPCo filed a motion for
approval of an interim rate increase of $180 million, effective July 2009
and subject to refund pending the final adjudication of the ENEC by December
2009.  In April 2009, the WVPSC granted intervention to several
parties and heard oral arguments from APCo, WPCo and intervenors on the
requested interim ENEC filing.  If the WVPSC were to disallow a
material portion of APCo’s and WPCo’s requested increase, it would have an
adverse effect on future net income and cash flows.





APCo’s
Filings for an IGCC Plant





See
“APCo’s Filings for an IGCC Plant” section within “Virginia Rate Matters” for
disclosure.





Mountaineer
Carbon Capture Project





See
“Mountaineer Carbon Capture Project” section within “Virginia Rate Matters” for
disclosure.





Indiana Rate
Matters





Indiana Base
Rate Filing





In a
January 2008 filing with the IURC, updated in the second quarter of 2008,
I&M requested an increase in its Indiana base rates of $80 million including
a return on equity of 11.5%.  The base rate increase included a $69
million annual reduction in depreciation expense previously approved by the IURC
and implemented for accounting purposes effective June 2007. In addition,
I&M proposed to share with customers, through a proposed tracker, 50% of
off-system sales margins initially estimated to be $96 million annually with a
guaranteed credit to customers of $20 million.





In
December 2008, I&M and all of the intervenors jointly filed a settlement
agreement with the IURC proposing to resolve all of the issues in the
case.  The settlement agreement incorporated the $69 million annual
reduction in revenues from depreciation rate reduction in the development of the
agreed to revenue increase of $44 million including a $22 million increase in
revenue from base rates with an authorized return on equity of 10.5% and a $22
million initial increase in tracker revenue for PJM, net emission allowance
and DSM costs.  The agreement also establishes an off-system sales
sharing mechanism and other provisions which include continued funding for the
eventual decommissioning of the Cook Nuclear Plant.  In March 2009,
the IURC approved the settlement agreement, with modifications, that provides
for an annual increase in revenues of $42 million including a $19 million
increase in revenue from base rates, net of the depreciation rate reduction, and
a $23 million increase in tracker revenue.  The IURC order removed
base rate recovery of the DSM costs but established a tracker with an initial
zero amount for DSM costs, adjusted the sharing of off-system sales margins to
50% above the $37.5 million included in base rates and approved the recovery of
$7.3 million of previously expensed NSR and OPEB costs which favorably affected
first quarter of 2009 net income.  In addition, the IURC order
requires I&M to review and file a final report by December 2009 on the
effectiveness of the Interconnection Agreement including I&M’s relationship
with PJM.





Rockport
and Tanners Creek Plants





In
January 2009, I&M filed a petition with the IURC requesting approval of a
Certificate of Public Convenience and Necessity (CPCN) to use advanced coal
technology which would allow I&M to reduce airborne emissions of NOx and
mercury from its existing coal-fired steam electric generating units at the
Rockport and Tanners Creek Plants.  In addition, the petition is
requesting approval to construct and recover the costs of selective
non-catalytic reduction (SNCR) systems at the Tanners Creek Plant and to recover
the costs of activated carbon injection (ACI) systems on both generating units
at the Rockport Plant.  I&M is requesting to depreciate the ACI
systems over an accelerated 10-year period and the SNCR systems over the
remaining useful life of the Tanners Creek generating units.  I&M
requested the IURC to approve a rate adjustment mechanism of unrecovered
carrying costs during construction and a return on investment, depreciation
expense and operation and maintenance costs, including consumables and new
emission allowance costs, once the projects are placed in
service.  I&M also requested the IURC to authorize the deferral of
the cost of service of these projects and carrying costs until such costs are
recognized in the requested rate adjustment mechanism.  Through March
2009, I&M incurred $9 million and $6 million in capitalized project costs
related to the Rockport and Tanners Creek Plants, respectively, which are
included in Construction Work in Progress.  In March 2009, the IURC
issued a prehearing conference order setting a procedural
schedule.  Since the Indiana base rate order included recovery of
emission allowance costs, that portion of this request will be
eliminated.  An order is expected by the third quarter of
2009.  Management is unable to predict the outcome of this
petition.


Indiana
Fuel Clause Filing





In
January 2009, I&M filed with the IURC an application to increase its fuel
adjustment charge by approximately $53 million for April through September
2009.  The filing included an under-recovery for the period ended
November 2008, mainly as a result of the extended outage of the Cook Plant Unit
1 (Unit 1) due to fire damage to the main turbine and generator, increased coal
prices and a projection for the future period of fuel costs including Unit 1
fire related outage replacement power costs.  The filing also included
an adjustment, beginning coincident with the receipt of insurance proceeds, to
reduce the incremental fuel cost of replacement power with a portion of the
insurance proceeds from the Unit 1 accidental outage policy.  See
“Cook Plant Unit 1 Fire and Shutdown” section of Note 4.  I&M
reached an agreement in February 2009 with intervenors, which was approved by
the IURC in March 2009, to collect the under-recovery over twelve months instead
of over six months as proposed.  Under the order, the fuel factor will
go into effect, subject to refund, and a subdocket will be established to
consider issues relating to the Unit 1 fire outage, the use of the insurance
proceeds and I&M’s fuel procurement practices.  The order provides
for the fire outage issues to be resolved subsequent to the date Unit 1 returns
to service, which if temporary repairs are successful, could occur as early as
October 2009.  Management cannot predict the outcome of the pending
proceedings, including the treatment of the insurance proceeds, and whether any
fuel clause revenues will have to be refunded as a result.





Michigan Rate
Matters





In March
2009, I&M filed with the Michigan Public Service Commission its 2008 power
supply cost recovery reconciliation.  The filing also included an
adjustment to reduce the incremental fuel cost of replacement power with a
portion of the insurance proceeds from the Cook Plant Unit 1 accidental outage
policy.  See “Cook Plant Unit 1 Fire and Shutdown” section of Note
4.  Management is unable to predict the outcome of this proceeding and
its possible effect on future net income and cash
flows.





Oklahoma Rate
Matters





PSO
Fuel and Purchased Power





2006 and Prior Fuel and
Purchased Power





Proceedings
addressing PSO’s historic fuel costs from 2001 through 2006 remain open at the
OCC due to the issue of the allocation of off-system sales margins among the AEP
operating companies in accordance with a FERC-approved allocation
agreement.





In 2002,
PSO under-recovered $42 million of fuel costs resulting from a reallocation
among AEP West companies of purchased power costs for periods prior to
2002.  PSO recovered the $42 million by offsetting it against an
existing fuel over-recovery during the period June 2007 through May
2008.  In June 2008, the Oklahoma Industrial Energy Consumers (OIEC)
appealed an ALJ recommendation that concluded it was a FERC jurisdictional
matter which allowed PSO to retain the $42 million it recovered from
ratepayers.  The OIEC requested that PSO be required to refund the $42
million through its fuel clause.  In August 2008, the OCC heard the
OIEC appeal and a decision is pending.  For further discussion and
estimated effect on net income, see “Allocation of Off-system Sales Margins”
section within “FERC Rate Matters”.





2007 Fuel and Purchased
Power





In
September 2008, the OCC initiated a review of PSO’s generation, purchased power
and fuel procurement processes and costs for 2007.  Management cannot
predict the outcome of the pending fuel and purchased power cost recovery
filings.  However, PSO believes its fuel and purchased power
procurement practices and costs were prudent and properly incurred and therefore
are legally recoverable.





2008
Oklahoma Base Rate Filing





In July
2008, PSO filed an application with the OCC to increase its base rates by $133
million (later adjusted to $127 million) on an annual basis.  PSO has
been recovering costs related to new peaking units recently placed into service
through a Generation Cost Recovery Rider (GCRR).  Subsequent to
implementation of the new base rates, the GCRR will terminate and PSO will
recover these costs through the new base rates.  Therefore, PSO’s net
annual requested increase in total revenues was actually $117 million (later
adjusted to $111 million).  The proposed revenue requirement reflected
a return on equity of 11.25%.





In
January 2009, the OCC issued a final order approving an $81 million increase in
PSO’s non-fuel base revenues and a 10.5% return on equity.  The rate
increase includes a $59 million increase in base rates and a $22 million
increase for costs to be recovered through riders outside of base
rates.  The $22 million increase includes $14 million for purchase
power capacity costs and $8 million for the recovery of carrying costs
associated with PSO’s program to convert overhead distribution lines to
underground service.  The $8 million recovery of carrying costs
associated with the overhead to underground conversion program will occur only
if PSO makes the required capital expenditures.  The final order
approved lower depreciation rates and also provides for the deferral of $6
million of generation maintenance expenses to be recovered over a six-year
period.  This deferral was recorded in the first quarter of
2009.  Additional deferrals were approved for distribution storm costs
above or below the amount included in base rates and for certain transmission
reliability expenses.  The new rates reflecting the final order were
implemented with the first billing cycle of February 2009.





PSO filed
an appeal with the Oklahoma Supreme Court challenging an adjustment the OCC made
on prepaid pension funding contained within the OCC final order.  In
February 2009, the Oklahoma Attorney General and several intervenors also filed
appeals with the Oklahoma Supreme Court raising several issues.  If
the Attorney General and/or the intervenor’s Supreme Court appeals are
successful, it could have an adverse effect on future net income and cash
flows.





Louisiana Rate
Matters





2008
Formula Rate Filing





In April
2008, SWEPCo filed the first formula rate plan (FRP) which would increase its
annual Louisiana retail rates by $11 million in August 2008 to earn an adjusted
return on common equity of 10.565%.  In August 2008, SWEPCo
implemented the FRP rates, subject to refund.  No provision for refund
has been recorded as SWEPCo believes that the rates as implemented are in
compliance with the FRP methodology approved by the LPSC.  The LPSC
has not approved the rates being collected.  If the rates are not
approved as filed, it could have an adverse effect on future net income and cash
flows.





2009
Formula Rate Filing





In April
2009, SWEPCo filed the second FRP which would increase its annual Louisiana
retail rates by an additional $4 million in August 2009 pursuant to the formula
rate methodology.  SWEPCo believes that the rates as filed are in
compliance with the FRP methodology previously approved by the
LPSC.





Stall
Unit





In May
2006, SWEPCo announced plans to build a new intermediate load, 500 MW, natural
gas-fired, combustion turbine, combined cycle generating unit (the Stall Unit)
at its existing Arsenal Hill Plant location in Shreveport,
Louisiana.  SWEPCo submitted the appropriate filings to the PUCT, the
APSC, the LPSC and the Louisiana Department of Environmental Quality to seek
approvals to construct the unit.  The Stall Unit is currently
estimated to cost $385 million, excluding AFUDC, and is expected to be
in-service in mid-2010.  The Louisiana Department of Environmental
Quality issued an air permit for the Stall unit in March 2008.





In March
2007, the PUCT approved SWEPCo’s request for a certificate of necessity for the
facility based on a prior cost estimate.  In July 2008, a Louisiana
ALJ issued a recommendation that SWEPCo be authorized to construct, own and
operate the Stall Unit and recommended that costs be capped at $445 million
(excluding transmission).  In October 2008, the LPSC issued a final
order effectively approving the ALJ recommendation.  In December 2008,
SWEPCo submitted an amended filing seeking approval from the APSC to construct
the unit.  The APSC staff filed testimony in March 2009 supporting the
approval of the plant.  The APSC staff also recommended that costs be
capped at $445 million (excluding transmission).  A hearing that had
been scheduled for April 2009 was cancelled and the APSC will issue its decision
based on the amended application and prefiled testimony.





If SWEPCo
does not receive appropriate authorizations and permits to build the Stall Unit,
SWEPCo would seek recovery of the capitalized construction costs including any
cancellation fees.  As of March 31, 2009, SWEPCo has capitalized
construction costs of $291 million (including AFUDC) and has contractual
construction commitments of an additional $74 million.  As of March
31, 2009, if the plant had been cancelled, cancellation fees of $40 million
would have been required in order to terminate the construction
commitments.  If SWEPCo cancels the plant and cannot recover its
capitalized costs, including any cancellation fees, it would have an adverse
effect on future net income, cash flows and possibly financial
condition.





Turk
Plant





See “Turk
Plant” section within “Arkansas Rate Matters” for disclosure.





Arkansas Rate
Matters





Turk
Plant





In August
2006, SWEPCo announced plans to build the Turk Plant, a new base load 600 MW
pulverized coal ultra-supercritical generating unit in
Arkansas.  SWEPCo submitted filings with the APSC, the PUCT and the
LPSC seeking certification of the plant.  SWEPCo will own 73% of the
Turk Plant and will operate the facility.  During 2007, SWEPCo signed
joint ownership agreements with the Oklahoma Municipal Power Authority (OMPA),
the Arkansas Electric Cooperative Corporation (AECC) and the East Texas Electric
Cooperative (ETEC) for the remaining 27% of the Turk Plant.  During
2007, OMPA exercised its participation option.  During the first
quarter of 2009, AECC and ETEC exercised their participation options and paid
SWEPCo $104 million.  SWEPCo recorded a $2.2 million gain from the
transactions.  The Turk Plant is currently estimated to cost $1.6
billion, excluding AFUDC, with SWEPCo’s portion estimated to cost $1.2
billion.  If approved on a timely basis, the plant is expected to be
in-service in 2012.





In
November 2007, the APSC granted approval to build the Turk
Plant.  Certain landowners have appealed the APSC’s decision to the
Arkansas State Court of Appeals.  In March 2008, the LPSC approved the
application to construct the Turk Plant.





In August
2008, the PUCT issued an order approving the Turk Plant with the following four
conditions: (a) the capping of capital costs for the Turk Plant at the
previously estimated $1.522 billion projected construction cost, excluding
AFUDC, (b) capping CO2 emission
costs at $28 per ton through the year 2030, (c) holding Texas ratepayers
financially harmless from any adverse impact related to the Turk Plant not being
fully subscribed to by other utilities or wholesale customers and (d) providing
the PUCT all updates, studies, reviews, reports and analyses as previously
required under the Louisiana and Arkansas orders.  In October 2008,
SWEPCo appealed the PUCT’s order regarding the two cost cap
restrictions.  If the cost cap restrictions are upheld and
construction or emission costs exceed the restrictions, it could have a material
adverse effect on future net income and cash flows.  In October 2008,
an intervenor filed an appeal contending that the PUCT’s grant of a conditional
Certificate of Public Convenience and Necessity for the Turk Plant was not
necessary to serve retail customers.





A request
to stop pre-construction activities at the site was filed in federal court by
Arkansas landowners.  In July 2008, the federal court denied the
request and the Arkansas landowners appealed the denial to the U.S. Court of
Appeals.  In January 2009, SWEPCo filed a motion to dismiss the
appeal.  In March 2009, the motion was granted.





In
November 2008, SWEPCo received the required air permit approval from the
Arkansas Department of Environmental Quality and commenced
construction.  In December 2008, Arkansas landowners filed an appeal
with the Arkansas Pollution Control and Ecology Commission (APCEC) which caused
construction of the Turk Plant to halt until the APCEC took further
action.  In December 2008, SWEPCo filed a request with the APCEC to
continue construction of the Turk Plant and the APCEC ruled to allow
construction to continue while an appeal of the Turk Plant’s permit is
heard.  Hearings on the air permit appeal is scheduled for June
2009.  SWEPCo is also working with the U.S. Army Corps of Engineers
for the approval of a wetlands and stream impact permit.  In March
2009, SWEPCo reported to the U.S. Army Corps of Engineers a potential wetlands
impact on approximately 2.5 acres at the Turk Plant.  The U.S. Army
Corps of Engineers directed SWEPCo to cease further work impacting the wetland
areas.  Construction has continued on other areas of the Turk
Plant.  The impact on the construction schedule and workforce is
currently being evaluated by management.





In
January and July 2008, SWEPCo filed Certificate of Environmental Compatibility
and Public Need (CECPN) applications with the APSC to construct transmission
lines necessary for service from the Turk Plant.  Several landowners
filed for intervention status and one landowner also contended he should be
permitted to re-litigate Turk Plant issues, including the need for the
generation.  The APSC granted their intervention but denied the
request to re-litigate the Turk Plant issues.  In June 2008, the
landowner filed an appeal to the Arkansas State Court of Appeals requesting to
re-litigate Turk Plant issues.  SWEPCo responded and the appeal was
dismissed.  In January 2009, the APSC approved the CECPN
applications.





The
Arkansas Governor’s Commission on Global Warming issued its final report to the
governor in October 2008.  The Commission was established to set a
global warming pollution reduction goal together with a strategic plan for
implementation in Arkansas.  The Commission’s final report included a
recommendation that the Turk Plant employ post combustion carbon capture and
storage measures as soon as it starts operating.  If legislation is
passed as a result of the findings in the Commission’s report, it could impact
SWEPCo’s proposal to build and operate the Turk Plant.





If SWEPCo
does not receive appropriate authorizations and permits to build the Turk Plant,
SWEPCo could incur significant cancellation fees to terminate its commitments
and would be responsible to reimburse OMPA, AECC and ETEC for their share of
costs incurred plus related shutdown costs.  If that occurred, SWEPCo
would seek recovery of its capitalized costs including any cancellation fees and
joint owner reimbursements.  As of March 31, 2009, SWEPCo has
capitalized approximately $480 million of expenditures (including AFUDC) and has
contractual construction commitments for an additional $655
million.  As of March 31, 2009, if the plant had been cancelled,
SWEPCo would have incurred cancellation fees of $100 million.  If the
Turk Plant does not receive all necessary approvals on reasonable terms and
SWEPCo cannot recover its capitalized costs, including any cancellation fees, it
would have an adverse effect on future net income, cash flows and possibly
financial condition.





Arkansas
Base Rate Filing





In
February 2009, SWEPCo filed an application with the APSC for a base rate
increase of $25 million based on a requested return on equity of
11.5%.  SWEPCo also requested a separate rider to recover financing
costs related to the construction of the Stall and Turk generating
facilities.  These financing costs are currently being capitalized as
AFUDC in Arkansas.  A decision is not expected until the fourth
quarter of 2009 or the first quarter of 2010.





Stall
Unit





See
“Stall Unit” section within “Louisiana Rate Matters” for
disclosure.





FERC Rate
Matters





Regional
Transmission Rate Proceedings at the FERC





SECA Revenue Subject to
Refund





Effective
December 1, 2004, AEP eliminated transaction-based through-and-out transmission
service (T&O) charges in accordance with FERC orders and collected, at the
FERC’s direction, load-based charges, referred to as RTO SECA, to partially
mitigate the loss of T&O revenues on a temporary basis through March 31,
2006.  Intervenors objected to the temporary SECA rates, raising
various issues.  As a result, the FERC set SECA rate issues for
hearing and ordered that the SECA rate revenues be collected, subject to
refund.  The AEP East companies paid SECA rates to other utilities at
considerably lesser amounts than they collected.  If a refund is
ordered, the AEP East companies would also receive refunds related to the SECA
rates they paid to third parties.  The AEP East companies recognized
gross SECA revenues of $220 million from December 2004 through March 2006 when
the SECA rates terminated leaving the AEP East companies and ultimately their
internal load retail customers to make up the short fall in
revenues.





In August
2006, a FERC ALJ issued an initial decision, finding that the rate design for
the recovery of SECA charges was flawed and that a large portion of the “lost
revenues” reflected in the SECA rates should not have been
recoverable.  The ALJ found that the SECA rates charged were unfair,
unjust and discriminatory and that new compliance filings and refunds should be
made.  The ALJ also found that the unpaid SECA rates must be paid in
the recommended reduced amount.





In
September 2006, AEP filed briefs jointly with other affected companies noting
exceptions to the ALJ’s initial decision and asking the FERC to reverse the
decision in large part.  Management believes, based on advice of legal
counsel, that the FERC should reject the ALJ’s initial decision because it
contradicts prior related FERC decisions, which are presently subject to
rehearing.  Furthermore, management believes the ALJ’s findings on key
issues are largely without merit.  AEP and SECA ratepayers are
engaged in settlement discussions in an effort to settle the SECA
issue.  However, if the ALJ’s initial decision is upheld in its
entirety, it could result in a disallowance of a large portion of any unsettled
SECA revenues.





Based on
anticipated settlements, the AEP East companies provided reserves for net
refunds for current and future SECA settlements totaling $39 million and $5
million in 2006 and 2007, respectively, applicable to a total of $220 million of
SECA revenues.  In February 2009, a settlement agreement was approved
by the FERC resulting in the completion of a $1 million settlement applicable to
$20 million of SECA revenue.  Including this most recent settlement,
AEP has completed settlements totaling $10 million applicable to $112 million of
SECA revenues.  The balance in the reserve for future settlements as
of March 2009 was $34 million.  As of March 31, 2009, there were no
in-process settlements.





If the
FERC adopts the ALJ’s decision and/or AEP cannot settle all of the remaining
unsettled claims within the remaining amount reserved for refund, it will have
an adverse effect on future net income and cash flows.  Based on
advice of external FERC counsel, recent settlement experience and the
expectation that most of the unsettled SECA revenues will be settled, management
believes that the available reserve of $34 million is adequate to settle the
remaining $108 million of contested SECA revenues.  If the remaining
unsettled SECA claims are settled for considerably more than the to-date
settlements or if the remaining unsettled claims are awarded a refund by the
FERC greater than the remaining reserve balance, it could have an adverse effect
on net income.  Cash flows will be adversely impacted by any
additional settlements or ordered refunds.  However, management cannot
predict the ultimate outcome of ongoing settlement discussions or future FERC
proceedings or court appeals, if any.





The FERC PJM Regional
Transmission Rate Proceeding





With the
elimination of T&O rates, the expiration of SECA rates and after
considerable administrative litigation at the FERC in which AEP sought to
mitigate the effect of the T&O rate elimination, the FERC failed to
implement a regional rate in PJM.  As a result, the AEP East
companies’ retail customers incur the bulk of the cost of the existing AEP east
transmission zone facilities.  However, the FERC ruled that the cost
of any new 500 kV and higher voltage transmission facilities built in PJM would
be shared by all customers in the region.  It is expected that most of
the new 500 kV and higher voltage transmission facilities will be built in other
zones of PJM, not AEP’s zone.  The AEP East companies will need to
obtain state regulatory approvals for recovery of any costs of new facilities
that are assigned to them by PJM.  In February 2008, AEP filed a
Petition for Review of the FERC orders in this case in the United States Court
of Appeals.  Management cannot estimate at this time what effect, if
any, this order will have on the AEP East companies’ future construction of new
transmission facilities, net income and cash flows.





The AEP
East companies filed for and in 2006 obtained increases in their wholesale
transmission rates to recover lost revenues previously applied to reduce those
rates.  AEP has also sought and received retail rate increases in
Ohio, Virginia, West Virginia and Kentucky.  In January and March
2009, AEP received retail rate increases in Tennessee and Indiana, respectively,
that recognized the higher retail transmission costs resulting from the loss of
wholesale transmission revenues from T&O transactions.  As a
result, AEP is now recovering approximately 98% of the lost T&O transmission
revenues.  The remaining 2% is being incurred by I&M until it can
revise its rates in Michigan to recover the lost revenues.





The FERC PJM and MISO
Regional Transmission Rate Proceeding





In the
SECA proceedings, the FERC ordered the RTOs and transmission owners in the
PJM/MISO region (the Super Region) to file, by August 1, 2007, a proposal to
establish a permanent transmission rate design for the Super Region to be
effective February 1, 2008.  All of the transmission owners in PJM and
MISO, with the exception of AEP and one MISO transmission owner, elected to
support continuation of zonal rates in both RTOs.  In September 2007,
AEP filed a formal complaint proposing a highway/byway rate design be
implemented for the Super Region where users pay based on their use of the
transmission system.  AEP argued the use of other PJM and MISO
facilities by AEP is not as large as the use of AEP transmission by others in
PJM and MISO.  Therefore, a regional rate design change is required to
recognize that the provision and use of transmission service in the Super Region
is not sufficiently uniform between transmission owners and users to justify
zonal rates.  In January 2008, the FERC denied AEP’s
complaint.  AEP filed a rehearing request with the FERC in March
2008.  In December 2008, the FERC denied AEP’s request for
rehearing.  In February 2009, AEP filed an appeal in the U.S. Court of
Appeals.  If the court appeal is successful, earnings could benefit
for a certain period of time due to regulatory lag until the AEP East companies
reduce future retail revenues in their next fuel or base rate proceedings to
reflect the resultant additional transmission cost
reductions.  Management is unable to predict the outcome of this
case.





PJM
Transmission Formula Rate Filing





In July
2008, AEP filed an application with the FERC to increase its rates for wholesale
transmission service within PJM by $63 million annually.  The filing
seeks to implement a formula rate allowing annual adjustments reflecting future
changes in the AEP East companies' cost of service.  In September
2008, the FERC issued an order conditionally accepting AEP’s proposed formula
rate, subject to a compliance filing, established a settlement proceeding with
an ALJ, and delayed the requested October 2008 effective date for five
months.  The requested increase, which the AEP East companies began
billing in April 2009 for service as of March 1, 2009, will produce a $63
million annualized increase in revenues. Approximately $8 million of the
increase will be collected from nonaffiliated customers within
PJM.  The remaining $55 million requested would be billed to the AEP
East companies but would be offset by compensation from PJM for use of the AEP
East companies’ transmission facilities so that retail rates for jurisdictions
other than Ohio are not directly affected.  Retail rates for CSPCo and
OPCo would be increased through the TCRR totaling approximately $10 million and
$13 million, respectively.  The TCRR includes a true-up mechanism so
CSPCo’s and OPCo’s net income will not be adversely affected by a FERC ordered
transmission rate increase.  In October 2008, AEP filed the required
compliance filing, and began settlement discussions with the intervenors and
FERC staff.  The settlement discussions are currently
ongoing.  Under the formula, rates will be updated effective July 1,
2009, and each year thereafter.  Also, beginning with the July 1, 2010
update, the rates each year will include an adjustment to true-up the prior
year's collections to the actual costs for the prior year.  Management
is unable to predict the outcome of the settlement discussions or any further
proceedings that might be necessary if settlement discussions are not
successful.





Allocation
of Off-system Sales Margins





In August
2008, the OCC filed a complaint at the FERC alleging that AEP inappropriately
allocated off-system sales margins between the AEP East companies and the AEP
West companies and did not properly allocate off-system sales margins within the
AEP West companies.  The PUCT, the APSC and the Oklahoma Industrial
Energy Consumers intervened in this filing.  In November 2008, the
FERC issued a final order concluding that AEP inappropriately deviated from
off-system sales margin allocation methods in the SIA and the CSW Operating
Agreement for the period June 2000 through March 2006.  The FERC
ordered AEP to recalculate and reallocate the off-system sales margins in
compliance with the SIA and to have the AEP East companies issue refunds to the
AEP West companies.  Although the FERC determined that AEP deviated
from the CSW Operating Agreement, the FERC determined the allocation methodology
was reasonable.  The FERC ordered AEP to submit a revised CSW
Operating Agreement for the period June 2000 to March 2006.  In
December 2008, AEP filed a motion for rehearing and a revised CSW Operating
Agreement for the period June 2000 to March 2006.  The motion for
rehearing is still pending.  In January 2009, AEP filed a compliance
filing with the FERC and refunded approximately $250 million from the AEP East
companies to the AEP West companies.  The AEP West companies shared a
portion of such revenues with their wholesale and retail customers during the
period June 2000 to March 2006.  In December 2008, the AEP West
companies recorded a provision for refund.  In January 2009, SWEPCo
refunded approximately $13 million to FERC wholesale customers.  In
February 2009, SWEPCo filed a settlement agreement with the PUCT that provides
for the Texas retail jurisdiction amount to be included in the March 2009 fuel
cost report submitted to the PUCT.  PSO began refunding approximately
$54 million plus accrued interest to Oklahoma retail customers through the fuel
adjustment clause over a 12-month period beginning with the March 2009 billing
cycle.  TCC and TNC in Texas filed applications in April 2009 to
initiate proceedings as a result of the FERC ruling.  TCC and TNC
propose to use the refund to reduce its AMS investment as discussed in the
“Advanced Metering System” section within “Texas Rate
Matters”.  SWEPCo is working with the APSC and the LPSC to determine
the effect the FERC order will have on retail rates.  Management
cannot predict the outcome of the requested FERC rehearing proceeding or any
future state regulatory proceedings but believes the AEP West companies’
provision for refund regarding future regulatory proceedings is
adequate.





4.
            COMMITMENTS,
      GUARANTEES AND CONTINGENCIES





We are
subject to certain claims and legal actions arising in our ordinary course of
business.  In addition, our business activities are subject to
extensive governmental regulation related to public health and the
environment.  The ultimate outcome of such pending or potential
litigation against us cannot be predicted.  For current proceedings
not specifically discussed below, management does not anticipate that the
liabilities, if any, arising from such proceedings would have a material adverse
effect on our financial statements.  The Commitments, Guarantees and
Contingencies note within our 2008 Annual Report should be read in conjunction
with this report.





GUARANTEES





We record
certain immaterial liabilities recorded for guarantees in accordance with FIN 45
“Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others.”  In addition, we
adopted FSP SFAS 133-1 and FIN 45-4 “Disclosures about Credit Derivatives and
Certain Guarantees:  An amendment of FASB Statement No. 133 and FASB
Interpretation No. 45; and Clarification of the Effective Date of FASB Statement
No. 161” effective December 31, 2008.  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 enter
into standby letters of credit (LOCs) with third parties.  These LOCs
cover items such as gas and electricity risk management contracts, construction
contracts, insurance programs, security deposits and debt service
reserves.  As the Parent, we issued all of these LOCs in our ordinary
course of business on behalf of our subsidiaries.  At March 31, 2009,
the maximum future payments for all the LOCs issued under the two $1.5 billion
credit facilities, which were reduced by Lehman Brothers Holdings Inc.’s
commitment amount of $46 million following its bankruptcy, are approximately
$120 million with maturities ranging from May 2009 to March 2010.





We have a
$650 million 3-year credit agreement and a $350 million 364-day credit agreement
which were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $23
million and $12 million, respectively, following its bankruptcy.  As
of March 31, 2009, $372 million of letters of credit were issued by subsidiaries
under the $650 million 3-year credit agreement to support variable rate
Pollution Control Bonds.  In April 2009, the $350 million 364-day
credit agreement expired.





Guarantees
Of Third-Party Obligations





SWEPCo





As part
of the process to receive a renewal of a Texas Railroad Commission permit for
lignite mining, SWEPCo provides guarantees of mine reclamation in the amount of
approximately $65 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 Sabine Mining Company
(Sabine), an entity consolidated under FIN 46R.  This guarantee ends
upon depletion of reserves and completion of final reclamation.  Based
on the latest study, we estimate the reserves will be depleted in 2029 with
final reclamation completed by 2036, at an estimated cost of approximately $39
million.  As of March 31, 2009, SWEPCo has collected approximately $39
million through a rider for final mine closure costs, of which approximately $3
million is recorded in Other Current Liabilities, $20 million is recorded in
Deferred Credits and Other and approximately $16 million is recorded in Asset
Retirement Obligations on our Condensed Consolidated Balance
Sheets.





Sabine
charges SWEPCo, its only customer, all its costs.  SWEPCo passes these
costs to customers through its fuel clause.





Indemnifications
And Other Guarantees





Contracts





We enter
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.  The status of certain sales agreements is
discussed in the 2008 Annual Report, “Dispositions” section of Note
7.  These sale agreements include indemnifications with a maximum
exposure related to the collective purchase price, which is approximately $1.2
billion.  Approximately $1 billion of the maximum exposure relates to
the Bank of America (BOA) litigation (see “Enron Bankruptcy” section of this
note), of which the probable payment/performance risk is $435 million and is
recorded in Deferred Credits and Other on our Condensed Consolidated Balance
Sheets as of March 31, 2009.  The remaining exposure is
remote.  There are no material liabilities recorded for any
indemnifications other than amounts recorded related to the BOA
litigation.





Master Lease
Agreements





We lease
certain equipment under master lease agreements.  GE Capital
Commercial Inc. (GE) notified us in November 2008 that they elected to terminate
our Master Leasing Agreements in accordance with the termination rights
specified within the contract.  In 2010 and 2011, we will be required
to purchase all equipment under the lease and pay GE an amount equal to the
unamortized value of all equipment then leased.  In December 2008, we
signed new master lease agreements with one-year commitment periods that include
lease terms of up to 10 years.  We expect to enter into additional
replacement leasing arrangements for the equipment affected by this notification
prior to the termination dates of 2010 and 2011.





For
equipment under the GE master lease agreements that expire prior to 2011, the
lessor is guaranteed receipt of 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 are 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.  Under the new master lease agreements, the
lessor is guaranteed receipt of up to 68% of the unamortized balance at the end
of the lease term.  If the actual fair market value of the leased
equipment is below the unamortized balance at the end of the lease term, we are
committed to pay the difference between the actual fair market value and
unamortized balance, with the total guarantee not to exceed 68% of the
unamortized balance.  At March 31, 2009, the maximum potential loss
for these lease agreements was approximately $8 million assuming the fair market
value of the equipment is zero at the end of the lease
term.  Historically, at the end of the lease term the fair market
value has been in excess of the unamortized balance.





Railcar
Lease





In June
2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered
into an agreement with BTM Capital Corporation, as lessor, to lease 875
coal-transporting aluminum railcars.  The lease is accounted for as an
operating lease.  In January 2008, AEP Transportation assigned the
remaining 848 railcars under the original lease agreement to I&M (390
railcars) and SWEPCo (458 railcars).  The assignment is accounted for
as operating leases for I&M and SWEPCo.  The initial lease term
was five years with three consecutive five-year renewal periods for a maximum
lease term of twenty years.  I&M and SWEPCo intend to renew these
leases for the full lease term of twenty years, via the renewal
options.  The future minimum lease obligations are $20 million for
I&M and $23 million for SWEPCo for the remaining railcars as of March 31,
2009.





Under the
lease agreement, the lessor is guaranteed that the sale proceeds under a
return-and-sale option will equal at least a lessee obligation amount specified
in the lease, which declines from approximately 84% under the current five-year
lease term to 77% at the end of the 20-year term of the projected fair market
value of the equipment.  I&M and SWEPCo have assumed the guarantee
under the return-and-sale option.  I&M’s maximum potential loss
related to the guarantee is approximately $12 million ($8 million, net of tax)
and SWEPCo’s is approximately $13 million ($9 million, net of tax) assuming the
fair market value of the equipment is zero at the end of the current five-year
lease term.  However, we believe that the fair market value would
produce a sufficient sales price to avoid any loss.





We have
other railcar lease arrangements that do not utilize this type of financing
structure.





CONTINGENCIES





Federal
EPA Complaint and Notice of Violation





The
Federal EPA, certain special interest groups and a number of states alleged that
CSPCo, Dayton Power and Light Company and Duke Energy Ohio, Inc. modified
certain units at their jointly-owned coal-fired generating units in violation of
the NSR requirements of the CAA.





A case
remains pending that could affect CSPCo’s share of jointly-owned Beckjord
Station.  The Beckjord case had a liability trial in
2008.  Following the trial, the jury found no liability for claims
made against the jointly-owned Beckjord unit.  In December 2008,
however, the court ordered a new trial in the Beckjord case.  Beckjord
is operated by Duke Energy Ohio, Inc.





We are
unable to estimate the loss or range of loss related to any contingent
liability, if any, we might have for civil penalties under the pending CAA
proceedings for Beckjord.  We are also unable to predict the timing of
resolution of these matters.  If we do not prevail, we believe we can
recover any capital and operating costs of additional pollution control
equipment that may be required through future regulated rates or market prices
of electricity.  If we are unable to recover such costs or if material
penalties are imposed, it would adversely affect our net income, cash flows and
possibly financial condition.





SWEPCo
Notice of Enforcement and Notice of Citizen Suit





In March
2005, two special interest groups, Sierra Club and Public Citizen, filed a
complaint in Federal District Court for the Eastern District of Texas alleging
violations of the CAA at SWEPCo’s Welsh Plant.  In April 2008, the
parties filed a proposed consent decree to resolve all claims in this case and
in the pending appeal of the altered permit for the Welsh Plant.  The
consent decree requires SWEPCo to install continuous particulate emission
monitors at the Welsh Plant, secure 65 MW of renewable energy capacity by 2010,
fund $2 million in emission reduction, energy efficiency or environmental
mitigation projects by 2012 and pay a portion of plaintiffs’ attorneys’ fees and
costs.  The consent decree was entered as a final order in June
2008.





In
February 2008, the Federal EPA issued a Notice of Violation (NOV) based on
alleged violations of a percent sulfur in fuel limitation and the heat input
values listed in the previous state permit.  The NOV also alleges that
a permit alteration issued by the Texas Commission on Environmental Quality was
improper.  SWEPCo met with the Federal EPA to discuss the alleged
violations in March 2008.  The Federal EPA did not object to the
settlement of similar alleged violations in the federal citizen
suit.  We are unable to predict the timing of any future action by the
Federal EPA or the effect of such actions on our net income, cash flows or
financial condition.





Carbon
Dioxide (CO2) Public
Nuisance Claims





In 2004,
eight states and the City of New York filed an action in Federal District Court
for the Southern District of New York against AEP, AEPSC, Cinergy Corp, Xcel
Energy, Southern Company and Tennessee Valley Authority.  The Natural
Resources Defense Council, on behalf of three special interest groups, filed a
similar complaint against the same defendants.  The actions allege
that CO2 emissions
from the defendants’ power plants constitute a public nuisance under federal
common law due to impacts of global warming, and sought injunctive relief in the
form of specific emission reduction commitments from the
defendants.  The dismissal of this lawsuit was appealed to the Second
Circuit Court of Appeals.  Briefing and oral argument concluded in
2006.  In April 2007, the U.S. Supreme Court issued a decision holding
that the Federal EPA has authority to regulate emissions of CO2 and other
greenhouse gases under the CAA, which may impact the Second Circuit’s analysis
of these issues.  The Second Circuit requested supplemental briefs
addressing the impact of the U.S. Supreme Court’s decision on this case which we
provided in 2007.  We believe the actions are without merit and intend
to defend against the claims.





Alaskan
Villages’ Claims





In
February 2008, the Native Village of Kivalina and the City of Kivalina,
Alaska  filed a lawsuit in Federal Court in the Northern District of
California against AEP, AEPSC and 22 other unrelated defendants including oil
& gas companies, a coal company and other electric generating
companies.  The complaint alleges that the defendants' emissions of
CO2
contribute to global warming and constitute a public and private nuisance and
that the defendants are acting together.  The complaint further
alleges that some of the defendants, including AEP, conspired to create a false
scientific debate about global warming in order to deceive the public and
perpetuate the alleged nuisance.  The plaintiffs also allege that the
effects of global warming will require the relocation of the village at an
alleged cost of $95 million to $400 million.  The defendants filed
motions to dismiss the action.  The motions are pending before the
court.  We believe the action is without merit and intend to defend
against the claims.





The
Comprehensive Environmental Response Compensation and Liability Act (Superfund)
and State Remediation





By-products
from the generation of electricity include materials such as ash, slag, sludge,
low-level radioactive waste and SNF.  Coal combustion by-products,
which constitute the overwhelming percentage of these materials, are typically
treated and deposited in captive disposal facilities or are beneficially
utilized.  In addition, our generating plants and transmission and
distribution facilities have used asbestos, polychlorinated biphenyls (PCBs) and
other hazardous and nonhazardous materials.  We currently incur costs
to safely dispose of these substances.





Superfund
addresses clean-up of hazardous substances that have been released to the
environment.  The Federal EPA administers the clean-up
programs.  Several states have enacted similar laws.  In
March 2008, I&M received  a letter from the Michigan Department of
Environmental Quality (MDEQ) concerning conditions at a site under state law and
requesting I&M take voluntary action necessary to prevent and/or mitigate
public harm.  I&M requested  remediation proposals from
environmental consulting firms.  In May 2008, I&M issued a
contract to one of the consulting firms and started remediation work in
accordance with a plan approved by MDEQ.  I&M recorded
approximately $4 million of expense during 2008.  Based upon updated
information, I&M recorded additional expense of $3 million in March
2009.  As the remediation work is completed, I&M’s cost may
continue to increase.  I&M cannot predict the amount of additional
cost, if any.





Defective
Environmental Equipment





As part
of our continuing environmental investment program, we chose to retrofit wet
flue gas desulfurization systems on several of our units utilizing the JBR
technology.  The retrofits on two units are
operational.  Due to unexpected operating results, we completed an
extensive review of the design and manufacture of the JBR internal
components.  Our review concluded that there are fundamental design
deficiencies and that inferior and/or inappropriate materials were selected for
the internal fiberglass components.  We initiated discussions with
Black & Veatch, the original equipment manufacturer, to develop a repair or
replacement corrective action plan.  We intend to pursue our
contractual and other legal remedies if we are unable to resolve these issues
with Black & Veatch.  If we are unsuccessful in obtaining
reimbursement for the work required to remedy this situation, the cost of repair
or replacement could have an adverse impact on construction costs, net income,
cash flows or financial condition.





Cook
Plant Unit 1 Fire and Shutdown





In
September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine
vibrations, likely caused by blade failure, which resulted in a fire on the
electric generator.  This equipment, located in the turbine building,
is separate and isolated from the nuclear reactor.  The turbine rotors
that caused the vibration were installed in 2006 and are within the vendor’s
warranty period.  The warranty provides for the repair or replacement
of the turbine rotors if the damage was caused by a defect in materials or
workmanship.  I&M is working with its insurance company, Nuclear
Electric Insurance Limited (NEIL), and its turbine vendor, Siemens, to evaluate
the extent of the damage resulting from the incident and facilitate repairs to
return the unit to service.  Repair of the property damage and
replacement of the turbine rotors and other equipment could cost up to
approximately $330 million.  Management believes that I&M should
recover a significant portion of these costs through the turbine vendor’s
warranty, insurance and the regulatory process.  The treatment of
property damage costs, replacement power costs and insurance proceeds will be
the subject of future regulatory proceedings in Indiana and
Michigan.   I&M is repairing Unit 1 to resume operations as
early as October 2009 at reduced power.  Should post-repair operations
prove unsuccessful, the replacement of parts will extend the outage into
2011.





The
refueling outage scheduled for the fall of 2009 for Unit 1 was rescheduled to
the spring of 2010.  Management anticipates that the loss of capacity
from Unit 1 will not affect I&M’s ability to serve customers due to the
existence of sufficient generating capacity in the AEP Power Pool.





I&M
maintains property insurance through NEIL with a $1 million
deductible.  As of March 31, 2009, we recorded $34 million in
Prepayments and Other on our Condensed Consolidated Balance Sheets representing
recoverable amounts under the property insurance policy.  I&M
received partial reimbursement from NEIL for the cost incurred to date to repair
the property damage.  I&M also maintains a separate accidental
outage policy with NEIL whereby, after a 12-week deductible period, I&M is
entitled to weekly payments of $3.5 million for the first 52 weeks following the
deductible period.  After the initial 52 weeks of indemnity, the
policy pays $2.8 million per week for up to an additional 110
weeks.  I&M began receiving payments under the accidental outage
policy in December 2008.  In the first quarter of 2009, I&M
recorded $54 million in revenues, including $9 million that were deferred at
December 31, 2008, related to the accidental outage policy.  In order
to hold customers harmless, in the first quarter of 2009, I&M applied $20
million of the accidental outage insurance proceeds to reduce fuel
underrecoveries reflecting recoverable fuel costs as if Unit 1 were
operating.  If the ultimate costs of the incident are not covered by
warranty, insurance or through the regulatory process or if the unit is not
returned to service in a reasonable period of time, it could have an adverse
impact on net income, cash flows and financial condition.





TEM
Litigation





We agreed
to sell up to approximately 800 MW of energy to Tractebel Energy Marketing, Inc.
(TEM) (now known as SUEZ Energy Marketing NA, Inc.) for a period of 20 years
under a Power Purchase and Sale Agreement (PPA).  Beginning May 1,
2003, we tendered replacement capacity, energy and ancillary services to TEM
pursuant to the PPA that TEM rejected as nonconforming.





In 2003,
TEM and AEP separately filed declaratory judgment actions in the United States
District Court for the Southern District of New York.





In
January 2008, we reached a settlement with TEM to resolve all litigation
regarding the PPA.  TEM paid us $255 million.  We recorded
the $255 million as a gain in January 2008 under Asset Impairments and Other
Related Charges on our Condensed Consolidated Statements of
Income.  This settlement related to the Plaquemine Cogeneration
Facility which we sold in 2006.





Enron
Bankruptcy





In 2001,
we purchased Houston Pipeline Company (HPL) from Enron.  Various
HPL-related contingencies and indemnities from Enron remained unsettled at the
date of Enron’s bankruptcy.  In connection with our acquisition of
HPL, we entered into an agreement with BAM Lease Company, which granted HPL the
exclusive right to use approximately 55 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, BOA and certain
other banks (the BOA Syndicate) and Enron entered into an agreement granting HPL
the exclusive use of the cushion gas.  Also at the time of our
acquisition, Enron and the BOA Syndicate released HPL from all prior and future
liabilities and obligations in connection with the financing
arrangement.  After the Enron bankruptcy, the BOA Syndicate informed
HPL of a purported default by Enron under the terms of the financing
arrangement.  This dispute is being litigated in the Enron bankruptcy
proceedings and in federal courts in Texas and New York.





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





In 2003,
AEP filed a lawsuit against BOA in the United States District Court for the
Southern District of Texas.  BOA led the lending syndicate involving
the monetization of the cushion gas to Enron and its
subsidiaries.  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 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.  In April 2005, the Judge
entered an order severing and transferring the declaratory judgment claims
involving the right to use and cushion gas consent agreements to the Southern
District of New York and retaining in the Southern District of Texas the four
counts alleging breach of contract, fraud and negligent
misrepresentation.  HPL and BOA filed motions for summary judgment in
the case pending in the Southern District of New York.  Trial in
federal court in Texas was continued pending a decision on the motions for
summary judgment in the New York case.





In August
2007, the judge in the New York action issued a decision granting BOA summary
judgment and dismissed our claims.  In December 2007, the judge held
that BOA is entitled to recover damages of approximately $347 million plus
interest.  In August 2008, the court entered a final judgment of $346
million (the original judgment less $1 million BOA would have incurred to remove
55 BCF of natural gas from the Bammel storage facility) and clarified the
interest calculation method.  We appealed and posted a bond
covering the amount of the judgment entered against us.  The appeal
was briefed during the first quarter of 2009.  Oral argument remains
to be scheduled.





In 2005,
we sold our interest in HPL.  We indemnified the buyer of HPL against
any damages resulting from the BOA litigation up to the purchase
price.  After recalculation for the final judgment, the liability for
the BOA litigation was $435 million and $433 million including interest at March
31, 2009 and December 31, 2008, respectively. These liabilities are
included in Deferred Credits and Other on our Condensed Consolidated Balance
Sheets.





Shareholder
Lawsuits





In 2002
and 2003, three putative class action lawsuits were filed in Federal District
Court, Columbus, Ohio against AEP, certain executives and AEP’s ERISA Plan
Administrator alleging violations of ERISA in the selection of AEP stock as an
investment alternative and in the allocation of assets to AEP
stock.  In these actions, the plaintiffs sought recovery of an
unstated amount of compensatory damages, attorney fees and costs.  Two
of the three actions were dropped voluntarily by the plaintiffs in those
cases.  In 2006, the court entered judgment in the remaining case,
denying the plaintiff’s motion for class certification and dismissing all claims
without prejudice.  In 2007, the appeals court reversed the trial
court’s decision and held that the plaintiff did have standing to pursue his
claim.  The appeals court remanded the case to the trial court to
consider the issue of whether the plaintiff is an adequate representative for
the class of plan participants.  In September 2008, the trial court
denied the plaintiff’s motion for class certification and ordered briefing on
whether the plaintiff may maintain an ERISA claim on behalf of the Plan in the
absence of class certification.  In March 2009, the court granted a
motion to intervene on behalf of an individual seeking to intervene as a new
plaintiff.  We will continue to defend against these
claims.





Natural
Gas Markets Lawsuits





In 2002,
the Lieutenant Governor of California filed a lawsuit in Los Angeles County
California Superior Court against numerous energy companies, including AEP,
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 was dismissed from
the case.  A number of similar cases were also filed in California and
in state and federal courts in several states making essentially the same
allegations under federal or state laws against the same
companies.  AEP (or a subsidiary) is among the companies named as
defendants in some of these cases.  These cases are at various
pre-trial stages.  In June 2008, we settled all of the cases pending
against us in California.  The settlements did not impact 2008
earnings due to provisions made in prior periods.  We will continue to
defend each remaining case where an AEP company is a defendant.  We
believe the provision we recorded for the remaining cases is
adequate.





Rail
Transportation Litigation





In
October 2008, the Oklahoma Municipal Power Authority and the Public Utilities
Board of the City of Brownsville, Texas, as co-owners of Oklaunion Plant, filed
a lawsuit in United States District Court, Western District of Oklahoma against
AEP alleging breach of contract and breach of fiduciary duties related to
negotiations for rail transportation services for the plant.  The
plaintiffs allege that AEP assumed the duties of the project manager, PSO, and
operated the plant for the project manager and is therefore responsible for the
alleged breaches.  In December 2008, the court denied our motion to
dismiss the case. We intend to vigorously defend against these
allegations.  We believe a provision recorded in 2008 should be
sufficient.





FERC
Long-term Contracts





In 2002,
the FERC held a hearing related to a complaint filed by Nevada Power Company and
Sierra Pacific Power Company (the Nevada utilities).  The complaint
sought to break long-term contracts entered during the 2000 and 2001 California
energy price spike which the customers alleged were
“high-priced.”  The complaint alleged that we sold power at unjust and
unreasonable prices because the market for power was allegedly dysfunctional at
the time such contracts were executed.  In 2003, the FERC rejected the
complaint.  In 2006, the U.S. Court of Appeals for the Ninth Circuit
reversed the FERC order and remanded the case to the FERC for further
proceedings.  That decision was appealed to the U.S. Supreme
Court.  In June 2008, the U.S. Supreme Court affirmed the validity of
contractually-agreed rates except in cases of serious harm to the
public.  The U.S. Supreme Court affirmed the Ninth Circuit’s remand on
two issues, market manipulation and excessive burden on
consumers.  The FERC initiated remand procedures and gave the parties
time to attempt to settle the issues.  We believe a provision recorded
in 2008 should be sufficient. We asserted claims against certain companies
that sold power to us, which we resold to the Nevada utilities, seeking to
recover a portion of any amounts we may owe to the Nevada
utilities.  Management is unable to predict the outcome of these
proceedings or their ultimate impact on future net income and cash
flows.





5.       BENEFIT
PLANS





Components
of Net Periodic Benefit Cost





The
following table provides the components of our net periodic benefit cost for the
plans for the three months ended March 31, 2009 and 2008:




OtherPostretirementPension
      Plans
                
                Benefit
      PlansThree
      Months Ended March 31,
                
                Three
      Months Ended March 31,2009
                
                2008
                
                2009
                
                2008(in
      millions)Service
      Cost
                
                $
                26
                
                
                $
                25
                
                
                $
                10
                
                
                $
                10Interest
      Cost
                
                
                63
                
                
                
                63
                
                
                
                27
                
                
                
                28Expected
      Return on Plan Assets
                
                
                (80
                )
                
                
                (84
                )
                
                
                (20
                )
                
                
                (28
                )Amortization
      of Transition Obligation
                
                
                -
                
                
                
                -
                
                
                
                7
                
                
                
                7Amortization
      of Net Actuarial Loss
                
                
                15
                
                
                
                9
                
                
                
                11
                
                
                
                3Net
      Periodic Benefit Cost
                
                $
                24
                
                
                $
                13
                
                
                $
                35
                
                
                $
                20





We
sponsor several trust funds with significant investments intended to provide for
future pension and OPEB payments.  All of our trust funds’ investments
are well-diversified and managed in compliance with all laws and
regulations.  The value of the investments in these trusts has
declined from the December 31, 2008 balances due to decreases in the equity and
fixed income markets.  Although the asset values are currently lower
than at year end, this decline has not affected the funds’ ability to make their
required payments.




6.       BUSINESS
SEGMENTS





As
outlined in our 2008 Annual Report, our primary business is our electric utility
operations.  Within our Utility Operations segment, we centrally
dispatch generation assets and manage our overall utility operations on an
integrated basis because of the substantial impact of cost-based rates and
regulatory oversight.  While our Utility Operations segment remains
our primary business segment, other segments include our AEP River Operations
segment with significant barging activities and our Generation and Marketing
segment, which includes our nonregulated generating, marketing and risk
management activities primarily in the ERCOT market
area.  Intersegment sales and transfers are generally based on
underlying contractual arrangements and agreements.





Our
reportable segments and their related business activities are as
follows:





Utility
Operations


·
            Generation
      of electricity for sale to U.S. retail and wholesale
      customers.·
            Electricity
      transmission and distribution in the
U.S.





AEP
River Operations


·
            Commercial
      Barging operations that annually transport approximately 33 million tons
      of coal and dry bulk commodities primarily on the Ohio, Illinois and lower
      Mississippi Rivers.  Approximately 38% of the barging is for
      transportation of agricultural products, 30% for coal, 13% for steel and
      19% for other commodities.





Generation
and Marketing


·
            Wind
      farms and marketing and risk management activities primarily in
      ERCOT.





The
remainder of our activities is presented as All Other.  While not
considered a business segment, All Other includes:





·
            Parent’s
      guarantee revenue received from affiliates, investment income, interest
      income and interest expense and other nonallocated
  costs.·
            Forward
      natural gas contracts that were not sold with our natural gas pipeline and
      storage operations in 2004 and 2005.  These contracts are
      financial derivatives which will gradually liquidate and completely expire
      in 2011.·
            The
      first quarter 2008 cash settlement of a purchase power and sale agreement
      with TEM related to the Plaquemine Cogeneration Facility which was sold in
      2006.·
            Revenue
      sharing related to the Plaquemine Cogeneration
  Facility.





The
tables below present our reportable segment information for the three months
ended March 31, 2009 and 2008 and balance sheet information as of March 31, 2009
and December 31, 2008.  These amounts include certain estimates and
allocations where necessary.





Nonutility
      OperationsUtility
      Operations
                            
                            
                            
                            AEP River
                              Operations
                            
                            
                            Generation
                              and
                              Marketing
                            
                            
                            All
      Other (a)
                            
                            
                            Reconciling
      Adjustments
                            
                            
                            Consolidated(in
      millions)Three
      Months Ended March 31, 2009Revenues
      from:External
      Customers
                            
                            $
                            3,267
                            
                            (d)
                            
                            $
                            123
                            
                            
                            $
                            87
                            
                            
                            $
                            (19
                            )
                            
                            $
                            -
                            
                            
                            $
                            3,458Other
      Operating Segments
                            
                            
                            -
                            
                            (d)
                            
                            
                            6
                            
                            
                            
                            5
                            
                            
                            
                            22
                            
                            
                            
                            (33
                            )
                            
                            
                            -Total
      Revenues
                            
                            $
                            3,267
                            
                            
                            
                            $
                            129
                            
                            
                            $
                            92
                            
                            
                            $
                            3
                            
                            
                            $
                            (33
                            )
                            
                            $
                            3,458Net
      Income (Loss)
                            
                            $
                            346
                            
                            
                            
                            $
                            11
                            
                            
                            $
                            24
                            
                            
                            $
                            (18
                            )
                            
                            $
                            -
                            
                            
                            $
                            363Less:
      Net Income Attributable to Noncontrolling Interests
                            
                            
                            (2
                            )
                            
                            
                            
                            -
                            
                            
                            
                            -
                            
                            
                            
                            -
                            
                            
                            
                            -
                            
                            
                            
                            (2
                            )Net
      Income (Loss) Attributable to AEP Shareholders
                            
                            
                            344
                            
                            
                            
                            
                            11
                            
                            
                            
                            24
                            
                            
                            
                            (18
                            )
                            
                            
                            -
                            
                            
                            
                            361Less:
      Preferred Stock Dividend Requirements of Subsidiaries
                            
                            
                            (1
                            )
                            
                            
                            
                            -
                            
                            
                            
                            -
                            
                            
                            
                            -
                            
                            
                            
                            -
                            
                            
                            
                            (1
                            )Earnings (Loss)
      Attributable to AEP Common Shareholders
                            
                            $
                            343
                            
                            
                            
                            $
                            11
                            
                            
                            $
                            24
                            
                            
                            $
                            (18
                            )
                            
                            $
                            -
                            
                            
                            $
                            360








Nonutility
      OperationsUtility
      Operations
                              
                              
                              
                              AEP River
                                Operations
                              
                              
                              Generation
                                and
                                Marketing
                              
                              
                              All
      Other (a)
                              
                              
                              Reconciling
      Adjustments
                              
                              
                              Consolidated(in
      millions)Three
      Months Ended March 31, 2008Revenues
      from:External
      Customers
                              
                              $
                              3,010
                              
                              (d)
                              
                              $
                              138
                              
                              
                              $
                              271
                              
                              
                              $
                              48
                              
                              
                              $
                              -
                              
                              
                              $
                              3,467Other
      Operating Segments
                              
                              
                              284
                              
                              (d)
                              
                              
                              4
                              
                              
                              
                              (212
                              )
                              
                              
                              (43
                              )
                              
                              
                              (33
                              )
                              
                              
                              -Total
      Revenues
                              
                              $
                              3,294
                              
                              
                              
                              $
                              142
                              
                              
                              $
                              59
                              
                              
                              $
                              5
                              
                              
                              $
                              (33
                              )
                              
                              $
                              3,467Net
      Income
                              
                              $
                              413
                              
                              
                              
                              $
                              7
                              
                              
                              $
                              1
                              
                              
                              $
                              155
                              
                              
                              $
                              -
                              
                              
                              $
                              576Less:
      Net Income Attributable to Noncontrolling Interests
                              
                              
                              (2
                              )
                              
                              
                              
                              -
                              
                              
                              
                              -
                              
                              
                              
                              -
                              
                              
                              
                              -
                              
                              
                              
                              (2
                              )Net
      Income Attributable to AEP Shareholders
                              
                              
                              411
                              
                              
                              
                              
                              7
                              
                              
                              
                              1
                              
                              
                              
                              155
                              
                              
                              
                              -
                              
                              
                              
                              574Less:
      Preferred Stock Dividend Requirements of Subsidiaries
                              
                              
                              (1
                              )
                              
                              
                              
                              -
                              
                              
                              
                              -
                              
                              
                              
                              -
                              
                              
                              
                              -
                              
                              
                              
                              (1
                              )Earnings Attributable
      to AEP Common Shareholders
                              
                              $
                              410
                              
                              
                              
                              $
                              7
                              
                              
                              $
                              1
                              
                              
                              $
                              155
                              
                              
                              $
                              -
                              
                              
                              $
                              573





Nonutility
      OperationsUtility
      Operations
                    
                    
                    AEP River
                      Operations
                    
                    
                    Generation
                      and
                      Marketing
                    
                    
                    All
      Other (a)
                    
                    
                    Reconciling
      Adjustments
                      (c)
                    
                    
                    
                    Consolidated(in
      millions)March
      31, 2009Total
      Property, Plant and Equipment
                    
                    $
                    49,454
                    
                    
                    $
                    368
                    
                    
                    $
                    570
                    
                    
                    $
                    10
                    
                    
                    $
                    (238
                    )
                    
                    
                    $
                    50,164Accumulated
      Depreciation and
                      Amortization
                    
                    
                    16,708
                    
                    
                    
                    76
                    
                    
                    
                    147
                    
                    
                    
                    8
                    
                    
                    
                    (26
                    )
                    
                    
                    
                    16,913Total
      Property, Plant and Equipment – Net
                    
                    $
                    32,746
                    
                    
                    $
                    292
                    
                    
                    $
                    423
                    
                    
                    $
                    2
                    
                    
                    $
                    (212
                    )
                    
                    
                    $
                    33,251Total
      Assets
                    
                    $
                    44,278
                    
                    
                    $
                    416
                    
                    
                    $
                    795
                    
                    
                    $
                    14,729
                    
                    
                    $
                    (14,353
                    )
                    (b)
                    
                    $
                    45,865








Nonutility
      OperationsUtility
      Operations
                                        
                                        AEP River
                                          Operations
                                        
                                        Generation
                                          and
                                          Marketing
                                        
                                        All
      Other (a)
                                        
                                        
                                        Reconciling
      Adjustment (c)
                                        
                                        
                                        ConsolidatedDecember
      31, 2008
                                        
                                        (in
      millions)Total
      Property, Plant and Equipment
                                        
                                        
                                        $
                                        48,997
                                        
                                        
                                        $
                                        371
                                        
                                        
                                        $
                                        565
                                        
                                        
                                        $
                                        10
                                        
                                        
                                        $
                                        (233
                                        )
                                        
                                        
                                        $
                                        49,710Accumulated
      Depreciation and
                                          Amortization
                                        
                                        
                                        
                                        16,525
                                        
                                        
                                        
                                        73
                                        
                                        
                                        
                                        140
                                        
                                        
                                        
                                        8
                                        
                                        
                                        
                                        (23
                                        )
                                        
                                        
                                        
                                        16,723Total
      Property, Plant and Equipment    – Net
                                        
                                        
                                        $
                                        32,472
                                        
                                        
                                        $
                                        298
                                        
                                        
                                        $
                                        425
                                        
                                        
                                        $
                                        2
                                        
                                        
                                        $
                                        (210
                                        )
                                        
                                        
                                        $
                                        32,987Total
      Assets
                                        
                                        
                                        $
                                        43,773
                                        
                                        
                                        $
                                        439
                                        
                                        
                                        $
                                        737
                                        
                                        
                                        $
                                        14,501
                                        
                                        
                                        $
                                        (14,295
                                        )
                                        (b)
                                        
                                        $
                                        45,155





(a)
            All
      Other includes:·
            Parent’s
      guarantee revenue received from affiliates, investment income, interest
      income and interest expense and other nonallocated
  costs.·
            Forward
      natural gas contracts that were not sold with our natural gas pipeline and
      storage operations in 2004 and 2005.  These contracts are
      financial derivatives which will gradually liquidate and completely expire
      in 2011.·
            The
      first quarter 2008 cash settlement of a purchase power and sale agreement
      with TEM related to the Plaquemine Cogeneration Facility which was sold in
      2006.  The cash settlement of $255 million ($164 million, net of
      tax) is included in Net Income.·
            Revenue
      sharing related to the Plaquemine Cogeneration
Facility.(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)
            Includes
      eliminations due to an intercompany capital lease.(d)
            PSO
      and SWEPCo transferred certain existing ERCOT energy marketing contracts
      to AEP Energy Partners, Inc. (AEPEP) (Generation and Marketing segment)
      and entered into intercompany financial and physical purchase and sales
      agreements with AEPEP.  As a result, we reported third-party net
      purchases or sales activity for these energy marketing contracts as
      Revenues from External Customers for the Utility Operations
      segment.  This is offset by the Utility Operations segment’s
      related net sales (purchases) for these contracts with AEPEP in Revenues
      from Other Operating Segments of $(5) million and $212 million for the
      three months ended March 31, 2009 and 2008, respectively.  The
      Generation and Marketing segment also reports these purchase or sales
      contracts with Utility Operations as Revenues from Other Operating
      Segments.  These affiliated contracts between PSO and SWEPCo
      with AEPEP will end in December
2009.





7.       DERIVATIVES, HEDGING AND
FAIR VALUE MEASUREMENTS





DERIVATIVES
AND HEDGING





Objectives for Utilization
of Derivative Instruments





We are
exposed to certain market risks as a major power producer and marketer of
wholesale electricity, coal and emission allowances.  These risks
include commodity price risk, interest rate risk, credit risk and to a lesser
extent foreign currency exchange risk.  These risks represent the risk
of loss that may impact us due to changes in the underlying market prices or
rates.  We manage these risk using derivative
instruments.





Strategies for Utilization
of Derivative Instruments to Achieve Objectives





Our
strategy surrounding the use of derivative instruments focuses on managing our
risk exposures, future cash flows and creating value based on our open trading
positions by utilizing both economic and formal SFAS 133 hedging strategies. To
accomplish our objectives, we primarily employ risk management contracts
including physical forward purchase and sale contracts, financial forward
purchase and sale contracts and financial swap instruments.  Not all
risk management contracts meet the definition of a derivative under SFAS
133.  Derivative risk management contracts elected normal under the
normal purchases and normal sales scope exception are not subject to the
requirements of SFAS 133.





We enter
into electricity, coal, natural gas, interest rate and to a lesser degree
heating oil, gasoline, emission allowance and other commodity contracts to
manage the risk associated with our energy business.  We enter into
interest rate derivative contracts in order to manage the interest rate exposure
associated with our commodity portfolio.   For disclosure
purposes, such risks are grouped as “Commodity,” as they are related to energy
risk management activities.  We also engage in risk management of
interest rate risk associated with debt financing and foreign currency risk
associated with future purchase obligations denominated in foreign
currencies.  For disclosure purposes these risks are grouped as
“Interest Rate and Foreign Currency.” The amount of risk taken is determined by
the Commercial Operations and Finance groups in accordance with our established
risk management policies as approved by the Finance Committee of AEP’s Board of
Directors.





The
following table represents the gross notional volume of our outstanding
derivative contracts as of March 31, 2009:




Notional
      Volume of Derivative InstrumentsMarch
      31, 2009Unit
      ofPrimary
      Risk Exposure
                    
                    Volume
                    
                    Measure(in
      millions)Commodity:Power
                    
                    
                    351
                    
                    MWHsCoal
                    
                    
                    51
                    
                    TonsNatural
      Gas
                    
                    
                    211
                    
                    MMBtuHeating
      Oil and Gasoline
                    
                    
                    4
                    
                    GallonsInterest
      Rate
                    
                    $
                    413
                    
                    USDInterest
      Rate and Foreign Currency
                    
                    $
                    501
                    
                    USD





Fair
Value Hedging Strategies





At
certain times, we enter into interest rate derivative transactions in order to
manage existing fixed interest rate risk exposure.  These interest
rate derivative transactions effectively modify our exposure to interest rate
risk by converting a portion of our fixed-rate debt to a floating
rate.  Currently, this strategy is not actively employed.





Cash
Flow Hedging Strategies





We enter
into and designate as cash flow hedges certain derivative transactions for the
purchase and sale of electricity, coal and natural gas (“Commodity”) in order to
manage the variable price risk related to the forecasted purchase and sale of
these commodities.  We monitor the potential impacts of commodity
price changes and, where appropriate, enter into derivative transactions to
protect profit margins for a portion of future electricity sales and fuel or
energy purchases.  We do not hedge all commodity price
risk.





Our
vehicle fleet is exposed to gasoline and diesel fuel price
volatility.  We enter into financial gasoline and heating oil
derivative contracts in order to mitigate price risk of our future fuel
purchases.  We do not hedge all of our fuel price risk.  For
disclosure purposes, these contracts are included with other hedging activity as
“Commodity.”





We enter
into a variety of interest rate derivative transactions in order to manage
interest rate risk exposure.  Some interest rate derivative
transactions effectively modify our exposure to interest rate risk by converting
a portion of our floating-rate debt to a fixed rate.  We also enter
into interest rate derivative contracts to manage interest rate exposure related
to anticipated borrowings of fixed-rate debt.  Our anticipated
fixed-rate debt offerings have a high probability of occurrence as the proceeds
will be used to fund existing debt maturities and projected capital
expenditures.  We do not hedge all interest rate
exposure.





At times,
we are exposed to foreign currency exchange rate risks primarily when we
purchase certain fixed assets from foreign suppliers.  In accordance
with our risk management policy, we may enter into foreign currency derivative
transactions to protect against the risk of increased cash outflows resulting
from a foreign currency’s appreciation against the dollar.  We do not
hedge all foreign currency exposure.





Accounting for Derivative
Instruments and the Impact on Our Financial Statements





SFAS 133
requires recognition of all qualifying derivative instruments as either assets
or liabilities in the balance sheet at fair value.  The fair values of
derivative instruments accounted for using MTM accounting or hedge accounting
are based on exchange prices and broker quotes.  If a quoted market
price is not available, the estimate of fair value is based on the best
information available including valuation models that estimate future energy
prices based on existing market and broker quotes, supply and demand market data
and assumptions.  In order to determine the relevant fair values of
our derivative instruments, we also apply valuation adjustments for discounting,
liquidity and credit quality.





Credit
risk is the risk that a counterparty will fail to perform on the contract or
fail to pay amounts due.  Liquidity risk represents the risk that
imperfections in the market will cause the price to vary from estimated fair
value based upon prevailing market supply and demand
conditions.  Since energy markets are imperfect and volatile, there
are inherent risks related to the underlying assumptions in models used to fair
value risk management contracts.  Unforeseen events may cause
reasonable price curves to differ from actual price curves throughout a
contract’s term and at the time a contract settles.  Consequently,
there could be significant adverse or favorable effects on future net income and
cash flows if market prices are not consistent with our estimates of current
market consensus for forward prices in the current period.  This is
particularly true for longer term contracts.  Cash flows may vary
based on market conditions, margin requirements and the timing of settlement of
our risk management contracts.





According
to FSP FIN 39-1, we reflect the fair values of our derivative instruments
subject to netting agreements with the same counterparty net of related cash
collateral.  For certain risk management contracts, we are required to
post or receive cash collateral based on third party contractual agreements and
risk profiles.  For the March 31, 2009 and December 31, 2008 balance
sheets, we netted $74 million and $11 million, respectively, of cash collateral
received from third parties against short-term and long-term risk management
assets and $117 million and $43 million, respectively, of cash collateral paid
to third parties against short-term and long-term risk management
liabilities.





The
following table represents the gross fair value impact of our derivative
activity on our Condensed Consolidated Balance Sheet as of March 31,
2009.





Fair Value of Derivative
      Instruments
                                March
      31, 2009Risk
      ManagementContracts
                              
                              Hedging
      ContractsInterest
      Rateand
      Foreign
                              
                              OtherBalance
      Sheet Location
                              
                              Commodity
      (a)
                              
                              Commodity
      (a)
                              
                              Currency
                              
                              (b)
                              
                              Total(in
      millions)Current
      Risk Management Assets
                              
                              
                              $
                              2,209
                              
                              
                              $
                              47
                              
                              
                              $
                              1
                              
                              
                              $
                              (1,964
                              )
                              
                              $
                              293Long-Term
      Risk Management Assets
                              
                              
                              
                              1,087
                              
                              
                              
                              2
                              
                              
                              
                              -
                              
                              
                              
                              (672
                              )
                              
                              
                              417Total
      Assets
                              
                              
                              
                              3,296
                              
                              
                              
                              49
                              
                              
                              
                              1
                              
                              
                              
                              (2,636
                              )
                              
                              
                              710Current
      Risk Management Liabilities
                              
                              
                              
                              2,121
                              
                              
                              
                              35
                              
                              
                              
                              4
                              
                              
                              
                              (1,981
                              )
                              
                              
                              179Long-Term
      Risk Management Liabilities
                              
                              
                              
                              902
                              
                              
                              
                              1
                              
                              
                              
                              4
                              
                              
                              
                              (733
                              )
                              
                              
                              174Total
      Liabilities
                              
                              
                              
                              3,023
                              
                              
                              
                              36
                              
                              
                              
                              8
                              
                              
                              
                              (2,714
                              )
                              
                              
                              353Total
      MTM Derivative Contract Net Assets (Liabilities)
                              
                              
                              $
                              273
                              
                              
                              $
                              13
                              
                              
                              $
                              (7
                              )
                              
                              $
                              78
                              
                              
                              $
                              357





(a)
            Derivative
      instruments within these categories are reported gross.  These
      instruments are subject to master netting agreements and are presented in
      the Condensed Consolidated Balance Sheet on a net basis in accordance with
      FIN 39 “Offsetting of Amounts Related to Certain
    Contracts.”(b)
            Amounts
      represent counterparty netting of risk management contracts, associated
      cash collateral in accordance with FSP FIN 39-1 and dedesignated risk
      management contracts.





The table
below presents our MTM activity of derivative risk management contracts for the
three months ended March 31, 2009:




Amount
      of Gain (Loss) Recognized on
              Risk
      Management ContractsFor
      the Three Months Ended March 31,
2009





Location
      of Gain (Loss)
                    
                    (in
      millions)Utility
      Operations Revenue
                    
                    $
                    65Other
      Revenue
                    
                    
                    13Regulatory
      Assets
                    
                    
                    (1
                    )Regulatory
      Liabilities
                    
                    
                    74Total
      Gain on Risk Management Contracts
                    
                    $
                    151





Certain
qualifying derivative instruments have been designated as normal purchase or
normal sale contracts, as provided in SFAS 133.  Derivative contracts
that have been designated as normal purchases or normal sales under SFAS 133 are
not subject to MTM accounting treatment and are recognized in the Condensed
Consolidated Statements of Income on an accrual basis.





Our
accounting for the changes in the fair value of a derivative instrument depends
on whether it qualifies for and has been designated as part of a hedging
relationship and further, on the type of hedging
relationship.  Depending on the exposure, we designate a hedging
instrument as a fair value hedge or a cash flow hedge.





For
contracts that have not been designated as part of a hedging relationship, the
accounting for changes in fair value depends on whether the derivative
instrument is held for trading purposes. Unrealized and realized gains and
losses on derivative instruments held for trading purposes are included in
Revenues on a net basis in the Condensed Consolidated Statements of Income.
Unrealized and realized gains and losses on derivative instruments not held for
trading purposes are included in Revenues or Expenses on the Condensed
Consolidated Statements of Income depending on the relevant facts and
circumstances.  However, unrealized and realized gains and losses in
regulated jurisdictions for both trading and non-trading derivative instruments
are recorded as regulatory assets (for losses) or regulatory liabilities (for
gains) in accordance with SFAS 71.





Accounting
for Fair Value Hedging Strategies





For fair
value hedges (i.e. hedging the exposure to changes in the fair value of an
asset, liability or an identified portion thereof attributable to a particular
risk), the gain or loss on the derivative instrument as well as the offsetting
gain or loss on the hedged item associated with the hedged risk impacts Net
Income during the period of change.





We record
realized gains or losses on interest rate swaps that qualify for fair value
hedge accounting treatment and any offsetting changes in the fair value of the
debt being hedged, in Interest Expense on our Condensed Consolidated Statements
of Income.  During the three months ended March 31, 2009, we did not
employ any fair value hedging strategies.  During the three months
ended March 31, 2008, we designated interest rate derivatives as fair value
hedges and did not recognize any hedge ineffectiveness related to these
derivative transactions.





Accounting
for Cash Flow Hedging Strategies





For cash
flow hedges (i.e. hedging the exposure to variability in expected future cash
flows attributable to a particular risk), we initially report the effective
portion of the gain or loss on the derivative instrument as a component of
Accumulated Other Comprehensive Income (Loss) on our Condensed Consolidated
Balance Sheets until the period the hedged item affects Net
Income.  We recognize any hedge ineffectiveness in Net Income
immediately during the period of change, except in regulated jurisdictions where
hedge ineffectiveness is recorded as a regulatory asset (for losses) or a
regulatory liability (for gains).





Realized
gains and losses on derivative contracts for the purchase and sale of
electricity, coal and natural gas designated as cash flow hedges are included in
Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased
Electricity for Resale in our Condensed Consolidated Statements of Income,
depending on the specific nature of the risk being hedged.  We do not
hedge all variable price risk exposure related to commodities.  During
the three months ended March 31, 2009 and 2008, we recognized immaterial amounts
in Net Income related to hedge ineffectiveness.





Beginning
in 2009, we executed financial heating oil and gasoline derivative contracts to
hedge the price risk of our diesel fuel and gasoline purchases.  We
reclassify gains and losses on financial fuel derivative contracts designated as
cash flow hedges from Accumulated Other Comprehensive Income (Loss) on our
Condensed Consolidated Balance Sheets into Other Operation and Maintenance
expense or Depreciation and Amortization expense, as it relates to capital
projects, on our Condensed Consolidated Statements of Income.  We do
not hedge all fuel price risk exposure.  During the three months ended
March 31, 2009, we recognized no hedge ineffectiveness related to this hedge
strategy.





We
reclassify gains and losses on interest rate derivative hedges related to our
debt financings from Accumulated Other Comprehensive Income (Loss) into Interest
Expense in those periods in which hedged interest payments
occur.  During the three months ended March 31, 2009 and 2008, we
recognized immaterial amounts in Net Income related to hedge
ineffectiveness.





The
accumulated gains or losses related to our foreign currency hedges are
reclassified from Accumulated Other Comprehensive Income (Loss) on our Condensed
Consolidated Balance Sheets into Depreciation and Amortization expense in our
Condensed Consolidated Statements of Income over the depreciable lives of the
fixed assets designated as the hedged items in qualifying foreign currency
hedging relationships.  We do not hedge all foreign currency
exposure.  During the three months ended March 31, 2009 and 2008, we
recognized no hedge ineffectiveness related to this hedge strategy.





The
following table provides details on designated, effective cash flow hedges
included in AOCI on our Condensed Consolidated Balance Sheets and the reasons
for changes in cash flow hedges from January 1, 2009 to March 31,
2009.  All amounts in the following table are presented net of related
income taxes.





Total
      Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow
      HedgesFor
      the Three Months Ended March 31, 2009Commodity
                    
                    
                    Interest
      Rate and Foreign Currency
                    
                    
                    Total(in
      millions)Beginning
      Balance in AOCI as of January 1, 2009
                    
                    $
                    7
                    
                    
                    $
                    (29
                    )
                    
                    $
                    (22
                    )Changes
      in Fair Value Recognized in AOCI
                    
                    
                    (3
                    )
                    
                    
                    -
                    
                    
                    
                    (3
                    )Amount
      of (Gain) or Loss Reclassified from AOCI  to Income
      Statement/within Balance SheetUtility
      Operations Revenue
                    
                    
                    (2
                    )
                    
                    
                    -
                    
                    
                    
                    (2
                    )Other
      Revenue
                    
                    
                    (2
                    )
                    
                    
                    -
                    
                    
                    
                    (2
                    )Purchased
      Electricity for Resale
                    
                    
                    8
                    
                    
                    
                    -
                    
                    
                    
                    8Interest
      Expense
                    
                    
                    -
                    
                    
                    
                    1
                    
                    
                    
                    1Regulatory
      Assets
                    
                    
                    2
                    
                    
                    
                    -
                    
                    
                    
                    2Regulatory
      Liabilities
                    
                    
                    (1
                    )
                    
                    
                    -
                    
                    
                    
                    (1
                    )Ending
      Balance in AOCI as of March 31, 2009
                    
                    $
                    9
                    
                    
                    $
                    (28
                    )
                    
                    $
                    (19
                    )





Cash flow
hedges included in Accumulated Other Comprehensive Income (Loss) on our
Condensed Consolidated Balance Sheet at March 31, 2009 were:





Impact
      of Cash Flow Hedges on our Condensed Consolidated Balance
      SheetCommodity
                
                Interest
      Rate and Foreign Currency
                
                Total(in
      millions)Hedging
      Assets (a)
                
                $
                40
                
                
                $
                1
                
                
                $
                41Hedging
      Liabilities (a)
                
                
                (27
                )
                
                
                (8
                )
                
                
                (35
                )AOCI
      Gain (Loss) Net of Tax
                
                
                9
                
                
                
                (28
                )
                
                
                (19
                )Portion
      Expected to be Reclassified to Net Income During the Next Twelve
      Months
                
                
                8
                
                
                
                (6
                )
                
                
                2





(a)
            Hedging
      Assets and Hedging Liabilities are included in Risk Management Assets and
      Liabilities on our Condensed Consolidated Balance
  Sheet.





The
actual amounts that we reclassify from Accumulated Other Comprehensive Income
(Loss) to Net Income can differ from the estimate above due to market price
changes.  As of March 31, 2009, the maximum length of time that we are
hedging (with SFAS 133 designated contracts) our exposure to variability in
future cash flows related to forecasted transactions is 44 months.





Credit
Risk





We limit
credit risk in our wholesale marketing and trading activities by assessing the
creditworthiness of potential counterparties before entering into transactions
with them and continuing to evaluate their creditworthiness on an ongoing
basis.  We use Moody’s, S&P and current market-based qualitative
and quantitative data to assess the financial health of counterparties on an
ongoing basis.  If an external rating is not available, an internal
rating is generated utilizing a quantitative tool developed by Moody’s to
estimate probability of default that corresponds to an implied external agency
credit rating.





We use
standardized master agreements which may include collateral
requirements.  These master agreements facilitate the netting of cash
flows associated with a single counterparty.  Cash, letters of credit,
and parental/affiliate guarantees may be obtained as security from
counterparties in order to mitigate credit risk.  The collateral
agreements require a counterparty to post cash or letters of credit in the event
an exposure exceeds our established threshold.  The threshold
represents an unsecured credit limit which may be supported by a
parental/affiliate guaranty, as determined in accordance with our credit
policy.  In addition, collateral agreements allow for termination and
liquidation of all positions in the event of a failure or inability to post
collateral.





Collateral
Triggering Events





Under a
limited number of derivative and non-derivative counterparty contracts primarily
related to our pre-2002 risk management activities and under the tariffs of the
RTOs and Independent System Operators (ISOs), we are obligated to post an amount
of collateral if our credit ratings decline below investment
grade.  The amount of collateral required fluctuates based on market
prices and our total exposure.  On an ongoing basis, our risk
management organization assesses the appropriateness of these collateral
triggering items in contracts.  We believe that a downgrade below
investment grade is unlikely.  As of March 31, 2009, the aggregate
value of such contracts was $127 million and AEP was not required to post any
collateral.  We would have been required to post $127 million of
collateral at March 31, 2009, if our credit ratings had declined below
investment grade of which $123 million was attributable to our RTO and ISO
activities.





FAIR
VALUE MEASUREMENTS





SFAS
157 Fair Value Measurements





As
described in our 2008 Annual Report, SFAS 157 establishes a fair value hierarchy
that prioritizes the inputs used to measure fair value.  The hierarchy
gives the highest priority to unadjusted quoted prices in active markets for
identical assets or liabilities (level 1 measurement) and the lowest priority to
unobservable inputs (level 3 measurement).  The Derivatives, Hedging
and Fair Value Measurements note within the 2008 Annual Report should be read in
conjunction with this report.





The
following tables set forth by level, within the fair value hierarchy, our
financial assets and liabilities that were accounted for at fair value on a
recurring basis as of March 31, 2009 and December 31, 2008.  As
required by SFAS 157, financial assets and liabilities are classified in their
entirety based on the lowest level of input that is significant to the fair
value measurement. Our assessment of the significance of a particular input to
the fair value measurement requires judgment, and may affect the valuation of
fair value assets and liabilities and their placement within the fair value
hierarchy levels.





Assets
      and Liabilities Measured at Fair Value on a Recurring Basis as of March
      31, 2009Level
      1
                
                
                Level
      2
                
                
                Level
      3
                
                
                Other
                
                
                TotalAssets:
                
                (in
      millions)Cash
      and Cash EquivalentsCash
      and Cash Equivalents (a)
                
                $
                637
                
                
                $
                -
                
                
                $
                -
                
                
                $
                58
                
                
                $
                695Debt
      Securities (b)
                
                
                -
                
                
                
                15
                
                
                
                -
                
                
                
                -
                
                
                
                15Total
      Cash and Cash Equivalents
                
                
                637
                
                
                
                15
                
                
                
                -
                
                
                
                58
                
                
                
                710Other
      Temporary InvestmentsCash
      and Cash Equivalents (a)
                
                
                107
                
                
                
                -
                
                
                
                -
                
                
                
                27
                
                
                
                134Debt
      Securities (c)
                
                
                56
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                56Equity
      Securities (d)
                
                
                25
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                25Total Other Temporary
      Investments
                
                
                188
                
                
                
                -
                
                
                
                -
                
                
                
                27
                
                
                
                215Risk
      Management AssetsRisk
      Management Contracts (e)
                
                
                71
                
                
                
                3,112
                
                
                
                99
                
                
                
                (2,648
                )
                
                
                634Cash
      Flow Hedges (e)
                
                
                8
                
                
                
                41
                
                
                
                -
                
                
                
                (8
                )
                
                
                41Dedesignated
      Risk Management Contracts (f)
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                35
                
                
                
                35Total
      Risk Management Assets
                
                
                79
                
                
                
                3,153
                
                
                
                99
                
                
                
                (2,621
                )
                
                
                710Spent
      Nuclear Fuel and Decommissioning TrustsCash
      and Cash Equivalents (g)
                
                
                -
                
                
                
                15
                
                
                
                -
                
                
                
                9
                
                
                
                24Debt
      Securities (h)
                
                
                -
                
                
                
                764
                
                
                
                -
                
                
                
                -
                
                
                
                764Equity
      Securities (d)
                
                
                419
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                419Total Spent Nuclear Fuel and
      Decommissioning Trusts
                
                
                419
                
                
                
                779
                
                
                
                -
                
                
                
                9
                
                
                
                1,207Total
      Assets
                
                $
                1,323
                
                
                $
                3,947
                
                
                $
                99
                
                
                $
                (2,527
                )
                
                $
                2,842Liabilities:Risk
      Management LiabilitiesRisk
      Management Contracts (e)
                
                $
                86
                
                
                $
                2,910
                
                
                $
                13
                
                
                $
                (2,691
                )
                
                $
                318Cash
      Flow Hedges (e)
                
                
                3
                
                
                
                40
                
                
                
                -
                
                
                
                (8
                )
                
                
                35Total
      Risk Management Liabilities
                
                $
                89
                
                
                $
                2,950
                
                
                $
                13
                
                
                $
                (2,699
                )
                
                $
                353






Assets
      and Liabilities Measured at Fair Value on a Recurring Basis as of December
      31, 2008Level
      1
                
                
                Level
      2
                
                
                Level
      3
                
                
                Other
                
                
                TotalAssets:
                
                (in
      millions)Cash
      and Cash EquivalentsCash
      and Cash Equivalents (a)
                
                $
                304
                
                
                $
                -
                
                
                $
                -
                
                
                $
                60
                
                
                $
                364Debt
      Securities (b)
                
                
                -
                
                
                
                47
                
                
                
                -
                
                
                
                -
                
                
                
                47Total
      Cash and Cash Equivalents
                
                
                304
                
                
                
                47
                
                
                
                -
                
                
                
                60
                
                
                
                411Other
      Temporary InvestmentsCash
      and Cash Equivalents (a)
                
                
                217
                
                
                
                -
                
                
                
                -
                
                
                
                26
                
                
                
                243Debt
      Securities (c)
                
                
                56
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                56Equity
      Securities (d)
                
                
                28
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                28Total Other Temporary
      Investments
                
                
                301
                
                
                
                -
                
                
                
                -
                
                
                
                26
                
                
                
                327Risk
      Management AssetsRisk
      Management Contracts (e)
                
                
                61
                
                
                
                2,413
                
                
                
                86
                
                
                
                (2,022
                )
                
                
                538Cash
      Flow Hedges (e)
                
                
                6
                
                
                
                32
                
                
                
                -
                
                
                
                (4
                )
                
                
                34Dedesignated
      Risk Management Contracts (f)
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                39
                
                
                
                39Total
      Risk Management Assets
                
                
                67
                
                
                
                2,445
                
                
                
                86
                
                
                
                (1,987
                )
                
                
                611Spent
      Nuclear Fuel and Decommissioning TrustsCash
      and Cash Equivalents (g)
                
                
                -
                
                
                
                6
                
                
                
                -
                
                
                
                12
                
                
                
                18Debt
      Securities (h)
                
                
                -
                
                
                
                773
                
                
                
                -
                
                
                
                -
                
                
                
                773Equity
      Securities (d)
                
                
                469
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                469Total Spent Nuclear Fuel and
      Decommissioning Trusts
                
                
                469
                
                
                
                779
                
                
                
                -
                
                
                
                12
                
                
                
                1,260Total
      Assets
                
                $
                1,141
                
                
                $
                3,271
                
                
                $
                86
                
                
                $
                (1,889
                )
                
                $
                2,609Liabilities:Risk
      Management LiabilitiesRisk
      Management Contracts (e)
                
                $
                77
                
                
                $
                2,213
                
                
                $
                37
                
                
                $
                (2,054
                )
                
                $
                273Cash
      Flow Hedges (e)
                
                
                1
                
                
                
                34
                
                
                
                -
                
                
                
                (4
                )
                
                
                31Total
      Risk Management Liabilities
                
                $
                78
                
                
                $
                2,247
                
                
                $
                37
                
                
                $
                (2,058
                )
                
                $
                304





(a)
            Amounts
      in “Other” column primarily represent cash deposits in bank accounts with
      financial institutions or with third parties.  Level 1 amounts
      primarily represent investments in money market funds.(b)
            Amount
      represents commercial paper investments with maturities of less than
      ninety days.(c)
            Amounts
      represent debt-based mutual funds.(d)
            Amount
      represents publicly traded equity securities and equity-based mutual
      funds.(e)
            Amounts
      in “Other” column primarily represent counterparty netting of risk
      management contracts and associated cash collateral under FSP FIN
      39-1.(f)
            “Dedesignated
      Risk Management Contracts” are contracts that were originally MTM but were
      subsequently elected as normal under SFAS 133.  At the time of
      the normal election, the MTM value was frozen and no longer fair
      valued.  This MTM value will be amortized into Utility
      Operations Revenues over the remaining life of the
    contracts.(g)
            Amounts
      in “Other” column primarily represent accrued interest receivables from
      financial institutions.  Level 2 amounts primarily represent
      investments in money market funds.(h)
            Amounts
      represent corporate, municipal and treasury
  bonds.


The
following tables set forth a reconciliation of changes in the fair value of net
trading derivatives and other investments classified as level 3 in the fair
value hierarchy:





Three
      Months Ended March 31, 2009
                
                Net
      Risk Management Assets (Liabilities)
                
                
                Other
      Temporary Investments
                
                
                Investments
      in Debt Securities(in
      millions)Balance
      as of January 1, 2009
                
                $
                49
                
                
                $
                -
                
                
                $
                -Realized
      (Gain) Loss Included in Net Income (or Changes in Net
    Assets)
                
                
                (12
                )
                
                
                -
                
                
                
                -Unrealized
      Gain (Loss) Included in Net Income (or Changes in Net
      Assets) Relating to Assets Still Held at the Reporting Date
      (a)
                
                
                59
                
                
                
                -
                
                
                
                -Realized
      and Unrealized Gains (Losses) Included in Other
      Comprehensive Income
                
                
                -
                
                
                
                -
                
                
                
                -Purchases,
      Issuances and Settlements (b)
                
                
                -
                
                
                
                -
                
                
                
                -Transfers
      in and/or out of Level 3 (c)
                
                
                (25
                )
                
                
                -
                
                
                
                -Changes
      in Fair Value Allocated to Regulated Jurisdictions (d)
                
                
                15
                
                
                
                -
                
                
                
                -Balance
      as of March 31, 2009
                
                $
                86
                
                
                $
                -
                
                
                $
                -





Three
      Months Ended March 31, 2008
                
                Net
      Risk Management Assets (Liabilities)
                
                
                Other
      Temporary Investments
                
                
                Investments
      in Debt Securities(in
      millions)Balance
      as of January 1, 2008
                
                $
                49
                
                
                $
                -
                
                
                $
                -Realized
      (Gain) Loss Included in Net Income (or Changes in Net
    Assets)
                
                
                (3
                )
                
                
                -
                
                
                
                -Unrealized
      Gain (Loss) Included in Net Income (or Changes in Net
      Assets) Relating to Assets Still Held at the Reporting Date
      (a)
                
                
                5
                
                
                
                -
                
                
                
                -Realized
      and Unrealized Gains (Losses) Included in Other
      Comprehensive Income
                
                
                -
                
                
                
                -
                
                
                
                -Purchases,
      Issuances and Settlements (b)
                
                
                -
                
                
                
                (96
                )
                
                
                -Transfers
      in and/or out of Level 3 (c)
                
                
                (5
                )
                
                
                118
                
                
                
                17Changes
      in Fair Value Allocated to Regulated Jurisdictions (d)
                
                
                3
                
                
                
                -
                
                
                
                -Balance
      as of March 31, 2008
                
                $
                49
                
                
                $
                22
                
                
                $
                17




(a)
            Included
      in revenues on our Condensed Consolidated Statements of
      Income.(b)
            Includes
      principal amount of securities settled during the
  period.(c)
            “Transfers
      in and/or out of Level 3” represent existing assets or liabilities that
      were either previously categorized as a higher level for which the inputs
      to the model became unobservable or assets and liabilities that were
      previously classified as level 3 for which the lowest significant input
      became observable during the period.(d)
            “Changes
      in Fair Value Allocated to Regulated Jurisdictions” relates to the net
      gains (losses) of those contracts that are not reflected on the Condensed
      Consolidated Statements of Income.  These net gains (losses) are
      recorded as regulatory
liabilities/assets.





8.     INCOME
      TAXES





We are no
longer subject to U.S. federal examination for years before 2000.  We
have completed the exam for the years 2001 through 2006 and have issues that we
are pursuing at the appeals level.  Although the outcome of tax audits
is uncertain, in management’s opinion, adequate provisions for income taxes have
been made for potential liabilities resulting from such matters.  In
addition, we accrue interest on these uncertain tax positions.  We are
not aware of any issues for open tax years that upon final resolution are
expected to have a material adverse effect on net income.





9.   FINANCING
      ACTIVITIES





Common
Stock





In April
2009, we issued 69 million shares of common stock at $24.50 per share for net
proceeds of $1.64 billion.  We used $1.25 billion of the proceeds to
repay part of the cash drawn under our credit facilities.





Long-term
Debt


March
      31,
                    
                    
                    December
      31,Type
      of Debt
                    
                    2009
                    
                    
                    2008(in
      millions)Senior
      Unsecured Notes
                    
                    $
                    11,890
                    
                    
                    $
                    11,069Pollution
      Control Bonds
                    
                    
                    2,080
                    
                    
                    
                    1,946Notes
      Payable
                    
                    
                    224
                    
                    
                    
                    233Securitization
      Bonds
                    
                    
                    2,051
                    
                    
                    
                    2,132Junior
      Subordinated Debentures
                    
                    
                    315
                    
                    
                    
                    315Spent
      Nuclear Fuel Obligation (a)
                    
                    
                    264
                    
                    
                    
                    264Other
      Long-term Debt
                    
                    
                    88
                    
                    
                    
                    88Unamortized
      Discount (net)
                    
                    
                    (69
                    )
                    
                    
                    (64
                    )Total
      Long-term Debt Outstanding
                    
                    
                    16,843
                    
                    
                    
                    15,983Less
      Portion Due Within One Year
                    
                    
                    939
                    
                    
                    
                    447Long-term
      Portion
                    
                    $
                    15,904
                    
                    
                    $
                    15,536





(a)
            Pursuant
      to the Nuclear Waste Policy Act of 1982, I&M (a nuclear licensee) has
      an obligation to 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.  Trust fund assets
      related to this obligation of $304 million and $301 million at March 31,
      2009 and December 31, 2008, respectively, are included in Spent Nuclear
      Fuel and Decommissioning Trusts on our Condensed Consolidated Balance
      Sheets.





Long-term
debt and other securities issued, retired and principal payments made during the
first three months of 2009 are shown in the tables below.




Company
                              
                              Type
      of Debt
                              
                              Principal
      Amount
                              
                              Interest
      Rate
                              
                              Due
      Date(in
      millions)
                              
                              (%)Issuances:APCo
                              
                              Senior
      Unsecured Notes
                              
                              $
                              350
                              
                              7.95
                              
                              2020I&M
                              
                              Senior
      Unsecured Notes
                              
                              
                              475
                              
                              7.00
                              
                              2019I&M
                              
                              Pollution
      Control Bonds
                              
                              
                              50
                              
                              6.25
                              
                              2025I&M
                              
                              Pollution
      Control Bonds
                              
                              
                              50
                              
                              6.25
                              
                              2025PSO
                              
                              Pollution
      Control Bonds
                              
                              
                              34
                              
                              5.25
                              
                              2014Total
      Issuances
                              
                              
                              
                              $
                              959
                              (a)




The
above borrowing arrangements do not contain guarantees, collateral or dividend
restrictions.





(a)
              Amount
      indicated on statement of cash flows of $947 million is net of issuance
      costs and premium or
discount.





Company
                      
                      Type
      of Debt
                      
                      Principal
                        Amount
      Paid
                      
                      Interest
      Rate
                      
                      Due
      Date(in
      millions)
                      
                      (%)Retirements
      and Principal Payments:OPCo
                      
                      Notes
      Payable
                      
                      $
                      1
                      
                      6.27
                      
                      2009OPCo
                      
                      Notes
      Payable
                      
                      
                      4
                      
                      7.21
                      
                      2009SWEPCo
                      
                      Notes
      Payable
                      
                      
                      1
                      
                      4.47
                      
                      2011Non-Registrant:AEP
      Subsidiaries
                      
                      Notes
      Payable
                      
                      
                      3
                      
                      Variable
                      
                      2017AEGCo
                      
                      Senior
      Unsecured Notes
                      
                      
                      4
                      
                      6.33
                      
                      2037TCC
                      
                      Securitization
      Bonds
                      
                      
                      31
                      
                      5.56
                      
                      2010TCC
                      
                      Securitization
      Bonds
                      
                      
                      50
                      
                      4.98
                      
                      2010Total
      Retirements and   Principal Payments
                      
                      
                      
                      $
                      94





During
2008, we chose to begin eliminating our auction-rate debt position due to market
conditions.  As of March 31, 2009, $272 million of our auction-rate
tax-exempt long-term debt, with rates ranging between 1.676% and 13%, remained
outstanding with rates reset every 35 days.  The instruments under
which the bonds are issued allow us to convert to other short-term variable-rate
structures, term-put structures and fixed-rate
structures.  Approximately $218 million of the $272 million of
outstanding auction-rate debt relates to a lease structure with JMG that we are
unable to refinance without their consent.  The rates for this debt
are at contractual maximum rate of 13%.  The initial term for the JMG
lease structure matures on March 31, 2010.  We are evaluating whether
to terminate this facility prior to maturity.  Termination of this
facility requires approval from the PUCO.





During
the first quarter of 2009, we issued $134 million of Pollution Control Bonds
which were previously held by trustees on our behalf.  As of March 31,
2009, trustees held, on our behalf, $195 million of our remaining reacquired
auction-rate tax-exempt long-term debt which we plan to reissue to the public as
market conditions permit.





Dividend
Restrictions





We have
the option to defer interest payments on the AEP Junior Subordinated Debentures
issued in March 2008 for one or more periods of up to 10 consecutive years per
period.  During any period in which we defer interest payments, we may
not declare or pay any dividends or distributions on, or redeem, repurchase or
acquire, our common stock.  We believe that these restrictions will
not have a material effect on our net income, cash flows, financial condition or
limit any dividend payments in the foreseeable future.





Short-term
Debt





Our
outstanding short-term debt is as follows:


March
      31, 2009
                    
                    
                    December
      31, 2008Outstanding
                      Amount
                    
                    Interest
                      Rate
      (a)
                    
                    
                    Outstanding
                      Amount
                    
                    Interest
                      Rate
      (a)Type
      of Debt
                    
                    (in
      thousands)
                    
                    
                    
                    
                    (in
      thousands)Line
      of Credit – AEP
                    
                    $
                    1,969,000
                    (b)
                    1.22%
                    (c)
                    
                    $
                    1,969,000
                    
                    2.28%
                    (c)Line
      of Credit – Sabine Mining Company (d)
                    
                    
                    6,559
                    
                    1.82%
                    
                    
                    
                    7,172
                    
                    1.54%Total
                    
                    $
                    1,975,559
                    
                    
                    
                    
                    $
                    1,976,172





(a)
            Weighted
      average rate.(b)
            Paid
      $1.25 billion with proceeds from the equity issuance in April
      2009.(c)
            Rate
      based on LIBOR.(d)
            Sabine
      Mining Company is consolidated under FIN 46R.  This line of
      credit does not reduce available liquidity under AEP’s credit
      facilities.





Credit
Facilities





As of
March 31, 2009, we have credit facilities totaling $3 billion to support our
commercial paper program which were reduced by Lehman Brothers Holdings Inc.’s
commitment amount of $46 million following its bankruptcy.  The
facilities are structured as two $1.5 billion credit facilities of which $750
million may be issued under each credit facility as letters of
credit.





We have a
$650 million 3-year credit agreement and a $350 million 364-day credit agreement
which were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $23
million and $12 million, respectively, following its
bankruptcy.  Under the facilities, we may issue letters of
credit.  As of March 31, 2009, $372 million of letters of credit were
issued by subsidiaries under the $650 million 3-year agreement to support
variable rate Pollution Control Bonds.  In April 2009, the $350
million 364-day credit agreement expired.







APPALACHIAN
POWER COMPANY
 AND
SUBSIDIARIES
 
  
 APPALACHIAN POWER COMPANY AND SUBSIDIARIES
 MANAGEMENT’S FINANCIAL
DISCUSSION AND ANALYSIS
 
 
 Results of
      Operations
 
 First Quarter of 2009
Compared to First Quarter of 2008
 
 Reconciliation
of First Quarter of 2008 to First Quarter of 2009
 Net
Income
 (in
millions)
 
 First
      Quarter of 2008
                            
                            
                            
                            
                            $
                            55Changes
      in Gross Margin:Retail
      Margins
                            
                            
                            87Off-system
      Sales
                            
                            
                            (47
                            )Other
                            
                            
                            1Total
      Change in Gross Margin
                            
                            
                            
                            
                            
                            
                            41Changes
      in Operating Expenses and Other:Other
      Operation and Maintenance
                            
                            
                            12Depreciation
      and Amortization
                            
                            
                            (7
                            )Carrying
      Costs Income
                            
                            
                            (6
                            )Other
      Income
                            
                            
                            (1
                            )Interest
      Expense
                            
                            
                            (6
                            )Total
      Change in Operating Expenses and Other
                            
                            
                            
                            
                            
                            
                            (8
                            )Income
      Tax Expense
                            
                            
                            
                            
                            
                            
                            (14
                            )First
      Quarter of 2009
                            
                            
                            
                            
                            
                            $
                            74
 
 Net
Income increased $19 million to $74 million in 2009.  The key drivers
of the increase were a $41 million increase in Gross Margin, partially offset by
a $14 million increase in Income Tax Expense and an $8 million increase in
Operating Expenses and Other.
 
 The major
components of the increase in Gross Margin, defined as revenues less the related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power were as follows:
 
 ·
              Retail
      Margins increased $87 million primarily due to the
    following:·
              A
      $49 million increase in rate relief primarily due to the impact of the
      Virginia base rate order issued in October 2008, an increase in the
      recovery of E&R costs in Virginia and an increase in the recovery of
      construction financing costs in West Virginia.·
              A
      $39 million increase due to a decrease in sharing of off-system sales
      margins with customers in Virginia and West Virginia.·
              A
      $7 million increase due to new rates effective January 2009 for a power
      supply contract with KGPCo.·
              A
      $3 million increase in residential and commercial revenue primarily due to
      increased usage resulting from a 5% increase in heating degree
      days.These
      increases were partially offset by:·
              A
      $14 million decrease due to higher capacity settlement expenses under the
      Interconnection Agreement net of recovery in West Virginia and
      environmental deferrals in Virginia.·
              Margins
      from Off-system Sales decreased $47 million primarily due to lower
      physical sales volumes and lower margins as a result of lower market
      prices, partially offset by higher trading margins.
  Operating
Expenses and Other and Income Tax Expense changed between years as
follows:
 
 ·
              Other
      Operation and Maintenance expenses decreased $12 million primarily due to
      lower employee-related expenses and generation plant
      maintenance.·
              Depreciation
      and Amortization expenses increased $7 million primarily due to a greater
      depreciation base resulting from asset improvements and the amortization
      of carrying charges and depreciation expenses that are being collected
      through the Virginia E&R surcharges.·
              Carrying
      Costs Income decreased $6 million due to the completion of reliability
      deferrals in Virginia in December 2008 and the decrease of environmental
      deferrals in Virginia in 2009.·
              Interest
      Expense increased $6 million primarily due to an increase in long-term
      debt issuances.·
              Income
      Tax Expense increased $14 million primarily due to an increase in pretax
      book income, partially offset by state income tax adjustments recorded in
      2008.
 
 Financial
Condition
 
 Credit
Ratings
 
 APCo’s
credit ratings as of March 31, 2009 were as follows:
 
 Moody’s
                
                S&P
                
                FitchSenior
      Unsecured Debt
                Baa2
                
                BBB
                
                BBB+
 
 S&P
has APCo on stable outlook, while Fitch has APCo on negative
outlook.  In February 2009, Moody’s changed its rating outlook for
APCo from negative to stable due to recent rate recoveries in Virginia and West
Virginia.  If APCo receives a downgrade from any of the rating
agencies, its borrowing costs could increase and access to borrowed funds could
be negatively affected.
 
 Cash
Flow
 
 Cash
flows for the three months ended March 31, 2009 and 2008 were as
follows:
 2009
                      
                      
                      2008(in
      thousands)Cash
      and Cash Equivalents at Beginning of Period
                      
                      $
                      1,996
                      
                      
                      $
                      2,195Cash
      Flows from (Used for):Operating
      Activities
                      
                      
                      (29,207
                      )
                      
                      
                      118,832Investing
      Activities
                      
                      
                      (220,590
                      )
                      
                      
                      (409,179
                      )Financing
      Activities
                      
                      
                      250,355
                      
                      
                      
                      290,804Net
      Increase in Cash and Cash Equivalents
                      
                      
                      558
                      
                      
                      
                      457Cash
      and Cash Equivalents at End of Period
                      
                      $
                      2,554
                      
                      
                      $
                      2,652
 
 Operating
Activities
 
 Net Cash
Flows Used for Operating Activities were $29 million in 2009.  APCo
produced Net Income of $74 million during the period and had noncash expense
items of $70 million for Depreciation and Amortization and $80 million for
Deferred Income 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 $116 million cash outflow from Accounts Payable was
primarily due to APCo’s provision for revenue refund of $77 million which was
paid in the first quarter 2009 to the AEP West companies as part of the FERC’s
recent order on the SIA.  The $71 million change in Fuel
Over/Under-Recovery, Net resulted in a net under-recovery of fuel cost in both
Virginia and West Virginia.
 
 Net Cash
Flows from Operating Activities were $119 million in 2008.  APCo
produced Net Income of $55 million during the period and a noncash expense item
of $63 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
relates to a number of items.  The $32 million cash inflow from
Accounts Receivable, Net was primarily due to a settlement of allowance sales to
affiliated companies.  The $20 million cash inflow from Fuel,
Materials and Supplies was primarily due to a reduction in fuel inventory to
reflect planned outages.  The $27 million change in Fuel
Over/Under-Recovery, Net resulted in a net under-recovery of fuel cost in both
Virginia and West Virginia.
 
 Investing
Activities
 
 Net Cash
Flows Used for Investing Activities during 2009 and 2008 were $221 million and
$409 million, respectively.  Construction Expenditures were $221
million and $159 million in 2009 and 2008, respectively, primarily related to
transmission and distribution service reliability projects, as well as
environmental upgrades for both periods.  Environmental upgrades
include the installation of selective catalytic reduction equipment on APCo’s
plants and flue gas desulfurization projects at the Amos and Mountaineer
Plants.  APCo’s investments in the Utility Money Pool increased by
$262 million in 2008.  APCo forecasts approximately $368 million of
construction expenditures for all of 2009, excluding AFUDC.
 
 Financing
Activities
 
 Net Cash
Flows from Financing Activities were $250 million in 2009.  APCo
issued $350 million of Senior Unsecured Notes in March 2009.  APCo had
a net decrease of $74 million in borrowings from the Utility Money
Pool.
 
 Net Cash
Flows from Financing Activities were $291 million in 2008.  APCo
received capital contributions from the Parent of $75 million.  APCo
issued $500 million of Senior Unsecured Notes in March 2008.  APCo had
a net decrease of $275 million in borrowings from the Utility Money
Pool.
 
 Financing
Activity
 
 Long-term
debt issuances and principal payments made during the first three months of 2009
were:
 
 Issuances
 Principal
                      Amount
                    
                    Interest
                    
                    DueType
      of Debt
                    
                    
                    Rate
                    
                    Date(in
      thousands)
                    
                    (%)Senior
      Unsecured Debt
                    
                    $
                    350,000
                    
                    7.95
                    
                    2020
 
 Principal
Payments
 Principal
                    Amount
      Paid
                  
                  Interest
                  
                  DueType
      of Debt
                  
                  
                  Rate
                  
                  Date(in
      thousands)
                  
                  (%)Land
      Note
                  
                  $
                  4
                  
                  13.718
                  
                  2026
 
 Liquidity
 
 The
financial markets remain volatile at both a global and domestic
level.  This marketplace distress could impact APCo’s access to
capital, liquidity and cost of capital.  The uncertainties in the
capital markets could have significant implications on APCo since it relies on
continuing access to capital to fund operations and capital
expenditures.  Management cannot predict the length of time the credit
situation will continue or its impact on APCo’s operations and ability to issue
debt at reasonable interest rates.
 
 APCo
participates in the Utility Money Pool, which provides access to AEP’s
liquidity.  APCo has $150 million of Senior Unsecured Notes that will
mature in May 2009.  APCo issued $350 million of Senior Unsecured
Notes in March 2009 that will be used to pay down its maturity.  APCo
will rely upon cash flows from operations and access to the Utility Money Pool
to fund current operations and capital expenditures.
 
 See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for additional discussion of liquidity.
 
 Summary Obligation
Information
 
 A summary
of contractual obligations is included in the 2008 Annual Report and has not
changed significantly from year-end other than the debt issuances discussed in
“Cash Flow” and “Financing Activity” above.
 
 Significant
Factors
 
 Litigation
and Regulatory Activity
 
 In the
ordinary course of business, APCo is involved in employment, commercial,
environmental and regulatory litigation.  Since it is difficult to
predict the outcome of these proceedings, management cannot state what the
eventual outcome of these proceedings will be, or what the timing of the amount
of any loss, fine or penalty may be.  Management does, however, assess
the probability of loss for such contingencies and accrues a liability for cases
which have a probable likelihood of loss and the loss amount can be
estimated.  For details on regulatory proceedings and pending
litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and
Contingencies in the 2008 Annual Report.  Also, see Note 3 – Rate
Matters and Note 4 – Commitments, Guarantees and Contingencies in the “Condensed
Notes to Condensed Financial Statements of Registrant Subsidiaries”
section.  Adverse results in these proceedings have the potential to
materially affect net income, financial condition and cash flows.
 
 See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for additional discussion of relevant factors.
 
 Critical Accounting
Estimates
 
 See the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in the 2008 Annual Report for a discussion
of the estimates and judgments required for regulatory accounting, revenue
recognition, the valuation of long-lived assets, pension and other
postretirement benefits and the impact of new accounting
pronouncements.
 
 Adoption of New Accounting
Pronouncements
 
 See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for a discussion of adoption of new accounting
pronouncements.
  
 QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
 
 Market
Risks
 
 Risk
management assets and liabilities are managed by AEPSC as agent.  The
related risk management policies and procedures are instituted and administered
by AEPSC.  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 APCo.
 
 MTM
Risk Management Contract Net Assets
 
 The
following two tables summarize the various mark-to-market (MTM) positions
included in APCo’s Condensed Consolidated Balance Sheet as of March 31, 2009 and
the reasons for changes in total MTM value as compared to December 31,
2008.
 
 Reconciliation
of MTM Risk Management Contracts to
 Condensed
Consolidated Balance Sheet
 March
31, 2009
 (in
thousands)
 
 MTM
      Risk
                  
                  
                  Cash
      Flow
                  
                  
                  DETMManagement
                  
                  
                  Hedge
                  
                  
                  Assignment
                  
                  
                  CollateralContracts
                  
                  
                  Contracts
                  
                  
                  (a)
                  
                  
                  Deposits
                  
                  
                  TotalCurrent
      Assets
                  
                  $
                  80,340
                  
                  
                  $
                  6,570
                  
                  
                  $
                  -
                  
                  
                  $
                  (11,715
                  )
                  
                  $
                  75,195Noncurrent
      Assets
                  
                  
                  77,857
                  
                  
                  
                  237
                  
                  
                  
                  -
                  
                  
                  
                  (13,323
                  )
                  
                  
                  64,771Total
      MTM Derivative Contract Assets
                  
                  
                  158,197
                  
                  
                  
                  6,807
                  
                  
                  
                  -
                  
                  
                  
                  (25,038
                  )
                  
                  
                  139,966Current
      Liabilities
                  
                  
                  (47,628
                  )
                  
                  
                  (518
                  )
                  
                  
                  (2,697
                  )
                  
                  
                  11,751
                  
                  
                  
                  (39,092
                  )Noncurrent
      Liabilities
                  
                  
                  (52,445
                  )
                  
                  
                  (41
                  )
                  
                  
                  (1,830
                  )
                  
                  
                  24,261
                  
                  
                  
                  (30,055
                  )Total
      MTM Derivative Contract Liabilities
                  
                  
                  (100,073
                  )
                  
                  
                  (559
                  )
                  
                  
                  (4,527
                  )
                  
                  
                  36,012
                  
                  
                  
                  (69,147
                  )Total
      MTM Derivative Contract Net Assets (Liabilities)
                  
                  $
                  58,124
                  
                  
                  $
                  6,248
                  
                  
                  $
                  (4,527
                  )
                  
                  $
                  10,974
                  
                  
                  $
                  70,819
 
 (a)
              See
      “Natural Gas Contracts with DETM” section of Note 15 of the 2008 Annual
      Report.
 
 MTM
Risk Management Contract Net Assets
 Three
Months Ended March 31, 2009
 (in
thousands)
  Total
      MTM Risk Management Contract Net Assets at December 31,
    2008
                  
                  $
                  56,936(Gain)
      Loss from Contracts Realized/Settled During the Period and Entered in a
      Prior Period
                  
                  
                  (9,387
                  )Fair
      Value of New Contracts at Inception When Entered During the Period
      (a)
                  
                  
                  -Net
      Option Premiums Paid/(Received) for Unexercised or Unexpired Option
      Contracts Entered During the Period
                  
                  
                  (113
                  )Change
      in Fair Value Due to Valuation Methodology Changes on Forward
      Contracts
                  
                  
                  -Changes
      in Fair Value Due to Market Fluctuations During the Period
    (b)
                  
                  
                  (339
                  )Changes
      in Fair Value Allocated to Regulated Jurisdictions (c)
                  
                  
                  11,027Total
      MTM Risk Management Contract Net Assets
                  
                  
                  58,124Cash
      Flow Hedge Contracts
                  
                  
                  6,248DETM
      Assignment (d)
                  
                  
                  (4,527
                  )Collateral
      Deposits
                  
                  
                  10,974Ending
      Net Risk Management Assets at March 31, 2009
                  
                  $
                  70,819
 
 (a)
              Reflects
      fair value on long-term contracts which are typically with customers that
      seek fixed pricing to limit their risk against fluctuating energy
      prices.  The contract prices are valued against market curves
      associated with the delivery location and delivery term.  A
      significant portion of the total volumetric position has been economically
      hedged.(b)
              Market
      fluctuations are attributable to various factors such as supply/demand,
      weather, etc.(c)
              “Changes
      in Fair Value Allocated to Regulated Jurisdictions” relates to the net
      gains (losses) of those contracts that are not reflected in the Condensed
      Consolidated Statements of Income.  These net gains (losses) are
      recorded as regulatory liabilities/assets.(d)
              See
      “Natural Gas Contracts with DETM” section of Note 15 of the 2008 Annual
      Report.
 
 Maturity
and Source of Fair Value of MTM Risk Management Contract Net Assets
 
 The
following table presents the maturity, by year, of net assets/liabilities to
give 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, 2009
 (in
thousands)
 
 Remainder
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    After2009
                    
                    
                    2010
                    
                    
                    2011
                    
                    
                    2012
                    
                    
                    2013
                    
                    
                    2013
                    
                    
                    TotalLevel
      1 (a)
                    
                    $
                    (1,815
                    )
                    
                    $
                    (47
                    )
                    
                    $
                    1
                    
                    
                    $
                    -
                    
                    
                    $
                    -
                    
                    
                    $
                    -
                    
                    
                    $
                    (1,861
                    )Level
      2 (b)
                    
                    
                    19,116
                    
                    
                    
                    10,941
                    
                    
                    
                    6,365
                    
                    
                    
                    (511
                    )
                    
                    
                    38
                    
                    
                    
                    -
                    
                    
                    
                    35,949Level
      3 (c)
                    
                    
                    5,508
                    
                    
                    
                    2,773
                    
                    
                    
                    1,679
                    
                    
                    
                    1,668
                    
                    
                    
                    219
                    
                    
                    
                    -
                    
                    
                    
                    11,847Total
                    
                    
                    22,809
                    
                    
                    
                    13,667
                    
                    
                    
                    8,045
                    
                    
                    
                    1,157
                    
                    
                    
                    257
                    
                    
                    
                    -
                    
                    
                    
                    45,935Dedesignated
      Risk Management Contracts (d)
                    
                    
                    3,739
                    
                    
                    
                    4,862
                    
                    
                    
                    1,894
                    
                    
                    
                    1,694
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    12,189Total
      MTM Risk Management Contract Net Assets
                    
                    $
                    26,548
                    
                    
                    $
                    18,529
                    
                    
                    $
                    9,939
                    
                    
                    $
                    2,851
                    
                    
                    $
                    257
                    
                    
                    $
                    -
                    
                    
                    $
                    58,124
 
 (a)
              Level
      1 inputs are quoted prices (unadjusted) in active markets for identical
      assets or liabilities that the reporting entity has the ability to access
      at the measurement date.  Level 1 inputs primarily consist of
      exchange traded contracts that exhibit sufficient frequency and volume to
      provide pricing information on an ongoing basis.(b)
              Level
      2 inputs are inputs other than quoted prices included within Level 1 that
      are observable for the asset or liability, either directly or
      indirectly.  If the asset or liability has a specified
      (contractual) term, a Level 2 input must be observable for substantially
      the full term of the asset or liability.  Level 2 inputs
      primarily consist of OTC broker quotes in moderately active or less active
      markets, exchange traded contracts where there was not sufficient market
      activity to warrant inclusion in Level 1 and OTC broker quotes that are
      corroborated by the same or similar transactions that have occurred in the
      market.(c)
              Level
      3 inputs are unobservable inputs for the asset or
      liability.  Unobservable inputs shall be used to measure fair
      value to the extent that the observable inputs are not available, thereby
      allowing for situations in which there is little, if any, market activity
      for the asset or liability at the measurement date.  Level 3
      inputs primarily consist of unobservable market data or are valued based
      on models and/or assumptions.(d)
              Dedesignated
      Risk Management Contracts are contracts that were originally MTM but were
      subsequently elected as normal under SFAS 133.  At the time of
      the normal election, the MTM value was frozen and no longer fair
      valued.  This will be amortized into Revenues over the remaining
      life of the contracts.
 
 Credit
Risk
 
 Counterparty
credit quality and exposure is generally consistent with that of
AEP.
 
 See Note
7 for further information regarding MTM risk management contracts, cash flow
hedging, accumulated other comprehensive income, credit risk and collateral
triggering events.
 
 VaR
Associated with Risk Management Contracts
 
 Management
uses a risk measurement model, which calculates Value at Risk (VaR) to measure
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, 2009, a near
term typical change in commodity prices is not expected to have a material
effect on net income, cash flows or financial condition.
  The
following table shows the end, high, average, and low market risk as measured by
VaR for the periods indicated:
 
 Three
      Months Ended
              
              
              
              
              Twelve
      Months EndedMarch
      31, 2009
              
              
              
              
              December
      31, 2008(in
      thousands)
              
              
              
              
              (in
      thousands)End
              
              High
              
              Average
              
              Low
              
              
              
              
              End
              
              High
              
              Average
              
              Low$297
              
              $546
              
              $306
              
              $151
              
              
              
              
              $176
              
              $1,096
              
              $396
              
              $161
 
 Management
back-tests its VaR results against performance due to actual price
moves.  Based on the assumed 95% confidence interval, the performance
due to actual price moves would be expected to exceed the VaR at least once
every 20 trading days.  Management’s backtesting results show that its
actual performance exceeded VaR far fewer than once every 20 trading
days.  As a result, management believes APCo’s VaR calculation is
conservative.
 
 As APCo’s
VaR calculation captures recent price moves, management also performs regular
stress testing of the portfolio to understand APCo’s exposure to extreme price
moves.  Management employs a historical-based method whereby the
current portfolio is subjected to actual, observed price moves from the last
three years in order to ascertain which historical price moves translated into
the largest potential MTM loss.  Management then researches the
underlying positions, price moves and market events that created the most
significant exposure.
 
 Interest
Rate Risk
 
 Management
utilizes an Earnings at Risk (EaR) model to measure interest rate market risk
exposure. EaR statistically quantifies the extent to which APCo’s interest
expense could vary over the next twelve months and gives a probabilistic
estimate of different levels of interest expense.  The resulting EaR
is interpreted as the dollar amount by which actual interest expense for the
next twelve months could exceed expected interest expense with a one-in-twenty
chance of occurrence.  The primary drivers of EaR are from the
existing floating rate debt (including short-term debt) as well as long-term
debt issuances in the next twelve months.  The estimated EaR on APCo’s
debt portfolio was $7.8 million.
 
 APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
 CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
 For
the Three Months Ended March 31, 2009 and 2008
 (in
thousands)
 (Unaudited)
 2009
                  
                  
                  2008REVENUESElectric
      Generation, Transmission and Distribution
                  
                  $
                  727,959
                  
                  
                  $
                  641,457Sales
      to AEP Affiliates
                  
                  
                  56,231
                  
                  
                  
                  90,090Other
                  
                  
                  1,839
                  
                  
                  
                  3,480TOTAL
                  
                  
                  786,029
                  
                  
                  
                  735,027EXPENSESFuel
      and Other Consumables Used for Electric Generation
                  
                  
                  143,681
                  
                  
                  
                  173,830Purchased
      Electricity for Resale
                  
                  
                  75,816
                  
                  
                  
                  43,199Purchased
      Electricity from AEP Affiliates
                  
                  
                  197,124
                  
                  
                  
                  189,595Other
      Operation
                  
                  
                  65,502
                  
                  
                  
                  75,531Maintenance
                  
                  
                  55,910
                  
                  
                  
                  57,844Depreciation
      and Amortization
                  
                  
                  69,995
                  
                  
                  
                  62,572Taxes
      Other Than Income Taxes
                  
                  
                  24,103
                  
                  
                  
                  23,991TOTAL
                  
                  
                  632,131
                  
                  
                  
                  626,562OPERATING
      INCOME
                  
                  
                  153,898
                  
                  
                  
                  108,465Other
      Income (Expense):Interest
      Income
                  
                  
                  382
                  
                  
                  
                  2,769Carrying
      Costs Income
                  
                  
                  4,083
                  
                  
                  
                  9,586Allowance
      for Equity Funds Used During Construction
                  
                  
                  2,653
                  
                  
                  
                  1,496Interest
      Expense
                  
                  
                  (49,705
                  )
                  
                  
                  (44,140
                  )INCOME
      BEFORE INCOME TAX EXPENSE
                  
                  
                  111,311
                  
                  
                  
                  78,176Income
      Tax Expense
                  
                  
                  36,904
                  
                  
                  
                  22,863NET
      INCOME
                  
                  
                  74,407
                  
                  
                  
                  55,313Preferred
      Stock Dividend Requirements Including Capital StockExpense
                  
                  
                  225
                  
                  
                  
                  238EARNINGS
      ATTRIBUTABLE TO COMMON STOCK
                  
                  $
                  74,182
                  
                  
                  $
                  55,075
 
 The
      common stock of APCo is wholly-owned by
AEP.
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
 
 
 APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
 CONDENSED
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
 EQUITY
AND COMPREHENSIVE INCOME (LOSS)
 For
the Three Months Ended March 31, 2009 and 2008
 (in
thousands)
 (Unaudited)
 
 Common
      Stock
                  
                  
                  Paid-in
      Capital
                  
                  
                  Retained
      Earnings
                  
                  
                  Accumulated
                    Other
                    Comprehensive
                    Income
      (Loss)
                  
                  
                  TotalDECEMBER
      31, 2007
                  
                  $
                  260,458
                  
                  
                  $
                  1,025,149
                  
                  
                  $
                  831,612
                  
                  
                  $
                  (35,187
                  )
                  
                  $
                  2,082,032EITF
      06-10 Adoption, Net of Tax of $1,175
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  (2,181
                  )
                  
                  
                  
                  
                  
                  
                  (2,181
                  )SFAS
      157 Adoption, Net of Tax of $154
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  (286
                  )
                  
                  
                  
                  
                  
                  
                  (286
                  )Capital
      Contribution from Parent
                  
                  
                  
                  
                  
                  
                  75,000
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  75,000Preferred
      Stock Dividends
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  (200
                  )
                  
                  
                  
                  
                  
                  
                  (200
                  )Capital
      Stock Expense
                  
                  
                  
                  
                  
                  
                  39
                  
                  
                  
                  (38
                  )
                  
                  
                  
                  
                  
                  
                  1TOTAL
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  2,154,366COMPREHENSIVE
      INCOMEOther
      Comprehensive Income (Loss), Net of Taxes:Cash
      Flow Hedges, Net of Taxof
      $7,438
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  (13,813
                  )
                  
                  
                  (13,813
                  )Amortization
      of Pension and OPEB Deferred Costs, Net of Tax of
$449
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  833
                  
                  
                  
                  833NET
      INCOME
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  55,313
                  
                  
                  
                  
                  
                  
                  
                  55,313TOTAL
      COMPREHENSIVE INCOME
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  42,333MARCH
      31, 2008
                  
                  $
                  260,458
                  
                  
                  $
                  1,100,188
                  
                  
                  $
                  884,220
                  
                  
                  $
                  (48,167
                  )
                  
                  $
                  2,196,699DECEMBER
      31, 2008
                  
                  $
                  260,458
                  
                  
                  $
                  1,225,292
                  
                  
                  $
                  951,066
                  
                  
                  $
                  (60,225
                  )
                  
                  $
                  2,376,591Common
      Stock Dividends
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  (20,000
                  )
                  
                  
                  
                  
                  
                  
                  (20,000
                  )Preferred
      Stock Dividends
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  (200
                  )
                  
                  
                  
                  
                  
                  
                  (200
                  )Capital
      Stock Expense
                  
                  
                  
                  
                  
                  
                  26
                  
                  
                  
                  (25
                  )
                  
                  
                  
                  
                  
                  
                  1TOTAL
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  2,356,392COMPREHENSIVE
      INCOMEOther
      Comprehensive Income, Net of Taxes:Cash
      Flow Hedges, Net of Taxof
      $945
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  1,756
                  
                  
                  
                  1,756Amortization
      of Pension and OPEB Deferred Costs, Net of Tax of $661
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  1,226
                  
                  
                  
                  1,226NET
      INCOME
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  74,407
                  
                  
                  
                  
                  
                  
                  
                  74,407TOTAL
      COMPREHENSIVE INCOME
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  77,389MARCH
      31, 2009
                  
                  $
                  260,458
                  
                  
                  $
                  1,225,318
                  
                  
                  $
                  1,005,248
                  
                  
                  $
                  (57,243
                  )
                  
                  $
                  2,433,781
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
 
 
 APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
 CONDENSED
CONSOLIDATED BALANCE SHEETS
 ASSETS
 March
31, 2009 and December 31, 2008
 (in
thousands)
 (Unaudited)
 2009
                  
                  
                  2008CURRENT
      ASSETSCash
      and Cash Equivalents
                  
                  $
                  2,554
                  
                  
                  $
                  1,996Accounts
      Receivable:Customers
                  
                  
                  158,282
                  
                  
                  
                  175,709Affiliated
      Companies
                  
                  
                  79,998
                  
                  
                  
                  110,982Accrued
      Unbilled Revenues
                  
                  
                  40,347
                  
                  
                  
                  55,733Miscellaneous
                  
                  
                  640
                  
                  
                  
                  498Allowance
      for Uncollectible Accounts
                  
                  
                  (6,566
                  )
                  
                  
                  (6,176
                  )Total
      Accounts Receivable
                  
                  
                  272,701
                  
                  
                  
                  336,746Fuel
                  
                  
                  168,257
                  
                  
                  
                  131,239Materials
      and Supplies
                  
                  
                  78,508
                  
                  
                  
                  76,260Risk
      Management Assets
                  
                  
                  75,195
                  
                  
                  
                  65,140Accrued
      Tax Benefits
                  
                  
                  55,247
                  
                  
                  
                  15,599Regulatory
      Asset for Under-Recovered Fuel Costs
                  
                  
                  236,743
                  
                  
                  
                  165,906Prepayments
      and Other
                  
                  
                  48,669
                  
                  
                  
                  45,657TOTAL
                  
                  
                  937,874
                  
                  
                  
                  838,543PROPERTY,
      PLANT AND EQUIPMENTElectric:Production
                  
                  
                  4,147,818
                  
                  
                  
                  3,708,850Transmission
                  
                  
                  1,769,947
                  
                  
                  
                  1,754,192Distribution
                  
                  
                  2,539,095
                  
                  
                  
                  2,499,974Other
                  
                  
                  355,514
                  
                  
                  
                  358,873Construction
      Work in Progress
                  
                  
                  700,084
                  
                  
                  
                  1,106,032Total
                  
                  
                  9,512,458
                  
                  
                  
                  9,427,921Accumulated
      Depreciation and Amortization
                  
                  
                  2,691,689
                  
                  
                  
                  2,675,784TOTAL
      - NET
                  
                  
                  6,820,769
                  
                  
                  
                  6,752,137OTHER
      NONCURRENT ASSETSRegulatory
      Assets
                  
                  
                  1,012,778
                  
                  
                  
                  999,061Long-term
      Risk Management Assets
                  
                  
                  64,771
                  
                  
                  
                  51,095Deferred
      Charges and Other
                  
                  
                  119,665
                  
                  
                  
                  121,828TOTAL
                  
                  
                  1,197,214
                  
                  
                  
                  1,171,984TOTAL
      ASSETS
                  
                  $
                  8,955,857
                  
                  
                  $
                  8,762,664
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
   
 APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
 CONDENSED
CONSOLIDATED BALANCE SHEETS
 LIABILITIES
AND SHAREHOLDERS’ EQUITY
 March
31, 2009 and December 31, 2008
 (Unaudited)
 2009
                      
                      
                      2008CURRENT
      LIABILITIES
                      
                      (in
      thousands)Advances
      from Affiliates
                      
                      $
                      120,481
                      
                      
                      $
                      194,888Accounts
      Payable:General
                      
                      
                      254,384
                      
                      
                      
                      358,081Affiliated
      Companies
                      
                      
                      97,749
                      
                      
                      
                      206,813Long-term
      Debt Due Within One Year – Nonaffiliated
                      
                      
                      150,017
                      
                      
                      
                      150,017Risk
      Management Liabilities
                      
                      
                      39,092
                      
                      
                      
                      30,620Customer
      Deposits
                      
                      
                      57,025
                      
                      
                      
                      54,086Deferred
      Income Taxes
                      
                      
                      107,721
                      
                      
                      
                      -Accrued
      Taxes
                      
                      
                      63,997
                      
                      
                      
                      65,550Accrued
      Interest
                      
                      
                      69,518
                      
                      
                      
                      47,804Other
                      
                      
                      74,269
                      
                      
                      
                      113,655TOTAL
                      
                      
                      1,034,253
                      
                      
                      
                      1,221,514NONCURRENT
      LIABILITIESLong-term
      Debt – Nonaffiliated
                      
                      
                      3,271,191
                      
                      
                      
                      2,924,495Long-term
      Debt – Affiliated
                      
                      
                      100,000
                      
                      
                      
                      100,000Long-term
      Risk Management Liabilities
                      
                      
                      30,055
                      
                      
                      
                      26,388Deferred
      Income Taxes
                      
                      
                      1,105,974
                      
                      
                      
                      1,131,164Regulatory
      Liabilities and Deferred Investment Tax Credits
                      
                      
                      518,038
                      
                      
                      
                      521,508Employee
      Benefits and Pension Obligations
                      
                      
                      329,245
                      
                      
                      
                      331,000Deferred
      Credits and Other
                      
                      
                      115,568
                      
                      
                      
                      112,252TOTAL
                      
                      
                      5,470,071
                      
                      
                      
                      5,146,807TOTAL
      LIABILITIES
                      
                      
                      6,504,324
                      
                      
                      
                      6,368,321Cumulative
      Preferred Stock Not Subject to Mandatory Redemption
                      
                      
                      17,752
                      
                      
                      
                      17,752Commitments
      and Contingencies (Note 4)COMMON
      SHAREHOLDER’S EQUITYCommon
      Stock – No Par Value:Authorized
      – 30,000,000 SharesOutstanding
      – 13,499,500 Shares
                      
                      
                      260,458
                      
                      
                      
                      260,458Paid-in
      Capital
                      
                      
                      1,225,318
                      
                      
                      
                      1,225,292Retained
      Earnings
                      
                      
                      1,005,248
                      
                      
                      
                      951,066Accumulated
      Other Comprehensive Income (Loss)
                      
                      
                      (57,243
                      )
                      
                      
                      (60,225
                      )TOTAL
                      
                      
                      2,433,781
                      
                      
                      
                      2,376,591TOTAL
      LIABILITIES AND SHAREHOLDERS’ EQUITY
                      
                      $
                      8,955,857
                      
                      
                      $
                      8,762,664
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
  
 APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
 CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS
 For
the Three Months Ended March 31, 2009 and 2008
 (in
thousands)
 (Unaudited)
 
 2009
                      
                      
                      2008OPERATING
      ACTIVITIESNet
      Income
                      
                      $
                      74,407
                      
                      
                      $
                      55,313Adjustments
      to Reconcile Net Income to Net Cash Flows from (Used for) Operating
      Activities:Depreciation
      and Amortization
                      
                      
                      69,995
                      
                      
                      
                      62,572Deferred
      Income Taxes
                      
                      
                      80,375
                      
                      
                      
                      25,066Carrying
      Costs Income
                      
                      
                      (4,083
                      )
                      
                      
                      (9,586
                      )Allowance
      for Equity Funds Used During Construction
                      
                      
                      (2,653
                      )
                      
                      
                      (1,496
                      )Mark-to-Market
      of Risk Management Contracts
                      
                      
                      (9,433
                      )
                      
                      
                      (1,658
                      )Change
      in Other Noncurrent Assets
                      
                      
                      (7,737
                      )
                      
                      
                      (13,102
                      )Change
      in Other Noncurrent Liabilities
                      
                      
                      3,098
                      
                      
                      
                      (5,555
                      )Changes
      in Certain Components of Working Capital:Accounts
      Receivable, Net
                      
                      
                      64,045
                      
                      
                      
                      32,344Fuel,
      Materials and Supplies
                      
                      
                      (39,266
                      )
                      
                      
                      20,442Accounts
      Payable
                      
                      
                      (115,697
                      )
                      
                      
                      4,235Accrued
      Taxes, Net
                      
                      
                      (41,201
                      )
                      
                      
                      (2,942
                      )Fuel
      Over/Under-Recovery, Net
                      
                      
                      (70,837
                      )
                      
                      
                      (26,584
                      )Other
      Current Assets
                      
                      
                      (16,033
                      )
                      
                      
                      (6,690
                      )Other
      Current Liabilities
                      
                      
                      (14,187
                      )
                      
                      
                      (13,527
                      )Net
      Cash Flows from (Used for) Operating Activities
                      
                      
                      (29,207
                      )
                      
                      
                      118,832INVESTING
      ACTIVITIESConstruction
      Expenditures
                      
                      
                      (221,053
                      )
                      
                      
                      (158,722
                      )Change
      in Other Cash Deposits
                      
                      
                      235
                      
                      
                      
                      -Change
      in Advances to Affiliates, Net
                      
                      
                      -
                      
                      
                      
                      (261,823
                      )Proceeds
      from Sales of Assets
                      
                      
                      228
                      
                      
                      
                      11,366Net
      Cash Flows Used for Investing Activities
                      
                      
                      (220,590
                      )
                      
                      
                      (409,179
                      )FINANCING
      ACTIVITIESCapital
      Contribution from Parent
                      
                      
                      -
                      
                      
                      
                      75,000Issuance
      of Long-term Debt – Nonaffiliated
                      
                      
                      345,814
                      
                      
                      
                      492,325Change
      in Advances from Affiliates, Net
                      
                      
                      (74,407
                      )
                      
                      
                      (275,257
                      )Retirement
      of Long-term Debt – Nonaffiliated
                      
                      
                      (4
                      )
                      
                      
                      (3
                      )Principal
      Payments for Capital Lease Obligations
                      
                      
                      (848
                      )
                      
                      
                      (1,061
                      )Dividends
      Paid on Common Stock
                      
                      
                      (20,000
                      )
                      
                      
                      -Dividends
      Paid on Cumulative Preferred Stock
                      
                      
                      (200
                      )
                      
                      
                      (200
                      )Net
      Cash Flows from Financing Activities
                      
                      
                      250,355
                      
                      
                      
                      290,804Net
      Increase in Cash and Cash Equivalents
                      
                      
                      558
                      
                      
                      
                      457Cash
      and Cash Equivalents at Beginning of Period
                      
                      
                      1,996
                      
                      
                      
                      2,195Cash
      and Cash Equivalents at End of Period
                      
                      $
                      2,554
                      
                      
                      $
                      2,652
 
 SUPPLEMENTARY
      INFORMATIONCash
      Paid for Interest, Net of Capitalized Amounts
                  
                  $
                  49,390
                  
                  
                  $
                  35,527Net
      Cash Paid (Received) for Income Taxes
                  
                  
                  (2,683
                  )
                  
                  
                  338Noncash
      Acquisitions Under Capital Leases
                  
                  
                  151
                  
                  
                  
                  478Construction
      Expenditures Included in Accounts Payable at March 31,
                  
                  
                  88,405
                  
                  
                  
                  83,766
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
 
 
 APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
 INDEX
TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT
SUBSIDIARIES
 
 The
condensed notes to APCo’s condensed consolidated financial statements are
combined with the condensed notes to condensed financial statements for other
registrant subsidiaries.  Listed below are the notes that apply to
APCo.
 
 Footnote
      ReferenceSignificant
      Accounting Matters
                                Note
      1New
      Accounting Pronouncements
                                Note
      2Rate
      Matters
                                Note
      3Commitments,
      Guarantees and Contingencies
                                Note
      4Benefit
      Plans
                                Note
      5Business
      Segments
                                Note
      6Derivatives,
      Hedging and Fair Value Measurements
                                Note
      7Income
      Taxes
                                Note
      8Financing
      Activities
                                Note
      9
  
  
 
 
 
 
 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 2009
Compared to First Quarter of 2008
 
 Reconciliation
of First Quarter of 2008 to First Quarter of 2009
 Net
Income
 (in
millions)
 
 First
      Quarter of 2008
                          
                          
                          
                          
                          $
                          76Changes
      in Gross Margin:Retail
      Margins
                          
                          
                          (19
                          )Off-system
      Sales
                          
                          
                          (23
                          )Total
      Change in Gross Margin
                          
                          
                          
                          
                          
                          
                          (42
                          )Changes
      in Operating Expenses and Other:Other
      Operation and Maintenance
                          
                          
                          (11
                          )Depreciation
      and Amortization
                          
                          
                          14Taxes
      Other Than Income Taxes
                          
                          
                          (1
                          )Other
      Income
                          
                          
                          (2
                          )Interest
      Expense
                          
                          
                          (1
                          )Total
      Change in Operating Expenses and Other
                          
                          
                          
                          
                          
                          
                          (1
                          )Income
      Tax Expense
                          
                          
                          
                          
                          
                          
                          16First
      Quarter of 2009
                          
                          
                          
                          
                          
                          $
                          49
 
 Net
Income decreased $27 million to $49 million in 2009.  The key driver
of the decrease was a $42 million decrease in Gross Margin, partially offset by
a $16 million decrease in Income Tax Expense.
 
 The major
components of the decrease in Gross Margin, defined as revenues less the related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power were as follows:
 
 ·
              Retail
      Margins decreased $19 million primarily due to:·
              A
      $14 million decrease as a result of Restructuring Transition Charge (RTC)
      revenues and their associated offset in fuel under-recovery in the first
      quarter of 2009.  The PUCO allowed CSPCo to continue collecting
      the RTC pending the implementation of the new ESP tariffs which did not
      occur until March 30, 2009.  In 2008, RTC revenues were recorded
      but were offset through the amortization of the transition regulatory
      assets as discussed below.·
              A
      $7 million decrease related to CSPCo’s Unit Power Agreement for AEGCo’s
      Lawrenceburg Plant.  Permission was granted to include in fuel
      as a result of the ESP order.·
              A
      $3 million decrease in industrial revenue primarily due to lower
      load.These
      decreases were partially offset by:·
              A
      $5 million increase in fuel margins due to the deferral of fuel costs in
      2009.  The PUCO’s March 2009 approval of CSPCo’s ESP allows for
      the recovery of fuel and related costs incurred since January 1,
      2009.  See “Ohio Electric Security Plan Filings” section of Note
      3.·
              A
      $5 million increase related to new rates implemented due to the accrual
      for March unbilled revenues at higher rates set by the Ohio
      ESP.·
              Margins
      from Off-system Sales decreased $23 million primarily due to lower
      physical sales volumes and lower margins as a result of lower market
      prices, partially offset by higher trading
  margins.
  Operating
Expenses and Other and Income Tax Expense changed between years as
follows:
 
 ·
              Other
      Operation and Maintenance expenses increased $11 million primarily due
      to:·
              An
      $8 million increase in overhead line expenses primarily due to ice and
      wind storms in the first quarter of 2009.·
              An
      $8 million increase related to an obligation to contribute to the
      “Partnership with Ohio” fund for low income, at-risk customers ordered by
      the PUCO’s March 2009 approval of CSPCo’s ESP.  See “Ohio
      Electric Security Plan Filings” section of Note 3.·
              A
      $6 million increase in recoverable PJM expenses.These
      increases were partially offset by:·
              An
      $8 million decrease in expenses related to CSPCo’s Unit Power Agreement
      for AEGCo’s Lawrenceburg Plant primarily due to the classification of
      capacity and depreciation to fuel accounts pursuant to the March 2009 ESP
      order.·
              A
      $5 million decrease in employee-related expenses.·
              Depreciation
      and Amortization decreased $14 million primarily due to the completed
      amortization of transition regulatory assets in December
    2008.·
              Income
      Tax Expense decreased $16 million primarily due to a decrease in pretax
      book income.
 
 Critical Accounting
Estimates
 
 See the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in the 2008 Annual Report for a discussion
of the estimates and judgments required for regulatory accounting, revenue
recognition, the valuation of long-lived assets, pension and other
postretirement benefits and the impact of new accounting
pronouncements.
 
 Adoption of New Accounting
Pronouncements
 
 See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for a discussion of adoption of new accounting
pronouncements.
 
 QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
 
 Market
Risks
 
 Risk
management assets and liabilities are managed by AEPSC as agent.  The
related risk management policies and procedures are instituted and administered
by AEPSC.  See complete discussion within AEP’s “Quantitative and
Qualitative Disclosures About Risk Management Activities” section for
disclosures about risk management activities.
 
 Interest
Rate Risk
 
 Management
utilizes an Earnings at Risk (EaR) model to measure interest rate market risk
exposure.  EaR statistically quantifies the extent to which CSPCo’s
interest expense could vary over the next twelve months and gives a
probabilistic estimate of different levels of interest expense.  The
resulting EaR is interpreted as the dollar amount by which actual interest
expense for the next twelve months could exceed expected interest expense with a
one-in-twenty chance of occurrence.  The primary drivers of EaR are
from the existing floating rate debt (including short-term debt) as well as
long-term debt issuances in the next twelve months.  The estimated EaR
on CSPCo’s debt portfolio was $1.4 million.
  
 COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
 CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
 For
the Three Months Ended March 31, 2009 and 2008
 (in
thousands)
 (Unaudited)
 2009
                  
                  
                  2008REVENUESElectric
      Generation, Transmission and Distribution
                  
                  $
                  460,922
                  
                  
                  $
                  505,324Sales
      to AEP Affiliates
                  
                  
                  10,206
                  
                  
                  
                  35,108Other
                  
                  
                  608
                  
                  
                  
                  1,217TOTAL
                  
                  
                  471,736
                  
                  
                  
                  541,649EXPENSESFuel
      and Other Consumables Used for Electric Generation
                  
                  
                  70,944
                  
                  
                  
                  85,127Purchased
      Electricity for Resale
                  
                  
                  29,838
                  
                  
                  
                  42,186Purchased
      Electricity from AEP Affiliates
                  
                  
                  93,092
                  
                  
                  
                  94,104Other
      Operation
                  
                  
                  76,088
                  
                  
                  
                  73,066Maintenance
                  
                  
                  31,014
                  
                  
                  
                  23,231Depreciation
      and Amortization
                  
                  
                  34,945
                  
                  
                  
                  48,602Taxes
      Other Than Income Taxes
                  
                  
                  45,282
                  
                  
                  
                  44,556TOTAL
                  
                  
                  381,203
                  
                  
                  
                  410,872OPERATING
      INCOME
                  
                  
                  90,533
                  
                  
                  
                  130,777Other
      Income (Expense):Interest
      Income
                  
                  
                  240
                  
                  
                  
                  2,339Carrying
      Costs Income
                  
                  
                  1,689
                  
                  
                  
                  1,766Allowance
      for Equity Funds Used During Construction
                  
                  
                  1,300
                  
                  
                  
                  855Interest
      Expense
                  
                  
                  (20,793
                  )
                  
                  
                  (19,239
                  )INCOME
      BEFORE INCOME TAX EXPENSE
                  
                  
                  72,969
                  
                  
                  
                  116,498Income
      Tax Expense
                  
                  
                  24,111
                  
                  
                  
                  40,345NET
      INCOME
                  
                  
                  48,858
                  
                  
                  
                  76,153Capital
      Stock Expense
                  
                  
                  39
                  
                  
                  
                  39EARNINGS ATTRIBUTABLE
      TO COMMON STOCK
                  
                  $
                  48,819
                  
                  
                  $
                  76,114
 
 The
      common stock of CSPCo is wholly-owned by
AEP.
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
 
  
 COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
 CONDENSED
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
 EQUITY
AND COMPREHENSIVE INCOME (LOSS)
 For
the Three Months Ended March 31, 2009 and 2008
 (in
thousands)
 (Unaudited)
 
 Common
      Stock
                  
                  
                  Paid-in
      Capital
                  
                  
                  Retained
      Earnings
                  
                  
                  Accumulated
      Other Comprehensive Income (Loss)
                  
                  
                  TotalDECEMBER
      31, 2007
                  
                  $
                  41,026
                  
                  
                  $
                  580,349
                  
                  
                  $
                  561,696
                  
                  
                  $
                  (18,794
                  )
                  
                  $
                  1,164,277EITF
      06-10 Adoption, Net of Tax of $589
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  (1,095
                  )
                  
                  
                  
                  
                  
                  
                  (1,095
                  )SFAS
      157 Adoption, Net of Tax of $170
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  (316
                  )
                  
                  
                  
                  
                  
                  
                  (316
                  )Common
      Stock Dividends
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  (37,500
                  )
                  
                  
                  
                  
                  
                  
                  (37,500
                  )Capital
      Stock Expense
                  
                  
                  
                  
                  
                  
                  39
                  
                  
                  
                  (39
                  )
                  
                  
                  
                  
                  
                  
                  -TOTAL
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  1,125,366COMPREHENSIVE
      INCOMEOther
      Comprehensive Income (Loss), Net of Taxes:Cash
      Flow Hedges, Net of Tax of $3,553
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  (6,598
                  )
                  
                  
                  (6,598
                  )Amortization
      of Pension and OPEB Deferred Costs, Net of Tax of $152
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  283
                  
                  
                  
                  283NET
      INCOME
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  76,153
                  
                  
                  
                  
                  
                  
                  
                  76,153TOTAL
      COMPREHENSIVE INCOME
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  69,838MARCH
      31, 2008
                  
                  $
                  41,026
                  
                  
                  $
                  580,388
                  
                  
                  $
                  598,899
                  
                  
                  $
                  (25,109
                  )
                  
                  $
                  1,195,204DECEMBER
      31, 2008
                  
                  $
                  41,026
                  
                  
                  $
                  580,506
                  
                  
                  $
                  674,758
                  
                  
                  $
                  (51,025
                  )
                  
                  $
                  1,245,265Common
      Stock Dividends
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  (50,000
                  )
                  
                  
                  
                  
                  
                  
                  (50,000
                  )Capital
      Stock Expense
                  
                  
                  
                  
                  
                  
                  39
                  
                  
                  
                  (39
                  )
                  
                  
                  
                  
                  
                  
                  -TOTAL
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  1,195,265COMPREHENSIVE
      INCOMEOther
      Comprehensive Income, Net of Taxes:Cash
      Flow Hedges, Net of Tax of $340
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  631
                  
                  
                  
                  631Amortization
      of Pension and OPEB Deferred Costs, Net of Tax of $298
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  554
                  
                  
                  
                  554NET
      INCOME
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  48,858
                  
                  
                  
                  
                  
                  
                  
                  48,858TOTAL
      COMPREHENSIVE INCOME
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  50,043MARCH
      31, 2009
                  
                  $
                  41,026
                  
                  
                  $
                  580,545
                  
                  
                  $
                  673,577
                  
                  
                  $
                  (49,840
                  )
                  
                  $
                  1,245,308
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
 
  
 COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
 CONDENSED
CONSOLIDATED BALANCE SHEETS
 ASSETS
 March
31, 2009 and December 31, 2008
 (in
thousands)
 (Unaudited)
 2009
                  
                  
                  2008CURRENT
      ASSETSCash
      and Cash Equivalents
                  
                  $
                  1,287
                  
                  
                  $
                  1,063Other
      Cash Deposits
                  
                  
                  21,207
                  
                  
                  
                  32,300Accounts
      Receivable:Customers
                  
                  
                  47,321
                  
                  
                  
                  56,008Affiliated
      Companies
                  
                  
                  14,651
                  
                  
                  
                  44,235Accrued
      Unbilled Revenues
                  
                  
                  11,795
                  
                  
                  
                  18,359Miscellaneous
                  
                  
                  13,216
                  
                  
                  
                  11,546Allowance
      for Uncollectible Accounts
                  
                  
                  (3,075
                  )
                  
                  
                  (2,895
                  )Total
      Accounts Receivable
                  
                  
                  83,908
                  
                  
                  
                  127,253Fuel
                  
                  
                  60,690
                  
                  
                  
                  42,075Materials
      and Supplies
                  
                  
                  35,020
                  
                  
                  
                  33,781Emission
      Allowances
                  
                  
                  18,042
                  
                  
                  
                  20,211Risk
      Management Assets
                  
                  
                  39,587
                  
                  
                  
                  35,984Margin
      Deposits
                  
                  
                  21,098
                  
                  
                  
                  13,613Prepayments
      and Other
                  
                  
                  29,445
                  
                  
                  
                  27,880TOTAL
                  
                  
                  310,284
                  
                  
                  
                  334,160PROPERTY,
      PLANT AND EQUIPMENTElectric:Production
                  
                  
                  2,343,392
                  
                  
                  
                  2,326,056Transmission
                  
                  
                  577,746
                  
                  
                  
                  574,018Distribution
                  
                  
                  1,651,218
                  
                  
                  
                  1,625,000Other
                  
                  
                  208,511
                  
                  
                  
                  211,088Construction
      Work in Progress
                  
                  
                  406,619
                  
                  
                  
                  394,918Total
                  
                  
                  5,187,486
                  
                  
                  
                  5,131,080Accumulated
      Depreciation and Amortization
                  
                  
                  1,802,510
                  
                  
                  
                  1,781,866TOTAL
      - NET
                  
                  
                  3,384,976
                  
                  
                  
                  3,349,214OTHER
      NONCURRENT ASSETSRegulatory
      Assets
                  
                  
                  314,200
                  
                  
                  
                  298,357Long-term
      Risk Management Assets
                  
                  
                  34,308
                  
                  
                  
                  28,461Deferred
      Charges and Other
                  
                  
                  109,452
                  
                  
                  
                  125,814TOTAL
                  
                  
                  457,960
                  
                  
                  
                  452,632TOTAL
      ASSETS
                  
                  $
                  4,153,220
                  
                  
                  $
                  4,136,006
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
 
  
 COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
 CONDENSED
CONSOLIDATED BALANCE SHEETS
 LIABILITIES
AND SHAREHOLDER’S EQUITY
 March
31, 2009 and December 31, 2008
 (Unaudited)
 2009
                  
                  
                  2008CURRENT
      LIABILITIES
                  
                  (in
      thousands)Advances
      from Affiliates
                  
                  $
                  177,736
                  
                  
                  $
                  74,865Accounts
      Payable:General
                  
                  
                  121,022
                  
                  
                  
                  131,417Affiliated
      Companies
                  
                  
                  53,594
                  
                  
                  
                  120,420Long-term
      Debt Due Within One Year – Affiliated
                  
                  
                  100,000
                  
                  
                  
                  -Risk
      Management Liabilities
                  
                  
                  20,561
                  
                  
                  
                  16,490Customer
      Deposits
                  
                  
                  31,724
                  
                  
                  
                  30,145Accrued
      Taxes
                  
                  
                  141,470
                  
                  
                  
                  185,293Other
                  
                  
                  82,399
                  
                  
                  
                  82,678TOTAL
                  
                  
                  728,506
                  
                  
                  
                  641,308NONCURRENT
      LIABILITIESLong-term
      Debt – Nonaffiliated
                  
                  
                  1,343,696
                  
                  
                  
                  1,343,594Long-term
      Debt – Affiliated
                  
                  
                  -
                  
                  
                  
                  100,000Long-term
      Risk Management Liabilities
                  
                  
                  15,923
                  
                  
                  
                  14,774Deferred
      Income Taxes
                  
                  
                  457,433
                  
                  
                  
                  435,773Regulatory
      Liabilities and Deferred Investment Tax Credits
                  
                  
                  164,955
                  
                  
                  
                  161,102Employee
      Benefits and Pension Obligations
                  
                  
                  146,009
                  
                  
                  
                  148,123Deferred
      Credits and Other
                  
                  
                  51,390
                  
                  
                  
                  46,067TOTAL
                  
                  
                  2,179,406
                  
                  
                  
                  2,249,433TOTAL
      LIABILITIES
                  
                  
                  2,907,912
                  
                  
                  
                  2,890,741Commitments
      and Contingencies (Note 4)COMMON
      SHAREHOLDER’S EQUITYCommon
      Stock – No Par Value:Authorized
      – 24,000,000 SharesOutstanding
      – 16,410,426 Shares
                  
                  
                  41,026
                  
                  
                  
                  41,026Paid-in
      Capital
                  
                  
                  580,545
                  
                  
                  
                  580,506Retained
      Earnings
                  
                  
                  673,577
                  
                  
                  
                  674,758Accumulated
      Other Comprehensive Income (Loss)
                  
                  
                  (49,840
                  )
                  
                  
                  (51,025
                  )TOTAL
                  
                  
                  1,245,308
                  
                  
                  
                  1,245,265TOTAL
      LIABILITIES AND SHAREHOLDER’S EQUITY
                  
                  $
                  4,153,220
                  
                  
                  $
                  4,136,006
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
 
  
 COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
 CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS
 For
the Three Months Ended March 31, 2009 and 2008
 (in
thousands)
 (Unaudited)
 2009
                          
                          
                          2008OPERATING
      ACTIVITIESNet
      Income
                          
                          $
                          48,858
                          
                          
                          $
                          76,153Adjustments
      to Reconcile Net Income to Net Cash Flows from Operating
      Activities:Depreciation
      and Amortization
                          
                          
                          34,945
                          
                          
                          
                          48,602Deferred
      Income Taxes
                          
                          
                          38,945
                          
                          
                          
                          872Allowance
      for Equity Funds Used During Construction
                          
                          
                          (1,300
                          )
                          
                          
                          (855
                          )Mark-to-Market
      of Risk Management Contracts
                          
                          
                          (3,204
                          )
                          
                          
                          (1,499
                          )Deferred
      Property Taxes
                          
                          
                          22,262
                          
                          
                          
                          21,728Fuel
      Over/Under-Recovery, Net
                          
                          
                          (16,934
                          )
                          
                          
                          -Change
      in Other Noncurrent Assets
                          
                          
                          (8,551
                          )
                          
                          
                          (11,440
                          )Change
      in Other Noncurrent Liabilities
                          
                          
                          13,410
                          
                          
                          
                          1,292Changes
      in Certain Components of Working Capital:Accounts
      Receivable, Net
                          
                          
                          43,345
                          
                          
                          
                          (3,383
                          )Fuel,
      Materials and Supplies
                          
                          
                          (19,854
                          )
                          
                          
                          6,485Accounts
      Payable
                          
                          
                          (81,080
                          )
                          
                          
                          (6,756
                          )Accrued
      Taxes, Net
                          
                          
                          (57,623
                          )
                          
                          
                          (2,001
                          )Other
      Current Assets
                          
                          
                          1,157
                          
                          
                          
                          (2,211
                          )Other
      Current Liabilities
                          
                          
                          (9,817
                          )
                          
                          
                          (20,972
                          )Net
      Cash Flows from Operating Activities
                          
                          
                          4,559
                          
                          
                          
                          106,015INVESTING
      ACTIVITIESConstruction
      Expenditures
                          
                          
                          (67,831
                          )
                          
                          
                          (84,513
                          )Change
      in Other Cash Deposits
                          
                          
                          11,093
                          
                          
                          
                          -Proceeds
      from Sales of Assets
                          
                          
                          206
                          
                          
                          
                          150Net
      Cash Flows Used for Investing Activities
                          
                          
                          (56,532
                          )
                          
                          
                          (84,363
                          )FINANCING
      ACTIVITIESChange
      in Advances from Affiliates, Net
                          
                          
                          102,871
                          
                          
                          
                          68,800Retirement
      of Long-term Debt – Nonaffiliated
                          
                          
                          -
                          
                          
                          
                          (52,000
                          )Principal
      Payments for Capital Lease Obligations
                          
                          
                          (674
                          )
                          
                          
                          (725
                          )Dividends
      Paid on Common Stock
                          
                          
                          (50,000
                          )
                          
                          
                          (37,500
                          )Net
      Cash Flows from (Used for) Financing Activities
                          
                          
                          52,197
                          
                          
                          
                          (21,425
                          )Net
      Increase in Cash and Cash Equivalents
                          
                          
                          224
                          
                          
                          
                          227Cash
      and Cash Equivalents at Beginning of Period
                          
                          
                          1,063
                          
                          
                          
                          1,389Cash
      and Cash Equivalents at End of Period
                          
                          $
                          1,287
                          
                          
                          $
                          1,616
 
 SUPPLEMENTARY
      INFORMATIONCash
      Paid for Interest, Net of Capitalized Amounts
                  
                  $
                  31,229
                  
                  
                  $
                  24,351Net
      Cash Paid for Income Taxes
                  
                  
                  387
                  
                  
                  
                  2,494Noncash
      Acquisitions Under Capital Leases
                  
                  
                  254
                  
                  
                  
                  355Construction
      Expenditures Included in Accounts Payable at March 31,
                  
                  
                  51,297
                  
                  
                  
                  48,392
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
  
 COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
 INDEX
TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
 REGISTRANT
SUBSIDIARIES
 
 The
condensed notes to CSPCo’s condensed consolidated financial statements are
combined with the condensed notes to condensed financial statements for other
registrant subsidiaries.  Listed below are the notes that apply to
CSPCo.
 Footnote
                                  ReferenceSignificant
      Accounting Matters
                                Note
      1New
      Accounting Pronouncements
                                Note
      2Rate
      Matters
                                Note
      3Commitments,
      Guarantees and Contingencies
                                Note
      4Benefit
      Plans
                                Note
      5Business
      Segments
                                Note
      6Derivatives,
      Hedging and Fair Value Measurements
                                Note
      7Income
      Taxes
                                Note
      8Financing
      Activities
                                Note
      9
 
 
 
 
 
 
 INDIANA
MICHIGAN POWER COMPANY
 AND
SUBSIDIARIES
 
  
 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
 MANAGEMENT’S NARRATIVE
FINANCIAL DISCUSSION AND ANALYSIS
 
 
 Results of
Operations
 
 First Quarter of 2009
Compared to First Quarter of 2008
 
 Reconciliation
of First Quarter of 2008 to First Quarter of 2009
 Net
Income
 (in
millions)
 
 First
      Quarter of 2008
                            
                            
                            
                            
                            $
                            55Changes
      in Gross Margin:Retail
      Margins
                            
                            
                            (3
                            )FERC
      Municipals and Cooperatives
                            
                            
                            (1
                            )Off-system
      Sales
                            
                            
                            (27
                            )Transmission
      Revenues
                            
                            
                            (1
                            )Other
                            
                            
                            56Total
      Change in Gross Margin
                            
                            
                            
                            
                            
                            
                            24Changes
      in Operating Expenses and Other:Other
      Operation and Maintenance
                            
                            
                            16Depreciation
      and Amortization
                            
                            
                            (1
                            )Taxes
      Other Than Income Taxes
                            
                            
                            (1
                            )Other
      Income
                            
                            
                            2Interest
      Expense
                            
                            
                            (4
                            )Total
      Change in Operating Expenses and Other
                            
                            
                            
                            
                            
                            
                            12Income
      Tax Expense
                            
                            
                            
                            
                            
                            
                            (10
                            )First
      Quarter of 2009
                            
                            
                            
                            
                            
                            $
                            81
 
 Net
Income increased $26 million to $81 million in 2009.  The key drivers
of the increase were a $24 million increase in Gross Margin and a $12 million
decrease in Operating Expenses and Other, partially offset by a $10 million
increase in Income Tax Expense.
 
 The major
components of the increase in Gross Margin, defined as revenues less the related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power were as follows:
 
 ·
              Retail
      Margins decreased $3 million primarily due to a $14 million decline in
      industrial margins due to a 21% decrease in industrial sales, partially
      offset by a $9 million increase in capacity revenue reflecting MLR
      changes.·
              Margins
      from Off-system Sales decreased $27 million primarily due to lower
      physical sales volumes and lower margins as a result of lower market
      prices.·
              Other
      Revenues increased $56 million primarily due to Cook Plant accidental
      outage insurance policy proceeds of $54 million.  Of these
      insurance proceeds, $20 million were used to offset fuel costs associated
      with the Cook Plant Unit 1 shutdown which are primarily included in Retail
      Margins.  See “Cook Plant Unit 1 Fire and Shutdown” section of
      Note 4.
  Operating
Expenses and Other and Income Tax Expense changed between years as
follows:
 
 ·
              Other
      Operation and Maintenance expenses decreased $16 million primarily due to
      lower nuclear and coal production, transmission and distribution costs and
      deferral of NSR and OPEB costs included in the rate settlement for
      recovery.  See “Indiana Base Rate Filing” section of Note
      3.·
              Interest
      Expense increased $4 million primarily due to increased
      borrowings.  In January 2009, I&M issued $475 million of 7%
      senior unsecured notes.·
              Income
      Tax Expense increased $10 million primarily due to an increase in pretax
      book income.
 
 Cook Plant Unit 1 Fire and
Shutdown
 
 In
September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine
vibrations, likely caused by blade failure, which resulted in a fire on the
electric generator.  This equipment, located in the turbine building,
is separate and isolated from the nuclear reactor.  The turbine rotors
that caused the vibration were installed in 2006 and are within the vendor’s
warranty period.  The warranty provides for the repair or replacement
of the turbine rotors if the damage was caused by a defect in materials or
workmanship.  I&M is working with its insurance company, Nuclear
Electric Insurance Limited (NEIL), and its turbine vendor, Siemens, to evaluate
the extent of the damage resulting from the incident and facilitate repairs to
return the unit to service.  Repair of the property damage and
replacement of the turbine rotors and other equipment could cost up to
approximately $330 million.  Management believes that I&M should
recover a significant portion of these costs through the turbine vendor’s
warranty, insurance and the regulatory process.  The treatment of
property damage costs, replacement power costs and insurance proceeds will be
the subject of future regulatory proceedings in Indiana and
Michigan.  I&M is repairing Unit 1 to resume operations as early
as October 2009 at reduced power.  Should post-repair operations prove
unsuccessful, the replacement of parts will extend the outage into
2011.
 
 I&M
maintains property insurance through NEIL with a $1 million
deductible.  As of March 31, 2009, I&M recorded $34 million in
Prepayments and Other on the Condensed Consolidated Balance Sheets representing
recoverable amounts under the property insurance policy.  I&M
received partial reimbursements from NEIL for the cost incurred to date to
repair the property damage.  I&M also maintains a separate
accidental outage policy with NEIL whereby, after a 12-week deductible period,
I&M is entitled to weekly payments of $3.5 million for the first 52 weeks
following the deductible period.  After the initial 52 weeks of
indemnity, the policy pays $2.8 million per week for up to an additional 110
weeks.  I&M began receiving payments under the accidental outage
policy in December 2008.  In the first quarter of 2009, I&M
recorded $54 million in revenues, including $9 million in revenues that were
deferred at December 31, 2008, related to the accidental outage
policy.  In order to hold customers harmless, in the first quarter of
2009, I&M applied $20 million of the accidental outage insurance proceeds to
reduce fuel underrecoveries reflecting recoverable fuel costs as if Unit 1 were
operating.  If the ultimate costs of the incident are not covered by
warranty, insurance or through the regulatory process or if the unit is not
returned to service in a reasonable period of time, it could have an adverse
impact on net income, cash flows and financial condition.
 
 Critical Accounting
Estimates
 
 See the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in the 2008 Annual Report for a discussion
of the estimates and judgments required for regulatory accounting, revenue
recognition, the valuation of long-lived assets, pension and other
postretirement benefits and the impact of new accounting
pronouncements.
 
 Adoption of New Accounting
Pronouncements
 
 See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for a discussion of adoption of new accounting
pronouncements.
  
 QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
 
 Market
Risks
 
 Risk
management assets and liabilities are managed by AEPSC as agent.  The
related risk management policies and procedures are instituted and administered
by AEPSC.  See complete discussion within AEP’s “Quantitative and
Qualitative Disclosures About Risk Management Activities” section for
disclosures about risk management activities.
 
 Interest
Rate Risk
 
 Management
utilizes an Earnings at Risk (EaR) model to measure interest rate market risk
exposure.  EaR statistically quantifies the extent to which I&M’s
interest expense could vary over the next twelve months and gives a
probabilistic estimate of different levels of interest expense.  The
resulting EaR is interpreted as the dollar amount by which actual interest
expense for the next twelve months could exceed expected interest expense with a
one-in-twenty chance of occurrence.  The primary drivers of EaR are
from the existing floating rate debt (including short- term debt) as well as
long-term debt issuances in the next twelve months.  The estimated EaR
on I&M’s debt portfolio was $4.5 million.
  
 INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
 CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
 For
the Three Months Ended March 31, 2009 and 2008
 (in
thousands)
 (Unaudited)
 2009
                      
                      
                      2008REVENUESElectric
      Generation, Transmission and Distribution
                      
                      $
                      421,927
                      
                      
                      $
                      431,592Sales
      to AEP Affiliates
                      
                      
                      59,986
                      
                      
                      
                      76,512Other
      – Affiliated
                      
                      
                      30,740
                      
                      
                      
                      23,219Other
      – Nonaffiliated
                      
                      
                      54,391
                      
                      
                      
                      5,826TOTAL
                      
                      
                      567,044
                      
                      
                      
                      537,149EXPENSESFuel
      and Other Consumables Used for Electric Generation
                      
                      
                      102,960
                      
                      
                      
                      101,241Purchased
      Electricity for Resale
                      
                      
                      38,361
                      
                      
                      
                      21,483Purchased
      Electricity from AEP Affiliates
                      
                      
                      79,978
                      
                      
                      
                      92,641Other
      Operation
                      
                      
                      109,460
                      
                      
                      
                      120,366Maintenance
                      
                      
                      46,274
                      
                      
                      
                      51,221Depreciation
      and Amortization
                      
                      
                      32,745
                      
                      
                      
                      31,722Taxes
      Other Than Income Taxes
                      
                      
                      20,696
                      
                      
                      
                      19,902TOTAL
                      
                      
                      430,474
                      
                      
                      
                      438,576OPERATING
      INCOME
                      
                      
                      136,570
                      
                      
                      
                      98,573Other
      Income (Expense):Interest
      Income
                      
                      
                      2,543
                      
                      
                      
                      829Allowance
      for Equity Funds Used During Construction
                      
                      
                      1,555
                      
                      
                      
                      880Interest
      Expense
                      
                      
                      (23,531
                      )
                      
                      
                      (19,202
                      )INCOME
      BEFORE INCOME TAX EXPENSE
                      
                      
                      117,137
                      
                      
                      
                      81,080Income
      Tax Expense
                      
                      
                      36,185
                      
                      
                      
                      25,822NET
      INCOME
                      
                      
                      80,952
                      
                      
                      
                      55,258Preferred
      Stock Dividend Requirements
                      
                      
                      85
                      
                      
                      
                      85EARNINGS
      ATTRIBUTABLE TO COMMON STOCK
                      
                      $
                      80,867
                      
                      
                      $
                      55,173
 
 The
      common stock of I&M is wholly-owned by
AEP.
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
   
 INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
 CONDENSED
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
 EQUITY
AND COMPREHENSIVE INCOME (LOSS)
 For
the Three Months Ended March 31, 2009 and 2008
 (in
thousands)
 (Unaudited)
 
 Common
      Stock
                    
                    
                    Paid-in
      Capital
                    
                    
                    Retained
      Earnings
                    
                    
                    Accumulated
                      Other
                      Comprehensive
                      Income
      (Loss)
                    
                    
                    TotalDECEMBER
      31, 2007
                    
                    $
                    56,584
                    
                    
                    $
                    861,291
                    
                    
                    $
                    483,499
                    
                    
                    $
                    (15,675
                    )
                    
                    $
                    1,385,699EITF
      06-10 Adoption, Net of Tax of $753
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    (1,398
                    )
                    
                    
                    
                    
                    
                    
                    (1,398
                    )Common
      Stock Dividends
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    (18,750
                    )
                    
                    
                    
                    
                    
                    
                    (18,750
                    )Preferred
      Stock Dividends
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    (85
                    )
                    
                    
                    
                    
                    
                    
                    (85
                    )TOTAL
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    1,365,466COMPREHENSIVE
      INCOMEOther
      Comprehensive Income (Loss),
                      Net of
      Taxes:Cash
      Flow Hedges, Net of Tax of $3,208
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    (5,958
                    )
                    
                    
                    (5,958
                    )Amortization
      of Pension and OPEB Deferred Costs, Net of Tax of $59
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    110
                    
                    
                    
                    110NET
      INCOME
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    55,258
                    
                    
                    
                    
                    
                    
                    
                    55,258TOTAL
      COMPREHENSIVE INCOME
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    49,410MARCH
      31, 2008
                    
                    $
                    56,584
                    
                    
                    $
                    861,291
                    
                    
                    $
                    518,524
                    
                    
                    $
                    (21,523
                    )
                    
                    $
                    1,414,876DECEMBER
      31, 2008
                    
                    $
                    56,584
                    
                    
                    $
                    861,291
                    
                    
                    $
                    538,637
                    
                    
                    $
                    (21,694
                    )
                    
                    $
                    1,434,818Common
      Stock Dividends
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    (24,500
                    )
                    
                    
                    
                    
                    
                    
                    (24,500
                    )Preferred
      Stock Dividends
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    (85
                    )
                    
                    
                    
                    
                    
                    
                    (85
                    )Gain
      on Reacquired Preferred Stock
                    
                    
                    
                    
                    
                    
                    1
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    1TOTAL
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    1,410,234COMPREHENSIVE
      INCOMEOther
      Comprehensive Income, Net of Taxes:Cash
      Flow Hedges, Net of Tax of $463
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    859
                    
                    
                    
                    859Amortization
      of Pension and OPEB Deferred Costs, Net of Tax of
$111
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    207
                    
                    
                    
                    207NET
      INCOME
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    80,952
                    
                    
                    
                    
                    
                    
                    
                    80,952TOTAL
      COMPREHENSIVE INCOME
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    82,018MARCH
      31, 2009
                    
                    $
                    56,584
                    
                    
                    $
                    861,292
                    
                    
                    $
                    595,004
                    
                    
                    $
                    (20,628
                    )
                    
                    $
                    1,492,252
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
 
  
 INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
 CONDENSED
CONSOLIDATED BALANCE SHEETS
 ASSETS
 March
31, 2009 and December 31, 2008
 (in
thousands)
 (Unaudited)
 2009
                  
                  
                  2008CURRENT
      ASSETSCash
      and Cash Equivalents
                  
                  $
                  983
                  
                  
                  $
                  728Accounts
      Receivable:Customers
                  
                  
                  53,502
                  
                  
                  
                  70,432Affiliated
      Companies
                  
                  
                  76,951
                  
                  
                  
                  94,205Accrued
      Unbilled Revenues
                  
                  
                  17,943
                  
                  
                  
                  19,260Miscellaneous
                  
                  
                  2,100
                  
                  
                  
                  1,010Allowance
      for Uncollectible Accounts
                  
                  
                  (3,398
                  )
                  
                  
                  (3,310
                  )Total
      Accounts Receivable
                  
                  
                  147,098
                  
                  
                  
                  181,597Fuel
                  
                  
                  67,036
                  
                  
                  
                  67,138Materials
      and Supplies
                  
                  
                  152,782
                  
                  
                  
                  150,644Risk
      Management Assets
                  
                  
                  38,758
                  
                  
                  
                  35,012Regulatory
      Asset for Under-Recovered Fuel Costs
                  
                  
                  37,649
                  
                  
                  
                  33,066Prepayments
      and Other
                  
                  
                  85,958
                  
                  
                  
                  66,733TOTAL
                  
                  
                  530,264
                  
                  
                  
                  534,918PROPERTY,
      PLANT AND EQUIPMENTElectric:Production
                  
                  
                  3,553,486
                  
                  
                  
                  3,534,188Transmission
                  
                  
                  1,123,849
                  
                  
                  
                  1,115,762Distribution
                  
                  
                  1,320,568
                  
                  
                  
                  1,297,482Other
      (including nuclear fuel and coal mining)
                  
                  
                  746,035
                  
                  
                  
                  703,287Construction
      Work in Progress
                  
                  
                  255,864
                  
                  
                  
                  249,020Total
                  
                  
                  6,999,802
                  
                  
                  
                  6,899,739Accumulated
      Depreciation, Depletion and Amortization
                  
                  
                  3,043,645
                  
                  
                  
                  3,019,206TOTAL
      - NET
                  
                  
                  3,956,157
                  
                  
                  
                  3,880,533OTHER
      NONCURRENT ASSETSRegulatory
      Assets
                  
                  
                  477,402
                  
                  
                  
                  455,132Spent
      Nuclear Fuel and Decommissioning Trusts
                  
                  
                  1,206,544
                  
                  
                  
                  1,259,533Long-term
      Risk Management Assets
                  
                  
                  33,282
                  
                  
                  
                  27,616Deferred
      Charges and Other
                  
                  
                  108,722
                  
                  
                  
                  86,193TOTAL
                  
                  
                  1,825,950
                  
                  
                  
                  1,828,474TOTAL
      ASSETS
                  
                  $
                  6,312,371
                  
                  
                  $
                  6,243,925
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
 
  
 INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
 CONDENSED
CONSOLIDATED BALANCE SHEETS
 LIABILITIES
AND SHAREHOLDERS’ EQUITY
 March
31, 2009 and December 31, 2008
 (Unaudited)
 2009
                  
                  
                  2008CURRENT
      LIABILITIES
                  
                  (in
      thousands)Advances
      from Affiliates
                  
                  $
                  16,421
                  
                  
                  $
                  476,036Accounts
      Payable:General
                  
                  
                  149,538
                  
                  
                  
                  194,211Affiliated
      Companies
                  
                  
                  52,450
                  
                  
                  
                  117,589Long-term
      Debt Due Within One Year – Affiliated
                  
                  
                  25,000
                  
                  
                  
                  -Risk
      Management Liabilities
                  
                  
                  20,101
                  
                  
                  
                  16,079Customer
      Deposits
                  
                  
                  28,161
                  
                  
                  
                  26,809Accrued
      Taxes
                  
                  
                  82,522
                  
                  
                  
                  66,363Obligations
      Under Capital Leases
                  
                  
                  26,410
                  
                  
                  
                  43,512Other
                  
                  
                  110,942
                  
                  
                  
                  141,160TOTAL
                  
                  
                  511,545
                  
                  
                  
                  1,081,759NONCURRENT
      LIABILITIESLong-term
      Debt – Nonaffiliated
                  
                  
                  1,949,877
                  
                  
                  
                  1,377,914Long-term
      Risk Management Liabilities
                  
                  
                  15,440
                  
                  
                  
                  14,311Deferred
      Income Taxes
                  
                  
                  480,091
                  
                  
                  
                  412,264Regulatory
      Liabilities and Deferred Investment Tax Credits
                  
                  
                  587,787
                  
                  
                  
                  656,396Asset
      Retirement Obligations
                  
                  
                  914,806
                  
                  
                  
                  902,920Deferred
      Credits and Other
                  
                  
                  352,496
                  
                  
                  
                  355,463TOTAL
                  
                  
                  4,300,497
                  
                  
                  
                  3,719,268TOTAL
      LIABILITIES
                  
                  
                  4,812,042
                  
                  
                  
                  4,801,027Cumulative
      Preferred Stock Not Subject to Mandatory Redemption
                  
                  
                  8,077
                  
                  
                  
                  8,080Commitments
      and Contingencies (Note 4)COMMON
      SHAREHOLDER’S EQUITYCommon
      Stock – No Par Value:Authorized
      – 2,500,000 SharesOutstanding
      – 1,400,000 Shares
                  
                  
                  56,584
                  
                  
                  
                  56,584Paid-in
      Capital
                  
                  
                  861,292
                  
                  
                  
                  861,291Retained
      Earnings
                  
                  
                  595,004
                  
                  
                  
                  538,637Accumulated
      Other Comprehensive Income (Loss)
                  
                  
                  (20,628
                  )
                  
                  
                  (21,694
                  )TOTAL
                  
                  
                  1,492,252
                  
                  
                  
                  1,434,818TOTAL
      LIABILITIES AND SHAREHOLDERS’ EQUITY
                  
                  $
                  6,312,371
                  
                  
                  $
                  6,243,925
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
   
 INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
 CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS
 For
the Three Months Ended March 31, 2009 and 2008
 (in
thousands)
 (Unaudited)
 2009
                          
                          
                          2008OPERATING
      ACTIVITIESNet
      Income
                          
                          $
                          80,952
                          
                          
                          $
                          55,258Adjustments
      to Reconcile Net Income to Net Cash Flows from Operating
      Activities:Depreciation
      and Amortization
                          
                          
                          32,745
                          
                          
                          
                          31,722Deferred
      Income Taxes
                          
                          
                          56,889
                          
                          
                          
                          5,191Deferral
      of Incremental Nuclear Refueling Outage Expenses, Net
                          
                          
                          (7,851
                          )
                          
                          
                          (881
                          )Allowance
      for Equity Funds Used During Construction
                          
                          
                          (1,555
                          )
                          
                          
                          (880
                          )Mark-to-Market
      of Risk Management Contracts
                          
                          
                          (3,272
                          )
                          
                          
                          (1,308
                          )Amortization
      of Nuclear Fuel
                          
                          
                          13,228
                          
                          
                          
                          21,619Change
      in Other Noncurrent Assets
                          
                          
                          (12,585
                          )
                          
                          
                          (10,754
                          )Change
      in Other Noncurrent Liabilities
                          
                          
                          9,715
                          
                          
                          
                          14,234Changes
      in Certain Components of Working Capital:Accounts
      Receivable, Net
                          
                          
                          34,499
                          
                          
                          
                          27,467Fuel,
      Materials and Supplies
                          
                          
                          (2,036
                          )
                          
                          
                          10,107Accounts
      Payable
                          
                          
                          (68,603
                          )
                          
                          
                          408Accrued
      Taxes, Net
                          
                          
                          (1,224
                          )
                          
                          
                          40,026Other
      Current Assets
                          
                          
                          (23,110
                          )
                          
                          
                          (6,718
                          )Other
      Current Liabilities
                          
                          
                          (27,859
                          )
                          
                          
                          (21,534
                          )Net
      Cash Flows from Operating Activities
                          
                          
                          79,933
                          
                          
                          
                          163,957INVESTING
      ACTIVITIESConstruction
      Expenditures
                          
                          
                          (92,814
                          )
                          
                          
                          (67,945
                          )Purchases
      of Investment Securities
                          
                          
                          (178,407
                          )
                          
                          
                          (132,311
                          )Sales
      of Investment Securities
                          
                          
                          158,086
                          
                          
                          
                          113,951Acquisitions
      of Nuclear Fuel
                          
                          
                          (75,670
                          )
                          
                          
                          (98,385
                          )Proceeds
      from Sales of Assets and Other
                          
                          
                          10,757
                          
                          
                          
                          2,815Net
      Cash Flows Used for Investing Activities
                          
                          
                          (178,048
                          )
                          
                          
                          (181,875
                          )FINANCING
      ACTIVITIESIssuance
      of Long-term Debt – Nonaffiliated
                          
                          
                          567,949
                          
                          
                          
                          -Issuance
      of Long-term Debt – Affiliated
                          
                          
                          25,000
                          
                          
                          
                          -Change
      in Advances from Affiliates, Net
                          
                          
                          (459,615
                          )
                          
                          
                          140,874Retirement
      of Long-term Debt – Nonaffiliated
                          
                          
                          -
                          
                          
                          
                          (95,000
                          )Retirement
      of Cumulative Preferred Stock
                          
                          
                          (2
                          )
                          
                          
                          -Principal
      Payments for Capital Lease Obligations
                          
                          
                          (10,377
                          )
                          
                          
                          (8,529
                          )Dividends
      Paid on Common Stock
                          
                          
                          (24,500
                          )
                          
                          
                          (18,750
                          )Dividends
      Paid on Cumulative Preferred Stock
                          
                          
                          (85
                          )
                          
                          
                          (85
                          )Net
      Cash Flows from Financing Activities
                          
                          
                          98,370
                          
                          
                          
                          18,510Net
      Increase in Cash and Cash Equivalents
                          
                          
                          255
                          
                          
                          
                          592Cash
      and Cash Equivalents at Beginning of Period
                          
                          
                          728
                          
                          
                          
                          1,139Cash
      and Cash Equivalents at End of Period
                          
                          $
                          983
                          
                          
                          $
                          1,731
 
 SUPPLEMENTARY
      INFORMATIONCash
      Paid for Interest, Net of Capitalized Amounts
                  
                  $
                  35,231
                  
                  
                  $
                  20,216Net
      Cash Received for Income Taxes
                  
                  
                  (355
                  )
                  
                  
                  (1,118
                  )Noncash
      Acquisitions Under Capital Leases
                  
                  
                  705
                  
                  
                  
                  2,023Construction
      Expenditures Included in Accounts Payable at March 31,
                  
                  
                  29,910
                  
                  
                  
                  16,280Acquisition
      of Nuclear Fuel Included in Accounts Payable at March 31,
                  
                  
                  17,016
                  
                  
                  
                  -
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
  
 INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
 INDEX
TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT
SUBSIDIARIES
 
 The
condensed notes to I&M’s condensed consolidated financial statements are
combined with the condensed notes to condensed financial statements for other
registrant subsidiaries.  Listed below are the notes that apply to
I&M.
 Footnote
                                  ReferenceSignificant
      Accounting Matters
                                Note
      1New
      Accounting Pronouncements
                                Note
      2Rate
      Matters
                                Note
      3Commitments,
      Guarantees and Contingencies
                                Note
      4Benefit
      Plans
                                Note
      5Business
      Segments
                                Note
      6Derivatives,
      Hedging and Fair Value Measurements
                                Note
      7Income
      Taxes
                                Note
      8Financing
      Activities
                                Note
      9
  
  
 
 
 
 
 OHIO
POWER COMPANY CONSOLIDATED
 
  
 OHIO POWER COMPANY CONSOLIDATED
 MANAGEMENT’S FINANCIAL
DISCUSSION AND ANALYSIS
 
 Results of
Operations
 
 First Quarter of 2009
Compared to First Quarter of 2008
 
 Reconciliation
of First Quarter of 2008 to First Quarter of 2009
 Net
Income
 (in
millions)
 
 First
      Quarter of 2008
                      
                      
                      
                      
                      $
                      138Changes
      in Gross Margin:Retail
      Margins
                      
                      
                      (37
                      )Off-system
      Sales
                      
                      
                      (29
                      )Other
                      
                      
                      10Total
      Change in Gross Margin
                      
                      
                      
                      
                      
                      
                      (56
                      )Changes
      in Operating Expenses and Other:Other
      Operation and Maintenance
                      
                      
                      (21
                      )Depreciation
      and Amortization
                      
                      
                      (15
                      )Carrying
      Costs Income
                      
                      
                      (2
                      )Other
      Income
                      
                      
                      (2
                      )Interest
      Expense
                      
                      
                      (5
                      )Total
      Change in Operating Expenses and Other
                      
                      
                      
                      
                      
                      
                      (45
                      )Income
      Tax Expense
                      
                      
                      
                      
                      
                      
                      36First
      Quarter of 2009
                      
                      
                      
                      
                      
                      $
                      73
 
 Net
Income decreased $65 million to $73 million in 2009.  The key drivers
of the decrease were a $56 million decrease in Gross Margin and a $45 million
increase in Operating Expenses and Other offset by a $36 million decrease in
Income Tax Expense.
 
 The major
components of the decrease in Gross Margin, defined as revenues less the related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power were as follows:
 
 ·
              Retail
      Margins decreased $37 million primarily due to the
    following:·
              A
      $58 million decrease in fuel expense related to a coal contract amendment
      recorded in 2008 which reduced future deliveries to OPCo in exchange for
      consideration received.·
              A
      $6 million decrease in retail and wholesale sales driven by lower
      industrial usage.These
      decreases were partially offset by:·
              A
      $1 million increase in fuel margins due to the deferral of fuel costs in
      2009.  The PUCO’s March 2009 approval of OPCo’s ESP allows for
      the recovery of fuel and related costs beginning January 1,
      2009.  See “Ohio Electric Security Plan Filings” section of Note
      3.·
              A
      $9 million increase in capacity settlements under the Interconnection
      Agreement.·
              An
      $8 million increase related to new rates implemented due to the accrual
      for March unbilled revenues at higher rates set by the Ohio
      ESP.·
              Margins
      from Off-system Sales decreased $29 million primarily due to lower
      physical sales volumes and lower margins as a result of lower market
      prices, partially offset by higher trading margins.·
              Other
      revenues increased $10 million primarily due to increased gains on sales
      of emission allowances.  Due to the implementation of OPCo’s ESP
      as discussed above, emission gains and losses incurred after January 1,
      2009 will be included in OPCo’s fuel adjustment
  clause.
  Operating
Expenses and Other and Income Tax Expense changed between years as
follows:
 
 ·
              Other
      Operation and Maintenance expenses increased $21 million primarily due
      to:·
              An
      $8 million increase related to an obligation to contribute to the
      “Partnership with Ohio” fund for low income, at-risk customers ordered by
      the PUCO’s March 2009 approval of OPCo’s ESP.  See “Ohio
      Electric Security Plan Filings” section of Note 3.·
              An
      $8 million increase in recoverable PJM expenses.·
              A
      $7 million increase in maintenance of overhead lines primarily due to ice
      and wind storm costs incurred in January and February
  2009.·
              A
      $4 million increase in maintenance expenses from planned and forced
      outages at various plants.These
      increases were partially offset by:·
              A
      $7 million decrease in employee-related expenses.·
              Depreciation
      and Amortization increased $15 million primarily due
to:·
              A
      $19 million increase from higher depreciable property balances as a result
      of environmental improvements placed in service and various other property
      additions and higher depreciation rates related to shortened depreciable
      lives for certain generating facilities.·
              A
      $2 million increase as a result of the completion of the amortization of a
      regulated liability in December 2008 related to energy sales to Ormet at
      below market rates.  See “Ormet” section of Note
    3.These
      increases were partially offset by:·
              A
      $7 million decrease due to the completion of the amortization of
      regulatory assets in December 2008.·
              Income
      Tax Expense decreased $36 million primarily due to a decrease in pretax
      book income.
 
 Financial
Condition
 
 Credit
Ratings
 
 OPCo’s
credit ratings as of March 31, 2009 were as follows:
 
 Moody’s
                
                S&P
                
                FitchSenior
      Unsecured Debt
                A3
                
                BBB
                
                BBB+
 
 S&P
and Fitch have OPCo on stable outlook while Moody’s has OPCo on negative
outlook.  In January 2009, Moody’s placed OPCo on review for possible
downgrade due to concerns about financial metrics and pending cost and
construction recoveries.  If OPCo receives a downgrade from any of the
rating agencies, its borrowing costs could increase and access to borrowed funds
could be negatively affected.
 
 Cash
Flow
 
 Cash
flows for the three months ended March 31, 2009 and 2008 were as
follows:
 
 2009
                    
                    
                    2008(in
      thousands)Cash
      and Cash Equivalents at Beginning of Period
                    
                    $
                    12,679
                    
                    
                    $
                    6,666Cash
      Flows from (Used for):Operating
      Activities
                    
                    
                    (22,900
                    )
                    
                    
                    150,065Investing
      Activities
                    
                    
                    (156,584
                    )
                    
                    
                    (140,253
                    )Financing
      Activities
                    
                    
                    180,174
                    
                    
                    
                    (12,861
                    )Net
      Increase (Decrease) in Cash and Cash Equivalents
                    
                    
                    690
                    
                    
                    
                    (3,049
                    )Cash
      and Cash Equivalents at End of Period
                    
                    $
                    13,369
                    
                    
                    $
                    3,617
 
 Operating
Activities
 
 Net Cash
Flows Used for Operating Activities were $23 million in 2009.  OPCo
produced income of $73 million during the period and a noncash expense item of
$84 million for Depreciation and Amortization, $72 million for Deferred Income
Taxes and $65 million for Fuel Over/Under-Recovery due to an under-recovery of
fuel costs in Ohio.  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 number of
items.  Accounts Payable had a $95 million cash outflow primarily due
to OPCo’s provision for revenue refund of $62 million which was paid in the
first quarter 2009 to the AEP West companies as part of the FERC’s recent order
on the SIA.  Accrued Taxes, Net had a $79 million cash outflow due to
a decrease of federal income tax related accruals and temporary timing
differences of payments for property taxes.  Fuel, Materials and
Supplies had a $53 million cash outflow primarily due to an increase in coal
inventory.  Accounts Receivable, Net had a $40 million inflow due to
timing differences of payments from customers and the receipt of final payment
due to a coal contract amendment.
 
 Net Cash
Flows from Operating Activities were $150 million in 2008.  OPCo
produced Net Income of $138 million during the period and a noncash expense item
of $69 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
relates to Accounts Receivable, Net.  Accounts Receivable, Net had a
$22 million outflow primarily due to a coal contract amendment in January
2008.
 
 Investing
Activities
 
 Net Cash
Used for Investing Activities were $157 million and $140 million in 2009 and
2008, respectively.  Construction Expenditures were $163 million and
$142 million in 2009 and 2008, respectively, primarily related to environmental
upgrades, as well as projects to improve service reliability for transmission
and distribution.  Environmental upgrades include the installation of
selective catalytic reduction equipment and the flue gas desulfurization
projects at the Cardinal, Amos and Mitchell plants.   OPCo
forecasts approximately $439 million of construction expenditures for all of
2009, excluding AFUDC.
 
 Financing
Activities
 
 Net Cash
Flows from Financing Activities were $180 million in 2009 primarily due to a net
increase of $186 million in borrowings from the Utility Money Pool.
 
 Net Cash
Flows Used for Financing Activities were $13 million in 2008 primarily due to a
net decrease of $14 million in borrowings from the Utility Money
Pool.
 
 Financing
Activity
 
 Long-term
debt issuances and principal payments made during the first three months of 2009
were:
 
 Issuances
 
 None
 
 Principal
Payments
 Principal
                      Amount
      Paid
                    
                    Interest
                    
                    DueType
      of Debt
                    
                    
                    Rate
                    
                    Date(in
      thousands)
                    
                    (%)Notes
      Payable – Nonaffiliated
                    
                    $
                    3,500
                    
                    7.21
                    
                    2009Notes
      Payable – Nonaffiliated
                    
                    
                    1,000
                    
                    6.27
                    
                    2009
 
 Liquidity
 
 The
financial markets remain volatile at both a global and domestic
level.  This marketplace distress could impact OPCo’s access to
capital, liquidity and cost of capital.  The uncertainties in the
capital markets could have significant implications on OPCo since it relies on
continuing access to capital to fund operations and capital
expenditures.  Management cannot predict the length of time the credit
situation will continue or its impact on OPCo’s operations and ability to issue
debt at reasonable interest rates.
 
 OPCo
participates in the Utility Money Pool, which provides access to AEP’s
liquidity.  OPCo has $78 million of Notes Payable that will mature in
2009.  To the extent refinancing is unavailable due to challenging
credit markets, OPCo will rely upon cash flows from operations and access to the
Utility Money Pool to fund its maturities, current operations and capital
expenditures.
 
 See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for additional discussion of liquidity.
 
 Summary Obligation
Information
 
 A summary
of contractual obligations is included in the 2008 Annual Report and has not
changed significantly from year-end.
 
 Significant
Factors
 
 Litigation
and Regulatory Activity
 
 In the
ordinary course of business, OPCo is involved in employment, commercial,
environmental and regulatory litigation.  Since it is difficult to
predict the outcome of these proceedings, management cannot state what the
eventual outcome of these proceedings will be, or what the timing of the amount
of any loss, fine or penalty may be.  Management does, however, assess
the probability of loss for such contingencies and accrues a liability for cases
which have a probable likelihood of loss and the loss amount can be
estimated.  For details on regulatory proceedings and pending
litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and
Contingencies in the 2008 Annual Report.  Also, see Note 3 – Rate
Matters and Note 4 – Commitments, Guarantees and Contingencies in the “Condensed
Notes to Condensed Financial Statements of Registrant Subsidiaries”
section.  Adverse results in these proceedings have the potential to
materially affect net income, financial condition and cash flows.
 
 See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for additional discussion of relevant factors.
 
 Critical Accounting
Estimates
 
 See the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in the 2008 Annual Report for a discussion
of the estimates and judgments required for regulatory accounting, revenue
recognition, the valuation of long-lived assets, pension and other
postretirement benefits and the impact of new accounting
pronouncements.
 
 Adoption of New Accounting
Pronouncements
 
 See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for a discussion of adoption of new accounting
pronouncements.
  
 QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
 
 Market
Risks
 
 Risk
management assets and liabilities are managed by AEPSC as agent.  The
related risk management policies and procedures are instituted and administered
by AEPSC.  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 OPCo.
 
 MTM
Risk Management Contract Net Assets
 
 The
following two tables summarize the various mark-to-market (MTM) positions
included in OPCo’s Condensed Consolidated Balance Sheet as of March 31, 2009 and
the reasons for changes in total MTM value as compared to December 31,
2008.
 
 Reconciliation
of MTM Risk Management Contracts to
 Condensed
Consolidated Balance Sheet
 March
31, 2009
 (in
thousands)
 
 MTM
      Risk Management Contracts
                  
                  
                  Cash
      Flow Hedge
                    Contracts
                  
                  
                  DETM
      Assignment (a)
                  
                  
                  Collateral
                    Deposits
                  
                  
                  TotalCurrent
      Assets
                  
                  $
                  65,411
                  
                  
                  $
                  5,646
                  
                  
                  $
                  -
                  
                  
                  $
                  (7,697
                  )
                  
                  $
                  63,360Noncurrent
      Assets
                  
                  
                  54,262
                  
                  
                  
                  156
                  
                  
                  
                  -
                  
                  
                  
                  (8,753
                  )
                  
                  
                  45,665Total
      MTM Derivative Contract Assets
                  
                  
                  119,673
                  
                  
                  
                  5,802
                  
                  
                  
                  -
                  
                  
                  
                  (16,450
                  )
                  
                  
                  109,025Current
      Liabilities
                  
                  
                  (40,578
                  )
                  
                  
                  (1,268
                  )
                  
                  
                  (1,772
                  )
                  
                  
                  7,723
                  
                  
                  
                  (35,895
                  )Noncurrent
      Liabilities
                  
                  
                  (39,704
                  )
                  
                  
                  (27
                  )
                  
                  
                  (1,203
                  )
                  
                  
                  15,939
                  
                  
                  
                  (24,995
                  )Total
      MTM Derivative Contract Liabilities
                  
                  
                  (80,282
                  )
                  
                  
                  (1,295
                  )
                  
                  
                  (2,975
                  )
                  
                  
                  23,662
                  
                  
                  
                  (60,890
                  )Total
      MTM Derivative Contract Net Assets (Liabilities)
                  
                  $
                  39,391
                  
                  
                  $
                  4,507
                  
                  
                  $
                  (2,975
                  )
                  
                  $
                  7,212
                  
                  
                  $
                  48,135
  (a)
              See
      “Natural Gas Contracts with DETM” section of Note 15 of the 2008 Annual
      Report.
 
 MTM
Risk Management Contract Net Assets
 Three
Months Ended March 31, 2009
 (in
thousands)
 
 Total
      MTM Risk Management Contract Net Assets at December 31,
    2008
                  
                  $
                  37,761(Gain)
      Loss from Contracts Realized/Settled During the Period and Entered in a
      Prior Period
                  
                  
                  (4,634
                  )Fair
      Value of New Contracts at Inception When Entered During the Period
      (a)
                  
                  
                  1,153Net
      Option Premiums Paid/(Received) for Unexercised or Unexpired Option
      Contracts Entered During the Period
                  
                  
                  -Change
      in Fair Value Due to Valuation Methodology Changes on Forward
      Contracts
                  
                  
                  -Changes
      in Fair Value Due to Market Fluctuations During the Period
    (b)
                  
                  
                  4,165Changes
      in Fair Value Allocated to Regulated Jurisdictions (c)
                  
                  
                  946Total
      MTM Risk Management Contract Net Assets
                  
                  
                  39,391Cash
      Flow Hedge Contracts
                  
                  
                  4,507DETM
      Assignment (d)
                  
                  
                  (2,975
                  )Collateral
      Deposits
                  
                  
                  7,212Ending
      Net Risk Management Assets at March 31, 2009
                  
                  $
                  48,135
 
 (a)
              Reflects
      fair value on long-term contracts which are typically with customers that
      seek fixed pricing to limit their risk against fluctuating energy
      prices.  The contract prices are valued against market curves
      associated with the delivery location and delivery term.  A
      significant portion of the total volumetric position has been economically
      hedged.(b)
              Market
      fluctuations are attributable to various factors such as supply/demand,
      weather, etc.(c)
              “Changes
      in Fair Value Allocated to Regulated Jurisdictions” relates to the net
      gains (losses) of those contracts that are not reflected in the Condensed
      Consolidated Statements of Income.  These net gains (losses) are
      recorded as regulatory liabilities/assets.(d)
              See
      “Natural Gas Contracts with DETM” section of Note 15 of the 2008 Annual
      Report.
 
 Maturity
and Source of Fair Value of MTM Risk Management Contract Net Assets
 
 The
following table presents the maturity, by year, of net assets/liabilities to
give 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, 2009
 (in
thousands)
 
 Remainder
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    After2009
                    
                    
                    2010
                    
                    
                    2011
                    
                    
                    2012
                    
                    
                    2013
                    
                    
                    2013
                    
                    
                    TotalLevel
      1 (a)
                    
                    $
                    (1,193
                    )
                    
                    $
                    (31
                    )
                    
                    $
                    1
                    
                    
                    $
                    -
                    
                    
                    $
                    -
                    
                    
                    $
                    -
                    
                    
                    $
                    (1,223
                    )Level
      2 (b)
                    
                    
                    15,214
                    
                    
                    
                    6,549
                    
                    
                    
                    3,357
                    
                    
                    
                    (342
                    )
                    
                    
                    26
                    
                    
                    
                    -
                    
                    
                    
                    24,804Level
      3 (c)
                    
                    
                    3,633
                    
                    
                    
                    1,826
                    
                    
                    
                    1,103
                    
                    
                    
                    1,096
                    
                    
                    
                    144
                    
                    
                    
                    -
                    
                    
                    
                    7,802Total
                    
                    
                    17,654
                    
                    
                    
                    8,344
                    
                    
                    
                    4,461
                    
                    
                    
                    754
                    
                    
                    
                    170
                    
                    
                    
                    -
                    
                    
                    
                    31,383Dedesignated
      Risk Management Contracts (d)
                    
                    
                    2,456
                    
                    
                    
                    3,195
                    
                    
                    
                    1,244
                    
                    
                    
                    1,113
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    8,008Total
      MTM Risk Management Contract Net Assets
                    
                    $
                    20,110
                    
                    
                    $
                    11,539
                    
                    
                    $
                    5,705
                    
                    
                    $
                    1,867
                    
                    
                    $
                    170
                    
                    
                    $
                    -
                    
                    
                    $
                    39,391
 
 (a)
              Level
      1 inputs are quoted prices (unadjusted) in active markets for identical
      assets or liabilities that the reporting entity has the ability to access
      at the measurement date.  Level 1 inputs primarily consist of
      exchange traded contracts that exhibit sufficient frequency and volume to
      provide pricing information on an ongoing basis.(b)
              Level
      2 inputs are inputs other than quoted prices included within Level 1 that
      are observable for the asset or liability, either directly or
      indirectly.  If the asset or liability has a specified
      (contractual) term, a Level 2 input must be observable for substantially
      the full term of the asset or liability.  Level 2 inputs
      primarily consist of OTC broker quotes in moderately active or less active
      markets, exchange traded contracts where there was not sufficient market
      activity to warrant inclusion in Level 1 and OTC broker quotes that are
      corroborated by the same or similar transactions that have occurred in the
      market.(c)
              Level
      3 inputs are unobservable inputs for the asset or
      liability.  Unobservable inputs shall be used to measure fair
      value to the extent that the observable inputs are not available, thereby
      allowing for situations in which there is little, if any, market activity
      for the asset or liability at the measurement date.  Level 3
      inputs primarily consist of unobservable market data or are valued based
      on models and/or assumptions.(d)
              Dedesignated
      Risk Management Contracts are contracts that were originally MTM but were
      subsequently elected as normal under SFAS 133.  At the time of
      the normal election, the MTM value was frozen and no longer fair
      valued.  This will be amortized into Revenues over the remaining
      life of the contracts.
 
 Credit
Risk
 
 Counterparty
credit quality and exposure is generally consistent with that of
AEP.
 
 See Note
7 for further information regarding MTM risk management contracts, cash flow
hedging, accumulated other comprehensive income, credit risk and collateral
triggering events.
 
 VaR
Associated with Risk Management Contracts
 
 Management
uses a risk measurement model, which calculates Value at Risk (VaR) to measure
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, 2009, a near
term typical change in commodity prices is not expected to have a material
effect on net income, cash flows or financial condition.
  The
following table shows the end, high, average, and low market risk as measured by
VaR for the periods indicated:
 
 Three
      Months Ended
              
              
              
              
              Twelve
      Months EndedMarch
      31, 2009
              
              
              
              
              December
      31, 2008(in
      thousands)
              
              
              
              
              (in
      thousands)End
              
              High
              
              Average
              
              Low
              
              
              
              
              End
              
              High
              
              Average
              
              Low$247
              
              $439
              
              $238
              
              $113
              
              
              
              
              $140
              
              $1,284
              
              $411
              
              $131
 
 Management
back-tests its VaR results against performance due to actual price
moves.  Based on the assumed 95% confidence interval, performance due
to actual price moves would be expected to exceed the VaR at least once every 20
trading days.  Management’s backtesting results show that its actual
performance exceeded VaR far fewer than once every 20 trading
days.  As a result, management believes OPCo’s VaR calculation is
conservative.
 
 As OPCo’s
VaR calculation captures recent price moves, management also performs regular
stress testing of the portfolio to understand OPCo’s exposure to extreme price
moves.  Management employs a historical-based method whereby the
current portfolio is subjected to actual, observed price moves from the last
three years in order to ascertain which historical price moves translated into
the largest potential MTM loss.  Management then researches the
underlying positions, price moves and market events that created the most
significant exposure.
 
 Interest
Rate Risk
 
 Management
utilizes an Earnings at Risk (EaR) model to measure interest rate market risk
exposure.  EaR statistically quantifies the extent to which OPCo’s
interest expense could vary over the next twelve months and gives a
probabilistic estimate of different levels of interest expense.  The
resulting EaR is interpreted as the dollar amount by which actual interest
expense for the next twelve months could exceed expected interest expense with a
one-in-twenty chance of occurrence.  The primary drivers of EaR are
from the existing floating rate debt (including short-term debt) as well as
long-term debt issuances in the next twelve months.  The estimated EaR
on OPCo’s debt portfolio was $12 million.
  
 OHIO
POWER COMPANY CONSOLIDATED
 CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
 For
the Three Months Ended March 31, 2009 and 2008
 (in
thousands)
 (Unaudited)
 2009
                      
                      
                      2008REVENUESElectric
      Generation, Transmission and Distribution
                      
                      $
                      524,686
                      
                      
                      $
                      555,478Sales
      to AEP Affiliates
                      
                      
                      226,694
                      
                      
                      
                      236,848Other
      - Affiliated
                      
                      
                      7,488
                      
                      
                      
                      5,299Other
      - Nonaffiliated
                      
                      
                      3,847
                      
                      
                      
                      4,563TOTAL
                      
                      
                      762,715
                      
                      
                      
                      802,188EXPENSESFuel
      and Other Consumables Used for Electric Generation
                      
                      
                      253,474
                      
                      
                      
                      238,934Purchased
      Electricity for Resale
                      
                      
                      52,269
                      
                      
                      
                      34,577Purchased
      Electricity from AEP Affiliates
                      
                      
                      16,742
                      
                      
                      
                      32,516Other
      Operation
                      
                      
                      99,598
                      
                      
                      
                      89,882Maintenance
                      
                      
                      60,040
                      
                      
                      
                      48,697Depreciation
      and Amortization
                      
                      
                      84,023
                      
                      
                      
                      68,566Taxes
      Other Than Income Taxes
                      
                      
                      51,492
                      
                      
                      
                      51,578TOTAL
                      
                      
                      617,638
                      
                      
                      
                      564,750OPERATING
      INCOME
                      
                      
                      145,077
                      
                      
                      
                      237,438Other
      Income (Expense):Interest
      Income
                      
                      
                      244
                      
                      
                      
                      2,908Carrying
      Costs Income
                      
                      
                      1,584
                      
                      
                      
                      4,229Allowance
      for Equity Funds Used During Construction
                      
                      
                      867
                      
                      
                      
                      544Interest
      Expense
                      
                      
                      (38,681
                      )
                      
                      
                      (33,919
                      )INCOME
      BEFORE INCOME TAX EXPENSE
                      
                      
                      109,091
                      
                      
                      
                      211,200Income
      Tax Expense
                      
                      
                      36,482
                      
                      
                      
                      72,910NET
      INCOME
                      
                      
                      72,609
                      
                      
                      
                      138,290Less:
      Net Income Attributable to Noncontrolling Interest
                      
                      
                      463
                      
                      
                      
                      463NET
      INCOME ATTRIBUTABLE TO OPCo SHAREHOLDERS
                      
                      
                      72,146
                      
                      
                      
                      137,827Less:
      Preferred Stock Dividend Requirements
                      
                      
                      183
                      
                      
                      
                      183EARNINGS
      ATTRIBUTABLE TO OPCo COMMON SHAREHOLDER
                      
                      $
                      71,963
                      
                      
                      $
                      137,644
 
 The
      common stock of OPCo is wholly-owned by
AEP.
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
  
 OHIO
POWER COMPANY CONSOLIDATED
 CONDENSED
CONSOLIDATED STATEMENTS OF CHANGES IN
 EQUITY
AND COMPREHENSIVE INCOME (LOSS)
 For
the Three Months Ended March 31, 2009 and 2008
 (in
thousands)
 (Unaudited)
 
 OPCo
      Common ShareholderCommon
      Stock
                      
                      
                      Paid-in
      Capital
                      
                      
                      Retained
      Earnings
                      
                      
                      Accumulated
                        Other
                        Comprehensive
                        Income
      (Loss)
                      
                      
                      Noncontrolling
                        Interest
                      
                      
                      TotalDECEMBER
      31, 2007
                      
                      $
                      321,201
                      
                      
                      $
                      536,640
                      
                      
                      $
                      1,469,717
                      
                      
                      $
                      (36,541
                      )
                      
                      $
                      15,923
                      
                      
                      $
                      2,306,940EITF
      06-10 Adoption, Net of Tax of $1,004
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      (1,864
                      )
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      (1,864
                      )SFAS
      157 Adoption, Net of Tax of $152
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      (282
                      )
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      (282
                      )Common
      Stock Dividends – Nonaffiliated
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      (463
                      )
                      
                      
                      (463
                      )Preferred
      Stock Dividends
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      (183
                      )
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      (183
                      )Other
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      2,015
                      
                      
                      
                      2,015TOTAL
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      2,306,163COMPREHENSIVE
      INCOMEOther
      Comprehensive Income (Loss), Net of Taxes:Cash
      Flow Hedges, Net of Tax of $4,745
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      (8,811
                      )
                      
                      
                      
                      
                      
                      
                      (8,811
                      )Amortization
      of Pension and OPEB Deferred Costs, Net of  Tax of
      $379
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      703
                      
                      
                      
                      
                      
                      
                      
                      703NET
      INCOME
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      137,827
                      
                      
                      
                      
                      
                      
                      
                      463
                      
                      
                      
                      138,290TOTAL
      COMPREHENSIVE INCOME
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      130,182MARCH
      31, 2008
                      
                      $
                      321,201
                      
                      
                      $
                      536,640
                      
                      
                      $
                      1,605,215
                      
                      
                      $
                      (44,649
                      )
                      
                      $
                      17,938
                      
                      
                      $
                      2,436,345DECEMBER
      31, 2008
                      
                      $
                      321,201
                      
                      
                      $
                      536,640
                      
                      
                      $
                      1,697,962
                      
                      
                      $
                      (133,858
                      )
                      
                      $
                      16,799
                      
                      
                      $
                      2,438,744Common
      Stock Dividends – Nonaffiliated
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      (463
                      )
                      
                      
                      (463
                      )Preferred
      Stock Dividends
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      (183
                      )
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      (183
                      )Other
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      1,111
                      
                      
                      
                      1,111TOTAL
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      2,439,209COMPREHENSIVE
      INCOMEOther
      Comprehensive Income, Net of Taxes:Cash
      Flow Hedges, Net of Tax of $570
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      1,058
                      
                      
                      
                      
                      
                      
                      
                      1,058Amortization
      of Pension and OPEB Deferred Costs, Net of  Tax of
      $855
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      1,588
                      
                      
                      
                      
                      
                      
                      
                      1,588NET
      INCOME
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      72,146
                      
                      
                      
                      
                      
                      
                      
                      463
                      
                      
                      
                      72,609TOTAL
      COMPREHENSIVE INCOME
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      
                      75,255MARCH
      31, 2009
                      
                      $
                      321,201
                      
                      
                      $
                      536,640
                      
                      
                      $
                      1,769,925
                      
                      
                      $
                      (131,212
                      )
                      
                      $
                      17,910
                      
                      
                      $
                      2,514,464
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
 
  
 OHIO
POWER COMPANY CONSOLIDATED
 CONDENSED
CONSOLIDATED BALANCE SHEETS
 ASSETS
 March
31, 2009 and December 31, 2008
 (in
thousands)
 (Unaudited)
 2009
                  
                  
                  2008CURRENT
      ASSETSCash
      and Cash Equivalents
                  
                  $
                  13,369
                  
                  
                  $
                  12,679Accounts
      Receivable:Customers
                  
                  
                  76,210
                  
                  
                  
                  91,235Affiliated
      Companies
                  
                  
                  99,508
                  
                  
                  
                  118,721Accrued
      Unbilled Revenues
                  
                  
                  22,658
                  
                  
                  
                  18,239Miscellaneous
                  
                  
                  12,797
                  
                  
                  
                  23,393Allowance
      for Uncollectible Accounts
                  
                  
                  (3,630
                  )
                  
                  
                  (3,586
                  )Total
      Accounts Receivable
                  
                  
                  207,543
                  
                  
                  
                  248,002Fuel
                  
                  
                  238,012
                  
                  
                  
                  186,904Materials
      and Supplies
                  
                  
                  108,899
                  
                  
                  
                  107,419Risk
      Management Assets
                  
                  
                  63,360
                  
                  
                  
                  53,292Accrued
      Tax Benefits
                  
                  
                  51,287
                  
                  
                  
                  13,568Prepayments
      and Other
                  
                  
                  40,101
                  
                  
                  
                  42,999TOTAL
                  
                  
                  722,571
                  
                  
                  
                  664,863PROPERTY,
      PLANT AND EQUIPMENTElectric:Production
                  
                  
                  6,589,421
                  
                  
                  
                  6,025,277Transmission
                  
                  
                  1,128,310
                  
                  
                  
                  1,111,637Distribution
                  
                  
                  1,493,642
                  
                  
                  
                  1,472,906Other
                  
                  
                  390,415
                  
                  
                  
                  391,862Construction
      Work in Progress
                  
                  
                  270,475
                  
                  
                  
                  787,180Total
                  
                  
                  9,872,263
                  
                  
                  
                  9,788,862Accumulated
      Depreciation and Amortization
                  
                  
                  3,149,697
                  
                  
                  
                  3,122,989TOTAL
      - NET
                  
                  
                  6,722,566
                  
                  
                  
                  6,665,873OTHER
      NONCURRENT ASSETSRegulatory
      Assets
                  
                  
                  510,585
                  
                  
                  
                  449,216Long-term
      Risk Management Assets
                  
                  
                  45,665
                  
                  
                  
                  39,097Deferred
      Charges and Other
                  
                  
                  160,171
                  
                  
                  
                  184,777TOTAL
                  
                  
                  716,421
                  
                  
                  
                  673,090TOTAL
      ASSETS
                  
                  $
                  8,161,558
                  
                  
                  $
                  8,003,826
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
 
  
 OHIO
POWER COMPANY CONSOLIDATED
 CONDENSED
CONSOLIDATED BALANCE SHEETS
 LIABILITIES
AND EQUITY
 March
31, 2009 and December 31, 2008
 (Unaudited)
 2009
                      
                      
                      2008CURRENT
      LIABILITIES
                      
                      (in
      thousands)Advances
      from Affiliates
                      
                      $
                      320,166
                      
                      
                      $
                      133,887Accounts
      Payable:General
                      
                      
                      188,516
                      
                      
                      
                      193,675Affiliated
      Companies
                      
                      
                      99,427
                      
                      
                      
                      206,984Long-term
      Debt Due Within One Year – Nonaffiliated
                      
                      
                      73,000
                      
                      
                      
                      77,500Risk
      Management Liabilities
                      
                      
                      35,895
                      
                      
                      
                      29,218Customer
      Deposits
                      
                      
                      26,406
                      
                      
                      
                      24,333Accrued
      Taxes
                      
                      
                      146,442
                      
                      
                      
                      187,256Accrued
      Interest
                      
                      
                      35,934
                      
                      
                      
                      44,245Other
                      
                      
                      166,113
                      
                      
                      
                      163,702TOTAL
                      
                      
                      1,091,899
                      
                      
                      
                      1,060,800NONCURRENT
      LIABILITIESLong-term
      Debt – Nonaffiliated
                      
                      
                      2,762,039
                      
                      
                      
                      2,761,876Long-term
      Debt – Affiliated
                      
                      
                      200,000
                      
                      
                      
                      200,000Long-term
      Risk Management Liabilities
                      
                      
                      24,995
                      
                      
                      
                      23,817Deferred
      Income Taxes
                      
                      
                      971,014
                      
                      
                      
                      927,072Regulatory
      Liabilities and Deferred Investment Tax Credits
                      
                      
                      127,916
                      
                      
                      
                      127,788Employee
      Benefits and Pension Obligations
                      
                      
                      284,918
                      
                      
                      
                      288,106Deferred
      Credits and Other
                      
                      
                      167,686
                      
                      
                      
                      158,996TOTAL
                      
                      
                      4,538,568
                      
                      
                      
                      4,487,655TOTAL
      LIABILITIES
                      
                      
                      5,630,467
                      
                      
                      
                      5,548,455Cumulative
      Preferred Stock Not Subject to Mandatory Redemption
                      
                      
                      16,627
                      
                      
                      
                      16,627Commitments
      and Contingencies (Note 4)EQUITYCommon
      Stock – No Par Value:Authorized
      – 40,000,000 SharesOutstanding
      – 27,952,473 Shares
                      
                      
                      321,201
                      
                      
                      
                      321,201Paid-in
      Capital
                      
                      
                      536,640
                      
                      
                      
                      536,640Retained
      Earnings
                      
                      
                      1,769,925
                      
                      
                      
                      1,697,962Accumulated
      Other Comprehensive Income (Loss)
                      
                      
                      (131,212
                      )
                      
                      
                      (133,858
                      )TOTAL
      COMMON SHAREHOLDER’S EQUITY
                      
                      
                      2,496,554
                      
                      
                      
                      2,421,945Noncontrolling
      Interest
                      
                      
                      17,910
                      
                      
                      
                      16,799TOTAL
      EQUITY
                      
                      
                      2,514,464
                      
                      
                      
                      2,438,744TOTAL
      LIABILITIES AND EQUITY
                      
                      $
                      8,161,558
                      
                      
                      $
                      8,003,826
 
 See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
  
 OHIO
POWER COMPANY CONSOLIDATED
 CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS
 For
the Three Months Ended March 31, 2009 and 2008
 (in
thousands)
 (Unaudited)
 2009
                          
                          
                          2008OPERATING
      ACTIVITIESNet
      Income
                          
                          $
                          72,609
                          
                          
                          $
                          138,290Adjustments
      to Reconcile Net Income to Net Cash Flows from (Used for) Operating
      Activities:Depreciation
      and Amortization
                          
                          
                          84,023
                          
                          
                          
                          68,566Deferred
      Income Taxes
                          
                          
                          71,740
                          
                          
                          
                          10,850Carrying
      Costs Income
                          
                          
                          (1,584
                          )
                          
                          
                          (4,229
                          )Allowance
      for Equity Funds Used During Construction
                          
                          
                          (867
                          )
                          
                          
                          (544
                          )Mark-to-Market
      of Risk Management Contracts
                          
                          
                          (7,117
                          )
                          
                          
                          (5,035
                          )Deferred
      Property Taxes
                          
                          
                          21,527
                          
                          
                          
                          20,574Fuel
      Over/Under-Recovery, Net
                          
                          
                          (65,192
                          )
                          
                          
                          -Change
      in Other Noncurrent Assets
                          
                          
                          1,669
                          
                          
                          
                          (46,438
                          )Change
      in Other Noncurrent Liabilities
                          
                          
                          19,318
                          
                          
                          
                          5,397Changes
      in Certain Components of Working Capital:Accounts
      Receivable, Net
                          
                          
                          39,518
                          
                          
                          
                          (21,586
                          )Fuel,
      Materials and Supplies
                          
                          
                          (52,588
                          )
                          
                          
                          (4,130
                          )Accounts
      Payable
                          
                          
                          (95,306
                          )
                          
                          
                          9,005Customer
      Deposits
                          
                          
                          2,073
                          
                          
                          
                          69Accrued
      Taxes, Net
                          
                          
                          (78,533
                          )
                          
                          
                          15,790Accrued
      Interest
                          
                          
                          (8,311
                          )
                          
                          
                          (4,348
                          )Other
      Current Assets
                          
                          
                          (15,394
                          )
                          
                          
                          (13,020
                          )Other
      Current Liabilities
                          
                          
                          (10,485
                          )
                          
                          
                          (19,146
                          )Net
      Cash Flows from (Used for) Operating Activities
                          
                          
                          (22,900
                          )
                          
                          
                          150,065INVESTING
      ACTIVITIESConstruction
      Expenditures
                          
                          
                          (163,263
                          )
                          
                          
                          (142,257
                          )Proceeds
      from Sales of Assets
                          
                          
                          2,796
                          
                          
                          
                          2,004Other
                          
                          
                          3,883
                          
                          
                          
                          -Net
      Cash Flows Used for Investing Activities
                          
                          
                          (156,584
                          )
                          
                          
                          (140,253
                          )FINANCING
      ACTIVITIESChange
      in Short-term Debt, Net – Nonaffiliated
                          
                          
                          -
                          
                          
                          
                          (701
                          )Change
      in Advances from Affiliates, Net
                          
                          
                          186,279
                          
                          
                          
                          (14,140
                          )Retirement
      of Long-term Debt – Nonaffiliated
                          
                          
                          (4,500
                          )
                          
                          
                          (7,463
                          )Funds
      from Amended Coal Contact
                          
                          
                          -
                          
                          
                          
                          10,000Principal
      Payments for Capital Lease Obligations
                          
                          
                          (1,316
                          )
                          
                          
                          (1,926
                          )Dividends
      Paid on Common Stock – Nonaffiliated
                          
                          
                          (463
                          )
                          
                          
                          (463
                          )Dividends
      Paid on Cumulative Preferred Stock
                          
                          
                          (183
                          )
                          
                          
                          (183
                          )Other
                          
                          
                          357
                          
                          
                          
                          2,015Net
      Cash Flows from (Used for) Financing Activities
                          
                          
                          180,174
                          
                          
                          
                          (12,861
                          )Net
      Increase (Decrease) in Cash and Cash Equivalents
                          
                          
                          690
                          
                          
                          
                          (3,049
                          )Cash
      and Cash Equivalents at Beginning of Period
                          
                          
                          12,679
                          
                          
                          
                          6,666Cash
      and Cash Equivalents at End of Period
                          
                          $
                          13,369
                          
                          
                          $
                          3,617
 
 SUPPLEMENTARY
      INFORMATIONCash
      Paid for Interest, Net of Capitalized Amounts
                  
                  $
                  64,554
                  
                  
                  $
                  37,491Net
      Cash Paid for Income Taxes
                  
                  
                  2,337
                  
                  
                  
                  10,850Noncash
      Acquisitions Under Capital Leases
                  
                  
                  157
                  
                  
                  
                  687Noncash
      Acquisition of Coal Land Rights
                  
                  
                  -
                  
                  
                  
                  41,600Construction
      Expenditures Included in Accounts Payable at March 31,
                  
                  
                  15,767
                  
                  
                  
                  21,828
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
  
 OHIO
POWER COMPANY CONSOLIDATED
 INDEX
TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
 REGISTRANT
SUBSIDIARIES
 
 The
condensed notes to OPCo’s condensed consolidated financial statements are
combined with the condensed notes to condensed financial statements for other
registrant subsidiaries.  Listed below are the notes that apply to
OPCo.
 Footnote
                                  ReferenceSignificant
      Accounting Matters
                                Note
      1New
      Accounting Pronouncements
                                Note
      2Rate
      Matters
                                Note
      3Commitments,
      Guarantees and Contingencies
                                Note
      4Benefit
      Plans
                                Note
      5Business
      Segments
                                Note
      6Derivatives,
      Hedging and Fair Value Measurements
                                Note
      7Income
      Taxes
                                Note
      8Financing
      Activities
                                Note
      9
 
  
  
 
 
 
 
 
 PUBLIC
SERVICE COMPANY OF OKLAHOMA
 
  
 PUBLIC SERVICE COMPANY OF OKLAHOMA
 MANAGEMENT’S FINANCIAL
DISCUSSION AND ANALYSIS
  Results of
Operations
 
 First Quarter of 2009
Compared to First Quarter of 2008
 
 Reconciliation
of First Quarter of 2008 to First Quarter of 2009
 Net
Income
 (in
millions)
 
 First
      Quarter of 2008
                        
                        
                        
                        
                        $
                        37Changes
      in Gross Margin:Retail
      and Off-system Sales Margins
                        
                        
                        17Transmission
      Revenues
                        
                        
                        1Other
                        
                        
                        (9
                        )Total
      Change in Gross Margin
                        
                        
                        
                        
                        
                        
                        9Changes
      in Operating Expenses and Other:Other
      Operation and Maintenance
                        
                        
                        26Deferral
      of Ice Storm Costs
                        
                        
                        (80
                        )Depreciation
      and Amortization
                        
                        
                        (2
                        )Other
      Income
                        
                        
                        (1
                        )Total
      Change in Operating Expenses and Other
                        
                        
                        
                        
                        
                        
                        (57
                        )Income
      Tax Expense
                        
                        
                        
                        
                        
                        
                        17First
      Quarter of 2009
                        
                        
                        
                        
                        
                        $
                        6
 
 Net
Income decreased $31 million to $6 million in 2009.  The key drivers
of the decrease were a $57 million increase in Operating Expenses and Other,
partially offset by a $17 million decrease in Income Tax Expense and a $9
million increase in Gross Margin.
 
 The major
components of the increase in Gross Margin, defined as revenues less the related
direct cost of fuel, including consumption of chemicals and emissions allowances
and purchased power were as follows:
 
 ·
              Retail
      and Off-system Sales Margins increased $17 million primarily due to an
      increase in retail sales margins resulting from base rate adjustments
      during the year.·
              Other
      revenues decreased $9 million primarily due to the recognition of the sale
      of SO2
      allowances in 2008.
 
 Operating
Expenses and Other and Income Tax Expense changed between years as
follows:
 
 ·
              Other
      Operation and Maintenance expenses decreased $26 million primarily due
      to:·
              A
      $10 million decrease primarily due to a write-off in 2008 of
      pre-construction costs related to the cancelled Red Rock Generating
      Facility.·
              A
      $6 million decrease due to the deferral of generation maintenance expenses
      as a result of PSO’s base rate filing.  See “2008 Oklahoma Base
      Rate Filing” section of Note 3.·
              A
      $4 million decrease in amortization of deferred ice storm
      costs.·
              A
      $4 million decrease in employee-related expenses.·
              Deferral
      of Ice Storm Costs in 2008 of $80 million results from an OCC order
      approving recovery of ice storm expenses related to storms in January and
      December 2007.·
              Depreciation
      and Amortization expenses increased $2 million primarily due to the
      amortization of regulatory assets related to the Generation Cost Recovery
      Rider.  See “2008 Oklahoma Base Rate Filing” section of Note
      3.·
              Income
      Tax Expense decreased $17 million primarily due to a decrease in pretax
      book income.
  Financial
Condition
 
 Credit
Ratings
 
 PSO’s
credit ratings as of March 31, 2009 were as follows:
 
 Moody’s
                
                S&P
                
                FitchSenior
      Unsecured Debt
                Baa1
                
                BBB
                
                BBB+
 
 S&P
and Fitch have PSO on stable outlook.  In February 2009, Moody’s
affirmed its stable rating outlook for PSO.  If PSO receives a
downgrade from any of the rating agencies, its borrowing costs could increase
and access to borrowed funds could be negatively affected.
 
 Cash
Flow
 
 Cash
flows for the three months ended March 31, 2009 and 2008 were as
follows:
 
 2009
                    
                    
                    2008(in
      thousands)Cash
      and Cash Equivalents at Beginning of Period
                    
                    $
                    1,345
                    
                    
                    $
                    1,370Cash
      Flows from (Used for):Operating
      Activities
                    
                    
                    103,803
                    
                    
                    
                    (39,805
                    )Investing
      Activities
                    
                    
                    (59,145
                    )
                    
                    
                    (21,853
                    )Financing
      Activities
                    
                    
                    (44,726
                    )
                    
                    
                    61,723Net
      Increase (Decrease) in Cash and Cash Equivalents
                    
                    
                    (68
                    )
                    
                    
                    65Cash
      and Cash Equivalents at End of Period
                    
                    $
                    1,277
                    
                    
                    $
                    1,435
 
 Operating
Activities
 
 Net Cash
Flows from Operating Activities were $104 million in 2009.  PSO
produced Net Income of $6 million during the period and had noncash expense item
of $28 million for Depreciation and Amortization offset by a $28 million
increase in Deferred Property Taxes and a $14 million increase in Deferred
Income 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 working capital relates to a number of items.  The $93 million
inflow from Accounts Receivable, Net was primarily due to receiving the SIA
refund from the AEP East companies and lower customer
receivables.  The $37 million inflow from Accrued Taxes, Net was the
result of increased accruals related to property and income
taxes.  The $37 million inflow from Fuel Over/Under-Recovery, Net was
primarily due to lower fuel costs.  The $29 million outflow from
Accounts Payable was primarily due to timing differences for payments to
affiliates and payment of items accrued at December 31, 2008.
 
 Net Cash
Flows Used for Operating Activities were $40 million in 2008.  PSO
produced Net Income of $37 million during the period and had noncash expense
items of $26 million for Depreciation and Amortization and $38 million for
Deferred Income Taxes offset by a $27 million increase in Deferred Property
Taxes.  PSO established an $80 million regulatory asset for an OCC
order approving recovery of ice storm costs related to storms in January and
December 2007.  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 Accounts
Payable.  Accounts Payable had a $26 million outflow primarily due to
payments for ice storm costs accrued at December 31, 2007 offset by an increase
in accruals related to fuel.
 
 Investing
Activities
 
 Net Cash
Flows Used for Investing Activities during 2009 and 2008 were $59 million and
$22 million, respectively.  Construction Expenditures of $52 million
and $73 million in 2009 and 2008, respectively, were primarily related to
projects for improved generation, transmission and distribution service
reliability.  In addition, during 2008, PSO had a net decrease of $51
million in investments in the Utility Money Pool.  PSO forecasts
approximately $188 million of construction expenditures for all of 2009,
excluding AFUDC.
 
 Financing
Activities
 
 Net Cash
Flows Used for Financing Activities were $45 million during 2009.  PSO
had a net decrease of $70 million in borrowings from the Utility Money
Pool.  PSO issued $34 million of Pollution Control Bonds in February
2009.  In addition, PSO paid $7 million in dividends on common
stock.
 
 Net Cash
Flows from Financing Activities were $62 million during 2008.  PSO had
a net increase of $62 million in borrowings from the Utility Money
Pool.
 
 Financing
Activity
 
 Long-term
debt issuances and retirements during the first three months of 2009
were:
 
 Issuances
 Principal
                    Amount
                  
                  Interest
                  
                  DueType
      of Debt
                  
                  
                  Rate
                  
                  Date(in
      thousands)
                  
                  (%)Pollution
      Control Bonds
                  
                  $
                  33,700
                  
                  5.25
                  
                  2014
 
 Retirements
 
 None
 
 Liquidity
 
 The
financial markets remain volatile at both a global and domestic
level.  This marketplace distress could impact PSO’s access to
capital, liquidity and cost of capital.  The uncertainties in the
capital markets could have significant implications on PSO since it relies on
continuing access to capital to fund operations and capital
expenditures.  Management cannot predict the length of time the credit
situation will continue or its impact on PSO’s operations and ability to issue
debt at reasonable interest rates.
 
 PSO
participates in the Utility Money Pool, which provides access to AEP’s
liquidity.  PSO has $50 million of Senior Unsecured Notes that will
mature in June 2009.  To the extent refinancing is unavailable due to
the challenging credit markets, PSO will rely upon cash flows from operations
and access to the Utility Money Pool to fund its maturity, current operations
and capital expenditures.
 
 See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for additional discussion of liquidity.
 
 Summary Obligation
Information
 
 A summary
of contractual obligations is included in the 2008 Annual Report and has not
changed significantly from year-end other than the debt issuances discussed in
“Cash Flow” and “Financing Activity” above.
 
 Significant
Factors
 
 New
Generation/Purchased Power Agreement
 
 See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section additional discussion of relevant factors.
 
 Litigation
and Regulatory Activity
 
 In the
ordinary course of business, PSO is involved in employment, commercial,
environmental and regulatory litigation.  Since it is difficult to
predict the outcome of these proceedings, management cannot state what the
eventual outcome of these proceedings will be, or what the timing of the amount
of any loss, fine or penalty may be.  Management does, however, assess
the probability of loss for such contingencies and accrues a liability for cases
which have a probable likelihood of loss and the loss amount can be
estimated.  For details on regulatory proceedings and pending
litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and
Contingencies in the 2008 Annual Report.  Also, see Note 3 – Rate
Matters and Note 4 – Commitments, Guarantees and Contingencies in the “Condensed
Notes to Condensed Financial Statements of Registrant Subsidiaries”
section.  Adverse results in these proceedings have the potential to
materially affect net income, financial condition and cash flows.
 
 See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for additional discussion of relevant factors.
 
 Critical Accounting
Estimates
 
 See the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in the 2008 Annual Report for a discussion
of the estimates and judgments required for regulatory accounting, revenue
recognition, the valuation of long-lived assets, pension and other
postretirement benefits and the impact of new accounting
pronouncements.
 
 Adoption of New Accounting
Pronouncements
 
 See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for a discussion of adoption of new accounting
pronouncements.
  
 QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
 
 Market
Risks
 
 Risk
management assets and liabilities are managed by AEPSC as agent.  The
related risk management policies and procedures are instituted and administered
by AEPSC.  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 PSO.
 
 MTM
Risk Management Contract Net Assets
 
 The
following two tables summarize the various mark-to-market (MTM) positions
included in PSO’s Condensed Balance Sheet as of March 31, 2009 and the reasons
for changes in total MTM value as compared to December 31, 2008.
 
 Reconciliation
of MTM Risk Management Contracts to
 Condensed
Balance Sheet
 March
31, 2009
 (in
thousands)
 
 MTM
      Risk Management Contracts
                  
                  
                  Cash
      Flow
                    Hedge
                    Contracts
                  
                  
                  DETM
      Assignment (a)
                  
                  
                  Collateral
                    Deposits
                  
                  
                  TotalCurrent
      Assets
                  
                  $
                  7,632
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  7,632Noncurrent
      Assets
                  
                  
                  600
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  600Total
      MTM Derivative Contract Assets
                  
                  
                  8,232
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  8,232Current
      Liabilities
                  
                  
                  (5,967
                  )
                  
                  
                  (33
                  )
                  
                  
                  (100
                  )
                  
                  
                  393
                  
                  
                  
                  (5,707
                  )Noncurrent
      Liabilities
                  
                  
                  (312
                  )
                  
                  
                  -
                  
                  
                  
                  (68
                  )
                  
                  
                  -
                  
                  
                  
                  (380
                  )Total
      MTM Derivative Contract Liabilities
                  
                  
                  (6,279
                  )
                  
                  
                  (33
                  )
                  
                  
                  (168
                  )
                  
                  
                  393
                  
                  
                  
                  (6,087
                  )Total
      MTM Derivative Contract Net Assets (Liabilities)
                  
                  $
                  1,953
                  
                  
                  $
                  (33
                  )
                  
                  $
                  (168
                  )
                  
                  $
                  393
                  
                  
                  $
                  2,145
  (a)
              See
      “Natural Gas Contracts with DETM” section of Note 15 of the 2008 Annual
      Report.
 
 MTM
Risk Management Contract Net Assets
 Three
Months Ended March 31, 2009
 (in
thousands)
 
 Total
      MTM Risk Management Contract Net Assets at December 31,
    2008
                  
                  $
                  1,660(Gain)
      Loss from Contracts Realized/Settled During the Period and Entered in a
      Prior Period
                  
                  
                  117Fair
      Value of New Contracts at Inception When Entered During the Period
      (a)
                  
                  
                  -Net
      Option Premiums Paid/(Received) for Unexercised or Unexpired Option
      Contracts Entered During the Period
                  
                  
                  -Change
      in Fair Value Due to Valuation Methodology Changes on Forward
      Contracts
                  
                  
                  -Changes
      in Fair Value Due to Market Fluctuations During the Period
    (b)
                  
                  
                  6Changes
      in Fair Value Allocated to Regulated Jurisdictions (c)
                  
                  
                  170Total
      MTM Risk Management Contract Net Assets
                  
                  
                  1,953Cash
      Flow Hedge Contracts
                  
                  
                  (33
                  )DETM
      Assignment (d)
                  
                  
                  (168
                  )Collateral
      Deposits
                  
                  
                  393Ending
      Net Risk Management Assets at March 31, 2009
                  
                  $
                  2,145
 
 (a)
              Reflects
      fair value on long-term contracts which are typically with customers that
      seek fixed pricing to limit their risk against fluctuating energy
      prices.  The contract prices are valued against market curves
      associated with the delivery location and delivery term.  A
      significant portion of the total volumetric position has been economically
      hedged.(b)
              Market
      fluctuations are attributable to various factors such as supply/demand,
      weather, etc.(c)
              “Changes
      in Fair Value Allocated to Regulated Jurisdictions” relates to the net
      gains (losses) of those contracts that are not reflected in the Condensed
      Statements of Income.  These net gains (losses) are recorded as
      regulatory liabilities/assets.(d)
              See
      “Natural Gas Contracts with DETM” section of Note 15 of the 2008 Annual
      Report.
 
 Maturity
and Source of Fair Value of MTM Risk Management Contract Net Assets
 
 The
following table presents the maturity, by year, of net assets/liabilities to
give 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, 2009
 (in
thousands)
 
 Remainder
                    2009
                  
                  
                  2010
                  
                  
                  2011
                  
                  
                  2012
                  
                  
                  2013
                  
                  
                  After
                    2013
                  
                  
                  TotalLevel
      1 (a)
                  
                  $
                  (439
                  )
                  
                  $
                  (1
                  )
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  (440
                  )Level
      2 (b)
                  
                  
                  1,605
                  
                  
                  
                  1,064
                  
                  
                  
                  (267
                  )
                  
                  
                  (10
                  )
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  2,392Level
      3 (c)
                  
                  
                  -
                  
                  
                  
                  1
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  1Total
                  
                  $
                  1,166
                  
                  
                  $
                  1,064
                  
                  
                  $
                  (267
                  )
                  
                  $
                  (10
                  )
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  1,953
 
 (a)
              Level
      1 inputs are quoted prices (unadjusted) in active markets for identical
      assets or liabilities that the reporting entity has the ability to access
      at the measurement date.  Level 1 inputs primarily consist of
      exchange traded contracts that exhibit sufficient frequency and volume to
      provide pricing information on an ongoing basis.(b)
              Level
      2 inputs are inputs other than quoted prices included within Level 1 that
      are observable for the asset or liability, either directly or
      indirectly.  If the asset or liability has a specified
      (contractual) term, a Level 2 input must be observable for substantially
      the full term of the asset or liability.  Level 2 inputs
      primarily consist of OTC broker quotes in moderately active or less active
      markets, exchange traded contracts where there was not sufficient market
      activity to warrant inclusion in Level 1 and OTC broker quotes that are
      corroborated by the same or similar transactions that have occurred in the
      market.(c)
              Level
      3 inputs are unobservable inputs for the asset or
      liability.  Unobservable inputs shall be used to measure fair
      value to the extent that the observable inputs are not available, thereby
      allowing for situations in which there is little, if any, market activity
      for the asset or liability at the measurement date.  Level 3
      inputs primarily consist of unobservable market data or are valued based
      on models and/or assumptions.
 
 Credit
Risk
 
 Counterparty
credit quality and exposure is generally consistent with that of
AEP.
 
 See Note
7 for further information regarding MTM risk management contracts, cash flow
hedging, accumulated other comprehensive income, credit risk and collateral
triggering events.
 
 VaR
Associated with Risk Management Contracts
 
 Management
uses a risk measurement model, which calculates Value at Risk (VaR) to measure
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, 2009, a near term
typical change in commodity prices is not expected to have a material effect on
PSO’s net income, cash flows or financial condition.
 
 The
following table shows the end, high, average and low market risk as measured by
VaR for the periods indicated:
 
 Three
      Months Ended
                
                
                
                
                Twelve
      Months EndedMarch
      31, 2009
                
                
                
                
                December
      31, 2008(in
      thousands)
                
                
                
                
                (in
      thousands)End
                
                High
                
                Average
                
                Low
                
                
                
                
                End
                
                High
                
                Average
                
                Low$14
                
                $34
                
                $13
                
                $4
                
                
                
                
                $4
                
                $164
                
                $44
                
                $6
 
 Management
back-tests its VaR results against performance due to actual price
moves.  Based on the assumed 95% confidence interval, the performance
due to actual price moves would be expected to exceed the VaR at least once
every 20 trading days.  Management’s backtesting results show that its
actual performance exceeded VaR far fewer than once every 20 trading
days.  As a result, management believes PSO’s VaR calculation is
conservative.
  As PSO’s
VaR calculation captures recent price moves, management also performs regular
stress testing of the portfolio to understand PSO’s exposure to extreme price
moves.  Management employs a historical-based method whereby the
current portfolio is subjected to actual, observed price moves from the last
three years in order to ascertain which historical price moves translated into
the largest potential MTM loss.  Management then researches the
underlying positions, price moves and market events that created the most
significant exposure.
 
 Interest
Rate Risk
 
 Management
utilizes an Earnings at Risk (EaR) model to measure interest rate market risk
exposure.  EaR statistically quantifies the extent to which PSO’s
interest expense could vary over the next twelve months and gives a
probabilistic estimate of different levels of interest expense.  The
resulting EaR is interpreted as the dollar amount by which actual interest
expense for the next twelve months could exceed expected interest expense with a
one-in-twenty chance of occurrence.  The primary drivers of EaR are
from the existing floating rate debt (including short-term debt) as well as
long-term debt issuances in the next twelve months.  The estimated EaR
on PSO’s debt portfolio was $909 thousand.
  
 PUBLIC
SERVICE COMPANY OF OKLAHOMA
 CONDENSED
STATEMENTS OF INCOME
 For
the Three Months Ended March 31, 2009 and 2008
 (in
thousands)
 (Unaudited)
 2009
                          
                          
                          2008REVENUESElectric
      Generation, Transmission and Distribution
                          
                          $
                          278,771
                          
                          
                          $
                          318,880Sales
      to AEP Affiliates
                          
                          
                          15,823
                          
                          
                          
                          15,935Other
                          
                          
                          693
                          
                          
                          
                          1,185TOTAL
                          
                          
                          295,287
                          
                          
                          
                          336,000EXPENSESFuel
      and Other Consumables Used for Electric Generation
                          
                          
                          119,399
                          
                          
                          
                          153,205Purchased
      Electricity for Resale
                          
                          
                          44,425
                          
                          
                          
                          48,582Purchased
      Electricity from AEP Affiliates
                          
                          
                          5,915
                          
                          
                          
                          17,269Other
      Operation
                          
                          
                          39,545
                          
                          
                          
                          55,999Maintenance
                          
                          
                          25,430
                          
                          
                          
                          34,587Deferral
      of Ice Storm Costs
                          
                          
                          -
                          
                          
                          
                          (79,902
                          )Depreciation
      and Amortization
                          
                          
                          27,950
                          
                          
                          
                          26,167Taxes
      Other Than Income Taxes
                          
                          
                          10,751
                          
                          
                          
                          10,952TOTAL
                          
                          
                          273,415
                          
                          
                          
                          266,859OPERATING
      INCOME
                          
                          
                          21,872
                          
                          
                          
                          69,141Other
      Income (Expense):Interest
      Income
                          
                          
                          648
                          
                          
                          
                          1,128Carrying
      Costs Income
                          
                          
                          1,711
                          
                          
                          
                          1,634Allowance
      for Equity Funds Used During Construction
                          
                          
                          170
                          
                          
                          
                          1,359Interest
      Expense
                          
                          
                          (14,805
                          )
                          
                          
                          (14,941
                          )INCOME
      BEFORE INCOME TAX EXPENSE
                          
                          
                          9,596
                          
                          
                          
                          58,321Income
      Tax Expense
                          
                          
                          3,558
                          
                          
                          
                          20,922NET
      INCOME
                          
                          
                          6,038
                          
                          
                          
                          37,399Preferred
      Stock Dividend Requirements
                          
                          
                          53
                          
                          
                          
                          53EARNINGS
      ATTRIBUTABLE TO COMMON STOCK
                          
                          $
                          5,985
                          
                          
                          $
                          37,346
 
 The
      common stock of PSO is wholly-owned by
AEP.
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
 
  
 PUBLIC
SERVICE COMPANY OF OKLAHOMA
 CONDENSED
STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
 EQUITY
AND COMPREHENSIVE INCOME (LOSS)
 For
the Three Months Ended March 31, 2009 and 2008
 (in
thousands)
 (Unaudited)
 
 Common
      Stock
                  
                  
                  Paid-in
      Capital
                  
                  
                  Retained
      Earnings
                  
                  
                  Accumulated
                    Other
                    Comprehensive
                    (Loss)
                  
                  
                  TotalDECEMBER
      31, 2007
                  
                  $
                  157,230
                  
                  
                  $
                  310,016
                  
                  
                  $
                  174,539
                  
                  
                  $
                  (887
                  )
                  
                  $
                  640,898EITF
      06-10 Adoption, Net of Tax of $596
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  (1,107
                  )
                  
                  
                  
                  
                  
                  
                  (1,107
                  )Preferred
      Stock Dividends
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  (53
                  )
                  
                  
                  
                  
                  
                  
                  (53
                  )TOTAL
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  639,738COMPREHENSIVE
      INCOMEOther Comprehensive
      Income, Net
      of Taxes:Cash
      Flow Hedges, Net of Tax of $24
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  45
                  
                  
                  
                  45NET
      INCOME
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  37,399
                  
                  
                  
                  
                  
                  
                  
                  37,399TOTAL
      COMPREHENSIVE INCOME
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  37,444MARCH
      31, 2008
                  
                  $
                  157,230
                  
                  
                  $
                  310,016
                  
                  
                  $
                  210,778
                  
                  
                  $
                  (842
                  )
                  
                  $
                  677,182DECEMBER
      31, 2008
                  
                  $
                  157,230
                  
                  
                  $
                  340,016
                  
                  
                  $
                  251,704
                  
                  
                  $
                  (704
                  )
                  
                  $
                  748,246Common
      Stock Dividends
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  (7,250
                  )
                  
                  
                  
                  
                  
                  
                  (7,250
                  )Preferred
      Stock Dividends
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  (53
                  )
                  
                  
                  
                  
                  
                  
                  (53
                  )Other
                  
                  
                  
                  
                  
                  
                  4,214
                  
                  
                  
                  (4,214
                  )
                  
                  
                  
                  
                  
                  
                  -TOTAL
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  740,943COMPREHENSIVE
      INCOMEOther
      Comprehensive Income, Net of Taxes:Cash
      Flow Hedges, Net of Tax of $12
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  22
                  
                  
                  
                  22NET
      INCOME
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  6,038
                  
                  
                  
                  
                  
                  
                  
                  6,038TOTAL
      COMPREHENSIVE INCOME
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  6,060MARCH
      31, 2009
                  
                  $
                  157,230
                  
                  
                  $
                  344,230
                  
                  
                  $
                  246,225
                  
                  
                  $
                  (682
                  )
                  
                  $
                  747,003
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
 
  
 PUBLIC
SERVICE COMPANY OF OKLAHOMA
 CONDENSED
BALANCE SHEETS
 ASSETS
 March
31, 2009 and December 31, 2008
 (in
thousands)
 (Unaudited)
 2009
                  
                  
                  2008CURRENT
      ASSETSCash
      and Cash Equivalents
                  
                  $
                  1,277
                  
                  
                  $
                  1,345Advances
      to Affiliates
                  
                  
                  7,009
                  
                  
                  
                  -Accounts
      Receivable:Customers
                  
                  
                  29,010
                  
                  
                  
                  39,823Affiliated
      Companies
                  
                  
                  60,513
                  
                  
                  
                  138,665Miscellaneous
                  
                  
                  4,955
                  
                  
                  
                  8,441Allowance
      for Uncollectible Accounts
                  
                  
                  (130
                  )
                  
                  
                  (20
                  )Total
      Accounts Receivable
                  
                  
                  94,348
                  
                  
                  
                  186,909Fuel
                  
                  
                  24,739
                  
                  
                  
                  27,060Materials
      and Supplies
                  
                  
                  44,982
                  
                  
                  
                  44,047Risk
      Management Assets
                  
                  
                  7,632
                  
                  
                  
                  5,830Deferred
      Tax Benefits
                  
                  
                  33,624
                  
                  
                  
                  9,123Accrued
      Tax Benefits
                  
                  
                  -
                  
                  
                  
                  3,876Prepayments
      and Other
                  
                  
                  6,607
                  
                  
                  
                  3,371TOTAL
                  
                  
                  220,218
                  
                  
                  
                  281,561PROPERTY,
      PLANT AND EQUIPMENTElectric:Production
                  
                  
                  1,273,326
                  
                  
                  
                  1,266,716Transmission
                  
                  
                  628,733
                  
                  
                  
                  622,665Distribution
                  
                  
                  1,493,418
                  
                  
                  
                  1,468,481Other
                  
                  
                  248,238
                  
                  
                  
                  248,897Construction
      Work in Progress
                  
                  
                  83,239
                  
                  
                  
                  85,252Total
                  
                  
                  3,726,954
                  
                  
                  
                  3,692,011Accumulated
      Depreciation and Amortization
                  
                  
                  1,204,894
                  
                  
                  
                  1,192,130TOTAL
      - NET
                  
                  
                  2,522,060
                  
                  
                  
                  2,499,881OTHER
      NONCURRENT ASSETSRegulatory
      Assets
                  
                  
                  300,305
                  
                  
                  
                  304,737Long-term
      Risk Management Assets
                  
                  
                  600
                  
                  
                  
                  917Deferred
      Charges and Other
                  
                  
                  39,088
                  
                  
                  
                  13,702TOTAL
                  
                  
                  339,993
                  
                  
                  
                  319,356TOTAL
      ASSETS
                  
                  $
                  3,082,271
                  
                  
                  $
                  3,100,798
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
  
 PUBLIC
SERVICE COMPANY OF OKLAHOMA
 CONDENSED
BALANCE SHEETS
 LIABILITIES
AND SHAREHOLDERS’ EQUITY
 March
31, 2009 and December 31, 2008
 (Unaudited)
 2009
                  
                  
                  2008CURRENT
      LIABILITIES
                  
                  (in
      thousands)Advances
      from Affiliates
                  
                  $
                  -
                  
                  
                  $
                  70,308Accounts
      Payable:General
                  
                  
                  68,187
                  
                  
                  
                  84,121Affiliated
      Companies
                  
                  
                  67,490
                  
                  
                  
                  86,407Long-term
      Debt Due Within One Year – Nonaffiliated
                  
                  
                  50,000
                  
                  
                  
                  50,000Risk
      Management Liabilities
                  
                  
                  5,707
                  
                  
                  
                  4,753Customer
      Deposits
                  
                  
                  41,967
                  
                  
                  
                  40,528Accrued
      Taxes
                  
                  
                  51,818
                  
                  
                  
                  19,000Regulatory
      Liability for Over-Recovered Fuel Costs
                  
                  
                  147,199
                  
                  
                  
                  58,395Provision
      for Revenue Refund
                  
                  
                  -
                  
                  
                  
                  52,100Other
                  
                  
                  39,606
                  
                  
                  
                  61,194TOTAL
                  
                  
                  471,974
                  
                  
                  
                  526,806NONCURRENT
      LIABILITIESLong-term
      Debt – Nonaffiliated
                  
                  
                  868,619
                  
                  
                  
                  834,859Long-term
      Risk Management Liabilities
                  
                  
                  380
                  
                  
                  
                  378Deferred
      Income Taxes
                  
                  
                  523,842
                  
                  
                  
                  514,720Regulatory
      Liabilities and Deferred Investment Tax Credits
                  
                  
                  324,693
                  
                  
                  
                  323,750Deferred
      Credits and Other
                  
                  
                  140,498
                  
                  
                  
                  146,777TOTAL
                  
                  
                  1,858,032
                  
                  
                  
                  1,820,484TOTAL
      LIABILITIES
                  
                  
                  2,330,006
                  
                  
                  
                  2,347,290Cumulative
      Preferred Stock Not Subject to Mandatory Redemption
                  
                  
                  5,262
                  
                  
                  
                  5,262Commitments
      and Contingencies (Note 4)COMMON
      SHAREHOLDER’S EQUITYCommon
      Stock – Par Value – $15 Per Share:Authorized
      – 11,000,000 SharesIssued
      – 10,482,000 SharesOutstanding
      – 9,013,000 Shares
                  
                  
                  157,230
                  
                  
                  
                  157,230Paid-in
      Capital
                  
                  
                  344,230
                  
                  
                  
                  340,016Retained
      Earnings
                  
                  
                  246,225
                  
                  
                  
                  251,704Accumulated
      Other Comprehensive Income (Loss)
                  
                  
                  (682
                  )
                  
                  
                  (704
                  )TOTAL
                  
                  
                  747,003
                  
                  
                  
                  748,246TOTAL
      LIABILITIES AND SHAREHOLDERS’ EQUITY
                  
                  $
                  3,082,271
                  
                  
                  $
                  3,100,798
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
  
 PUBLIC
SERVICE COMPANY OF OKLAHOMA
 CONDENSED
STATEMENTS OF CASH FLOWS
 For
the Three Months Ended March 31, 2009 and 2008
 (in
thousands)
 (Unaudited)
 2009
                      
                      
                      2008OPERATING
      ACTIVITIESNet
      Income
                      
                      $
                      6,038
                      
                      
                      $
                      37,399Adjustments
      to Reconcile Net Income to Net Cash Flows from (Used for) Operating
      Activities:Depreciation
      and Amortization
                      
                      
                      27,950
                      
                      
                      
                      26,167Deferred
      Income Taxes
                      
                      
                      (13,835
                      )
                      
                      
                      37,899Deferral
      of Ice Storm Costs
                      
                      
                      -
                      
                      
                      
                      (79,902
                      )Allowance
      for Equity Funds Used During Construction
                      
                      
                      (170
                      )
                      
                      
                      (1,359
                      )Mark-to-Market
      of Risk Management Contracts
                      
                      
                      (562
                      )
                      
                      
                      (11,881
                      )Deferred
      Property Taxes
                      
                      
                      (28,050
                      )
                      
                      
                      (26,694
                      )Change
      in Other Noncurrent Assets
                      
                      
                      (1,282
                      )
                      
                      
                      22,022Change
      in Other Noncurrent Liabilities
                      
                      
                      (1,879
                      )
                      
                      
                      (20,541
                      )Changes
      in Certain Components of Working Capital:Accounts
      Receivable, Net
                      
                      
                      92,561
                      
                      
                      
                      (5,027
                      )Fuel,
      Materials and Supplies
                      
                      
                      1,386
                      
                      
                      
                      (5,086
                      )Accounts
      Payable
                      
                      
                      (28,623
                      )
                      
                      
                      (25,698
                      )Accrued
      Taxes, Net
                      
                      
                      36,694
                      
                      
                      
                      22,107Fuel
      Over/Under-Recovery, Net
                      
                      
                      36,650
                      
                      
                      
                      4,572Other
      Current Assets
                      
                      
                      (3,511
                      )
                      
                      
                      6,976Other
      Current Liabilities
                      
                      
                      (19,564
                      )
                      
                      
                      (20,759
                      )Net
      Cash Flows from (Used for) Operating Activities
                      
                      
                      103,803
                      
                      
                      
                      (39,805
                      )INVESTING
      ACTIVITIESConstruction
      Expenditures
                      
                      
                      (52,368
                      )
                      
                      
                      (73,203
                      )Change
      in Advances to Affiliates, Net
                      
                      
                      (7,009
                      )
                      
                      
                      51,202Proceeds
      from Sales of Assets
                      
                      
                      232
                      
                      
                      
                      148Net
      Cash Flows Used for Investing Activities
                      
                      
                      (59,145
                      )
                      
                      
                      (21,853
                      )FINANCING
      ACTIVITIESIssuance
      of Long-term Debt – Nonaffiliated
                      
                      
                      33,283
                      
                      
                      
                      -Change
      in Advances from Affiliates, Net
                      
                      
                      (70,308
                      )
                      
                      
                      62,159Principal
      Payments for Capital Lease Obligations
                      
                      
                      (398
                      )
                      
                      
                      (383
                      )Dividends
      Paid on Common Stock
                      
                      
                      (7,250
                      )
                      
                      
                      -Dividends
      Paid on Cumulative Preferred Stock
                      
                      
                      (53
                      )
                      
                      
                      (53
                      )Net
      Cash Flows from (Used for) Financing Activities
                      
                      
                      (44,726
                      )
                      
                      
                      61,723Net
      Increase (Decrease) in Cash and Cash Equivalents
                      
                      
                      (68
                      )
                      
                      
                      65Cash
      and Cash Equivalents at Beginning of Period
                      
                      
                      1,345
                      
                      
                      
                      1,370Cash
      and Cash Equivalents at End of Period
                      
                      $
                      1,277
                      
                      
                      $
                      1,435
 
 SUPPLEMENTARY
      INFORMATIONCash
      Paid for Interest, Net of Capitalized Amounts
                  
                  $
                  29,174
                  
                  
                  $
                  12,380Net
      Cash Paid (Received) for Income Taxes
                  
                  
                  391
                  
                  
                  
                  (19,408
                  )Noncash
      Acquisitions Under Capital Leases
                  
                  
                  391
                  
                  
                  
                  135Construction
      Expenditures Included in Accounts Payable at March 31,
                  
                  
                  11,776
                  
                  
                  
                  21,086
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
 
  
 PUBLIC
SERVICE COMPANY OF OKLAHOMA
 INDEX
TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT
SUBSIDIARIES
 
 The
condensed notes to PSO’s condensed financial statements are combined with the
condensed notes to condensed financial statements for other registrant
subsidiaries.  Listed below are the notes that apply to
PSO.
 
 FootnoteReferenceSignificant
      Accounting Matters
                                Note
      1New
      Accounting Pronouncements
                                Note
      2Rate
      Matters
                                Note
      3Commitments,
      Guarantees and Contingencies
                                Note
      4Benefit
      Plans
                                Note
      5Business
      Segments
                                Note
      6Derivatives,
      Hedging and Fair Value Measurements
                                Note
      7Income
      Taxes
                                Note
      8Financing
      Activities
                                Note
      9
 
  
  
 
 
 
 
 
 SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
 
  
 SOUTHWESTERN ELECTRIC POWER COMPANY
CONSOLIDATED
 MANAGEMENT’S FINANCIAL
DISCUSSION AND ANALYSIS
 
 Results of
Operations
 
 First Quarter of 2009
Compared to First Quarter of 2008
 
 Reconciliation
of First Quarter of 2008 to First Quarter of 2009
 Net
Income
 (in
millions)
 
 First
      Quarter of 2008
                        
                        
                        
                        
                        $
                        6Changes
      in Gross Margin:Retail
      and Off-system Sales Margins (a)
                        
                        
                        (3
                        )Transmission
      Revenues
                        
                        
                        2Other
                        
                        
                        (2
                        )Total
      Change in Gross Margin
                        
                        
                        
                        
                        
                        
                        (3
                        )Changes
      in Operating Expenses and Other:Other
      Operation and Maintenance
                        
                        
                        10Depreciation
      and Amortization
                        
                        
                        (1
                        )Taxes
      Other Than Income Taxes
                        
                        
                        2Other
      Income
                        
                        
                        3Interest
      Expense
                        
                        
                        1Total
      Change in Operating Expenses and Other
                        
                        
                        
                        
                        
                        
                        15Income
      Tax Expense
                        
                        
                        
                        
                        
                        
                        (6
                        )First
      Quarter of 2009
                        
                        
                        
                        
                        
                        $
                        12
 
 (a)
                Includes
      firm wholesale sales to municipals and
  cooperatives.
 
 Net
Income increased $6 million to $12 million in 2009.  The key drivers
of the increase were a $15 million decrease in Operating Expenses and Other,
partially offset by a $6 million increase in Income Tax Expense and a $3 million
decrease in Gross Margin.
 
 The major
components of the decrease in Gross Margin, defined as revenues less the related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power were as follows:
 
 ·
              Retail
      and Off-system Sales Margins decreased $3 million primarily due to a $4
      million decrease in retail sales margins primarily related to reduced
      customer usage, partially offset by increased rates related to the
      Louisiana Formula Rate Plan.·
              Transmission
      Revenues increased $2 million primarily due to higher rates in the SPP
      region.·
              Other
      revenues decreased $2 million primarily due to a decrease in revenues from
      coal deliveries from SWEPCo’s mining subsidiary, Dolet Hills Lignite
      Company, LLC to Cleco Corporation, a nonaffiliated entity and decreased
      gain on sales of emission allowances.  The decreased revenue
      from coal deliveries was offset by a corresponding decrease in Other
      Operation and Maintenance expenses from mining operations as discussed
      below.
 
 Operating
Expenses and Other and Income Tax Expense changed between years as
follows:
 
 ·
              Other
      Operation and Maintenance expenses decreased $10 million primarily due
      to:·
              A
      $5 million decrease in operation expense as a result of lower
      employee-related expenses.·
              A
      $2 million gain on sale of property related to the sale of percentage
      ownership of Turk Plant to nonaffiliated companies who exercised their
      participation options.·
              A
      $2 million decrease in expenses for coal deliveries from SWEPCo’s mining
      subsidiary, Dolet Hills Lignite Company, LLC.  The decreased
      expenses for coal deliveries were partially offset by a corresponding
      decrease in revenues from mining operations as discussed
      above.·
              Taxes
      Other Than Income Taxes decreased $2 million primarily due to lower
      property tax and revenue tax.·
              Other
      Income increased $3 million primarily due to an increase in the AFUDC
      equity as a result of construction at the Turk Plant and Stall
      Unit.  See Note 3.·
              Income
      Tax Expense increased $6 million primarily due to an increase in pre-tax
      book income and prior year income tax
  adjustments.
 
 Financial
Condition
 
 Credit
Ratings
 
 SWEPCo’s
credit ratings as of March 31, 2009 were as follows:
 
 Moody’s
                
                S&P
                
                FitchSenior
      Unsecured Debt
                Baa1
                
                BBB
                
                BBB+
 
 S&P
and Fitch have SWEPCo on stable outlook.  In 2009, Moody’s placed
SWEPCo on review for possible downgrade due to concerns about financial metrics
and pending cost and construction recoveries.  If SWEPCo receives a
downgrade from any of the rating agencies, its borrowing costs could increase
and access to borrowed funds could be negatively affected.
 
 Cash
Flow
 
 Cash
flows for the three months ended March 31, 2009 and 2008 were as
follows:
 
 2009
                    
                    
                    2008(in
      thousands)Cash
      and Cash Equivalents at Beginning of Period
                    
                    $
                    1,910
                    
                    
                    $
                    1,742Cash
      Flows from (Used for):Operating
      Activities
                    
                    
                    93,470
                    
                    
                    
                    (3,153
                    )Investing
      Activities
                    
                    
                    (103,382
                    )
                    
                    
                    (125,877
                    )Financing
      Activities
                    
                    
                    9,739
                    
                    
                    
                    133,191Net
      Increase (Decrease) in Cash and Cash Equivalents
                    
                    
                    (173
                    )
                    
                    
                    4,161Cash
      and Cash Equivalents at End of Period
                    
                    $
                    1,737
                    
                    
                    $
                    5,903
 
 Operating
Activities
 
 Net Cash
Flows from Operating Activities were $93 million in 2009.  SWEPCo
produced Net Income of $12 million during the period and had a noncash expense
item of $37 million for Depreciation and Amortization, $30 million for Deferred
Property Taxes and $27 million for Deferred Income 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 working capital relates to a number
of items.  The $95 million inflow from Accounts Receivable, Net was
primarily due to the receipt of payment for SIA from the AEP East
companies.  The $59 million inflow from Accrued Taxes, Net was the
result of increased accruals related to income and property
taxes.  The $50 million outflow from Other Current Liabilities was due
to a decrease in checks outstanding, a refund to wholesale customers for the SIA
and payments of employee-related expenses.  The $27 million inflow
from Fuel Over/Under-Recovery, Net was the result of a decrease in fuel costs in
relation to the recovery of these costs from customers.  The $20
million outflow from Accrued Interest was due to increased long-term debt
outstanding as well as the timing of interest payments in relation to the
accruals for payments.
 
 Net Cash
Flows Used for Operating Activities were $3 million in 2008.  SWEPCo
produced Net Income of $6 million during the period and had a noncash expense
item of $36 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 relates to a number
of items.  The $40 million outflow from Fuel Over/Under-Recovery, Net
was the result of higher fuel costs.  The $22 million inflow from
Accounts Receivable, Net was primarily due to the assignment of certain ERCOT
contracts to an affiliate company.  The $21 million inflow from
Accrued Taxes, Net was the result of increased accruals related to property and
income taxes.
 
 Investing
Activities
 
 Net Cash
Flows Used for Investing Activities during 2009 and 2008 were $103 million and
$126 million, respectively.  Construction Expenditures of $170 million
and $125 million in 2009 and 2008, respectively, were primarily related to new
generation projects at the Turk Plant and Stall Unit.  Proceeds from
Sales of Assets in 2009 primarily includes $104 million in progress payments for
Turk Plant construction from the joint owners.  Change in Advances to
Affiliates, Net of $38 million in 2009 was primarily due to the contribution
from Parent and net income.  SWEPCo forecasts approximately $457
million of construction expenditures for all of 2009, excluding
AFUDC.
 
 Financing
Activities
 
 Net Cash
Flows from Financing Activities were $10 million during 2009.  SWEPCo
received a Capital Contribution from Parent of $18 million.  SWEPCo
had a net decrease of $3 million in borrowings from the Utility Money
Pool.
 
 Net Cash
Flows from Financing Activities were $133 million during 2008.  SWEPCo
received a Capital Contribution from Parent of $50 million.  SWEPCo
had a net increase of $88 million in borrowings from the Utility Money
Pool.
 
 Financing
Activity
 
 Long-term
debt issuances and principal payments made during the first three months of 2009
were:
 
 Issuances
 
 None
 
 Principal
Payments
 Principal
                  Amount
      Paid
                
                Interest
                
                DueType
      of Debt
                
                
                Rate
                
                Date(in
      thousands)
                
                (%)Notes
      Payable – Nonaffiliated
                
                $
                1,101
                
                4.47
                
                2011
 
 Liquidity
 
 The
financial markets remain volatile at both a global and domestic
level.  This marketplace distress could impact SWEPCo’s access to
capital, liquidity and cost of capital.  The uncertainties in the
capital markets could have significant implications on SWEPCo since it relies on
continuing access to capital to fund operations and capital
expenditures.  Management cannot predict the length of time the credit
situation will continue or its impact on SWEPCo’s operations and ability to
issue debt at reasonable interest rates.
 
 SWEPCo
participates in the Utility Money Pool, which provides access to AEP’s
liquidity.  SWEPCo will rely upon cash flows from operations and
access to the Utility Money Pool to fund its current operations and capital
expenditures.
 
 See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for additional discussion of liquidity.
 
 Summary Obligation
Information
 
 A summary
of contractual obligations is included in the 2008 Annual Report and has not
changed significantly from year-end.
 
 Significant
Factors
 
 Litigation
and Regulatory Activity
 
 In the
ordinary course of business, SWEPCo is involved in employment, commercial,
environmental and regulatory litigation.  Since it is difficult to
predict the outcome of these proceedings, management cannot state what the
eventual outcome of these proceedings will be, or what the timing of the amount
of any loss, fine or penalty may be.  Management does, however, assess
the probability of loss for such contingencies and accrues a liability for cases
which have a probable likelihood of loss if the loss amount can be
estimated.  For details on regulatory proceedings and pending
litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and
Contingencies in the 2008 Annual Report.  Also, see Note 3 – Rate
Matters and Note 4 – Commitments, Guarantees and Contingencies in the “Condensed
Notes to Condensed Financial Statements of Registrant Subsidiaries”
section.  Adverse results in these proceedings have the potential to
materially affect net income, financial condition and cash flows.
 
 See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for additional discussion of relevant factors.
 
 Critical Accounting
Estimates
 
 See the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in the 2008 Annual Report for a discussion
of the estimates and judgments required for regulatory accounting, revenue
recognition, the valuation of long-lived assets, pension and other
postretirement benefits and the impact of new accounting
pronouncements.
 
 Adoption of New Accounting
Pronouncements
 
 See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for a discussion of adoption of new accounting
pronouncements.
  
  QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
 
 Market
Risks
 
 Risk
management assets and liabilities are managed by AEPSC as agent.  The
related risk management policies and procedures are instituted and administered
by AEPSC.  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 SWEPCo.
 
 MTM
Risk Management Contract Net Assets
 
 The
following two tables summarize the various mark-to-market (MTM) positions
included in SWEPCo’s Condensed Consolidated Balance Sheet as of March 31, 2009
and the reasons for changes in total MTM value as compared to December 31,
2008.
 
 Reconciliation
of MTM Risk Management Contracts to
 Condensed
Consolidated Balance Sheet
 March
31, 2009
 (in
thousands)
 
 MTM
      Risk Management Contracts
                  
                  
                  Cash
      Flow Hedge Contracts
                  
                  
                  DETM
      Assignment (a)
                  
                  
                  Collateral
                    Deposits
                  
                  
                  TotalCurrent
      Assets
                  
                  $
                  10,187
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  10,187Noncurrent
      Assets
                  
                  
                  919
                  
                  
                  
                  1
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  920Total
      MTM Derivative Contract Assets
                  
                  
                  11,106
                  
                  
                  
                  1
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  11,107Current
      Liabilities
                  
                  
                  (7,572
                  )
                  
                  
                  (331
                  )
                  
                  
                  (118
                  )
                  
                  
                  456
                  
                  
                  
                  (7,565
                  )Noncurrent
      Liabilities
                  
                  
                  (448
                  )
                  
                  
                  -
                  
                  
                  
                  (80
                  )
                  
                  
                  -
                  
                  
                  
                  (528
                  )Total
      MTM Derivative Contract Liabilities
                  
                  
                  (8,020
                  )
                  
                  
                  (331
                  )
                  
                  
                  (198
                  )
                  
                  
                  456
                  
                  
                  
                  (8,093
                  )Total
      MTM Derivative Contract Net Assets (Liabilities)
                  
                  $
                  3,086
                  
                  
                  $
                  (330
                  )
                  
                  $
                  (198
                  )
                  
                  $
                  456
                  
                  
                  $
                  3,014
 
 (a)
              See
      “Natural Gas Contracts with DETM” section of Note 15 of the 2008 Annual
      Report.
 
 MTM
Risk Management Contract Net Assets
 Three
Months Ended March 31, 2009
 (in
thousands)
 
 Total
      MTM Risk Management Contract Net Assets at December 31,
    2008
                  
                  $
                  2,643(Gain)
      Loss from Contracts Realized/Settled During the Period and Entered in a
      Prior Period
                  
                  
                  263Fair
      Value of New Contracts at Inception When Entered During the Period
      (a)
                  
                  
                  -Net
      Option Premiums Paid/(Received) for Unexercised or Unexpired Option
      Contracts Entered During the Period
                  
                  
                  -Change
      in Fair Value Due to Valuation Methodology Changes on Forward
      Contracts
                  
                  
                  -Changes
      in Fair Value Due to Market Fluctuations During the Period
    (b)
                  
                  
                  85Changes
      in Fair Value Allocated to Regulated Jurisdictions (c)
                  
                  
                  95Total
      MTM Risk Management Contract Net Assets
                  
                  
                  3,086Cash
      Flow Hedge Contracts
                  
                  
                  (330
                  )DETM
      Assignment (d)
                  
                  
                  (198
                  )Collateral
      Deposits
                  
                  
                  456Ending
      Net Risk Management Assets at March 31, 2009
                  
                  $
                  3,014
 
 (a)
              Reflects
      fair value on long-term contracts which are typically with customers that
      seek fixed pricing to limit their risk against fluctuating energy
      prices.  The contract prices are valued against market curves
      associated with the delivery location and delivery term.  A
      significant portion of the total volumetric position has been economically
      hedged.(b)
              Market
      fluctuations are attributable to various factors such as supply/demand,
      weather, etc.(c)
              “Changes
      in Fair Value Allocated to Regulated Jurisdictions” relates to the net
      gains (losses) of those contracts that are not reflected in the Condensed
      Consolidated Statements of Income.  These net gains (losses) are
      recorded as regulatory liabilities/assets.(d)
              See
      “Natural Gas Contracts with DETM” section of Note 15 of the 2008 Annual
      Report.
  Maturity
and Source of Fair Value of MTM Risk Management Contract Net Assets
 
 The
following table presents the maturity, by year, of net assets/liabilities to
give 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, 2009
 (in
thousands)
 
 Remainder
                      2009
                    
                    
                    2010
                    
                    
                    2011
                    
                    
                    2012
                    
                    
                    2013
                    
                    
                    After
                      2013
                    
                    
                    TotalLevel
      1 (a)
                    
                    $
                    (518
                    )
                    
                    $
                    (1
                    )
                    
                    $
                    -
                    
                    
                    $
                    -
                    
                    
                    $
                    -
                    
                    
                    $
                    -
                    
                    
                    $
                    (519
                    )Level
      2 (b)
                    
                    
                    2,340
                    
                    
                    
                    1,688
                    
                    
                    
                    (412
                    )
                    
                    
                    (13
                    )
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    3,603Level
      3 (c)
                    
                    
                    -
                    
                    
                    
                    2
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    2Total
                    
                    $
                    1,822
                    
                    
                    $
                    1,689
                    
                    
                    $
                    (412
                    )
                    
                    $
                    (13
                    )
                    
                    $
                    -
                    
                    
                    $
                    -
                    
                    
                    $
                    3,086
 
 (a)
              Level
      1 inputs are quoted prices (unadjusted) in active markets for identical
      assets or liabilities that the reporting entity has the ability to access
      at the measurement date.  Level 1 inputs primarily consist of
      exchange traded contracts that exhibit sufficient frequency and volume to
      provide pricing information on an ongoing basis.(b)
              Level
      2 inputs are inputs other than quoted prices included within Level 1 that
      are observable for the asset or liability, either directly or
      indirectly.  If the asset or liability has a specified
      (contractual) term, a Level 2 input must be observable for substantially
      the full term of the asset or liability.  Level 2 inputs
      primarily consist of OTC broker quotes in moderately active or less active
      markets, exchange traded contracts where there was not sufficient market
      activity to warrant inclusion in Level 1 and OTC broker quotes that are
      corroborated by the same or similar transactions that have occurred in the
      market.(c)
              Level
      3 inputs are unobservable inputs for the asset or
      liability.  Unobservable inputs shall be used to measure fair
      value to the extent that the observable inputs are not available, thereby
      allowing for situations in which there is little, if any, market activity
      for the asset or liability at the measurement date.  Level 3
      inputs primarily consist of unobservable market data or are valued based
      on models and/or assumptions.
 
 Credit
Risk
 
 Counterparty
credit quality and exposure is generally consistent with that of
AEP.
 
 See Note
7 for further information regarding MTM risk management contracts, cash flow
hedging, accumulated other comprehensive income, credit risk and collateral
triggering events.
 
 VaR
Associated with Risk Management Contracts
 
 Management
uses a risk measurement model, which calculates Value at Risk (VaR) to measure
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, 2009, a near term
typical change in commodity prices is not expected to have a material effect on
net income, cash flows or financial condition.
 
 The
following table shows the end, high, average, and low market risk as measured by
VaR for the periods indicated:
 
 Three
      Months Ended
                
                
                
                
                Twelve
      Months EndedMarch
      31, 2009
                
                
                
                
                December
      31, 2008(in
      thousands)
                
                
                
                
                (in
      thousands)End
                
                High
                
                Average
                
                Low
                
                
                
                
                End
                
                High
                
                Average
                
                Low$23
                
                $49
                
                $20
                
                $6
                
                
                
                
                $8
                
                $220
                
                $62
                
                $8
 
 Management
back-tests its VaR results against performance due to actual price
moves.  Based on the assumed 95% confidence interval, the performance
due to actual price moves would be expected to exceed the VaR at least once
every 20 trading days.  Management’s backtesting results show that its
actual performance exceeded VaR far fewer than once every 20 trading
days.  As a result, management believes SWEPCo’s VaR calculation is
conservative.
  As
SWEPCo’s VaR calculation captures recent price moves, management also performs
regular stress testing of the portfolio to understand SWEPCo’s exposure to
extreme price moves.  Management employs a historical-based method
whereby the current portfolio is subjected to actual, observed price moves from
the last three years in order to ascertain which historical price moves
translated into the largest potential MTM loss.  Management then
researches the underlying positions, price moves and market events that created
the most significant exposure.
 
 Interest
Rate Risk
 
 Management
utilizes an Earnings at Risk (EaR) model to measure interest rate market risk
exposure.  EaR statistically quantifies the extent to which SWEPCo’s
interest expense could vary over the next twelve months and gives a
probabilistic estimate of different levels of interest expense.  The
resulting EaR is interpreted as the dollar amount by which actual interest
expense for the next twelve months could exceed expected interest expense with a
one-in-twenty chance of occurrence.  The primary drivers of EaR are
from the existing floating rate debt (including short-term debt) as well as
long-term debt issuances in the next twelve months.  The estimated EaR
on SWEPCo’s debt portfolio was $3 million.
  
 SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
 CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
 For
the Three Months Ended March 31, 2009 and 2008
 (in
thousands)
 (Unaudited)
 2009
                          
                          
                          2008REVENUESElectric
      Generation, Transmission and Distribution
                          
                          $
                          302,383
                          
                          
                          $
                          313,913Sales
      to AEP Affiliates
                          
                          
                          8,344
                          
                          
                          
                          13,592Lignite
      Revenues – Nonaffiliated
                          
                          
                          10,720
                          
                          
                          
                          11,988Other
                          
                          
                          355
                          
                          
                          
                          300TOTAL
                          
                          
                          321,802
                          
                          
                          
                          339,793EXPENSESFuel
      and Other Consumables Used for Electric Generation
                          
                          
                          126,315
                          
                          
                          
                          117,661Purchased
      Electricity for Resale
                          
                          
                          24,397
                          
                          
                          
                          40,270Purchased
      Electricity from AEP Affiliates
                          
                          
                          13,010
                          
                          
                          
                          20,440Other
      Operation
                          
                          
                          54,204
                          
                          
                          
                          63,579Maintenance
                          
                          
                          26,702
                          
                          
                          
                          27,468Depreciation
      and Amortization
                          
                          
                          36,792
                          
                          
                          
                          36,136Taxes
      Other Than Income Taxes
                          
                          
                          15,389
                          
                          
                          
                          17,419TOTAL
                          
                          
                          296,809
                          
                          
                          
                          322,973OPERATING
      INCOME
                          
                          
                          24,993
                          
                          
                          
                          16,820Other
      Income (Expense):Interest
      Income
                          
                          
                          454
                          
                          
                          
                          877Allowance
      for Equity Funds Used During Construction
                          
                          
                          6,405
                          
                          
                          
                          3,063Interest
      Expense
                          
                          
                          (16,299
                          )
                          
                          
                          (17,142
                          )INCOME
      BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS
                          
                          
                          15,553
                          
                          
                          
                          3,618Income
      Tax Expense (Credit)
                          
                          
                          3,853
                          
                          
                          
                          (1,987
                          )NET
      INCOME
                          
                          
                          11,700
                          
                          
                          
                          5,605Less:
      Net Income Attributable to Noncontrolling Interest
                          
                          
                          1,137
                          
                          
                          
                          995NET
      INCOME ATTRIBUTABLE TO SWEPCo SHAREHOLDERS
                          
                          
                          10,563
                          
                          
                          
                          4,610Less:
      Preferred Stock Dividend Requirements
                          
                          
                          57
                          
                          
                          
                          57EARNINGS
      ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER
                          
                          $
                          10,506
                          
                          
                          $
                          4,553
 
 The
      common stock of SWEPCo is wholly-owned by
AEP.
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
   
 SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
 CONDENSED
CONSOLIDATED STATEMENTS OF CHANGES IN
 EQUITY
AND COMPREHENSIVE INCOME (LOSS)
 For
the Three Months Ended March 31, 2009 and 2008
 (in
thousands)
 (Unaudited)
 
 SWEPCo
      Common ShareholderCommon
      Stock
                              
                              
                              Paid-in
      Capital
                              
                              
                              Retained
                                Earnings
                              
                              
                              Accumulated
                                Other
                                Comprehensive
                                Income
      (Loss)
                              
                              
                              Noncontrolling
                                Interest
                              
                              
                              TotalDECEMBER
      31, 2007
                              
                              $
                              135,660
                              
                              
                              $
                              330,003
                              
                              
                              $
                              523,731
                              
                              
                              $
                              (16,439
                              )
                              
                              $
                              1,687
                              
                              
                              $
                              974,642EITF
      06-10 Adoption, Net of Tax of $622
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              (1,156
                              )
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              (1,156
                              )SFAS
      157 Adoption, Net of Tax of $6
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              10
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              10Capital
      Contribution from Parent
                              
                              
                              
                              
                              
                              
                              50,000
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              50,000Common
      Stock Dividends – Nonaffiliated
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              (949
                              )
                              
                              
                              (949
                              )Preferred
      Stock Dividends
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              (57
                              )
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              (57
                              )TOTAL
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              1,022,490COMPREHENSIVE
      INCOMEOther
      Comprehensive Income (Loss), Net of Taxes:Cash
      Flow Hedges, Net of Tax of $143
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              (269
                              )
                              
                              
                              4
                              
                              
                              
                              (265
                              )Amortization
      of Pension and OPEB Deferred Costs, Net of Tax of $127
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              235
                              
                              
                              
                              
                              
                              
                              
                              235NET
      INCOME
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              4,610
                              
                              
                              
                              
                              
                              
                              
                              995
                              
                              
                              
                              5,605TOTAL
      COMPREHENSIVE INCOME
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              5,575MARCH
      31, 2008
                              
                              $
                              135,660
                              
                              
                              $
                              380,003
                              
                              
                              $
                              527,138
                              
                              
                              $
                              (16,473
                              )
                              
                              $
                              1,737
                              
                              
                              $
                              1,028,065DECEMBER
      31, 2008
                              
                              $
                              135,660
                              
                              
                              $
                              530,003
                              
                              
                              $
                              615,110
                              
                              
                              $
                              (32,120
                              )
                              
                              $
                              276
                              
                              
                              $
                              1,248,929Capital
      Contribution from Parent
                              
                              
                              
                              
                              
                              
                              17,500
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              17,500Common
      Stock Dividends – Nonaffiliated
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              (1,115
                              )
                              
                              
                              (1,115
                              )Preferred
      Stock Dividends
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              (57
                              )
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              (57
                              )Other
                              
                              
                              
                              
                              
                              
                              2,476
                              
                              
                              
                              (2,476
                              )
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              -TOTAL
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              1,265,257COMPREHENSIVE
      INCOMEOther
      Comprehensive Income, Net of Taxes:Cash
      Flow Hedges, Net of Tax of $51
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              95
                              
                              
                              
                              
                              
                              
                              
                              95Amortization
      of Pension and OPEB Deferred Costs, Net of Tax of $243
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              451
                              
                              
                              
                              
                              
                              
                              
                              451NET
      INCOME
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              10,563
                              
                              
                              
                              
                              
                              
                              
                              1,137
                              
                              
                              
                              11,700TOTAL
      COMPREHENSIVE INCOME
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              12,246MARCH
      31, 2009
                              
                              $
                              135,660
                              
                              
                              $
                              549,979
                              
                              
                              $
                              623,140
                              
                              
                              $
                              (31,574
                              )
                              
                              $
                              298
                              
                              
                              $
                              1,277,503
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
   
 SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
 CONDENSED
CONSOLIDATED BALANCE SHEETS
 ASSETS
 March
31, 2009 and December 31, 2008
 (in
thousands)
 (Unaudited)
 2009
                  
                  
                  2008CURRENT
      ASSETSCash
      and Cash Equivalents
                  
                  $
                  1,737
                  
                  
                  $
                  1,910Advances
      to Affiliates
                  
                  
                  37,649
                  
                  
                  
                  -Accounts
      Receivable:Customers
                  
                  
                  53,346
                  
                  
                  
                  53,506Affiliated
      Companies
                  
                  
                  29,914
                  
                  
                  
                  121,928Miscellaneous
                  
                  
                  9,590
                  
                  
                  
                  12,052Allowance
      for Uncollectible Accounts
                  
                  
                  (145
                  )
                  
                  
                  (135
                  )Total
      Accounts Receivable
                  
                  
                  92,705
                  
                  
                  
                  187,351Fuel
                  
                  
                  103,544
                  
                  
                  
                  100,018Materials
      and Supplies
                  
                  
                  50,973
                  
                  
                  
                  49,724Risk
      Management Assets
                  
                  
                  10,187
                  
                  
                  
                  8,185Regulatory
      Asset for Under-Recovered Fuel Costs
                  
                  
                  35,495
                  
                  
                  
                  75,006Prepayments
      and Other
                  
                  
                  23,420
                  
                  
                  
                  20,147TOTAL
                  
                  
                  355,710
                  
                  
                  
                  442,341PROPERTY,
      PLANT AND EQUIPMENTElectric:Production
                  
                  
                  1,811,359
                  
                  
                  
                  1,808,482Transmission
                  
                  
                  793,702
                  
                  
                  
                  786,731Distribution
                  
                  
                  1,415,210
                  
                  
                  
                  1,400,952Other
                  
                  
                  712,739
                  
                  
                  
                  711,260Construction
      Work in Progress
                  
                  
                  904,837
                  
                  
                  
                  869,103Total
                  
                  
                  5,637,847
                  
                  
                  
                  5,576,528Accumulated
      Depreciation and Amortization
                  
                  
                  2,048,482
                  
                  
                  
                  2,014,154TOTAL
      - NET
                  
                  
                  3,589,365
                  
                  
                  
                  3,562,374OTHER
      NONCURRENT ASSETSRegulatory
      Assets
                  
                  
                  219,245
                  
                  
                  
                  210,174Long-term
      Risk Management Assets
                  
                  
                  920
                  
                  
                  
                  1,500Deferred
      Charges and Other
                  
                  
                  63,328
                  
                  
                  
                  36,696TOTAL
                  
                  
                  283,493
                  
                  
                  
                  248,370TOTAL
      ASSETS
                  
                  $
                  4,228,568
                  
                  
                  $
                  4,253,085
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
 
 SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
 CONDENSED
CONSOLIDATED BALANCE SHEETS
 LIABILITIES
AND EQUITY
 March
31, 2009 and December 31, 2008
 (Unaudited)
 2009
                  
                  
                  2008CURRENT
      LIABILITIES
                  
                  (in
      thousands)Advances
      from Affiliates
                  
                  $
                  -
                  
                  
                  $
                  2,526Accounts
      Payable:General
                  
                  
                  121,185
                  
                  
                  
                  133,538Affiliated
      Companies
                  
                  
                  56,181
                  
                  
                  
                  51,040Short-term
      Debt – Nonaffiliated
                  
                  
                  6,559
                  
                  
                  
                  7,172Long-term
      Debt Due Within One Year – Nonaffiliated
                  
                  
                  4,406
                  
                  
                  
                  4,406Long-term
      Debt Due Within One Year – Affiliated
                  
                  
                  50,000
                  
                  
                  
                  -Risk
      Management Liabilities
                  
                  
                  7,565
                  
                  
                  
                  6,735Customer
      Deposits
                  
                  
                  38,211
                  
                  
                  
                  35,622Accrued
      Taxes
                  
                  
                  92,538
                  
                  
                  
                  33,744Accrued
      Interest
                  
                  
                  16,487
                  
                  
                  
                  36,647Regulatory
      Liability for Over-Recovered Fuel Costs
                  
                  
                  6,380
                  
                  
                  
                  5,162Provision
      for Revenue Refund
                  
                  
                  26,957
                  
                  
                  
                  54,100Other
                  
                  
                  59,117
                  
                  
                  
                  97,373TOTAL
                  
                  
                  485,586
                  
                  
                  
                  468,065NONCURRENT
      LIABILITIESLong-term
      Debt – Nonaffiliated
                  
                  
                  1,422,744
                  
                  
                  
                  1,423,743Long-term
      Debt – Affiliated
                  
                  
                  -
                  
                  
                  
                  50,000Long-term
      Risk Management Liabilities
                  
                  
                  528
                  
                  
                  
                  516Deferred
      Income Taxes
                  
                  
                  386,089
                  
                  
                  
                  403,125Regulatory
      Liabilities and Deferred Investment Tax Credits
                  
                  
                  333,386
                  
                  
                  
                  335,749Asset
      Retirement Obligations
                  
                  
                  52,018
                  
                  
                  
                  53,433Employment
      Benefits and Pension Obligations
                  
                  
                  123,689
                  
                  
                  
                  117,772Deferred
      Credits and Other
                  
                  
                  142,328
                  
                  
                  
                  147,056TOTAL
                  
                  
                  2,460,782
                  
                  
                  
                  2,531,394TOTAL
      LIABILITIES
                  
                  
                  2,946,368
                  
                  
                  
                  2,999,459Cumulative
      Preferred Stock Not Subject to Mandatory Redemption
                  
                  
                  4,697
                  
                  
                  
                  4,697Commitments
      and Contingencies (Note 4)EQUITYCommon
      Stock – Par Value – $18 Per Share:Authorized
      – 7,600,000 SharesOutstanding
      – 7,536,640 Shares
                  
                  
                  135,660
                  
                  
                  
                  135,660Paid-in
      Capital
                  
                  
                  549,979
                  
                  
                  
                  530,003Retained
      Earnings
                  
                  
                  623,140
                  
                  
                  
                  615,110Accumulated
      Other Comprehensive Income (Loss)
                  
                  
                  (31,574
                  )
                  
                  
                  (32,120
                  )TOTAL
      COMMON SHAREHOLDER’S EQUITY
                  
                  
                  1,277,205
                  
                  
                  
                  1,248,653Noncontrolling
      Interest
                  
                  
                  298
                  
                  
                  
                  276TOTAL
      EQUITY
                  
                  
                  1,277,503
                  
                  
                  
                  1,248,929TOTAL
      LIABILITIES AND EQUITY
                  
                  $
                  4,228,568
                  
                  
                  $
                  4,253,085
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
 
 
 SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
 CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS
 For
the Three Months Ended March 31, 2009 and 2008
 (in
thousands)
 (Unaudited)
 2009
                      
                      
                      2008OPERATING
      ACTIVITIESNet
      Income
                      
                      $
                      11,700
                      
                      
                      $
                      5,605Adjustments
      to Reconcile Net Income to Net Cash Flows from (Used for) Operating
        Activities:Depreciation
      and Amortization
                      
                      
                      36,792
                      
                      
                      
                      36,136Deferred
      Income Taxes
                      
                      
                      (27,042
                      )
                      
                      
                      3,804Allowance
      for Equity Funds Used During Construction
                      
                      
                      (6,405
                      )
                      
                      
                      (3,063
                      )Mark-to-Market
      of Risk Management Contracts
                      
                      
                      (752
                      )
                      
                      
                      (14,231
                      )Deferred
      Property Taxes
                      
                      
                      (29,792
                      )
                      
                      
                      (29,799
                      )Change
      in Other Noncurrent Assets
                      
                      
                      6,230
                      
                      
                      
                      6,589Change
      in Other Noncurrent Liabilities
                      
                      
                      331
                      
                      
                      
                      (14,680
                      )Changes
      in Certain Components of Working Capital:Accounts
      Receivable, Net
                      
                      
                      94,646
                      
                      
                      
                      22,169Fuel,
      Materials and Supplies
                      
                      
                      (4,775
                      )
                      
                      
                      (1,874
                      )Accounts
      Payable
                      
                      
                      (2,717
                      )
                      
                      
                      7,398Accrued
      Taxes, Net
                      
                      
                      58,794
                      
                      
                      
                      21,279Accrued
      Interest
                      
                      
                      (20,160
                      )
                      
                      
                      749Fuel
      Over/Under-Recovery, Net
                      
                      
                      26,786
                      
                      
                      
                      (39,888
                      )Other
      Current Assets
                      
                      
                      326
                      
                      
                      
                      7,683Other
      Current Liabilities
                      
                      
                      (50,492
                      )
                      
                      
                      (11,030
                      )Net
      Cash Flows from (Used for) Operating Activities
                      
                      
                      93,470
                      
                      
                      
                      (3,153
                      )INVESTING
      ACTIVITIESConstruction
      Expenditures
                      
                      
                      (169,603
                      )
                      
                      
                      (125,358
                      )Change
      in Other Cash Deposits
                      
                      
                      (954
                      )
                      
                      
                      (585
                      )Change
      in Advances to Affiliates, Net
                      
                      
                      (37,649
                      )
                      
                      
                      -Proceeds
      from Sales of Assets
                      
                      
                      104,824
                      
                      
                      
                      66Net
      Cash Flows Used for Investing Activities
                      
                      
                      (103,382
                      )
                      
                      
                      (125,877
                      )FINANCING
      ACTIVITIESCapital
      Contribution from Parent
                      
                      
                      17,500
                      
                      
                      
                      50,000Issuance
      of Long-term Debt – Nonaffiliated
                      
                      
                      (15
                      )
                      
                      
                      -Change
      in Short-term Debt, Net – Nonaffiliated
                      
                      
                      (613
                      )
                      
                      
                      (285
                      )Change
      in Advances from Affiliates, Net
                      
                      
                      (2,526
                      )
                      
                      
                      87,645Retirement
      of Long-term Debt – Nonaffiliated
                      
                      
                      (1,101
                      )
                      
                      
                      (1,851
                      )Principal
      Payments for Capital Lease Obligations
                      
                      
                      (2,334
                      )
                      
                      
                      (1,312
                      )Dividends
      Paid on Common Stock – Nonaffiliated
                      
                      
                      (1,115
                      )
                      
                      
                      (949
                      )Dividends
      Paid on Cumulative Preferred Stock
                      
                      
                      (57
                      )
                      
                      
                      (57
                      )Net
      Cash Flows from Financing Activities
                      
                      
                      9,739
                      
                      
                      
                      133,191Net
      Increase (Decrease) in Cash and Cash Equivalents
                      
                      
                      (173
                      )
                      
                      
                      4,161Cash
      and Cash Equivalents at Beginning of Period
                      
                      
                      1,910
                      
                      
                      
                      1,742Cash
      and Cash Equivalents at End of Period
                      
                      $
                      1,737
                      
                      
                      $
                      5,903
 
 SUPPLEMENTARY
      INFORMATIONCash
      Paid for Interest, Net of Capitalized Amounts
                  
                  $
                  51,573
                  
                  
                  $
                  14,049Net
      Cash Paid (Received) for Income Taxes
                  
                  
                  (1,117
                  )
                  
                  
                  641Noncash
      Acquisitions Under Capital Leases
                  
                  
                  1,568
                  
                  
                  
                  6,796Construction
      Expenditures Included in Accounts Payable at March 31,
                  
                  
                  72,331
                  
                  
                  
                  63,973
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
 
 SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
 INDEX
TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
 REGISTRANT
SUBSIDIARIES
 
 The
condensed notes to SWEPCo’s condensed consolidated financial statements are
combined with the condensed notes to condensed financial statements for other
registrant subsidiaries.  Listed below are the notes that apply to
SWEPCo.
 Footnote
      ReferenceSignificant
      Accounting Matters
                                  Note
      1New
      Accounting Pronouncements
                                  Note
      2Rate
      Matters
                                  Note
      3Commitments,
      Guarantees and Contingencies
                                  Note
      4Benefit
      Plans
                                  Note
      5Business
      Segments
                                  Note
      6Derivatives,
      Hedging and Fair Value Measurements
                                  Note
      7Income
      Taxes
                                  Note
      8Financing
      Activities
                                  Note
      9









CONDENSED NOTES TO CONDENSED
FINANCIAL STATEMENTS OF


REGISTRANT
SUBSIDIARIES





The
      condensed notes to condensed financial statements that follow are a
      combined presentation for the Registrant Subsidiaries.  The
      following list indicates the registrants to which the footnotes
      apply:1.
                              Significant
      Accounting Matters
                              APCo,
      CSPCo, I&M, OPCo, PSO, SWEPCo2.
                              New
      Accounting Pronouncements
                              APCo,
      CSPCo, I&M, OPCo, PSO, SWEPCo3.
                              Rate
      Matters
                              APCo,
      CSPCo, I&M, OPCo, PSO, SWEPCo4.
                              Commitments,
      Guarantees and Contingencies
                              APCo,
      CSPCo, I&M, OPCo, PSO, SWEPCo5.
                              Benefit
      Plans
                              APCo,
      CSPCo, I&M, OPCo, PSO, SWEPCo6.
                              Business
      Segments
                              APCo,
      CSPCo, I&M, OPCo, PSO, SWEPCo7.
                              Derivatives,
      Hedging and Fair Value Measurements
                              APCo,
      CSPCo, I&M, OPCo, PSO, SWEPCo8.
                              Income
      Taxes
                              APCo,
      CSPCo, I&M, OPCo, PSO, SWEPCo9.
                              Financing
      Activities
                              APCo,
      CSPCo, I&M, OPCo, PSO,
SWEPCo













1.
            SIGNIFICANT ACCOUNTING
      MATTERS





General





The
accompanying unaudited condensed financial statements and footnotes were
prepared in accordance with GAAP for interim financial information and with the
instructions to Form 10-Q and Article 10 of Regulation S-X of the
SEC.  Accordingly, they do not include all the information and
footnotes required by GAAP for complete annual financial
statements.





In the
opinion of management, the unaudited interim financial statements reflect all
normal and recurring accruals and adjustments necessary for a fair presentation
of the net income, financial position and cash flows for the interim periods for
each Registrant Subsidiary.  The net income for the three months March
31, 2009 is not necessarily indicative of results that may be expected for the
year ending December 31, 2009.  The accompanying condensed financial
statements are unaudited and should be read in conjunction with the audited 2008
financial statements and notes thereto, which are included in the Registrant
Subsidiaries’ Annual Reports on Form 10-K for the year ended December 31, 2008
as filed with the SEC on February 27, 2009.





Variable Interest
Entities





FIN 46R
is a consolidation model that considers risk absorption of a variable interest
entity (VIE), also referred to as variability.  Entities are required
to consolidate a VIE when it is determined that they are the primary beneficiary
of that VIE, as defined by FIN 46R.  In determining whether they are
the primary beneficiary of a VIE, each Registrant Subsidiary considers factors
such as equity at risk, the amount of the VIE’s variability the Registrant
Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out
rights, the power to direct the VIE and other factors.  Management
believes that significant assumptions and judgments were applied consistently
and that there are no other reasonable judgments or assumptions that would
result in a different conclusion.  In addition, the Registrant
Subsidiaries have not provided financial or other support to any VIE that was
not previously contractually required.





SWEPCo is
the primary beneficiary of Sabine and DHLC.  OPCo is the primary
beneficiary of JMG.  APCo, CSPCo, I&M, OPCo, PSO and SWEPCo each
hold a significant variable interest in AEPSC.  I&M and CSPCo each
hold a significant variable interest in AEGCo.





Sabine is
a mining operator providing mining services to SWEPCo.  SWEPCo has no
equity investment in Sabine but is Sabine’s only customer.  SWEPCo
guarantees the debt obligations and lease obligations of
Sabine.  Under the terms of the note agreements, substantially all
assets are pledged and all rights under the lignite mining agreement are
assigned to SWEPCo.  The creditors of Sabine have no recourse to any
AEP entity other than SWEPCo.  Under the provisions of the mining
agreement, SWEPCo is required to pay, as a part of the cost of lignite
delivered, an amount equal to mining costs plus a management fee which is
included in Fuel and Other Consumables Used for Electric Generation on SWEPCo’s
Condensed Consolidated Statements of Income.  Based on these facts,
management has concluded that SWEPCo is the primary beneficiary and is required
to consolidate Sabine.  SWEPCo’s total billings from Sabine for the
three months ended March 31, 2009 and 2008 were $35 million and $20 million,
respectively.  See the tables below for the classification of Sabine’s
assets and liabilities on SWEPCo’s Condensed Consolidated Balance
Sheets.





DHLC is a
wholly-owned subsidiary of SWEPCo.  DHLC is a mining operator who
sells 50% of the lignite produced to SWEPCo and 50% to Cleco Corporation, a
nonaffiliated company.  SWEPCo and Cleco Corporation share half of the
executive board seats, with equal voting rights and each entity guarantees a 50%
share of DHLC’s debt.  The creditors of DHLC have no recourse to any
AEP entity other than SWEPCo.  Based on the structure and equity
ownership, management has concluded that SWEPCo is the primary beneficiary and
is required to consolidate DHLC.  SWEPCo’s total billings from DHLC
for the three months ended March 31, 2009 and 2008 were $11 million and $12
million, respectively.  These billings are included in Fuel and Other
Consumables Used for Electric Generation on SWEPCo’s Condensed Consolidated
Statements of Income.  See the tables below for the classification of
DHLC assets and liabilities on SWEPCo’s Condensed Consolidated Balance
Sheets.





The
balances below represent the assets and liabilities of the VIEs that are
consolidated.  These balances include intercompany transactions that
would be eliminated upon consolidation.





SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED


VARIABLE
INTEREST ENTITIES


March
31, 2009


(in
millions)





Sabine
                          
                          
                          DHLCASSETSCurrent
      Assets
                          
                          $
                          34
                          
                          
                          $
                          18Net
      Property, Plant and Equipment
                          
                          
                          122
                          
                          
                          
                          32Other
      Noncurrent Assets
                          
                          
                          30
                          
                          
                          
                          11Total
      Assets
                          
                          $
                          186
                          
                          
                          $
                          61LIABILITIES
      AND EQUITYCurrent
      Liabilities
                          
                          $
                          34
                          
                          
                          $
                          12Noncurrent
      Liabilities
                          
                          
                          152
                          
                          
                          
                          45Equity
                          
                          
                          -
                          
                          
                          
                          4Total
      Liabilities and Equity
                          
                          $
                          186
                          
                          
                          $
                          61





SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED


VARIABLE
INTEREST ENTITIES


December
31, 2008


(in
millions)





Sabine
                  
                  
                  DHLCASSETSCurrent
      Assets
                  
                  $
                  33
                  
                  
                  $
                  22Net
      Property, Plant and Equipment
                  
                  
                  117
                  
                  
                  
                  33Other
      Noncurrent Assets
                  
                  
                  24
                  
                  
                  
                  11Total
      Assets
                  
                  $
                  174
                  
                  
                  $
                  66LIABILITIES
      AND EQUITYCurrent
      Liabilities
                  
                  $
                  32
                  
                  
                  $
                  18Noncurrent
      Liabilities
                  
                  
                  142
                  
                  
                  
                  44Equity
                  
                  
                  -
                  
                  
                  
                  4Total
      Liabilities and Equity
                  
                  $
                  174
                  
                  
                  $
                  66





OPCo has
a lease agreement with JMG to finance OPCo’s FGD system installed on OPCo’s
Gavin Plant.  The PUCO approved the original lease agreement between
OPCo and JMG.  JMG has a capital structure of substantially all debt
from pollution control bonds and other debt.  JMG owns and leases the
FGD to OPCo.  JMG is considered a single-lessee leasing arrangement
with only one asset.  OPCo’s lease payments are the only form of
repayment associated with JMG’s debt obligations even though OPCo does not
guarantee JMG’s debt.  The creditors of JMG have no recourse to any
AEP entity other than OPCo for the lease payment.  OPCo does not have
any ownership interest in JMG.  Based on the structure of the entity,
management has concluded that OPCo is the primary beneficiary and is required to
consolidate JMG.  OPCo’s total billings from JMG for the three months
ended March 31, 2009 and 2008 were $17 million and $12 million,
respectively.  See the tables below for the classification of JMG’s
assets and liabilities on OPCo’s Condensed Consolidated Balance
Sheets.





The
balances below represent the assets and liabilities of the VIE that are
consolidated.  These balances include intercompany transactions that
would be eliminated upon consolidation.





OHIO
POWER COMPANY CONSOLIDATED


VARIABLE
INTEREST ENTITY


March
31, 2009


(in
millions)





JMGASSETSCurrent
      Assets
                  
                  $
                  13Net
      Property, Plant and Equipment
                  
                  
                  417Other
      Noncurrent Assets
                  
                  
                  1Total
      Assets
                  
                  $
                  431LIABILITIES
      AND EQUITYCurrent
      Liabilities
                  
                  $
                  156Noncurrent
      Liabilities
                  
                  
                  257Equity
                  
                  
                  18Total
      Liabilities and Equity
                  
                  $
                  431





OHIO
POWER COMPANY CONSOLIDATED


VARIABLE
INTEREST ENTITY


December
31, 2008


(in
millions)





JMGASSETSCurrent
      Assets
                  
                  $
                  11Net
      Property, Plant and Equipment
                  
                  
                  423Other
      Noncurrent Assets
                  
                  
                  1Total
      Assets
                  
                  $
                  435LIABILITIES
      AND EQUITYCurrent
      Liabilities
                  
                  $
                  161Noncurrent
      Liabilities
                  
                  
                  257Equity
                  
                  
                  17Total
      Liabilities and Equity
                  
                  $
                  435





AEPSC
provides certain managerial and professional services to AEP’s
subsidiaries.  AEP is the sole equity owner of AEPSC.  The
costs of the services are based on a direct charge or on a prorated basis and
billed to the AEP subsidiary companies at AEPSC’s cost.  No AEP
subsidiary has provided financial or other support outside of the reimbursement
of costs for services rendered.  AEPSC finances its operations by cost
reimbursement from other AEP subsidiaries.  There are no other terms
or arrangements between AEPSC and any of the AEP subsidiaries that could require
additional financial support from an AEP subsidiary or expose them to losses
outside of the normal course of business.  AEPSC and its billings are
subject to regulation by the FERC.  AEP’s subsidiaries are exposed to
losses to the extent they cannot recover the costs of AEPSC through their normal
business operations.  All Registrant Subsidiaries are considered to
have a significant interest in the variability in AEPSC due to their activity in
AEPSC’s cost reimbursement structure.  AEPSC is consolidated by
AEP.  In the event AEPSC would require financing or other support
outside the cost reimbursement billings, this financing would be provided by
AEP.





Total
AEPSC billings to the Registrant Subsidiaries were as follows:





Three
      Months Ended March 31,2009
                        
                        
                        2008Company
                        
                        (in
      millions)APCo
                        
                        $
                        50
                        
                        
                        $
                        62CSPCo
                        
                        
                        29
                        
                        
                        
                        32I&M
                        
                        
                        29
                        
                        
                        
                        40OPCo
                        
                        
                        41
                        
                        
                        
                        51PSO
                        
                        
                        21
                        
                        
                        
                        30SWEPCo
                        
                        
                        29
                        
                        
                        
                        34





The
carrying amount and classification of variable interest in AEPSC’s accounts
payable are as follows:





March
      31, 2009
                  
                  
                  December
      31, 2008As
      Reported in
                    theBalance
      Sheet
                  
                  
                  Maximum
                    Exposure
                  
                  
                  As
      Reported in
                    theBalance
      Sheet
                  
                  
                  Maximum
                    Exposure(in
      millions)APCo
                  
                  $
                  14
                  
                  
                  $
                  14
                  
                  
                  $
                  27
                  
                  
                  $
                  27CSPCo
                  
                  
                  9
                  
                  
                  
                  9
                  
                  
                  
                  15
                  
                  
                  
                  15I&M
                  
                  
                  8
                  
                  
                  
                  8
                  
                  
                  
                  14
                  
                  
                  
                  14OPCo
                  
                  
                  11
                  
                  
                  
                  11
                  
                  
                  
                  21
                  
                  
                  
                  21PSO
                  
                  
                  6
                  
                  
                  
                  6
                  
                  
                  
                  10
                  
                  
                  
                  10SWEPCo
                  
                  
                  8
                  
                  
                  
                  8
                  
                  
                  
                  14
                  
                  
                  
                  14





AEGCo, a
wholly-owned subsidiary of AEP, is consolidated by AEP.  AEGCo owns a
50% ownership interest in Rockport Plant Unit 1, leases a 50% interest in
Rockport Plant Unit 2 and owns 100% of the Lawrenceburg Generating
Station.  AEGCo sells all the output from the Rockport Plant to
I&M and KPCo.  In May 2007, AEGCo began leasing the Lawrenceburg
Generating Station to CSPCo.  AEP guarantees all the debt obligations
of AEGCo.  I&M and CSPCo are considered to have a significant
interest in AEGCo due to these transactions.  I&M and CSPCo are
exposed to losses to the extent they cannot recover the costs of AEGCo through
their normal business operations.  Due to the nature of the AEP Power
Pool, there is a sharing of the cost of Rockport and Lawrenceburg Plants such
that no member of the AEP Power Pool is the primary beneficiary of AEGCo’s
Rockport or Lawrenceburg Plants.  In the event AEGCo would require
financing or other support outside the billings to I&M, CSPCo and KPCo, this
financing would be provided by AEP.  For additional information
regarding AEGCo’s lease, see “Rockport Lease” section of Note 13 in the 2008
Annual Report.





Total
billings from AEGCo were as follows:





Three
      Months Ended March 31,2009
                      
                      2008(in
      millions)CSPCo
                      
                      $
                      17
                      
                      
                      $
                      24I&M
                      
                      
                      63
                      
                      
                      
                      59





The
carrying amount and classification of variable interest in AEGCo’s accounts
payable are as follows:





March
      31, 2009
                  
                  December
      31, 2008As
      Reported in the
                    Consolidated
                    Balance
      Sheet
                  
                  Maximum
                    Exposure
                  
                  As
      Reported in the
                    Consolidated
                    Balance
      Sheet
                  
                  Maximum
                    Exposure(in
      millions)CSPCo
                  
                  $
                  6
                  
                  
                  $
                  6
                  
                  
                  $
                  5
                  
                  
                  $
                  5I&M
                  
                  
                  21
                  
                  
                  
                  21
                  
                  
                  
                  23
                  
                  
                  
                  23





Revenue
Recognition – Traditional Electricity Supply and Demand





Revenues
are recognized from retail and wholesale electricity sales and electricity
transmission and distribution delivery services.  The Registrant
Subsidiaries recognize the revenues on their statements of income upon
delivery of the energy to the customer and include unbilled as well as billed
amounts.





Most of
the power produced at the generation plants of the AEP East companies is sold to
PJM, the RTO operating in the east service territory.  The AEP East
companies then purchase power from PJM to supply their
customers.  Generally, these power sales and purchases are reported on
a net basis as revenues on the AEP East companies’ statements of
income.  However, in the first quarter of 2009, there were times when
the AEP East companies were  purchasers of power from PJM to serve
retail load.  These purchases were recorded gross as Purchased
Electricity for Resale on the AEP East companies’ statements of
income.  Other RTOs in which the AEP East companies operate do not
function in the same manner as PJM.  They function as balancing
organizations and not as exchanges.





Physical
energy purchases, including those from RTOs, that are identified as non-trading,
are accounted for on a gross basis in Purchased Electricity for Resale on the
statements of income.




CSPCo
and OPCo Revised Depreciation Rates
 
 Effective
January 1, 2009, CSPCo and OPCo revised book depreciation rates for generating
plants consistent with a recently completed depreciation
study.  OPCo’s overall higher depreciation rates primarily related to
shortened depreciable lives for certain OPCo generating
facilities.  The impact of the change in depreciation rates was an
increase in OPCo’s depreciation expense of $17 million and a decrease in CSPCo’s
depreciation expense of $4 million when comparing the three months ended March
31, 2009 and 2008.




Acquisition
– Oxbow Mine Lignite – Affecting SWEPCo
 
 In April
2009, SWEPCo and its wholly-owned lignite mining subsidiary, Dolet Hills Mining
Company, LLC (DHLC), agreed to purchase 50% of the Oxbow Mine lignite reserves
and 100% of all associated mining equipment and assets from The North American
Coal Corporation and its affiliates, Red River Mining Company and Oxbow Property
Company, LLC for $42 million.  Cleco Power LLC (Cleco), will acquire
the remaining 50% of the lignite reserves.  Consummation of the
transaction is subject to regulatory approval by the LPSC and the APSC and the
transfer of other regulatory instruments.  If approved, DHLC will
acquire and own the Oxbow Mine mining equipment and related assets and it will
operate the Oxbow Mine.  The Oxbow Mine is located near Coushatta,
Louisiana and will be used as one of the fuel sources for SWEPCo’s and Cleco’s
jointly-owned Dolet Hills Generating Station.





2.
            NEW ACCOUNTING
      PRONOUNCEMENTS





Upon
issuance of final pronouncements, management reviews the new accounting
literature to determine its relevance, if any, to the Registrant Subsidiaries’
business.  The following represents a summary of final pronouncements
issued or implemented in 2009 and standards issued but not implemented that
management has determined relate to the Registrant Subsidiaries’
operations.





Pronouncements Adopted
During the First Quarter of 2009





The
following standards were effective during the first quarter of
2009.  Consequently, the financial statements and footnotes reflect
their impact.





SFAS
141 (revised 2007) “Business Combinations” (SFAS 141R)





In
December 2007, the FASB issued SFAS 141R, improving financial reporting about
business combinations and their effects.  It established how the
acquiring entity recognizes and measures the identifiable assets acquired,
liabilities assumed, goodwill acquired, any gain on bargain purchases and any
noncontrolling interest in the acquired entity.  SFAS 141R no longer
allows acquisition-related costs to be included in the cost of the business
combination, but rather expensed in the periods they are incurred, with the
exception of the costs to issue debt or equity securities which shall be
recognized in accordance with other applicable GAAP.  The standard
requires disclosure of information for a business combination that occurs during
the accounting period or prior to the issuance of the financial statements for
the accounting period.  SFAS 141R can affect tax positions on previous
acquisitions.  The Registrant Subsidiaries do not have any such tax
positions that result in adjustments.





In April
2009, the FASB issued FSP SFAS 141(R)-1 “Accounting for Assets Acquired and
Liabilities Assumed in a Business Combination That Arise from
Contingencies.”  The standard clarifies accounting and disclosure for
contingencies arising in business combinations.  It was effective
January 1, 2009.





The
Registrant Subsidiaries adopted SFAS 141R, including the FSP, effective January
1, 2009.  It is effective prospectively for business combinations with
an acquisition date on or after January 1, 2009.  The Registrant
Subsidiaries will apply it to any future business combinations.





SFAS
160 “Noncontrolling Interest in Consolidated Financial Statements” (SFAS
160)





In
December 2007, the FASB issued SFAS 160, modifying reporting for noncontrolling
interest (minority interest) in consolidated financial
statements.  The statement requires noncontrolling interest be
reported in equity and establishes a new framework for recognizing net income or
loss and comprehensive income by the controlling interest.  Upon
deconsolidation due to loss of control over a subsidiary, the standard requires
a fair value remeasurement of any remaining noncontrolling equity investment to
be used to properly recognize the gain or loss.  SFAS 160 requires
specific disclosures regarding changes in equity interest of both the
controlling and noncontrolling parties and presentation of the noncontrolling
equity balance and income or loss for all periods presented.





The
Registrant Subsidiaries adopted SFAS 160 effective January 1, 2009 and
retrospectively applied the standard to prior periods.  The adoption
of SFAS 160 had no impact on APCo, CSPCo, I&M and PSO.  The
retrospective application of this standard impacted OPCo and SWEPCo as
follows:





OPCo:


·
            Reclassifies
      Interest Expense of $463 thousand for the three months ended March 31,
      2008 as Net Income Attributable to Noncontrolling Interest below Net
      Income in the presentation of Earnings Attributable to OPCo Common
      Shareholder in its Condensed Consolidated Statements of
      Income.·
            Reclassifies
      minority interest of $16.8 million as of December 31, 2008 previously
      included in Deferred Credits and Other and Total Liabilities as
      Noncontrolling Interest in Total Equity on its Condensed Consolidated
      Balance Sheets.·
            Separately
      reflects changes in Noncontrolling Interest in its Statements of Changes
      in Equity and Comprehensive Income (Loss).·
            Reclassifies
      dividends paid to noncontrolling interests of $463 thousand for the three
      months ended March 31, 2008 from Operating Activities to Financing
      Activities in the Condensed Consolidated Statements of Cash
      Flows.





SWEPCo:


·
            Reclassifies
      Minority Interest Expense of $995 thousand for the three months ended
      March 31, 2008 as Net Income Attributable to Noncontrolling Interest below
      Net Income in the presentation of Earnings Attributable to SWEPCo
      Common Shareholder in its Condensed Consolidated Statements of
      Income.·
            Reclassifies
      minority interest of $276 thousand as of December 31, 2008 previously
      included in Deferred Credits and Other and Total Liabilities as
      Noncontrolling Interest in Total Equity on its Condensed Consolidated
      Balance Sheets.·
            Separately
      reflects changes in Noncontrolling Interest in the Statements of Changes
      in Equity and Comprehensive Income (Loss).·
            Reclassifies
      dividends paid to noncontrolling interests of $949 thousand for the three
      months ended March 31, 2008 from Operating Activities to Financing
      Activities in the Condensed Consolidated Statements of Cash
      Flows.





SFAS
161 “Disclosures about Derivative Instruments and Hedging Activities” (SFAS
161)





In March
2008, the FASB issued SFAS 161, enhancing disclosure requirements for derivative
instruments and hedging activities.  Affected entities are required to
provide enhanced disclosures about (a) how and why an entity uses derivative
instruments, (b) how an entity accounts for derivative instruments and related
hedged items and (c) how derivative instruments and related hedged items affect
an entity’s financial position, financial performance and cash
flows.  The standard requires that objectives for using derivative
instruments be disclosed in terms of the primary underlying risk and accounting
designation.





The
Registrant Subsidiaries adopted SFAS 161 effective January 1,
2009.  This standard increased the disclosures related to derivative
instruments and hedging activities.  See “Derivatives and Hedging”
section of Note 7 for further information.




EITF
Issue No. 08-5 “Issuer’s Accounting for Liabilities Measured at Fair Value with
a Third-Party Credit
 Enhancement” (EITF 08-5)


In
September 2008, the FASB ratified the consensus on liabilities with third-party
credit enhancements when the liability is measured and disclosed at fair
value.  The consensus treats the liability and the credit enhancement
as two units of accounting.  Under the consensus, the fair value
measurement of the liability does not include the effect of the third-party
credit enhancement.  Consequently, changes in the issuer’s credit
standing without the support of the credit enhancement affect the fair value
measurement of the issuer’s liability.  Entities will need to provide
disclosures about the existence of any third-party credit enhancements related
to their liabilities.  In the period of adoption, entities must
disclose the valuation method(s) used to measure the fair value of liabilities
within its scope and any change in the fair value measurement method that occurs
as a result of its initial application.





The
Registrant Subsidiaries adopted EITF 08-5 effective January 1,
2009.  It will be applied prospectively with the effect of initial
application included as a change in fair value of the liability.





EITF
Issue No. 08-6 “Equity Method Investment Accounting Considerations” (EITF
08-6)





In
November 2008, the FASB ratified the consensus on equity method investment
accounting including initial and allocated carrying values and subsequent
measurements.  It requires initial carrying value be determined using
the SFAS 141R cost allocation method.  When an investee issues shares,
the equity method investor should treat the transaction as if the investor sold
part of its interest.





The
Registrant Subsidiaries adopted EITF 08-6 effective January 1, 2009 with no
impact on the financial statements.  It was applied
prospectively.





FSP
SFAS 142-3 “Determination of the Useful Life of Intangible Assets” (SFAS
142-3)





In April
2008, the FASB issued SFAS 142-3 amending factors that should be considered in
developing renewal or extension assumptions used to determine the useful life of
a recognized intangible asset.  The standard is expected to improve
consistency between the useful life of a recognized intangible asset and the
period of expected cash flows used to measure its fair value.





The
Registrant Subsidiaries adopted SFAS 142-3 effective January 1,
2009.  The guidance is prospectively applied to intangible assets
acquired after the effective date.  The standard’s disclosure
requirements are applied prospectively to all intangible assets as of January 1,
2009.  The adoption of this standard had no impact on the
financial statements.





FSP
SFAS 157-2 “Effective Date of FASB Statement No. 157” (SFAS 157-2)





In
February 2008, the FASB issued SFAS 157-2 which delays the effective date of
SFAS 157 to fiscal years beginning after November 15, 2008 for all nonfinancial
assets and nonfinancial liabilities, except those that are recognized or
disclosed at fair value in the financial statements on a recurring basis (at
least annually).  As defined in SFAS 157, fair value is the price that
would be received to sell an asset or paid to transfer a liability in an orderly
transaction between market participants at the measurement date.  The
fair value hierarchy gives the highest priority to unadjusted quoted prices in
active markets for identical assets or liabilities and the lowest priority to
unobservable inputs.  In the absence of quoted prices for identical or
similar assets or investments in active markets, fair value is estimated using
various internal and external valuation methods including cash flow analysis and
appraisals.





The
Registrant Subsidiaries adopted SFAS 157-2 effective January 1,
2009.  The Registrant Subsidiaries will apply these requirements to
applicable fair value measurements which include new asset retirement
obligations and impairment analysis related to long-lived assets, equity
investments, goodwill and intangibles.  The Registrant Subsidiaries
did not record any fair value measurements for nonrecurring nonfinancial assets
and liabilities in the first quarter of 2009.





Pronouncements Effective in
the Future





The
following standards will be effective in the future and their impacts disclosed
at that time.





FSP
      SFAS 107-1 and APB 28-1 “Interim Disclosures about Fair Value of Financial
      Instruments”
                (FSP SFAS 107-1 and APB 28-1)





In April
2009, the FASB issued FSP SFAS 107-1 and APB 28-1 requiring disclosure about the
fair value of financial instruments in all interim reporting
periods.  The standard requires disclosure of the method and
significant assumptions used to determine the fair value of financial
instruments.





This
standard is effective for interim periods ending after June 15,
2009.  Management expects this standard to increase the disclosure
requirements related to financial instruments.  The Registrant
Subsidiaries will adopt the standard effective second quarter of
2009.





FSP
      SFAS 115-2 and SFAS 124-2 “Recognition and Presentation of
      Other-Than-Temporary Impairments”
                (FSP SFAS 115-2 and SFAS
124-2)





In April
2009, the FASB issued FSP SFAS 115-2 and SFAS 124-2 amending the
other-than-temporary impairment (OTTI) recognition and measurement guidance for
debt securities.  For both debt and equity securities, the standard
requires disclosure for each interim reporting period of information by security
class similar to previous annual disclosure requirements.





This
standard is effective for interim periods ending after June 15,
2009.  Management does not expect a material impact as a result of the
new OTTI evaluation method for debt securities, but expects this standard to
increase the disclosure requirements related to financial
instruments.  The Registrant Subsidiaries will adopt the standard
effective second quarter of 2009.





FSP
SFAS 132R-1 “Employers’ Disclosures about Postretirement Benefit Plan Assets”
(FSP SFAS 132R-1)





In
December 2008, the FASB issued FSP SFAS 132R-1 providing additional disclosure
guidance for pension and OPEB plan assets.  The rule requires
disclosure of investment policy including target allocations by investment
class, investment goals, risk management policies and permitted or prohibited
investments.  It specifies a minimum of investment classes by further
dividing equity and debt securities by issuer grouping.  The standard
adds disclosure requirements including hierarchical classes for fair value and
concentration of risk.





This
standard is effective for fiscal years ending after December 15,
2009.  Management expects this standard to increase the disclosure
requirements related to AEP’s benefit plans.  The Registrant
Subsidiaries will adopt the standard effective for the 2009 Annual
Report.





FSP
      SFAS 157-4 “Determining Fair Value When the Volume and Level of Activity
      for the Asset or Liability
                Have Significantly Decreased and Identifying Transactions That Are Not
      Orderly” (FSP SFAS 157-4)





In April
2009, the FASB issued FSP SFAS 157-4 providing additional guidance on estimating
fair value when the volume and level of activity for an asset or liability has
significantly decreased, including guidance on identifying circumstances
indicating when a transaction is not orderly.  Fair value measurements
shall be based on the price that would be received to sell an asset or paid to
transfer a liability in an orderly (not a distressed sale or forced liquidation)
transaction between market participants at the measurement date under current
market conditions.  The standard also requires disclosures of the
inputs and valuation techniques used to measure fair value and a discussion of
changes in valuation techniques and related inputs, if any, for both interim and
annual periods.





This
standard is effective for interim and annual periods ending after June 15,
2009.  Management expects this standard to have no impact on the
financial statement but will increase disclosure requirements.  The
Registrant Subsidiaries will adopt the standard effective second quarter of
2009.





Future
Accounting Changes





The
FASB’s standard-setting process is ongoing and until new standards have been
finalized and issued by FASB, management cannot determine the impact on the
reporting of the Registrant Subsidiaries’ operations and financial position that
may result from any such future changes.  The FASB is currently
working on several projects including revenue recognition, contingencies,
liabilities and equity, emission allowances, leases, insurance, hedge
accounting, discontinued operations, trading inventory and related tax
impacts.  Management also expects to see more FASB projects as a
result of its desire to converge International Accounting Standards with
GAAP.  The ultimate pronouncements resulting from these and future
projects could have an impact on future net income and financial
position.





3.
            RATE
      MATTERS





The
Registrant Subsidiaries are involved in rate and regulatory proceedings at the
FERC and their state commissions.  The Rate Matters note within the
2008 Annual Report should be read in conjunction with this report to gain a
complete understanding of material rate matters still pending that could impact
net income, cash flows and possibly financial condition.  The
following discusses ratemaking developments in 2009 and updates the 2008 Annual
Report.





Ohio Rate
Matters





Ohio
Electric Security Plan Filings – Affecting CSPCo and OPCo





In July
2008, as required by the 2008 amendments to the Ohio restructuring legislation,
CSPCo and OPCo filed ESPs with the PUCO to establish standard service offer
rates.  CSPCo and OPCo did not file an optional Market Rate Offer
(MRO).  CSPCo’s and OPCo’s ESP filings requested an annual rate
increase for 2009 through 2011 that would not exceed approximately 15% per
year.  A significant portion of the requested ESP increases resulted
from the implementation of a fuel adjustment clause (FAC) that includes fuel
costs, purchased power costs, consumables such as urea, gains and losses on
sales of emission allowances and most other variable production
costs.  FAC costs were proposed to be phased into customer bills over
the three-year period from 2009 through 2011 with unrecovered FAC costs to be
recorded as a FAC phase-in regulatory asset.  The phase-in regulatory
asset deferral along with a deferred weighted average cost of capital carrying
cost was proposed to be recovered over seven years from 2012 through
2018.





In March
2009, the PUCO issued an order that modified and approved CSPCo’s and OPCo’s
ESPs.  The ESPs will be in effect through 2011.  The ESP
order authorized increases to revenues during the ESP period and capped the
overall revenue increases through a phase-in of the FAC.  The ordered
increases for CSPCo are 7% in 2009, 6% in 2010 and 6% in 2011 and for OPCo are
8% in 2009, 7% in 2010 and 8% in 2011.  After final PUCO review and
approval of conforming rate schedules, CSPCo and OPCo implemented rates for the
April 2009 billing cycle.  CSPCo and OPCo will collect the 2009
annualized revenue increase over the remainder of 2009.





The order
provides a FAC for the three-year period of the ESP.  The FAC increase
will be phased in to meet the ordered annual caps described
above.  The FAC increase before phase-in will be subject to quarterly
true-ups to actual recoverable FAC costs and to annual accounting audits and
prudency reviews.  The order allows CSPCo and OPCo to defer
unrecovered FAC costs resulting from the annual caps/phase-in plan and to accrue
carrying charges on such deferrals at CSPCo’s and OPCo’s weighted average cost
of capital.  The deferred FAC balance at the end of the ESP period
will be recovered through a non-bypassable surcharge over the period 2012
through 2018.  As of March 31, 2009, the FAC deferral balances were
$17 million and $66 million for CSPCo and OPCo, respectively, including carrying
charges.  The PUCO rejected a proposal by several intervenors to
offset the FAC costs with a credit for off-system sales margins.  As a
result, CSPCo and OPCo will retain the benefit of their share of the AEP
System’s off-system sales.  In addition, the ESP order provided for
both the FAC deferral credits and the off-system sales margins to be excluded
from the methodology for the Significantly Excessive Earnings Test
(SEET).  The SEET is discussed below.





Additionally,
the order addressed several other items, including:





·
            The
      approval of new distribution riders, subject to true-up for recovery of
      costs for enhanced vegetation management programs, for CSPCo and OPCo and
      the proposed gridSMART advanced metering initial program roll out in a
      portion of CSPCo’s service territory.  The PUCO proposed that
      CSPCo mitigate the costs of gridSMART by seeking matching funds under the
      American Recovery and Reinvestment Act of 2009.  As a result, a
      rider was established to recover 50% or $32 million of the projected $64
      million revenue requirement related to gridSMART costs.  The
      PUCO denied the other distribution system reliability programs proposed by
      CSPCo and OPCo as part of their ESP filings.  The PUCO decided
      that those requests should be examined in the context of a complete
      distribution base rate case.  The order did not require CSPCo
      and/or OPCo to file a distribution base rate
  case.





·
            The
      approval of CSPCo’s and OPCo’s request to recover the incremental carrying
      costs related to environmental investments made from 2001 through 2008
      that are not reflected in existing rates.  Future recovery
      during the ESP period of incremental carrying charges on environmental
      expenditures incurred beginning in 2009 may be requested in annual
      filings.





·
            The
      approval of a $97 million and $55 million increase in CSPCo’s and OPCo’s
      Provider of Last Resort charges, respectively, to compensate for the risk
      of customers changing electric suppliers during the ESP
      period.





·
            The
      requirement that CSPCo’s and OPCo’s shareholders fund a combined minimum
      of $15 million in costs over the ESP period for low-income, at-risk
      customer programs.  This funding obligation was recognized as a
      liability and an unfavorable adjustment to Other Operation and Maintenance
      expense for the three-month period ending March 31,
  2009.





·
            The
      deferral of CSPCo’s and OPCo’s request to recover certain existing
      regulatory assets, including customer choice implementation and line
      extension carrying costs as part of the ESPs.  The PUCO decided
      it would be more appropriate to consider this request in the context of
      CSPCo’s and OPCo’s next distribution base rate case.  These
      regulatory assets, which were approved by prior PUCO orders, total $58
      million for CSPCo and $40 million for OPCo as of March 31,
      2009.  In addition, CSPCo and OPCo would recover and recognize
      as income, when collected, $35 million and $26 million, respectively, of
      related unrecorded equity carrying costs incurred through March
      2009.





Finally,
consistent with its decisions on ESP orders of other companies, the PUCO ordered
its staff to convene a workshop to determine the methodology for the SEET that
will be applicable to all electric utilities in Ohio.  The SEET
requires the PUCO to determine, following the end of each year of the ESP, if
any rate adjustments included in the ESP resulted in excessive earnings as
measured by whether the earned return on common equity of CSPCo and OPCo is
significantly in excess of the return on common equity that was earned during
the same period by publicly traded companies, including utilities, that have
comparable business and financial risk.  If the rate adjustments, in
the aggregate, result in significantly excessive earnings in comparison, the
PUCO must require that the amount of the excess be returned to
customers.  The PUCO’s decision on the SEET review of CSPCo’s and
OPCo’s 2009 earnings is not expected to be finalized until the second or third
quarter of 2010.





In March
2009, intervenors filed a motion to stay a portion of the ESP rates or
alternately make that portion subject to refund because the intervenors believed
that the ordered ESP rates for 2009 were retroactive and therefore
unlawful.  In March 2009, the PUCO approved CSPCo’s and OPCo’s tariffs
effective with the April 2009 billing cycle and rejected the intervenors’
motion.  The PUCO also clarified that the reference in its earlier
order to the January 1, 2009 date related to the term of the ESP, not to the
effective date of tariffs and clarified the tariffs were not
retroactive.  In March 2009, CSPCo and OPCo implemented the new ESP
tariffs effective with the start of the April 2009 billing cycle.  In
April 2009, CSPCo and OPCo filed a motion requesting rehearing of several
issues.  In April 2009, several intervenors filed motions requesting
rehearing of issues underlying the PUCO’s authorized rate increases and one
intervenor filed a motion requesting the PUCO to direct CSPCo and OPCo to cease
collecting rates under the order.  Certain intervenors also filed a
complaint for writ of prohibition with the Ohio Supreme Court to halt any
further collection from customers of what the intervenors claim is unlawful
retroactive rate increases.





Management
will evaluate whether it will withdraw the ESP applications after a final order,
thereby terminating the ESP proceedings.  If CSPCo and/or OPCo
withdraw the ESP applications, CSPCo and/or OPCo may file an MRO or another ESP
as permitted by the law.  The revenues collected and recorded in 2009
under this PUCO order are subject to possible refund through the SEET
process.  Management is unable, due to the decision of the PUCO to
defer guidance on the SEET methodology to a future generic SEET proceeding, to
estimate the amount, if any, of a possible refund that could result from the
SEET process in 2010.





Ohio
IGCC Plant – Affecting CSPCo and OPCo





In March
2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority
to recover costs related to building and operating a 629 MW IGCC power plant
using clean-coal technology.  In June 2006, the PUCO issued an order
approving a tariff to allow CSPCo and OPCo to recover pre-construction costs
over a period of no more than twelve months effective July 1,
2006.  During that period, CSPCo and OPCo each collected $12 million
in pre-construction costs and incurred $11 million in pre-construction
costs.  As a result, CSPCo and OPCo each established a net regulatory
liability of approximately $1 million.





The order
also provided that if CSPCo and OPCo have not commenced a continuous course of
construction of the proposed IGCC plant within five years of the June 2006 PUCO
order, all pre-construction cost recoveries associated with items that may be
utilized in projects at other sites must be refunded to Ohio ratepayers with
interest.





In
September 2008, the Ohio Consumers’ Counsel filed a motion with the PUCO
requesting all pre-construction costs be refunded to Ohio ratepayers with
interest.  In October 2008, CSPCo and OPCo filed a motion with the
PUCO that argued the Ohio Consumers’ Counsel’s motion was without legal merit
and contrary to past precedent.





In
January 2009, a PUCO Attorney Examiner issued an order that CSPCo and OPCo file
a detailed statement outlining the status of the construction of the IGCC plant,
including whether CSPCo and OPCo are engaged in a continuous course of
construction on the IGCC plant.  In February 2009, CSPCo and OPCo
filed a statement that CSPCo and OPCo have not commenced construction of the
IGCC plant and believe there exist real statutory barriers to the construction
of any new base load generation in Ohio, including IGCC plants.  The
statement also indicated that while construction on the IGCC plant might not
begin by June 2011, changes in circumstances could result in the commencement of
construction on a continuous course by that time.





Management
continues to pursue the ultimate construction of the IGCC
plant.  However, CSPCo and OPCo will not start construction of the
IGCC plant until sufficient assurance of regulatory cost recovery
exists.  If CSPCo and OPCo were required to refund the $24 million
collected and those costs were not recoverable in another jurisdiction in
connection with the construction of an IGCC plant, it would have an adverse
effect on future net income and cash flows.  Management cannot predict
the outcome of the cost recovery litigation concerning the Ohio IGCC plant or
what, if any effect, the litigation will have on future net income and cash
flows.





Ormet
– Affecting CSPCo and OPCo





In
December 2008, CSPCo, OPCo and Ormet, a large aluminum company with a load of
520 MW, filed an application with the PUCO for approval of an interim
arrangement governing the provision of generation service to
Ormet.  The arrangement would be effective January 1, 2009 and remain
in effect and expire upon the effective date of CSPCo’s and OPCo’s new ESP rates
and the effective date of a new arrangement between Ormet and CSPCo/OPCo as
approved by the PUCO.  Under the interim arrangement, Ormet would pay
the then-current applicable generation tariff rates and riders.  CSPCo
and OPCo sought to defer as a regulatory asset beginning in 2009 the difference
between the PUCO approved 2008 market price of $53.03 per MWH and the applicable
generation tariff rates and riders.  CSPCo and OPCo proposed to
recover the deferral through the fuel adjustment clause mechanism they proposed
in the ESP proceeding.  In January 2009, the PUCO approved the
application as an interim arrangement.  In February 2009, an
intervenor filed an application for rehearing of the PUCO’s interim arrangement
approval.  In March 2009, the PUCO granted that application for
further consideration of the matters specified in the rehearing
application.





In
February 2009, as amended in April 2009, Ormet filed an application with the
PUCO for approval of a proposed Ormet power contract for 2009 through
2018.  Ormet proposed to pay varying amounts based on certain
conditions, including the price of aluminum and the level of
production.  The difference between the amounts paid by Ormet and the
otherwise applicable PUCO ESP tariff rate would be either collected from or
refunded to CSPCo’s and OPCo’s retail customers.





In March
2009, the PUCO issued an order in the ESP filings which included approval of a
FAC for the ESP period.  The approval of an ESP FAC, together with the
January 2009 PUCO approval of the Ormet interim arrangement, provided the basis
to record regulatory assets of $10 million and $9 million for CSPCo and OPCo,
respectively, for the differential in the approved market price of $53.03 versus
the rate paid by Ormet during the first quarter of 2009.  These
amounts are included in CSPCo’s and OPCo’s FAC phase-in deferral balance of $17
million and $66 million, respectively.  See “Ohio Electric Security
Plan Filings” section above.





The
pricing and deferral authority under the PUCO’s January 2009 approval of the
interim arrangement will continue until the 2009-2018 power contract becomes
effective.  Management cannot predict when or if the PUCO will approve
the new power contract.





Hurricane
Ike – Affecting CSPCo and OPCo





In
September 2008, the service territories of CSPCo and OPCo were impacted by
strong winds from the remnants of Hurricane Ike.  Under the RSP, which
was effective in 2008, CSPCo and OPCo could seek a distribution rate adjustment
to recover incremental distribution expenses related to major storm service
restoration efforts.  In September 2008, CSPCo and OPCo established
regulatory assets of $17 million and $10 million, respectively, for the expected
recovery of the storm restoration costs.  In December 2008, CSPCo and
OPCo filed with the PUCO a request to establish the regulatory assets under the
terms of the RSP, plus accrue carrying costs on the unrecovered balance using
CSPCo’s and OPCo’s weighted average cost of capital carrying charge
rates.  In December 2008, the PUCO subsequently approved the
establishment of the regulatory assets but authorized CSPCo and OPCo to record a
long-term debt only carrying cost on the regulatory asset.  In its
order approving the deferrals, the PUCO stated that the mechanism for recovery
would be determined in CSPCo’s and OPCo’s next distribution rate
filing.





In
December 2008, the Consumers for Reliable Electricity in Ohio filed a request
with the PUCO asking for an investigation into the service reliability of Ohio’s
investor-owned electric utilities, including CSPCo and OPCo.  The
investigation request included the widespread outages caused by the September
2008 wind storm.  CSPCo and OPCo filed a response asking the PUCO to
deny the request.





As a
result of the past favorable treatment of storm restoration costs under the RSP
and the RSP recovery provisions, which were in effect when the storm occurred
and the filings made, management believes the recovery of the regulatory assets
is probable.  However, if these regulatory assets are not recovered,
it would have an adverse effect on future net income and cash
flows.





TexasRate
Matters





Texas
Restructuring – SPP – Affecting SWEPCo





In August
2006, the PUCT adopted a rule extending the delay in implementation of customer
choice in SWEPCo’s SPP area of Texas until no sooner than January 1,
2011.  In April 2009, the Texas Senate passed a bill related to
SWEPCo’s SPP area of Texas that requires cost of service regulation until
certain stages have been completed and approved by the PUCT such that fair
competition is available to all retail customer classes.  The bill is
expected to be reviewed by the Texas House of Representatives which, if passed,
would be sent to the governor of Texas for approval.  If the bill is
signed, management may be required to re-apply SFAS 71 for the generation
portion of SWEPCo’s Texas jurisdiction.  The initial reapplication of
SFAS 71 regulatory accounting would likely result in an extraordinary
loss.





Stall
Unit





See
“Stall Unit” section within “Louisiana Rate Matters” for
disclosure.





Turk
Plant





See “Turk
Plant” section within “Arkansas Rate Matters” for disclosure.





Virginia Rate
Matters





Virginia
E&R Costs Recovery Filing – Affecting APCo





Due to
the recovery provisions in Virginia law, APCo has been deferring incremental
E&R costs as incurred, excluding the equity return on non-CWIP capital
investments, pending future recovery.  In October 2008, the Virginia
SCC approved a stipulation agreement to recover $61 million of incremental
E&R costs incurred from October 2006 to December 2007 through a surcharge in
2009 which will have a favorable effect on cash flows of $61 million and on net
income for the previously unrecognized equity portion of the carrying costs of
approximately $11 million.





The
Virginia E&R cost recovery mechanism under Virginia law ceased effective
with costs incurred through December 2008.  However, the 2007
amendments to Virginia’s electric utility restructuring law provide for a rate
adjustment clause to be requested in 2009 to recover incremental E&R costs
incurred through December 2008.  Under this amendment, APCo will
request recovery of its 2008 unrecovered incremental E&R costs in a planned
May 2009 filing.  As of March 31, 2009, APCo has $109 million of
deferred Virginia incremental E&R costs (excluding $22 million of
unrecognized equity carrying costs).  The $109 million consists of $6
million of over recovery of costs collected from the 2008 surcharge, $36 million
approved by the Virginia SCC related to the 2009 surcharge and $79 million,
representing costs deferred during 2008, to be included in the 2009 E&R
filing, for collection in 2010.





If the
Virginia SCC were to disallow a material portion of APCo’s 2008 deferred
incremental E&R costs, it would have an adverse effect on future net income
and cash flows.





APCo’s
Filings for an IGCC Plant – Affecting APCo





In
January 2006, APCo filed a petition from the WVPSC requesting approval of a
Certificate of Public Convenience and Necessity (CPCN) to construct a 629 MW
IGCC plant adjacent to APCo’s existing Mountaineer Generating Station in Mason
County, West Virginia.





In June
2007, APCo sought pre-approval from the WVPSC for a surcharge rate mechanism to
provide for the timely recovery of pre-construction costs and the ongoing
finance costs of the project during the construction period, as well as the
capital costs, operating costs and a return on equity once the facility is
placed into commercial operation.  In March 2008, the WVPSC granted
APCo the CPCN to build the plant and approved the requested cost
recovery.  In March 2008, various intervenors filed petitions with the
WVPSC to reconsider the order.  No action has been taken on the
requests for rehearing.





In July
2007, APCo filed a request with the Virginia SCC for a rate adjustment clause to
recover initial costs associated with a proposed IGCC plant.  The
filing requested recovery of an estimated $45 million over twelve months
beginning January 1, 2009.  The $45 million included a return on
projected CWIP and development, design and planning pre-construction costs
incurred from July 1, 2007 through December 31, 2009.  APCo also
requested authorization to defer a carrying cost on deferred pre-construction
costs incurred beginning July 1, 2007 until such costs are
recovered.





The
Virginia SCC issued an order in April 2008 denying APCo’s requests, in part,
upon its finding that the estimated cost of the plant was uncertain and may
escalate.  The Virginia SCC also expressed concern that the $2.2
billion estimated cost did not include a retrofitting of carbon capture and
sequestration facilities.  In July 2008, based on the unfavorable
order received in Virginia, the WVPSC issued a notice seeking comments from
parties on how the WVPSC should proceed.  Various parties, including
APCo, filed comments but the WVPSC has not taken any action.





Through
March 31, 2009, APCo deferred for future recovery pre-construction IGCC costs of
approximately $9 million applicable to its West Virginia jurisdiction,
approximately $2 million applicable to its FERC jurisdiction and approximately
$9 million allocated to its Virginia jurisdiction.





In July
2008, the IRS allocated $134 million in future tax credits to APCo for the
planned IGCC plant contingent upon the commencement of construction, qualifying
expenses being incurred and certification of the IGCC plant prior to July
2010.





Although
management continues to pursue the construction of the IGCC plant, APCo will not
start construction of the IGCC plant until sufficient assurance of cost recovery
exists.  If the plant is cancelled, APCo plans to seek recovery of its
prudently incurred deferred pre-construction costs.  If the plant is
cancelled and if the deferred costs are not recoverable, it would have an
adverse effect on future net income and cash flows.





Mountaineer
Carbon Capture Project – Affecting APCo





In
January 2008, APCo and ALSTOM Power Inc. (Alstom), an unrelated third party,
entered into an agreement to jointly construct a CO2 capture
demonstration facility.  APCo and Alstom will each own part of the
CO2
capture facility.  APCo will also construct and own the necessary
facilities to store the CO2.  RWE
AG, a German electric power and natural gas public utility, is participating in
the project and is providing some funding to offset APCo's
costs.  APCo’s estimated cost for its share of the facilities is $73
million.  Through March 31, 2009, APCo incurred $45 million in
capitalized project costs which are included in Regulatory
Assets.  APCo earns a return on the capitalized project costs incurred
through June 30, 2008, as a result of the base rate case settlement approved by
the Virginia SCC in November 2008.  APCo plans to seek recovery for
the CO2 capture
and storage project costs including a return on the additional investment since
June 2008 in its next Virginia and West Virginia base rate filings which are
expected to be filed in 2009.  If a significant portion of the
deferred project costs are excluded from base rates and ultimately disallowed in
future Virginia or West Virginia rate proceedings, it could have an adverse
effect on future net income and cash flows.





West Virginia Rate
Matters





APCo’s
2009 Expanded Net Energy Cost (ENEC) Filing – Affecting APCo





In March
2009, APCo filed an annual ENEC filing with the WVPSC for an increase of
approximately $398 million for incremental fuel, purchased power and
environmental compliance project expenses, to become effective July
2009.  Within the filing, APCo requested the WVPSC to allow APCo to
temporarily adopt a modified ENEC mechanism due to the distressed
economy.  The proposed modified ENEC mechanism provides that all
deferred ENEC amounts as of June 30, 2009 be recovered over a five-year period
beginning in July 2009.  The mechanism also extends cost projections
out for a period of three years through June 30, 2012 and provides for three
annual increases to recover projected future ENEC cost
increases.  APCo is also requesting all deferred amounts that exceed
the deferred amounts that would have existed under the traditional ENEC
mechanism be subject to a carrying charge based upon APCo’s weighted average
cost of capital.  As filed, the modified ENEC mechanism would produce
three annual increases, including carrying charges, of $170 million, $149
million and $155 million, effective July 2009, 2010 and 2011,
respectively.





In March
2009, the WVPSC issued an order suspending the rate increase request until
December 2009.  In April 2009, APCo filed a motion for approval of an
interim rate increase of $162 million, effective July 2009 and subject to refund
pending the final adjudication of the ENEC by December 2009.  In April
2009, the WVPSC granted intervention to several parties and heard oral arguments
from APCo and intervenors on the requested interim ENEC filing.  If
the WVPSC were to disallow a material portion of APCo’s requested increase, it
would have an adverse effect on future net income and cash flows.





APCo’s
Filings for an IGCC Plant – Affecting APCo





See
“APCo’s Filings for an IGCC Plant” section within “Virginia Rate Matters” for
disclosure.





Mountaineer
Carbon Capture Project – Affecting APCo





See
“Mountaineer Carbon Capture Project” section within “Virginia Rate Matters” for
disclosure.





Indiana Rate
Matters





Indiana Base
Rate Filing – Affecting I&M





In a
January 2008 filing with the IURC, updated in the second quarter of 2008,
I&M requested an increase in its Indiana base rates of $80 million including
a return on equity of 11.5%.  The base rate increase included a $69
million annual reduction in depreciation expense previously approved by the IURC
and implemented for accounting purposes effective June 2007. In addition,
I&M proposed to share with customers, through a proposed tracker, 50% of
off-system sales margins initially estimated to be $96 million annually with a
guaranteed credit to customers of $20 million.





In
December 2008, I&M and all of the intervenors jointly filed a settlement
agreement with the IURC proposing to resolve all of the issues in the
case.  The settlement agreement incorporated the $69 million annual
reduction in revenues from depreciation rate reduction in the development of the
agreed to revenue increase of $44 million including a $22 million increase in
revenue from base rates with an authorized return on equity of 10.5% and a $22
million initial increase in tracker revenue for PJM, net emission allowance
and DSM costs.  The agreement also establishes an off-system sales
sharing mechanism and other provisions which include continued funding for the
eventual decommissioning of the Cook Nuclear Plant.  In March 2009,
the IURC approved the settlement agreement, with modifications, that provides
for an annual increase in revenues of $42 million including a $19 million
increase in revenue from base rates, net of the depreciation rate reduction, and
a $23 million increase in tracker revenue.  The IURC order removed
base rate recovery of the DSM costs but established a tracker with an initial
zero amount for DSM costs, adjusted the sharing of off-system sales margins to
50% above the $37.5 million included in base rates and approved the recovery of
$7.3 million of previously expensed NSR and OPEB costs which favorably affected
first quarter of 2009 net income.  In addition, the IURC order
requires I&M to review and file a final report by December 2009 on the
effectiveness of the Interconnection Agreement including I&M’s relationship
with PJM.





Rockport
and Tanners Creek Plants – Affecting I&M





In
January 2009, I&M filed a petition with the IURC requesting approval of a
Certificate of Public Convenience and Necessity (CPCN) to use advanced coal
technology which would allow I&M to reduce airborne emissions of NOx and
mercury from its existing coal-fired steam electric generating units at the
Rockport and Tanners Creek Plants.  In addition, the petition is
requesting approval to construct and recover the costs of selective
non-catalytic reduction (SNCR) systems at the Tanners Creek Plant and to recover
the costs of activated carbon injection (ACI) systems on both generating units
at the Rockport Plant.  I&M is requesting to depreciate the ACI
systems over an accelerated 10-year period and the SNCR systems over the
remaining useful life of the Tanners Creek generating units.  I&M
requested the IURC to approve a rate adjustment mechanism of unrecovered
carrying costs during construction and a return on investment, depreciation
expense and operation and maintenance costs, including consumables and new
emission allowance costs, once the projects are placed in
service.  I&M also requested the IURC to authorize the deferral of
the cost of service of these projects and carrying costs until such costs are
recognized in the requested rate adjustment mechanism.  Through March
2009, I&M incurred $9 million and $6 million in capitalized project costs
related to the Rockport and Tanners Creek Plants, respectively, which are
included in Construction Work in Progress.  In March 2009, the IURC
issued a prehearing conference order setting a procedural
schedule.  Since the Indiana base rate order included recovery of
emission allowance costs, that portion of this request will be
eliminated.  An order is expected by the third quarter of
2009.  Management is unable to predict the outcome of this
petition.





Indiana
Fuel Clause Filing – Affecting I&M





In
January 2009, I&M filed with the IURC an application to increase its fuel
adjustment charge by approximately $53 million for April through September
2009.  The filing included an under-recovery for the period ended
November 2008, mainly as a result of the extended outage of the Cook Plant Unit
1 (Unit 1) due to fire damage to the main turbine and generator, increased coal
prices and a projection for the future period of fuel costs including Unit 1
fire related outage replacement power costs.  The filing also included
an adjustment, beginning coincident with the receipt of insurance proceeds, to
reduce the incremental fuel cost of replacement power with a portion of the
insurance proceeds from the Unit 1 accidental outage policy.  See
“Cook Plant Unit 1 Fire and Shutdown” section of Note 4.  I&M
reached an agreement in February 2009 with intervenors, which was approved by
the IURC in March 2009, to collect the under-recovery over twelve months instead
of over six months as proposed.  Under the order, the fuel factor will
go into effect, subject to refund, and a subdocket will be established to
consider issues relating to the Unit 1 fire outage, the use of the insurance
proceeds and I&M’s fuel procurement practices.  The order provides
for the fire outage issues to be resolved subsequent to the date Unit 1 returns
to service, which if temporary repairs are successful, could occur as early as
October 2009.  Management cannot predict the outcome of the pending
proceedings, including the treatment of the insurance proceeds, and whether any
fuel clause revenues will have to be refunded as a result.





Michigan Rate Matters– Affecting
I&M





In March
2009, I&M filed with the Michigan Public Service Commission its 2008 power
supply cost recovery reconciliation.  The filing also included an
adjustment to reduce the incremental fuel cost of replacement power with a
portion of the insurance proceeds from the Cook Plant Unit 1 accidental outage
policy.  See “Cook Plant Unit 1 Fire and Shutdown” section of Note
4.  Management is unable to predict the outcome of this proceeding and
its possible effect on future net income and cash
flows.





Oklahoma Rate
Matters





PSO
Fuel and Purchased Power – Affecting PSO





2006 and Prior Fuel and
Purchased Power





Proceedings
addressing PSO’s historic fuel costs from 2001 through 2006 remain open at the
OCC due to the issue of the allocation of off-system sales margins among the AEP
operating companies in accordance with a FERC-approved allocation
agreement.





In 2002,
PSO under-recovered $42 million of fuel costs resulting from a reallocation
among AEP West companies of purchased power costs for periods prior to
2002.  PSO recovered the $42 million by offsetting it against an
existing fuel over-recovery during the period June 2007 through May
2008.  In June 2008, the Oklahoma Industrial Energy Consumers (OIEC)
appealed an ALJ recommendation that concluded it was a FERC jurisdictional
matter which allowed PSO to retain the $42 million it recovered from
ratepayers.  The OIEC requested that PSO be required to refund the $42
million through its fuel clause.  In August 2008, the OCC heard the
OIEC appeal and a decision is pending.  For further discussion and
estimated effect on net income, see “Allocation of Off-system Sales Margins”
section within “FERC Rate Matters”.





2007 Fuel and Purchased
Power





In
September 2008, the OCC initiated a review of PSO’s generation, purchased power
and fuel procurement processes and costs for 2007.  Management cannot
predict the outcome of the pending fuel and purchased power cost recovery
filings.  However, PSO believes its fuel and purchased power
procurement practices and costs were prudent and properly incurred and therefore
are legally recoverable.





2008
Oklahoma Base Rate Filing – Affecting PSO





In July
2008, PSO filed an application with the OCC to increase its base rates by $133
million (later adjusted to $127 million) on an annual basis.  PSO has
been recovering costs related to new peaking units recently placed into service
through a Generation Cost Recovery Rider (GCRR).  Subsequent to
implementation of the new base rates, the GCRR will terminate and PSO will
recover these costs through the new base rates.  Therefore, PSO’s net
annual requested increase in total revenues was actually $117 million (later
adjusted to $111 million).  The proposed revenue requirement reflected
a return on equity of 11.25%.





In
January 2009, the OCC issued a final order approving an $81 million increase in
PSO’s non-fuel base revenues and a 10.5% return on equity.  The rate
increase includes a $59 million increase in base rates and a $22 million
increase for costs to be recovered through riders outside of base
rates.  The $22 million increase includes $14 million for purchase
power capacity costs and $8 million for the recovery of carrying costs
associated with PSO’s program to convert overhead distribution lines to
underground service.  The $8 million recovery of carrying costs
associated with the overhead to underground conversion program will occur only
if PSO makes the required capital expenditures.  The final order
approved lower depreciation rates and also provides for the deferral of $6
million of generation maintenance expenses to be recovered over a six-year
period.  This deferral was recorded in the first quarter of
2009.  Additional deferrals were approved for distribution storm costs
above or below the amount included in base rates and for certain transmission
reliability expenses.  The new rates reflecting the final order were
implemented with the first billing cycle of February 2009.





PSO filed
an appeal with the Oklahoma Supreme Court challenging an adjustment the OCC made
on prepaid pension funding contained within the OCC final order.  In
February 2009, the Oklahoma Attorney General and several intervenors also filed
appeals with the Oklahoma Supreme Court raising several issues.  If
the Attorney General and/or the intervenor’s Supreme Court appeals are
successful, it could have an adverse effect on future net income and cash
flows.





Louisiana Rate
Matters





2008
Formula Rate Filing – Affecting SWEPCo





In April
2008, SWEPCo filed the first formula rate plan (FRP) which would increase its
annual Louisiana retail rates by $11 million in August 2008 to earn an adjusted
return on common equity of 10.565%.  In August 2008, SWEPCo
implemented the FRP rates, subject to refund.  No provision for refund
has been recorded as SWEPCo believes that the rates as implemented are in
compliance with the FRP methodology approved by the LPSC.  The LPSC
has not approved the rates being collected.  If the rates are not
approved as filed, it could have an adverse effect on future net income and cash
flows.





2009
Formula Rate Filing – Affecting SWEPCo





In April
2009, SWEPCo filed the second FRP which would increase its annual Louisiana
retail rates by an additional $4 million in August 2009 pursuant to the formula
rate methodology.  SWEPCo believes that the rates as filed are in
compliance with the FRP methodology previously approved by the
LPSC.





Stall
Unit – Affecting SWEPCo





In May
2006, SWEPCo announced plans to build a new intermediate load, 500 MW, natural
gas-fired, combustion turbine, combined cycle generating unit (the Stall Unit)
at its existing Arsenal Hill Plant location in Shreveport,
Louisiana.  SWEPCo submitted the appropriate filings to the PUCT, the
APSC, the LPSC and the Louisiana Department of Environmental Quality to seek
approvals to construct the unit.  The Stall Unit is currently
estimated to cost $385 million, excluding AFUDC, and is expected to be
in-service in mid-2010.  The Louisiana Department of Environmental
Quality issued an air permit for the Stall unit in March 2008.





In March
2007, the PUCT approved SWEPCo’s request for a certificate of necessity for the
facility based on a prior cost estimate.  In July 2008, a Louisiana
ALJ issued a recommendation that SWEPCo be authorized to construct, own and
operate the Stall Unit and recommended that costs be capped at $445 million
(excluding transmission).  In October 2008, the LPSC issued a final
order effectively approving the ALJ recommendation.  In December 2008,
SWEPCo submitted an amended filing seeking approval from the APSC to construct
the unit.  The APSC staff filed testimony in March 2009 supporting the
approval of the plant.  The APSC staff also recommended that costs be
capped at $445 million (excluding transmission).  A hearing that had
been scheduled for April 2009 was cancelled and the APSC will issue its decision
based on the amended application and prefiled testimony.





If SWEPCo
does not receive appropriate authorizations and permits to build the Stall Unit,
SWEPCo would seek recovery of the capitalized construction costs including any
cancellation fees.  As of March 31, 2009, SWEPCo has capitalized
construction costs of $291 million (including AFUDC) and has contractual
construction commitments of an additional $74 million.  As of March
31, 2009, if the plant had been cancelled, cancellation fees of $40 million
would have been required in order to terminate the construction
commitments.  If SWEPCo cancels the plant and cannot recover its
capitalized costs, including any cancellation fees, it would have an adverse
effect on future net income, cash flows and possibly financial
condition.





Turk
Plant – Affecting SWEPCo





See “Turk
Plant” section within “Arkansas Rate Matters” for disclosure.





Arkansas Rate
Matters





Turk
Plant – Affecting SWEPCo





In August
2006, SWEPCo announced plans to build the Turk Plant, a new base load 600 MW
pulverized coal ultra-supercritical generating unit in
Arkansas.  SWEPCo submitted filings with the APSC, the PUCT and the
LPSC seeking certification of the plant.  SWEPCo will own 73% of the
Turk Plant and will operate the facility.  During 2007, SWEPCo signed
joint ownership agreements with the Oklahoma Municipal Power Authority (OMPA),
the Arkansas Electric Cooperative Corporation (AECC) and the East Texas Electric
Cooperative (ETEC) for the remaining 27% of the Turk Plant.  During
2007, OMPA exercised its participation option.  During the first
quarter of 2009, AECC and ETEC exercised their participation options and paid
SWEPCo $104 million.  SWEPCo recorded a $2.2 million gain from the
transactions.  The Turk Plant is currently estimated to cost $1.6
billion, excluding AFUDC, with SWEPCo’s portion estimated to cost $1.2
billion.  If approved on a timely basis, the plant is expected to be
in-service in 2012.





In
November 2007, the APSC granted approval to build the Turk
Plant.  Certain landowners have appealed the APSC’s decision to the
Arkansas State Court of Appeals.  In March 2008, the LPSC approved the
application to construct the Turk Plant.





In August
2008, the PUCT issued an order approving the Turk Plant with the following four
conditions: (a) the capping of capital costs for the Turk Plant at the
previously estimated $1.522 billion projected construction cost, excluding
AFUDC, (b) capping CO2 emission
costs at $28 per ton through the year 2030, (c) holding Texas ratepayers
financially harmless from any adverse impact related to the Turk Plant not being
fully subscribed to by other utilities or wholesale customers and (d) providing
the PUCT all updates, studies, reviews, reports and analyses as previously
required under the Louisiana and Arkansas orders.  In October 2008,
SWEPCo appealed the PUCT’s order regarding the two cost cap
restrictions.  If the cost cap restrictions are upheld and
construction or emission costs exceed the restrictions, it could have a material
adverse effect on future net income and cash flows.  In October 2008,
an intervenor filed an appeal contending that the PUCT’s grant of a conditional
Certificate of Public Convenience and Necessity for the Turk Plant was not
necessary to serve retail customers.





A request
to stop pre-construction activities at the site was filed in federal court by
Arkansas landowners.  In July 2008, the federal court denied the
request and the Arkansas landowners appealed the denial to the U.S. Court of
Appeals.  In January 2009, SWEPCo filed a motion to dismiss the
appeal.  In March 2009, the motion was granted.





In
November 2008, SWEPCo received the required air permit approval from the
Arkansas Department of Environmental Quality and commenced
construction.  In December 2008, Arkansas landowners filed an appeal
with the Arkansas Pollution Control and Ecology Commission (APCEC) which caused
construction of the Turk Plant to halt until the APCEC took further
action.  In December 2008, SWEPCo filed a request with the APCEC to
continue construction of the Turk Plant and the APCEC ruled to allow
construction to continue while an appeal of the Turk Plant’s permit is
heard.  Hearings on the air permit appeal is scheduled for June
2009.  SWEPCo is also working with the U.S. Army Corps of Engineers
for the approval of a wetlands and stream impact permit.  In March
2009, SWEPCo reported to the U.S. Army Corps of Engineers a potential wetlands
impact on approximately 2.5 acres at the Turk Plant.  The U.S. Army
Corps of Engineers directed SWEPCo to cease further work impacting the wetland
areas.  Construction has continued on other areas of the Turk
Plant.  The impact on the construction schedule and workforce is
currently being evaluated by management.





In
January and July 2008, SWEPCo filed Certificate of Environmental Compatibility
and Public Need (CECPN) applications with the APSC to construct transmission
lines necessary for service from the Turk Plant.  Several landowners
filed for intervention status and one landowner also contended he should be
permitted to re-litigate Turk Plant issues, including the need for the
generation.  The APSC granted their intervention but denied the
request to re-litigate the Turk Plant issues.  In June 2008, the
landowner filed an appeal to the Arkansas State Court of Appeals requesting to
re-litigate Turk Plant issues.  SWEPCo responded and the appeal was
dismissed.  In January 2009, the APSC approved the CECPN
applications.





The
Arkansas Governor’s Commission on Global Warming issued its final report to the
governor in October 2008.  The Commission was established to set a
global warming pollution reduction goal together with a strategic plan for
implementation in Arkansas.  The Commission’s final report included a
recommendation that the Turk Plant employ post combustion carbon capture and
storage measures as soon as it starts operating.  If legislation is
passed as a result of the findings in the Commission’s report, it could impact
SWEPCo’s proposal to build and operate the Turk Plant.





If SWEPCo
does not receive appropriate authorizations and permits to build the Turk Plant,
SWEPCo could incur significant cancellation fees to terminate its commitments
and would be responsible to reimburse OMPA, AECC and ETEC for their share of
costs incurred plus related shutdown costs.  If that occurred, SWEPCo
would seek recovery of its capitalized costs including any cancellation fees and
joint owner reimbursements.  As of March 31, 2009, SWEPCo has
capitalized approximately $480 million of expenditures (including AFUDC) and has
contractual construction commitments for an additional $655
million.  As of March 31, 2009, if the plant had been cancelled,
SWEPCo would have incurred cancellation fees of $100 million.  If the
Turk Plant does not receive all necessary approvals on reasonable terms and
SWEPCo cannot recover its capitalized costs, including any cancellation fees, it
would have an adverse effect on future net income, cash flows and possibly
financial condition.





Arkansas
Base Rate Filing – Affecting SWEPCo





In
February 2009, SWEPCo filed an application with the APSC for a base rate
increase of $25 million based on a requested return on equity of
11.5%.  SWEPCo also requested a separate rider to recover financing
costs related to the construction of the Stall and Turk generating
facilities.  These financing costs are currently being capitalized as
AFUDC in Arkansas.  A decision is not expected until the fourth
quarter of 2009 or the first quarter of 2010.





Stall
Unit – Affecting SWEPCo





See
“Stall Unit” section within “Louisiana Rate Matters” for
disclosure.





FERC Rate
Matters





Regional
Transmission Rate Proceedings at the FERC – Affecting APCo, CSPCo, I&M and
OPCo





SECA Revenue Subject to
Refund





Effective
December 1, 2004, AEP eliminated transaction-based through-and-out transmission
service (T&O) charges in accordance with FERC orders and collected, at the
FERC’s direction, load-based charges, referred to as RTO SECA, to partially
mitigate the loss of T&O revenues on a temporary basis through March 31,
2006.  Intervenors objected to the temporary SECA rates, raising
various issues.  As a result, the FERC set SECA rate issues for
hearing and ordered that the SECA rate revenues be collected, subject to
refund.  The AEP East companies paid SECA rates to other utilities at
considerably lesser amounts than they collected.  If a refund is
ordered, the AEP East companies would also receive refunds related to the SECA
rates they paid to third parties.  The AEP East companies recognized
gross SECA revenues of $220 million from December 2004 through March 2006 when
the SECA rates terminated leaving the AEP East companies and ultimately their
internal load retail customers to make up the short fall in
revenues.  APCo’s, CSPCo’s, I&M’s and OPCo’s portions of
recognized gross SECA revenues are as follows:





Company
                    
                    (in
      millions)APCo
                    
                    $
                    70.2CSPCo
                    
                    
                    38.8I&M
                    
                    
                    41.3OPCo
                    
                    
                    53.3





In August
2006, a FERC ALJ issued an initial decision, finding that the rate design for
the recovery of SECA charges was flawed and that a large portion of the “lost
revenues” reflected in the SECA rates should not have been
recoverable.  The ALJ found that the SECA rates charged were unfair,
unjust and discriminatory and that new compliance filings and refunds should be
made.  The ALJ also found that the unpaid SECA rates must be paid in
the recommended reduced amount.





In
September 2006, AEP filed briefs jointly with other affected companies noting
exceptions to the ALJ’s initial decision and asking the FERC to reverse the
decision in large part.  Management believes, based on advice of legal
counsel, that the FERC should reject the ALJ’s initial decision because it
contradicts prior related FERC decisions, which are presently subject to
rehearing.  Furthermore, management believes the ALJ’s findings on key
issues are largely without merit.  AEP and SECA ratepayers are
engaged in settlement discussions in an effort to settle the SECA
issue.  However, if the ALJ’s initial decision is upheld in its
entirety, it could result in a disallowance of a large portion of any unsettled
SECA revenues.





Based on
anticipated settlements, the AEP East companies provided reserves for net
refunds for current and future SECA settlements totaling $39 million and $5
million in 2006 and 2007, respectively, applicable to a total of $220 million of
SECA revenues.  APCo’s, CSPCo’s, I&M’s and OPCo’s portions of the
provision are as follows:





2007
                    
                    
                    2006Company
                    
                    (in
      millions)APCo
                    
                    $
                    1.7
                    
                    
                    $
                    12.4CSPCo
                    
                    
                    0.9
                    
                    
                    
                    6.9I&M
                    
                    
                    1.0
                    
                    
                    
                    7.3OPCo
                    
                    
                    1.3
                    
                    
                    
                    9.4





In
February 2009, a settlement agreement was approved by the FERC resulting in the
completion of a $1 million settlement applicable to $20 million of SECA
revenue.  Including this most recent settlement, AEP has completed
settlements totaling $10 million applicable to $112 million of SECA
revenues.  As of March 31, 2009, there were no in-process
settlements.  APCo’s, CSPCo’s, I&M’s and OPCo’s reserve balance at
March 31, 2009 was:





March
      31, 2009Company
                          
                          (in
      millions)APCo
                          
                          $
                          10.7CSPCo
                          
                          
                          5.9I&M
                          
                          
                          6.3OPCo
                          
                          
                          8.2





If the
FERC adopts the ALJ’s decision and/or AEP cannot settle all of the remaining
unsettled claims within the remaining amount reserved for refund, it will have
an adverse effect on future net income and cash flows.  Based on
advice of external FERC counsel, recent settlement experience and the
expectation that most of the unsettled SECA revenues will be settled, management
believes that the available reserve of $34 million is adequate to settle the
remaining $108 million of contested SECA revenues.  If the remaining
unsettled SECA claims are settled for considerably more than the to-date
settlements or if the remaining unsettled claims are awarded a refund by the
FERC greater than the remaining reserve balance, it could have an adverse effect
on net income.  Cash flows will be adversely impacted by any
additional settlements or ordered refunds.  However, management cannot
predict the ultimate outcome of ongoing settlement discussions or future FERC
proceedings or court appeals, if any.





The FERC PJM Regional
Transmission Rate Proceeding





With the
elimination of T&O rates, the expiration of SECA rates and after
considerable administrative litigation at the FERC in which AEP sought to
mitigate the effect of the T&O rate elimination, the FERC failed to
implement a regional rate in PJM.  As a result, the AEP East
companies’ retail customers incur the bulk of the cost of the existing AEP east
transmission zone facilities.  However, the FERC ruled that the cost
of any new 500 kV and higher voltage transmission facilities built in PJM would
be shared by all customers in the region.  It is expected that most of
the new 500 kV and higher voltage transmission facilities will be built in other
zones of PJM, not AEP’s zone.  The AEP East companies will need to
obtain state regulatory approvals for recovery of any costs of new facilities
that are assigned to them by PJM.  In February 2008, AEP filed a
Petition for Review of the FERC orders in this case in the United States Court
of Appeals.  Management cannot estimate at this time what effect, if
any, this order will have on the AEP East companies’ future construction of new
transmission facilities, net income and cash flows.





The AEP
East companies filed for and in 2006 obtained increases in their wholesale
transmission rates to recover lost revenues previously applied to reduce those
rates.  AEP has also sought and received retail rate increases in
Ohio, Virginia, West Virginia and Kentucky.  In January and March
2009, AEP received retail rate increases in Tennessee and Indiana, respectively,
that recognized the higher retail transmission costs resulting from the loss of
wholesale transmission revenues from T&O transactions.  As a
result, AEP is now recovering approximately 98% of the lost T&O transmission
revenues.  The remaining 2% is being incurred by I&M until it can
revise its rates in Michigan to recover the lost revenues.





The FERC PJM and MISO
Regional Transmission Rate Proceeding





In the
SECA proceedings, the FERC ordered the RTOs and transmission owners in the
PJM/MISO region (the Super Region) to file, by August 1, 2007, a proposal to
establish a permanent transmission rate design for the Super Region to be
effective February 1, 2008.  All of the transmission owners in PJM and
MISO, with the exception of AEP and one MISO transmission owner, elected to
support continuation of zonal rates in both RTOs.  In September 2007,
AEP filed a formal complaint proposing a highway/byway rate design be
implemented for the Super Region where users pay based on their use of the
transmission system.  AEP argued the use of other PJM and MISO
facilities by AEP is not as large as the use of AEP transmission by others in
PJM and MISO.  Therefore, a regional rate design change is required to
recognize that the provision and use of transmission service in the Super Region
is not sufficiently uniform between transmission owners and users to justify
zonal rates.  In January 2008, the FERC denied AEP’s
complaint.  AEP filed a rehearing request with the FERC in March
2008.  In December 2008, the FERC denied AEP’s request for
rehearing.  In February 2009, AEP filed an appeal in the U.S. Court of
Appeals.  If the court appeal is successful, earnings could benefit
for a certain period of time due to regulatory lag until the AEP East companies
reduce future retail revenues in their next fuel or base rate proceedings to
reflect the resultant additional transmission cost
reductions.  Management is unable to predict the outcome of this
case.





PJM
Transmission Formula Rate Filing – Affecting APCo, CSPCo, I&M and
OPCo





In July
2008, AEP filed an application with the FERC to increase its rates for wholesale
transmission service within PJM by $63 million annually.  The filing
seeks to implement a formula rate allowing annual adjustments reflecting future
changes in the AEP East companies' cost of service.  In September
2008, the FERC issued an order conditionally accepting AEP’s proposed formula
rate, subject to a compliance filing, established a settlement proceeding with
an ALJ, and delayed the requested October 2008 effective date for five
months.  The requested increase, which the AEP East companies began
billing in April 2009 for service as of March 1, 2009, will produce a $63
million annualized increase in revenues. Approximately $8 million of the
increase will be collected from nonaffiliated customers within
PJM.  The remaining $55 million requested would be billed to the AEP
East companies but would be offset by compensation from PJM for use of the AEP
East companies’ transmission facilities so that retail rates for jurisdictions
other than Ohio are not directly affected.  Retail rates for CSPCo and
OPCo would be increased through the TCRR totaling approximately $10 million and
$13 million, respectively.  The TCRR includes a true-up mechanism so
CSPCo’s and OPCo’s net income will not be adversely affected by a FERC ordered
transmission rate increase.  In October 2008, AEP filed the required
compliance filing, and began settlement discussions with the intervenors and
FERC staff.  The settlement discussions are currently
ongoing.  Under the formula, rates will be updated effective July 1,
2009, and each year thereafter.  Also, beginning with the July 1, 2010
update, the rates each year will include an adjustment to true-up the prior
year's collections to the actual costs for the prior year.  Management
is unable to predict the outcome of the settlement discussions or any further
proceedings that might be necessary if settlement discussions are not
successful.





Allocation
of Off-system Sales Margins – Affecting APCo, CSPCo, I&M, OPCo,
PSO  and SWEPCo





In August
2008, the OCC filed a complaint at the FERC alleging that AEP inappropriately
allocated off-system sales margins between the AEP East companies and the AEP
West companies and did not properly allocate off-system sales margins within the
AEP West companies.  The PUCT, the APSC and the Oklahoma Industrial
Energy Consumers intervened in this filing.  In November 2008, the
FERC issued a final order concluding that AEP inappropriately deviated from
off-system sales margin allocation methods in the SIA and the CSW Operating
Agreement for the period June 2000 through March 2006.  The FERC
ordered AEP to recalculate and reallocate the off-system sales margins in
compliance with the SIA and to have the AEP East companies issue refunds to the
AEP West companies.  Although the FERC determined that AEP deviated
from the CSW Operating Agreement, the FERC determined the allocation methodology
was reasonable.  The FERC ordered AEP to submit a revised CSW
Operating Agreement for the period June 2000 to March 2006.  In
December 2008, AEP filed a motion for rehearing and a revised CSW Operating
Agreement for the period June 2000 to March 2006.  The motion for
rehearing is still pending.  In January 2009, AEP filed a compliance
filing with the FERC and refunded approximately $250 million from the AEP East
companies to the AEP West companies.  The AEP West companies shared a
portion of such revenues with their wholesale and retail customers during the
period June 2000 to March 2006.  In December 2008, the AEP West
companies recorded a provision for refund.  In January 2009, SWEPCo
refunded approximately $13 million to FERC wholesale customers.  In
February 2009, SWEPCo filed a settlement agreement with the PUCT that provides
for the Texas retail jurisdiction amount to be included in the March 2009 fuel
cost report submitted to the PUCT.  PSO began refunding approximately
$54 million plus accrued interest to Oklahoma retail customers through the fuel
adjustment clause over a 12-month period beginning with the March 2009 billing
cycle.  SWEPCo is working with the APSC and the LPSC to determine the
effect the FERC order will have on retail rates.  Management cannot
predict the outcome of the requested FERC rehearing proceeding or any future
state regulatory proceedings but believes the AEP West companies’ provision for
refund regarding future regulatory proceedings is adequate.





SPP
Transmission Formula Rate Filing – Affecting PSO and SWEPCo





In June
2007, AEPSC filed revised tariffs to establish an up-to-date revenue requirement
for SPP transmission services over the facilities owned by PSO and SWEPCo and to
implement a transmission cost of service formula rate.  PSO and SWEPCo
requested an effective date of September 1, 2007 for the revised
tariff.  If approved as filed, the revised tariff will increase annual
network transmission service revenues from nonaffiliated municipal and rural
cooperative utilities in the AEP pricing zone of SPP by approximately $10
million.  In August 2007, the FERC issued an order conditionally
accepting PSO’s and SWEPCo’s proposed formula rate, subject to a compliance
filing, suspended the effective date until February 1, 2008 and established a
hearing schedule and settlement proceedings.  New rates, subject to
refund, were implemented in February 2008.  A settlement agreement was
reached and has been filed with the FERC.  FERC approval is
pending.





Transmission
Equalization Agreement – Affecting APCo, CSPCo, I&M and OPCo





Certain
transmission equipment placed in service in 1998 was inadvertently excluded from
the AEP East companies’ TEA calculation prior to January
2009.  Management does not believe that it is probable that a material
retroactive rate adjustment will result from the omission.  However,
if a retroactive adjustment is required for APCo, CSPCo, I&M and OPCo, it
could have an adverse effect on future net income, cash flows and financial
condition.





4.       COMMITMENTS, GUARANTEES AND
CONTINGENCIES





The
Registrant Subsidiaries are subject to certain claims and legal actions arising
in their ordinary course of business.  In addition, their business
activities are subject to extensive governmental regulation related to public
health and the environment.  The ultimate outcome of such pending or
potential litigation cannot be predicted.  For current proceedings not
specifically discussed below, management does not anticipate that the
liabilities, if any, arising from such proceedings would have a material adverse
effect on the financial statements.  The Commitments, Guarantees and
Contingencies note within the 2008 Annual Report should be read in conjunction
with this report.





GUARANTEES





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.





Letters
of Credit – Affecting APCo, I&M, OPCo and SWEPCo





Certain
Registrant Subsidiaries enter into standby letters of credit (LOCs) with third
parties.  These LOCs cover items such as insurance programs, security
deposits and debt service reserves.  These LOCs were issued in the
ordinary course of business under the two $1.5 billion credit facilities which
were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $46 million
following its bankruptcy.





The
Registrant Subsidiaries and certain other companies in the AEP System have a
$650 million 3-year credit agreement and a $350 million 364-day credit agreement
which were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $23
million and $12 million, respectively, following its bankruptcy.  As
of March 31, 2009, $372 million of letters of credit were issued by Registrant
Subsidiaries under the $650 million 3-year credit agreement to support variable
rate Pollution Control Bonds.  In April 2009, the $350 million 364-day
credit agreement expired.





At March
31, 2009, the maximum future payments of the LOCs were as follows:





BorrowerAmount
              
              Maturity
              
              SublimitCompany
              
              (in
      thousands)$1.5
      billion LOC:I&M
              
              $
              300
              
              March
      2010
              
              
              N/ASWEPCo
              
              
              4,448
              
              December
      2009
              
              
              N/A$650
      million LOC:APCo
              
              $
              126,716
              
              June
      2010
              
              $
              300,000I&M
              
              
              77,886
              
              May
      2010
              
              
              230,000OPCo
              
              
              166,899
              
              June
      2010
              
              
              400,000





Guarantees
of Third-Party Obligations – Affecting SWEPCo





As part
of the process to receive a renewal of a Texas Railroad Commission permit for
lignite mining, SWEPCo provides guarantees of mine reclamation in the amount of
approximately $65 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 Sabine Mining Company
(Sabine), an entity consolidated under FIN 46R.  This guarantee ends
upon depletion of reserves and completion of final reclamation.  Based
on the latest study, it is estimated the reserves will be depleted in 2029 with
final reclamation completed by 2036, at an estimated cost of approximately $39
million.  As of March 31, 2009, SWEPCo collected approximately $39
million through a rider for final mine closure costs, of which approximately $3
million is recorded in Other Current Liabilities, approximately $16 million is
recorded in Asset Retirement Obligations and approximately $20 million is
recorded in Deferred Credits and Other on SWEPCo’s Condensed Consolidated
Balance Sheets.





Sabine
charges SWEPCo, its only customer, all of its costs.  SWEPCo passes
these costs to customers through its fuel clause.





Indemnifications
and Other Guarantees – Affecting APCo, CSPCo, I&M, OPCo, PSO and
SWEPCo





Contracts





The
Registrant Subsidiaries enter into certain 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, exposure generally does not
exceed the sale price.  Prior to March 31, 2009, Registrant
Subsidiaries entered into sale agreements which included indemnifications with a
maximum exposure that was not significant for any individual Registrant
Subsidiary.  There are no material liabilities recorded for any
indemnifications.





The AEP
East companies, PSO and SWEPCo are jointly and severally liable for activity
conducted by AEPSC on behalf of the AEP East companies, PSO and SWEPCo related
to power purchase and sale activity conducted pursuant to the SIA.





Master Lease
Agreements





Certain
Registrant Subsidiaries lease certain equipment under master lease
agreements.  GE Capital Commercial Inc. (GE) notified management in
November 2008 that they elected to terminate the Master Leasing Agreements in
accordance with the termination rights specified within the
contract.  In 2010 and 2011, the Registrant Subsidiaries will be
required to purchase all equipment under the lease and pay GE an amount equal to
the unamortized value of all equipment then leased.  In December 2008,
management signed new master lease agreements with one-year commitment periods
that include lease terms of up to 10 years.  Management expects to
enter into additional replacement leasing arrangements for the equipment
affected by this notification prior to the termination dates of 2010 and
2011.





For
equipment under the GE master lease agreements that expire prior to 2011, the
lessor is guaranteed receipt of 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 Registrant Subsidiaries are 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.  Under the new master lease
agreements, the lessor is guaranteed receipt of up to 68% of the unamortized
balance at the end of the lease term.  If the actual fair market value
of the leased equipment is below the unamortized balance at the end of the lease
term, the Registrant Subsidiaries are committed to pay the difference between
the actual fair market value and unamortized balance, with the total guarantee
not to exceed 68% of the unamortized balance.  At March 31, 2009, the
maximum potential loss by Registrant 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:





MaximumPotentialLossCompany
                    (in
      thousands)APCo
                    
                    $
                    1,055CSPCo
                    
                    
                    431I&M
                    
                    
                    720OPCo
                    
                    
                    857PSO
                    
                    
                    1,183SWEPCo
                    
                    
                    799


Railcar
Lease





In June
2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered
into an agreement with BTM Capital Corporation, as lessor, to lease 875
coal-transporting aluminum railcars.  The lease is accounted for as an
operating lease.  In January 2008, AEP Transportation assigned the
remaining 848 railcars under the original lease agreement to I&M (390
railcars) and SWEPCo (458 railcars).  The assignment is accounted for
as operating leases for I&M and SWEPCo.  The initial lease term
was five years with three consecutive five-year renewal periods for a maximum
lease term of twenty years.  I&M and SWEPCo intend to renew these
leases for the full lease term of twenty years, via the renewal
options.  The future minimum lease obligations are $20 million for
I&M and $23 million for SWEPCo for the remaining railcars as of March 31,
2009.





Under the
lease agreement, the lessor is guaranteed that the sale proceeds under a
return-and-sale option will equal at least a lessee obligation amount specified
in the lease, which declines from approximately 84% under the current five-year
lease term to 77% at the end of the 20-year term of the projected fair market
value of the equipment.  I&M and SWEPCo have assumed the guarantee
under the return-and-sale option.  I&M’s maximum potential loss
related to the guarantee is approximately $12 million ($8 million, net of tax)
and SWEPCo’s is approximately $13 million ($9 million, net of tax) assuming the
fair market value of the equipment is zero at the end of the current five-year
lease term.  However,
management believes that the fair market value would produce a sufficient sales
price to avoid any loss.





The
Registrant Subsidiaries have other railcar lease arrangements that do not
utilize this type of financing structure.





CONTINGENCIES





Federal
EPA Complaint and Notice of Violation – Affecting CSPCo





The
Federal EPA, certain special interest groups and a number of states alleged that
CSPCo, Dayton Power and Light Company and Duke Energy Ohio, Inc. modified
certain units at their jointly-owned coal-fired generating units in violation of
the NSR requirements of the CAA.





A case
remains pending that could affect CSPCo’s share of jointly-owned Beckjord
Station.  The Beckjord case had a liability trial in
2008.  Following the trial, the jury found no liability for claims
made against the jointly-owned Beckjord unit.  In December 2008,
however, the court ordered a new trial in the Beckjord case.  Beckjord
is operated by Duke Energy Ohio, Inc.





Management
is unable to estimate the loss or range of loss related to any contingent
liability, if any, CSPCo might have for civil penalties under the pending CAA
proceedings for Beckjord.  Management is also unable to predict the
timing of resolution of these matters.  If CSPCo does not prevail,
management believes CSPCo can recover any capital and operating costs of
additional pollution control equipment that may be required through future
regulated rates or market prices of electricity.  If CSPCo is unable
to recover such costs or if material penalties are imposed, it would adversely
affect net income, cash flows and possibly financial condition.





Notice
of Enforcement and Notice of Citizen Suit – Affecting SWEPCo





In March
2005, two special interest groups, Sierra Club and Public Citizen, filed a
complaint in Federal District Court for the Eastern District of Texas alleging
violations of the CAA at SWEPCo’s Welsh Plant.  In April 2008, the
parties filed a proposed consent decree to resolve all claims in this case and
in the pending appeal of the altered permit for the Welsh Plant.  The
consent decree requires SWEPCo to install continuous particulate emission
monitors at the Welsh Plant, secure 65 MW of renewable energy capacity by 2010,
fund $2 million in emission reduction, energy efficiency or environmental
mitigation projects by 2012 and pay a portion of plaintiffs’ attorneys’ fees and
costs.  The consent decree was entered as a final order in June
2008.





In
February 2008, the Federal EPA issued a Notice of Violation (NOV) based on
alleged violations of a percent sulfur in fuel limitation and the heat input
values listed in the previous state permit.  The NOV also alleges that
the permit alteration issued by Texas Commission on Environmental Quality was
improper.  SWEPCo met with the Federal EPA to discuss the alleged
violations in March 2008.  The Federal EPA did not object to the
settlement of similar alleged violations in the federal citizen
suit.  Management is unable to predict the timing of any future action
by the Federal EPA or the effect of such actions on net income, cash flows or
financial condition.





Carbon
Dioxide (CO2) Public
Nuisance Claims – Affecting AEP East Companies and AEP West
Companies





In 2004,
eight states and the City of New York filed an action in Federal District Court
for the Southern District of New York against AEP, AEPSC, Cinergy Corp, Xcel
Energy, Southern Company and Tennessee Valley Authority.  The Natural
Resources Defense Council, on behalf of three special interest groups, filed a
similar complaint against the same defendants.  The actions allege
that CO2emissions from the defendants’ power plants constitute a public nuisance
under federal common law due to impacts of global warming, and sought injunctive
relief in the form of specific emission reduction commitments from the
defendants.  The dismissal of this lawsuit was appealed to the Second
Circuit Court of Appeals.  Briefing and oral argument concluded in
2006.  In April 2007, the U.S. Supreme Court issued a decision holding
that the Federal EPA has authority to regulate emissions of CO2 and other
greenhouse gases under the CAA, which may impact the Second Circuit’s analysis
of these issues.  The Second Circuit requested supplemental briefs
addressing the impact of the U.S. Supreme Court’s decision on this case which
were provided in 2007.  Management believes the actions are without
merit and intends to defend against the claims.





Alaskan
Villages’ Claims – Affecting AEP East Companies and AEP West
Companies





In
February 2008, the Native Village of Kivalina and the City of Kivalina,
Alaska  filed a lawsuit in Federal Court in the Northern District of
California against AEP, AEPSC and 22 other unrelated defendants including oil
& gas companies, a coal company and other electric generating
companies.  The complaint alleges that the defendants' emissions of
CO2
contribute to global warming and constitute a public and private nuisance and
that the defendants are acting together.  The complaint further
alleges that some of the defendants, including AEP, conspired to create a false
scientific debate about global warming in order to deceive the public and
perpetuate the alleged nuisance.  The plaintiffs also allege that the
effects of global warming will require the relocation of the village at an
alleged cost of $95 million to $400 million.  The defendants filed
motions to dismiss the action.  The motions are pending before the
court.  Management believes the action is without merit and intends to
defend against the claims.





The
Comprehensive Environmental Response Compensation and Liability Act (Superfund)
and State


Remediation – Affecting I&M





By-products
from the generation of electricity include materials such as ash, slag, sludge,
low-level radioactive waste and SNF.  Coal combustion by-products,
which constitute the overwhelming percentage of these materials, are typically
treated and deposited in captive disposal facilities or are beneficially
utilized.  In addition, the generating plants and transmission and
distribution facilities have used asbestos, polychlorinated biphenyls (PCBs) and
other hazardous and nonhazardous materials.  Costs are currently being
incurred to safely dispose of these substances.





Superfund
addresses clean-up of hazardous substances that have been released to the
environment.  The Federal EPA administers the clean-up
programs.  Several states have enacted similar laws.  In
March 2008, I&M received a letter from the Michigan Department of
Environmental Quality (MDEQ) concerning conditions at a site under state law and
requesting I&M take voluntary action necessary to prevent and/or mitigate
public harm.  I&M requested remediation proposals from
environmental consulting firms.  In May 2008, I&M issued a
contract to one of the consulting firms and started remediation work in
accordance with a plan approved by MDEQ.  I&M recorded
approximately $4 million of expense during 2008.  Based upon updated
information, I&M recorded additional expense of $3 million in March
2009.  As the remediation work is completed, I&M’s cost may
continue to increase.  I&M cannot predict the amount of additional
cost, if any.





Defective
Environmental Equipment – Affecting CSPCo and OPCo





As part
of the AEP System’s continuing environmental investment program, management
chose to retrofit wet flue gas desulfurization systems on units utilizing the
JBR technology.  The retrofits on two units are
operational.  Due to unexpected operating results, management
completed an extensive review of the design and manufacture of the JBR internal
components.  The review concluded that there are fundamental design
deficiencies and that inferior and/or inappropriate materials were selected for
the internal fiberglass components.  Management initiated discussions
with Black & Veatch, the original equipment manufacturer, to develop a
repair or replacement corrective action plan.  Management intends to
pursue contractual and other legal remedies if these issues with Black &
Veatch are not resolved.  If the AEP System is unsuccessful in
obtaining reimbursement for the work required to remedy this situation, the cost
of repair or replacement could have an adverse impact on construction costs, net
income, cash flows or financial condition.





Cook
Plant Unit 1 Fire and Shutdown – Affecting I&M





In
September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine
vibrations, likely caused by blade failure, which resulted in a fire on the
electric generator.  This equipment, located in the turbine building,
is separate and isolated from the nuclear reactor.  The turbine rotors
that caused the vibration were installed in 2006 and are within the vendor’s
warranty period.  The warranty provides for the repair or replacement
of the turbine rotors if the damage was caused by a defect in materials or
workmanship.  I&M is working with its insurance company, Nuclear
Electric Insurance Limited (NEIL), and its turbine vendor, Siemens, to evaluate
the extent of the damage resulting from the incident and facilitate repairs to
return the unit to service.  Repair of the property damage and
replacement of the turbine rotors and other equipment could cost up to
approximately $330 million.  Management believes that I&M should
recover a significant portion of these costs through the turbine vendor’s
warranty, insurance and the regulatory process.  The treatment of
property damage costs, replacement power costs and insurance proceeds will be
the subject of future regulatory proceedings in Indiana and
Michigan.  I&M is repairing Unit 1 to resume operations as early
as October 2009 at reduced power.  Should post-repair operations prove
unsuccessful, the replacement of parts will extend the outage into
2011.





The
refueling outage scheduled for the fall of 2009 for Unit 1 was rescheduled to
the spring of 2010.  Management anticipates that the loss of capacity
from Unit 1 will not affect I&M’s ability to serve customers due to the
existence of sufficient generating capacity in the AEP Power Pool.





I&M
maintains property insurance through NEIL with a $1 million
deductible.  As of March 31, 2009, I&M recorded $34 million in
Prepayments and Other on the Condensed Consolidated Balance Sheets representing
recoverable amounts under the property insurance policy.  I&M
received partial reimbursement from NEIL for the cost incurred to date to repair
the property damage.  I&M also maintains a separate accidental
outage policy with NEIL whereby, after a 12-week deductible period, I&M is
entitled to weekly payments of $3.5 million for the first 52 weeks following the
deductible period.  After the initial 52 weeks of indemnity, the
policy pays $2.8 million per week for up to an additional 110
weeks.  I&M began receiving payments under the accidental outage
policy in December 2008.  In the first quarter of 2009, I&M
recorded $54 million in revenues, including $9 million that were deferred at
December 31, 2008, related to the accidental outage policy.  In order
to hold customers harmless, in the first quarter of 2009, I&M applied $20
million of the accidental outage insurance proceeds to reduce fuel
underrecoveries reflecting recoverable fuel costs as if Unit 1 were
operating.  If the ultimate costs of the incident are not covered by
warranty, insurance or through the regulatory process or if the unit is not
returned to service in a reasonable period of time, it could have an adverse
impact on net income, cash flows and financial condition.





Coal
Transportation Rate Dispute - Affecting PSO





In 1985,
the Burlington Northern Railroad Co. (now BNSF) entered into a coal
transportation agreement with PSO.  The agreement contained a base
rate subject to adjustment, a rate floor, a reopener provision and an
arbitration provision.  In 1992, PSO reopened the pricing
provision.  The parties failed to reach an agreement and the matter
was arbitrated, with the arbitration panel establishing a lowered rate as of
July 1, 1992 (the 1992 Rate), and modifying the rate adjustment
formula.  The decision did not mention the rate floor.  From
April 1996 through the contract termination in December 2001, the 1992 Rate
exceeded the adjusted rate, determined according to the decision.  PSO
paid the adjusted rate and contended that the panel eliminated the rate
floor.  BNSF invoiced at the 1992 Rate and contended that the 1992
Rate was the new rate floor.  At the end of 1991, PSO terminated the
contract by paying a termination fee, as required by the
agreement.  BNSF contends that the termination fee should have been
calculated on the 1992 Rate, not the adjusted rate, resulting in an underpayment
of approximately $9.5 million, including interest.





This
matter was submitted to an arbitration board.  In April 2006, the
arbitration board filed its decision, denying BNSF’s underpayments
claim.  PSO filed a request for an order confirming the arbitration
award and a request for entry of judgment on the award with the U.S. District
Court for the Northern District of Oklahoma.  On July 14, 2006, the
U.S. District Court issued an order confirming the arbitration
award.  On July 24, 2006, BNSF filed a Motion to Reconsider the July
14, 2006 Arbitration Confirmation Order and Final Judgment and its Motion to
Vacate and Correct the Arbitration Award with the U.S. District
Court.  In February 2007, the U.S. District Court granted BNSF’s
Motion to Reconsider.  PSO filed a substantive response to BNSF’s
motion and BNSF filed a reply.  Management continues to defend its
position that PSO paid BNSF all amounts owed.





Rail
Transportation Litigation – Affecting PSO





In
October 2008, the Oklahoma Municipal Power Authority and the Public Utilities
Board of the City of Brownsville, Texas, as co-owners of Oklaunion Plant, filed
a lawsuit in United States District Court, Western District of Oklahoma against
AEP alleging breach of contract and breach of fiduciary duties related to
negotiations for rail transportation services for the plant.  The
plaintiffs allege that AEP assumed the duties of the project manager, PSO, and
operated the plant for the project manager and is therefore responsible for the
alleged breaches.  In December 2008, the court denied AEP’s motion to
dismiss the case.  Management intends to vigorously defend against
these allegations.  Management believes a provision recorded in 2008
should be sufficient.





FERC
Long-term Contracts – Affecting AEP East Companies and AEP West
Companies





In 2002,
the FERC held a hearing related to a complaint filed by Nevada Power Company and
Sierra Pacific Power Company (the Nevada utilities).  The complaint
sought to break long-term contracts entered during the 2000 and 2001 California
energy price spike which the customers alleged were
“high-priced.”  The complaint alleged that AEP subsidiaries sold power
at unjust and unreasonable prices because the market for power was allegedly
dysfunctional at the time such contracts were executed.  In 2003, the
FERC rejected the complaint.  In 2006, the U.S. Court of Appeals for
the Ninth Circuit reversed the FERC order and remanded the case to the FERC for
further proceedings.  That decision was appealed to the U.S. Supreme
Court.  In June 2008, the U.S. Supreme Court affirmed the validity of
contractually-agreed rates except in cases of serious harm to the
public.  The U.S. Supreme Court affirmed the Ninth Circuit’s remand on
two issues, market manipulation and excessive burden on
consumers.  The FERC initiated remand procedures and gave the parties
time to attempt to settle the issues. Management believes a provision
recorded in 2008 should be sufficient.  The Registrant Subsidiaries
asserted claims against certain companies that sold power to them, which was
resold to the Nevada utilities, seeking to recover a portion of any amounts the
Registrant Subsidiaries may owe to the Nevada utilities.  Management
is unable to predict the outcome of these proceedings or their ultimate impact
on future net income and cash flows.





5.
            BENEFIT
      PLANS





APCo,
CSPCo, I&M, OPCo, PSO and SWEPCo participate in AEP sponsored 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, OPCo,
PSO and SWEPCo participate in other postretirement benefit plans sponsored by
AEP to provide medical and death benefits for retired employees.





Components
of Net Periodic Benefit Cost





The
following table provides the components of AEP’s net periodic benefit cost for
the plans for the three months ended March 31, 2009 and 2008:


Other
      PostretirementPension
      Plans
                
                Benefit
      PlansThree
      Months Ended March 31,
                
                Three
      Months Ended March 31,2009
                
                2008
                
                2009
                
                2008(in
      millions)Service
      Cost
                
                $
                26
                
                
                $
                25
                
                
                $
                10
                
                
                $
                10Interest
      Cost
                
                
                63
                
                
                
                63
                
                
                
                27
                
                
                
                28Expected
      Return on Plan Assets
                
                
                (80
                )
                
                
                (84
                )
                
                
                (20
                )
                
                
                (28
                )Amortization
      of Transition Obligation
                
                
                -
                
                
                
                -
                
                
                
                7
                
                
                
                7Amortization
      of Net Actuarial Loss
                
                
                15
                
                
                
                9
                
                
                
                11
                
                
                
                3Net
      Periodic Benefit Cost
                
                $
                24
                
                
                $
                13
                
                
                $
                35
                
                
                $
                20





The
following table provides the Registrant Subsidiaries’ net periodic benefit cost
(credit) for the plans for the three months ended March 31, 2009 and
2008:


Other
      PostretirementPension
      Plans
                
                Benefit
      PlansThree
      Months Ended March 31,
                
                Three
      Months Ended March 31,2009
                
                2008
                
                2009
                
                2008Company
                (in
      thousands)APCo
                
                $
                2,615
                
                
                $
                835
                
                
                $
                6,058
                
                
                $
                3,699CSPCo
                
                
                688
                
                
                
                (349
                )
                
                
                2,638
                
                
                
                1,498I&M
                
                
                3,485
                
                
                
                1,821
                
                
                
                4,358
                
                
                
                2,423OPCo
                
                
                2,067
                
                
                
                319
                
                
                
                5,139
                
                
                
                2,816PSO
                
                
                770
                
                
                
                508
                
                
                
                2,283
                
                
                
                1,387SWEPCo
                
                
                1,208
                
                
                
                935
                
                
                
                2,363
                
                
                
                1,376





AEP
sponsors several trust funds with significant investments intended to provide
for future pension and OPEB payments.  All of the trust funds’
investments are well-diversified and managed in compliance with all laws and
regulations.  The value of the investments in these trusts has
declined from the December 31, 2008 balances due to decreases in the equity and
fixed income markets.  Although the asset values are currently lower
than at year end, this decline has not affected the funds’ ability to make their
required payments.





6.
            BUSINESS
      SEGMENTS





The
Registrant Subsidiaries have one reportable segment.  The one
reportable segment is an electricity generation, transmission and distribution
business.  All of the Registrant Subsidiaries’ other activities are
insignificant.  The Registrant Subsidiaries’ operations are managed as
one segment because of the substantial impact of cost-based rates and regulatory
oversight on the business process, cost structures and operating
results.





7.
            DERIVATIVES, HEDGING
      AND FAIR VALUE MEASUREMENTS





DERIVATIVES
AND HEDGING





Objectives for Utilization
of Derivative Instruments





The
Registrant Subsidiaries are exposed to certain market risks as major power
producers and marketers of wholesale electricity, coal and emission
allowances.  These risks include commodity price risk, interest rate
risk, credit risk and to a lesser extent foreign currency exchange
risk.  These risks represent the risk of loss that may impact the
Registrant Subsidiaries due to changes in the underlying market prices or
rates.  These risks are managed using derivative
instruments.





Strategies for Utilization
of Derivative Instruments to Achieve Objectives





The
Registrant Subsidiaries’ strategy surrounding the use of derivative instruments
focuses on managing risk exposures, future cash flows and creating value based
on open trading positions by utilizing both economic and formal SFAS 133 hedging
strategies. To accomplish these objectives, AEPSC, on behalf of the Registrant
Subsidiaries, primarily employs risk management contracts including physical
forward purchase and sale contracts, financial forward purchase and sale
contracts and financial swap instruments.  Not all risk management
contracts meet the definition of a derivative under SFAS
133.  Derivative risk management contracts elected normal under the
normal purchases and normal sales scope exception are not subject to the
requirements of SFAS 133.





AEPSC, on
behalf of the Registrant Subsidiaries, enters into electricity, coal, natural
gas, interest rate and to a lesser degree heating oil, gasoline, emission
allowance and other commodity contracts to manage the risk associated with the
energy business.  AEPSC, on behalf of the Registrant Subsidiaries,
enters into interest rate derivative contracts in order to manage the interest
rate exposure associated with long-term commodity derivative
positions.   For disclosure purposes, such risks are grouped as
“Commodity,” as these risks are related to energy risk management
activities.  From time to time, AEPSC, on behalf of the Registrant
Subsidiaries, also engages in risk management of interest rate risk associated
with debt financing and foreign currency risk associated with future purchase
obligations denominated in foreign currencies.  For disclosure
purposes these risks are grouped as “Interest Rate and Foreign Currency.” The
amount of risk taken is determined by the Commercial Operations and Finance
groups in accordance with established risk management policies as approved by
the Finance Committee of AEP’s Board of Directors.





The
following table represents the gross notional volume of the Registrant
Subsidiaries’ outstanding derivative contracts as of March 31,
2009:


Notional
      Volume of Derivative InstrumentsMarch
      31, 2009(in
      thousands)Primary
      Risk Exposure
                      
                      Unit
      of Measure
                      
                      APCo
                      
                      
                      CSPCo
                      
                      
                      I&M
                      
                      
                      OPCo
                      
                      
                      PSO
                      
                      
                      SWEPCoCommodity:Power
                      
                      MWHs
                      
                      
                      102,761
                      
                      
                      
                      54,500
                      
                      
                      
                      52,744
                      
                      
                      
                      67,512
                      
                      
                      
                      609
                      
                      
                      
                      718Coal
                      
                      Tons
                      
                      
                      10,972
                      
                      
                      
                      5,551
                      
                      
                      
                      5,860
                      
                      
                      
                      18,810
                      
                      
                      
                      3,012
                      
                      
                      
                      4,853Natural
      Gas
                      
                      MMBtus
                      
                      
                      37,953
                      
                      
                      
                      20,129
                      
                      
                      
                      19,480
                      
                      
                      
                      24,935
                      
                      
                      
                      4,887
                      
                      
                      
                      5,760Heating Oil and
                        Gasoline
                      
                      Gallons
                      
                      
                      871
                      
                      
                      
                      360
                      
                      
                      
                      415
                      
                      
                      
                      627
                      
                      
                      
                      494
                      
                      
                      
                      466Interest
      Rate
                      
                      USD
                      
                      $
                      41,480
                      
                      
                      $
                      21,959
                      
                      
                      $
                      21,325
                      
                      
                      $
                      28,946
                      
                      
                      $
                      2,552
                      
                      
                      $
                      3,207Interest
      Rate and
                        Foreign Currency
                      
                      USD
                      
                      $
                      -
                      
                      
                      $
                      -
                      
                      
                      $
                      -
                      
                      
                      $
                      400,000
                      
                      
                      $
                      -
                      
                      
                      $
                      3,918





Fair
Value Hedging Strategies





At
certain times, AEPSC, on behalf of the Registrant Subsidiaries, enters into
interest rate derivative transactions in order to manage an existing fixed
interest rate risk exposure.  These interest rate derivative
transactions effectively modify an exposure to interest rate risk by converting
a portion of fixed-rate debt to a floating rate.  This strategy is not
actively employed by any of the Registrant Subsidiaries in
2009.  During 2008, APCo had designated interest rate derivatives as
fair value hedges.





Cash
Flow Hedging Strategies





AEPSC, on
behalf of the Registrant Subsidiaries, enters into and designate as cash flow
hedges certain derivative transactions for the purchase and sale of electricity,
coal and natural gas (“Commodity”) in order to manage the variable price risk
related to the forecasted purchase and sale of these
commodities.  Management closely monitors the potential impacts of
commodity price changes and, where appropriate, enters into derivative
transactions to protect profit margins for a portion of future electricity sales
and fuel or energy purchases.  The Registrant Subsidiaries do not
hedge all commodity price risk.  During 2009 and 2008, APCo, CSPCo,
I&M and OPCo designated cash flow hedging relationships using these
commodities.





The
Registrant Subsidiaries’ vehicle fleet is exposed to gasoline and diesel fuel
price volatility.  AEPSC, on behalf of the Registrant Subsidiaries,
enters into financial gasoline and heating oil derivative contracts in order
mitigate price risk of future fuel purchases.  The Registrant
Subsidiaries do not hedge all fuel price risk.  During 2009, APCo,
CSPCo, I&M, OPCo, PSO and SWEPCo designated cash flow hedging strategies of
forecasted fuel purchases.  This strategy was not active for any of
the Registrant Subsidiaries during 2008.  For disclosure purposes,
these contracts are included with other hedging activity as
“Commodity.”





AEPSC, on
behalf of the Registrant Subsidiaries, enters into a variety of interest rate
derivative transactions in order to manage interest rate risk
exposure.  Some interest rate derivative transactions effectively
modify exposure to interest rate risk by converting a portion of floating-rate
debt to a fixed rate.  AEPSC, on behalf of the Registrant
Subsidiaries, also enters into interest rate derivative contracts to manage
interest rate exposure related to anticipated borrowings of fixed-rate
debt.  The anticipated fixed-rate debt offerings have a high
probability of occurrence as the proceeds will be used to fund existing debt
maturities and projected capital expenditures.  The Registrant
Subsidiaries do not hedge all interest rate exposure.  During 2009 and
2008, APCo and OPCo designated interest rate derivatives as cash flow
hedges.





At times,
the Registrant Subsidiaries are exposed to foreign currency exchange rate risks
primarily because some fixed assets are purchased from foreign
suppliers.  In accordance with AEP’s risk management policy, AEPSC, on
behalf of the Registrant Subsidiaries, may enter into foreign currency
derivative transactions to protect against the risk of increased cash outflows
resulting from a foreign currency’s appreciation against the
dollar.  The Registrant Subsidiaries do not hedge all foreign currency
exposure.  During 2009 and 2008, APCo, OPCo and SWEPCo designated
foreign currency derivatives as cash flow hedges.





Accounting for Derivative
Instruments and the Impact on the Financial Statements





SFAS 133
requires recognition of all qualifying derivative instruments as either assets
or liabilities in the balance sheet at fair value.  The fair values of
derivative instruments accounted for using MTM accounting or hedge accounting
are based on exchange prices and broker quotes.  If a quoted market
price is not available, the estimate of fair value is based on the best
information available including valuation models that estimate future energy
prices based on existing market and broker quotes, supply and demand market data
and assumptions.  In order to determine the relevant fair values of
the derivative instruments, the Registrant Subsidiaries also apply valuation
adjustments for discounting, liquidity and credit quality.





Credit
risk is the risk that a counterparty will fail to perform on the contract or
fail to pay amounts due.  Liquidity risk represents the risk that
imperfections in the market will cause the price to vary from estimated fair
value based upon prevailing market supply and demand
conditions.  Since energy markets are imperfect and volatile, there
are inherent risks related to the underlying assumptions in models used to fair
value risk management contracts.  Unforeseen events may cause
reasonable price curves to differ from actual price curves throughout a
contract’s term and at the time a contract settles.  Consequently,
there could be significant adverse or favorable effects on future net income and
cash flows if market prices are not consistent with management’s estimates of
current market consensus for forward prices in the current
period.  This is particularly true for longer term
contracts.  Cash flows may vary based on market conditions, margin
requirements and the timing of settlement of risk management
contracts.





According
to FSP FIN 39-1, the Registrant Subsidiaries reflect the fair values of
derivative instruments subject to netting agreements with the same counterparty
net of related cash collateral.  For certain risk management
contracts, the Registrant Subsidiaries are required to post or receive cash
collateral based on third party contractual agreements and risk
profiles.  For the March 31, 2009 and December 31, 2008 balance
sheets, the Registrant Subsidiaries netted cash collateral received from third
parties against short-term and long-term risk management assets and cash
collateral paid to third parties against short-term and long-term risk
management liabilities as follows:





March
      31, 2009
                
                December
      31, 2008Cash
      Collateral
                
                Cash
      Collateral
                
                Cash
      Collateral
                
                Cash
      CollateralReceived
                
                Paid
                
                Received
                
                PaidNetted
      Against
                
                Netted
      Against
                
                Netted
      Against
                
                Netted
      AgainstRisk
      Management
                
                Risk
      Management
                
                Risk
      Management
                
                Risk ManagementAssets
                
                Liabilities
                
                Assets
                
                LiabilitiesCompany
                (in
      thousands)APCo
                
                $
                25,038
                
                
                $
                36,012
                
                
                $
                2,189
                
                
                $
                5,621CSPCo
                
                
                13,279
                
                
                
                19,092
                
                
                
                1,229
                
                
                
                3,156I&M
                
                
                12,851
                
                
                
                18,481
                
                
                
                1,189
                
                
                
                3,054OPCo
                
                
                16,450
                
                
                
                23,662
                
                
                
                1,522
                
                
                
                3,909PSO
                
                
                -
                
                
                
                393
                
                
                
                -
                
                
                
                105SWEPCo
                
                
                -
                
                
                
                456
                
                
                
                -
                
                
                
                124





The
following table represents the gross fair value impact of the Registrant
Subsidiaries’ derivative activity on the Condensed Balance Sheets as of March
31, 2009:





Fair
      Value of Derivative InstrumentsMarch
      31, 2009APCo
                  Risk
      Management Contracts
                  
                  Hedging
      ContractsCommodity
                    (a)
                  
                  Commodity
                    (a)
                  
                  Interest
      Rate and Foreign Currency
                  
                  Other
      (b)
                  
                  TotalBalance
      Sheet Location
                  (in
      thousands)Current
      Risk Management Assets
                  
                  $
                  672,985
                  
                  
                  $
                  8,048
                  
                  
                  $
                  -
                  
                  
                  $
                  (605,838
                  )
                  
                  $
                  75,195Long-Term
      Risk Management Assets
                  
                  
                  276,740
                  
                  
                  
                  615
                  
                  
                  
                  -
                  
                  
                  
                  (212,584
                  )
                  
                  
                  64,771Total
      Assets
                  
                  
                  949,725
                  
                  
                  
                  8,663
                  
                  
                  
                  -
                  
                  
                  
                  (818,422
                  )
                  
                  
                  139,966Current
      Risk Management Liabilities
                  
                  
                  645,041
                  
                  
                  
                  1,996
                  
                  
                  
                  -
                  
                  
                  
                  (607,945
                  )
                  
                  
                  39,092Long-Term
      Risk Management Liabilities
                  
                  
                  258,749
                  
                  
                  
                  419
                  
                  
                  
                  -
                  
                  
                  
                  (229,113
                  )
                  
                  
                  30,055Total
      Liabilities
                  
                  
                  903,790
                  
                  
                  
                  2,415
                  
                  
                  
                  -
                  
                  
                  
                  (837,058
                  )
                  
                  
                  69,147Total
      MTM Derivative Contract Net Assets (Liabilities)
                  
                  $
                  45,935
                  
                  
                  $
                  6,248
                  
                  
                  $
                  -
                  
                  
                  $
                  18,636
                  
                  
                  $
                  70,819








CSPCoRisk
      Management Contracts
                  
                  
                  Hedging
      ContractsCommodity
                    (a)
                  
                  
                  Commodity
                    (a)
                  
                  
                  Interest
      Rate and Foreign Currency
                  
                  
                  Other
      (b)
                  
                  
                  TotalBalance
      Sheet Location
                  
                  (in
      thousands)Current
      Risk Management Assets
                  
                  $
                  354,953
                  
                  
                  $
                  4,268
                  
                  
                  $
                  -
                  
                  
                  $
                  (319,634
                  )
                  
                  $
                  39,587Long-Term
      Risk Management Assets
                  
                  
                  146,110
                  
                  
                  
                  326
                  
                  
                  
                  -
                  
                  
                  
                  (112,128
                  )
                  
                  
                  34,308Total
      Assets
                  
                  
                  501,063
                  
                  
                  
                  4,594
                  
                  
                  
                  -
                  
                  
                  
                  (431,762
                  )
                  
                  
                  73,895Current
      Risk Management Liabilities
                  
                  
                  340,254
                  
                  
                  
                  1,050
                  
                  
                  
                  -
                  
                  
                  
                  (320,743
                  )
                  
                  
                  20,561Long-Term
      Risk Management Liabilities
                  
                  
                  136,595
                  
                  
                  
                  222
                  
                  
                  
                  -
                  
                  
                  
                  (120,894
                  )
                  
                  
                  15,923Total
      Liabilities
                  
                  
                  476,849
                  
                  
                  
                  1,272
                  
                  
                  
                  -
                  
                  
                  
                  (441,637
                  )
                  
                  
                  36,484Total
      MTM Derivative Contract Net Assets (Liabilities)
                  
                  $
                  24,214
                  
                  
                  $
                  3,322
                  
                  
                  $
                  -
                  
                  
                  $
                  9,875
                  
                  
                  $
                  37,411





I&MRisk
      Management Contracts
                  
                  
                  Hedging
      ContractsCommodity
                    (a)
                  
                  
                  Commodity
                    (a)
                  
                  
                  Interest
      Rate and Foreign Currency
                  
                  
                  Other
      (b)
                  
                  
                  TotalBalance
      Sheet Location
                  
                  (in
      thousands)Current
      Risk Management Assets
                  
                  $
                  347,018
                  
                  
                  $
                  4,131
                  
                  
                  $
                  -
                  
                  
                  $
                  (312,391
                  )
                  
                  $
                  38,758Long-Term
      Risk Management Assets
                  
                  
                  142,607
                  
                  
                  
                  315
                  
                  
                  
                  -
                  
                  
                  
                  (109,640
                  )
                  
                  
                  33,282Total
      Assets
                  
                  
                  489,625
                  
                  
                  
                  4,446
                  
                  
                  
                  -
                  
                  
                  
                  (422,031
                  )
                  
                  
                  72,040Current
      Risk Management Liabilities
                  
                  
                  332,550
                  
                  
                  
                  1,021
                  
                  
                  
                  -
                  
                  
                  
                  (313,470
                  )
                  
                  
                  20,101Long-Term
      Risk Management Liabilities
                  
                  
                  133,350
                  
                  
                  
                  214
                  
                  
                  
                  -
                  
                  
                  
                  (118,124
                  )
                  
                  
                  15,440Total
      Liabilities
                  
                  
                  465,900
                  
                  
                  
                  1,235
                  
                  
                  
                  -
                  
                  
                  
                  (431,594
                  )
                  
                  
                  35,541Total
      MTM Derivative Contract Net Assets (Liabilities)
                  
                  $
                  23,725
                  
                  
                  $
                  3,211
                  
                  
                  $
                  -
                  
                  
                  $
                  9,563
                  
                  
                  $
                  36,499








OPCoRisk
      Management Contracts
                  
                  
                  Hedging
      ContractsCommodity
                    (a)
                  
                  
                  Commodity
                    (a)
                  
                  
                  Interest
      Rate and Foreign Currency
                  
                  
                  Other
      (b)
                  
                  
                  TotalBalance
      Sheet Location
                  
                  (in
      thousands)Current
      Risk Management Assets
                  
                  $
                  525,935
                  
                  
                  $
                  5,288
                  
                  
                  $
                  1,329
                  
                  
                  $
                  (469,192
                  )
                  
                  $
                  63,360Long-Term
      Risk Management Assets
                  
                  
                  210,595
                  
                  
                  
                  404
                  
                  
                  
                  -
                  
                  
                  
                  (165,334
                  )
                  
                  
                  45,665Total
      Assets
                  
                  
                  736,530
                  
                  
                  
                  5,692
                  
                  
                  
                  1,329
                  
                  
                  
                  (634,526
                  )
                  
                  
                  109,025Current
      Risk Management Liabilities
                  
                  
                  504,236
                  
                  
                  
                  1,314
                  
                  
                  
                  925
                  
                  
                  
                  (470,580
                  )
                  
                  
                  35,895Long-Term
      Risk Management Liabilities
                  
                  
                  200,912
                  
                  
                  
                  275
                  
                  
                  
                  -
                  
                  
                  
                  (176,192
                  )
                  
                  
                  24,995Total
      Liabilities
                  
                  
                  705,148
                  
                  
                  
                  1,589
                  
                  
                  
                  925
                  
                  
                  
                  (646,772
                  )
                  
                  
                  60,890Total
      MTM Derivative Contract Net Assets (Liabilities)
                  
                  $
                  31,382
                  
                  
                  $
                  4,103
                  
                  
                  $
                  404
                  
                  
                  $
                  12,246
                  
                  
                  $
                  48,135





PSORisk
      Management Contracts
                  
                  
                  Hedging
      ContractsCommodity
                    (a)
                  
                  
                  Commodity
                    (a)
                  
                  
                  Interest
      Rate and Foreign Currency
                  
                  
                  Other
      (b)
                  
                  
                  TotalBalance
      Sheet Location
                  
                  (in
      thousands)Current
      Risk Management Assets
                  
                  $
                  41,231
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  (33,599
                  )
                  
                  $
                  7,632Long-Term
      Risk Management Assets
                  
                  
                  7,811
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  (7,211
                  )
                  
                  
                  600Total
      Assets
                  
                  
                  49,042
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  (40,810
                  )
                  
                  
                  8,232Current
      Risk Management Liabilities
                  
                  
                  39,566
                  
                  
                  
                  33
                  
                  
                  
                  -
                  
                  
                  
                  (33,892
                  )
                  
                  
                  5,707Long-Term
      Risk Management Liabilities
                  
                  
                  7,523
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  (7,143
                  )
                  
                  
                  380Total
      Liabilities
                  
                  
                  47,089
                  
                  
                  
                  33
                  
                  
                  
                  -
                  
                  
                  
                  (41,035
                  )
                  
                  
                  6,087Total
      MTM Derivative Contract Net Assets (Liabilities)
                  
                  $
                  1,953
                  
                  
                  $
                  (33
                  )
                  
                  $
                  -
                  
                  
                  $
                  225
                  
                  
                  $
                  2,145





SWEPCoRisk
      Management Contracts
                  
                  
                  Hedging
      ContractsCommodity
                    (a)
                  
                  
                  Commodity
                    (a)
                  
                  
                  Interest
      Rate and Foreign Currency
                  
                  
                  Other
      (b)
                  
                  
                  TotalBalance
      Sheet Location
                  
                  (in
      thousands)Current
      Risk Management Assets
                  
                  $
                  57,959
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  (47,772
                  )
                  
                  $
                  10,187Long-Term
      Risk Management Assets
                  
                  
                  12,427
                  
                  
                  
                  -
                  
                  
                  
                  1
                  
                  
                  
                  (11,508
                  )
                  
                  
                  920Total
      Assets
                  
                  
                  70,386
                  
                  
                  
                  -
                  
                  
                  
                  1
                  
                  
                  
                  (59,280
                  )
                  
                  
                  11,107Current
      Risk Management Liabilities
                  
                  
                  55,344
                  
                  
                  
                  30
                  
                  
                  
                  301
                  
                  
                  
                  (48,110
                  )
                  
                  
                  7,565Long-Term
      Risk Management Liabilities
                  
                  
                  11,956
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  (11,428
                  )
                  
                  
                  528Total
      Liabilities
                  
                  
                  67,300
                  
                  
                  
                  30
                  
                  
                  
                  301
                  
                  
                  
                  (59,538
                  )
                  
                  
                  8,093Total
      MTM Derivative Contract Net Assets (Liabilities)
                  
                  $
                  3,086
                  
                  
                  $
                  (30
                  )
                  
                  $
                  (300
                  )
                  
                  $
                  258
                  
                  
                  $
                  3,014





(a)
            Derivative
      instruments within these categories are reported gross.  These
      instruments are subject to master netting agreements and are presented in
      the Condensed Balance Sheets on a net basis in accordance with FIN 39
      “Offsetting of Amounts Related to Certain Contracts.”(b)
            Amounts
      represent counterparty netting of risk management contracts, associated
      cash collateral in accordance with FSP FIN 39-1 and dedesignated risk
      management contracts.





The table
below presents the Registrant Subsidiaries MTM activity of derivative risk
management contracts for the three months ended March 31, 2009:





Amount
      of Gain (Loss) Recognized
                      on
      Risk Management ContractsFor
      the Three Months Ended March 31, 2009APCo
                    
                    CSPCo
                    
                    I&M
                    
                    OPCo
                    
                    PSO
                    
                    SWEPCo(in
      thousands)Location
      of Gain (Loss)Electric
      Generation, Transmission and Distribution Revenues
                    
                    $
                    9,817
                    
                    
                    $
                    10,745
                    
                    
                    $
                    18,178
                    
                    
                    $
                    12,711
                    
                    
                    $
                    1,255
                    
                    
                    $
                    1,523Sales
      to AEP Affiliates
                    
                    
                    (7,020
                    )
                    
                    
                    (4,076
                    )
                    
                    
                    (3,971
                    )
                    
                    
                    (3,214
                    )
                    
                    
                    (1,462
                    )
                    
                    
                    (1,781
                    )Regulatory
      Assets
                    
                    
                    (755
                    )
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    (41
                    )Regulatory
      Liabilities
                    
                    
                    38,861
                    
                    
                    
                    11,628
                    
                    
                    
                    6,940
                    
                    
                    
                    13,856
                    
                    
                    
                    334
                    
                    
                    
                    386Total
      Gain (Loss) on Risk Management Contracts
                    
                    $
                    40,903
                    
                    
                    $
                    18,297
                    
                    
                    $
                    21,147
                    
                    
                    $
                    23,353
                    
                    
                    $
                    127
                    
                    
                    $
                    87





Certain
qualifying derivative instruments have been designated as normal purchase or
normal sale contracts, as provided in SFAS 133.  Derivative contracts
that have been designated as normal purchases or normal sales under SFAS 133 are
not subject to MTM accounting treatment and are recognized in the Condensed
Statements of Income on an accrual basis.





The
accounting for the changes in the fair value of a derivative instrument depends
on whether it qualifies for and has been designated as part of a hedging
relationship and further, on the type of hedging
relationship.  Depending on the exposure, management designates a
hedging instrument as a fair value hedge or a cash flow hedge.





For
contracts that have not been designated as part of a hedging relationship, the
accounting for changes in fair value depends on whether the derivative
instrument is held for trading purposes. Unrealized and realized gains and
losses on derivative instruments held for trading purposes are included in
Revenues on a net basis in the Condensed Statements of Income. Unrealized and
realized gains and losses on derivative instruments not held for trading
purposes are included in Revenues or Expenses on the Condensed Statements of
Income depending on the relevant facts and circumstances.  However,
unrealized and realized gains and losses in regulated jurisdictions (APCo,
I&M, PSO and the non-Texas portion of SWEPCo) for both trading and
non-trading derivative instruments are recorded as regulatory assets (for
losses) or regulatory liabilities (for gains) in accordance with SFAS
71.





Accounting
for Fair Value Hedging Strategies





For fair
value hedges (i.e. hedging the exposure to changes in the fair value of an
asset, liability or an identified portion thereof attributable to a particular
risk), the Registrant Subsidiaries recognize the gain or loss on the derivative
instrument as well as the offsetting gain or loss on the hedged item associated
with the hedged risk in Net Income during the period of change.





The
Registrant Subsidiaries record realized gains or losses on interest rate swaps
that qualify for fair value hedge accounting treatment and any offsetting
changes in the fair value of the debt being hedged, in Interest Expense on the
Condensed Statements of Income.  During the three months ended March
31, 2009, the Registrant Subsidiaries did not employ any fair value hedging
strategies.  During the three months ended 2008, APCo designated
interest rate derivatives as fair value hedges and did not recognize any hedge
ineffectiveness related to these derivative transactions.





Accounting
for Cash Flow Hedging Strategies





For cash
flow hedges (i.e. hedging the exposure to variability in expected future cash
flows that is attributable to a particular risk), the Registrant Subsidiaries
initially report the effective portion of the gain or loss on the derivative
instrument as a component of Accumulated Other Comprehensive Income (Loss) on
the Condensed Balance Sheets until the period the hedged item affects Net
Income.  The Registrant Subsidiaries recognize any hedge
ineffectiveness in Net Income immediately during the period of change, except in
regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory
asset (for losses) or a regulatory liability (for gains).





Realized
gains and losses on derivatives transactions for the purchase and sale of
electricity, coal and natural gas designated as cash flow hedges are included in
Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased
Electricity for Resale in the Condensed Statements of Income, depending on the
specific nature of the risk being hedged.  The Registrant Subsidiaries
do not hedge all variable price risk exposure related to
commodities.  During the three months ended March 31, 2009 and 2008,
APCo, CSPCo, I&M and OPCo recognized immaterial amounts in Net Income
related to hedge ineffectiveness.





Beginning
in 2009, the Registrant Subsidiaries executed financial heating oil and gasoline
derivative contracts to hedge the price risk of diesel fuel and gasoline
purchases.  The Registrant Subsidiaries reclassify gains and losses on
financial fuel derivative contracts designated as cash flow hedges from
Accumulated Other Comprehensive Income (Loss) on the Condensed Balance Sheets
into Other Operation and Maintenance expense or Depreciation and Amortization
expense, as it relates to capital projects, on the Condensed Statements of
Income.  The Registrant Subsidiaries do not hedge all fuel price
exposure.  During the three months ended March 31, 2009, APCo, CSPCo,
I&M, OPCo, PSO and SWEPCo recognized no hedge ineffectiveness related to
this hedge strategy.





The
Registrant Subsidiaries reclassify gains and losses on interest rate derivative
hedges related to debt financing from Accumulated Other Comprehensive Income
(Loss) into Interest Expense in those periods in which hedged interest payments
occur.  During the three months ended March 31, 2009 and 2008, APCo
and OPCo recognized immaterial amounts in Net Income related to hedge
ineffectiveness.





The
accumulated gains or losses related to foreign currency hedges are reclassified
from Accumulated Other Comprehensive Income (Loss) on the Condensed Balance
Sheets into Depreciation and Amortization expense in the Condensed Statements of
Income over the depreciable lives of the fixed assets that were designated as
the hedged items in qualifying foreign currency hedging
relationships.  The Registrant Subsidiaries do not hedge all foreign
currency exposure.  During the three months ended March 31, 2009 and
2008, APCo, OPCo and SWEPCo recognized no hedge ineffectiveness related to this
hedge strategy.





The
following table provides details on designated, effective cash flow hedges
included in AOCI on the Condensed Balance Sheets and the reasons for changes in
cash flow hedges from January 1, 2009 to March 31, 2009.  All amounts
in the following table are presented net of related income taxes.





Total
      Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow
      HedgesFor
      the Three Months Ended March 31, 2009APCo
                    
                    CSPCo
                    
                    I&M
                    
                    OPCo
                    
                    PSO
                    
                    SWEPCo(in
      thousands)Commodity
      ContractsBeginning
      Balance in AOCI as of January 1, 2009
                    
                    $
                    2,726
                    
                    
                    $
                    1,531
                    
                    
                    $
                    1,482
                    
                    
                    $
                    1,898
                    
                    
                    $
                    -
                    
                    
                    $
                    -Changes
      in Fair Value Recognized in AOCI
                    
                    
                    380
                    
                    
                    
                    118
                    
                    
                    
                    113
                    
                    
                    
                    136
                    
                    
                    
                    (24
                    )
                    
                    
                    (21
                    )Amount
      of (Gain) or Loss Reclassified from AOCI to Income Statements/within
      Balance Sheets:Electric
      Generation, Transmission and Distribution Revenues
                    
                    
                    (251
                    )
                    
                    
                    (613
                    )
                    
                    
                    (504
                    )
                    
                    
                    (759
                    )
                    
                    
                    -
                    
                    
                    
                    -Purchased
      Electricity for Resale
                    
                    
                    462
                    
                    
                    
                    1,126
                    
                    
                    
                    926
                    
                    
                    
                    1,394
                    
                    
                    
                    -
                    
                    
                    
                    -Regulatory
      Assets
                    
                    
                    1,639
                    
                    
                    
                    -
                    
                    
                    
                    163
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -Regulatory
      Liabilities
                    
                    
                    (890
                    )
                    
                    
                    -
                    
                    
                    
                    (89
                    )
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -Ending
      Balance in AOCI as of
                      March31,
      2009
                    
                    $
                    4,066
                    
                    
                    $
                    2,162
                    
                    
                    $
                    2,091
                    
                    
                    $
                    2,669
                    
                    
                    $
                    (24
                    )
                    
                    $
                    (21
                    )





APCo
                      
                      
                      CSPCo
                      
                      
                      I&M
                      
                      
                      OPCo
                      
                      
                      PSO
                      
                      
                      SWEPCo(in
      thousands)Interest
      Rate and Foreign Currency ContractsBeginning
      Balance in AOCI as of January 1, 2009
                      
                      $
                      (8,118
                      )
                      
                      $
                      -
                      
                      
                      $
                      (10,521
                      )
                      
                      $
                      1,752
                      
                      
                      $
                      (704
                      )
                      
                      $
                      (5,924
                      )Changes
      in Fair Value Recognized in AOCI
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      263
                      
                      
                      
                      -
                      
                      
                      
                      (91
                      )Amount
      of (Gain) or Loss Reclassified from AOCI to Income Statements/within
      Balance Sheets:Depreciation
      and Amortization Expense
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      (2
                      )
                      
                      
                      1
                      
                      
                      
                      -
                      
                      
                      
                      -Interest Expense
                      
                      
                      416
                      
                      
                      
                      -
                      
                      
                      
                      252
                      
                      
                      
                      23
                      
                      
                      
                      46
                      
                      
                      
                      207Ending
      Balance in AOCI as of
                        March31,
      2009
                      
                      $
                      (7,702
                      )
                      
                      $
                      -
                      
                      
                      $
                      (10,271
                      )
                      
                      $
                      2,039
                      
                      
                      $
                      (658
                      )
                      
                      $
                      (5,808
                      )





APCo
                  
                  
                  CSPCo
                  
                  
                  I&M
                  
                  
                  OPCo
                  
                  
                  PSO
                  
                  
                  SWEPCo(in
      thousands)TOTAL
      ContractsBeginning
      Balance in AOCI as of January 1, 2009
                  
                  $
                  (5,392
                  )
                  
                  $
                  1,531
                  
                  
                  $
                  (9,039
                  )
                  
                  $
                  3,650
                  
                  
                  $
                  (704
                  )
                  
                  $
                  (5,924
                  )Changes
      in Fair Value Recognized in AOCI
                  
                  
                  380
                  
                  
                  
                  118
                  
                  
                  
                  113
                  
                  
                  
                  399
                  
                  
                  
                  (24
                  )
                  
                  
                  (112
                  )Amount
      of (Gain) or Loss Reclassified from AOCI to Income Statements/within
      Balance Sheets:Electric
      Generation, Transmission and Distribution Revenues
                  
                  
                  (251
                  )
                  
                  
                  (613
                  )
                  
                  
                  (504
                  )
                  
                  
                  (759
                  )
                  
                  
                  -
                  
                  
                  
                  -Purchased
      Electricity for Resale
                  
                  
                  462
                  
                  
                  
                  1,126
                  
                  
                  
                  926
                  
                  
                  
                  1,394
                  
                  
                  
                  -
                  
                  
                  
                  -Depreciation
      and Amortization Expense
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  (2
                  )
                  
                  
                  1
                  
                  
                  
                  -
                  
                  
                  
                  -Interest
      Expense
                  
                  
                  416
                  
                  
                  
                  -
                  
                  
                  
                  252
                  
                  
                  
                  23
                  
                  
                  
                  46
                  
                  
                  
                  207Regulatory
      Assets
                  
                  
                  1,639
                  
                  
                  
                  -
                  
                  
                  
                  163
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -Regulatory
      Liabilities
                  
                  
                  (890
                  )
                  
                  
                  -
                  
                  
                  
                  (89
                  )
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -Ending
      Balance in AOCI as of
                    March31,
      2009
                  
                  $
                  (3,636
                  )
                  
                  $
                  2,162
                  
                  
                  $
                  (8,180
                  )
                  
                  $
                  4,708
                  
                  
                  $
                  (682
                  )
                  
                  $
                  (5,829
                  )





Cash flow
hedges included in Accumulated Other Comprehensive Income (Loss) on the
Condensed Balance Sheets at March 31, 2009 were:




Impact
of Cash Flow Hedges on the Registrant Subsidiaries’


Condensed
Balance Sheets





Hedging
      Assets (a)
                
                
                Hedging
      Liabilities (a)
                
                
                AOCI
      Gain (Loss) Net of TaxCommodity
                
                
                Interest
      Rate and Foreign Currency
                
                
                Commodity
                
                
                Interest
      Rate and Foreign Currency
                
                
                Commodity
                
                
                Interest
      Rate and Foreign CurrencyCompany
                
                (in
      thousands)APCo
                
                $
                6,807
                
                
                $
                -
                
                
                $
                (559
                )
                
                $
                -
                
                
                $
                4,066
                
                
                $
                (7,702
                )CSPCo
                
                
                3,610
                
                
                
                -
                
                
                
                (288
                )
                
                
                -
                
                
                
                2,162
                
                
                
                -I&M
                
                
                3,494
                
                
                
                -
                
                
                
                (283
                )
                
                
                -
                
                
                
                2,091
                
                
                
                (10,271
                )OPCo
                
                
                4,474
                
                
                
                1,328
                
                
                
                (371
                )
                
                
                (924
                )
                
                
                2,669
                
                
                
                2,039PSO
                
                
                -
                
                
                
                -
                
                
                
                (33
                )
                
                
                -
                
                
                
                (24
                )
                
                
                (658
                )SWEPCo
                
                
                -
                
                
                
                1
                
                
                
                (30
                )
                
                
                (301
                )
                
                
                (21
                )
                
                
                (5,808
                )





Expected
      to be Reclassified to
                        Net
      Income During the Next
                        Twelve
      MonthsCommodity
                      
                      
                      Interest
      Rate and Foreign Currency
                      
                      
                      Maximum
      Term for Exposure to Variability of Future Cash FlowsCompany
                      
                      (in
      thousands)
                      
                      
                      (in
      months)APCo
                      
                      $
                      3,939
                      
                      
                      $
                      (1,670
                      )
                      
                      
                      14CSPCo
                      
                      
                      2,095
                      
                      
                      
                      -
                      
                      
                      
                      14I&M
                      
                      
                      2,024
                      
                      
                      
                      (1,007
                      )
                      
                      
                      14OPCo
                      
                      
                      2,586
                      
                      
                      
                      273
                      
                      
                      
                      14PSO
                      
                      
                      (23
                      )
                      
                      
                      (183
                      )
                      
                      
                      10SWEPCo
                      
                      
                      (21
                      )
                      
                      
                      (829
                      
                      
                      
                      44





(a)
            Hedging
      Assets and Hedging Liabilities are in included in Risk Management Assets
      and Liabilities on the Condensed Balance
Sheets.





The
actual amounts reclassified from Accumulated Other Comprehensive Income (Loss)
to Net Income can differ from the estimate above due to market price
changes.





Credit
Risk





The
Registrant Subsidiaries limit credit risk in their wholesale marketing and
trading activities by assessing the creditworthiness of potential counterparties
before entering into transactions with them and continuing to evaluate their
creditworthiness on an ongoing basis.  The Registrant Subsidiaries use
Moody’s, S&P and current market-based qualitative and quantitative data to
assess the financial health of counterparties on an ongoing basis.  If
an external rating is not available, an internal rating is generated utilizing a
quantitative tool developed by Moody’s to estimate probability of default that
corresponds to an implied external agency credit rating.





The
Registrant Subsidiaries use standardized master agreements which may include
collateral requirements.  These master agreements facilitate the
netting of cash flows associated with a single counterparty.  Cash,
letters of credit, and parental/affiliate guarantees may be obtained as security
from counterparties in order to mitigate credit risk.  The collateral
agreements require a counterparty to post cash or letters of credit in the event
an exposure exceeds the established threshold.  The threshold
represents an unsecured credit limit which may be supported by a
parental/affiliate guaranty, as determined in accordance with AEP’s credit
policy.  In addition, collateral agreements allow for termination and
liquidation of all positions in the event of a failure or inability to post
collateral.




Collateral
Triggering Events
 
 Under a
limited number of derivative and non-derivative counterparty contracts primarily
related to pre-2002 risk management activities and under the tariffs of the RTOs
and Independent System Operators (ISOs), the Registrant Subsidiaries are
obligated to post an amount of collateral if certain credit ratings decline
below investment grade.  The amount of collateral required fluctuates
based on market prices and total exposure.  On an ongoing basis, the
risk management organization assesses the appropriateness of these collateral
triggering items in contracts.  Management believes that a downgrade
below investment grade is unlikely.  The following table represents
the Registrant Subsidiaries’ aggregate fair value of such contracts, the amount
of collateral the Registrant Subsidiaries would have been required to post if
the credit ratings had declined below investment grade and how much was
attributable to RTO and ISO activities as of March 31, 2009.
 
 Aggregate
      Fair Value Contracts
                          
                          
                          Amount
      of Collateral the Registrant Subsidiaries Would Have Been Required to
      Post
                          
                          
                          Amount
      Attributable to RTO and ISO ActivitiesCompany
                          
                          (in
      thousands)APCo
                          
                          $
                          38,664
                          
                          
                          $
                          38,664
                          
                          
                          $
                          38,220CSPCo
                          
                          
                          20,506
                          
                          
                          
                          20,506
                          
                          
                          
                          20,270I&M
                          
                          
                          19,845
                          
                          
                          
                          19,845
                          
                          
                          
                          19,617OPCo
                          
                          
                          25,401
                          
                          
                          
                          25,401
                          
                          
                          
                          25,110PSO
                          
                          
                          5,101
                          
                          
                          
                          5,101
                          
                          
                          
                          4,608SWEPCo
                          
                          
                          6,012
                          
                          
                          
                          6,012
                          
                          
                          
                          5,431
 
 As of
March 31, 2009, the Registrant Subsidiaries were not required to post any
collateral.





FAIR
VALUE MEASUREMENTS





SFAS
157 Fair Value Measurements





As
described in the 2008 Annual Report, SFAS 157 establishes a fair value hierarchy
that prioritizes the inputs used to measure fair value.  The hierarchy
gives the highest priority to unadjusted quoted prices in active markets for
identical assets or liabilities (level 1 measurement) and the lowest priority to
unobservable inputs (level 3 measurement).  The Derivatives, Hedging
and Fair Value Measurements note within the 2008 Annual Report should be read in
conjunction with this report.





The
following tables set forth by level within the fair value hierarchy the
financial assets and liabilities that were accounted for at fair value on a
recurring basis as of March 31, 2009 and December 31, 2008.  As
required by SFAS 157, financial assets and liabilities are classified in their
entirety based on the lowest level of input that is significant to the fair
value measurement. Management’s assessment of the significance of a particular
input to the fair value measurement requires judgment, and may affect the
valuation of fair value assets and liabilities and their placement within the
fair value hierarchy levels.





Assets
and Liabilities Measured at Fair Value on a Recurring Basis as of March 31,
2009


APCoLevel
      1
                  
                  
                  Level
      2
                  
                  
                  Level
      3
                  
                  
                  Other
                  
                  
                  TotalAssets:
                  
                  (in
      thousands)Other
      Cash Deposits (d)
                  
                  $
                  421
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  51
                  
                  
                  $
                  472Risk
      Management AssetsRisk
      Management Contracts (a)
                  
                  
                  18,217
                  
                  
                  
                  912,180
                  
                  
                  
                  16,344
                  
                  
                  
                  (825,771
                  )
                  
                  
                  120,970Cash
      Flow and Fair Value Hedges (a)
                  
                  
                  -
                  
                  
                  
                  8,663
                  
                  
                  
                  -
                  
                  
                  
                  (1,856
                  )
                  
                  
                  6,807Dedesignated
      Risk Management Contracts (b)
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  12,189
                  
                  
                  
                  12,189Total
      Risk Management Assets
                  
                  
                  18,217
                  
                  
                  
                  920,843
                  
                  
                  
                  16,344
                  
                  
                  
                  (815,438
                  )
                  
                  
                  139,966Total
      Assets
                  
                  $
                  18,638
                  
                  
                  $
                  920,843
                  
                  
                  $
                  16,344
                  
                  
                  $
                  (815,387
                  )
                  
                  $
                  140,438Liabilities:Risk
      Management LiabilitiesRisk
      Management Contracts (a)
                  
                  $
                  20,078
                  
                  
                  $
                  876,231
                  
                  
                  $
                  4,497
                  
                  
                  $
                  (836,745
                  )
                  
                  $
                  64,061Cash
      Flow and Fair Value Hedges (a)
                  
                  
                  -
                  
                  
                  
                  2,415
                  
                  
                  
                  -
                  
                  
                  
                  (1,856
                  )
                  
                  
                  559DETM
      Assignment (c)
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  4,527
                  
                  
                  
                  4,527Total
      Risk Management Liabilities
                  
                  $
                  20,078
                  
                  
                  $
                  878,646
                  
                  
                  $
                  4,497
                  
                  
                  $
                  (834,074
                  )
                  
                  $
                  69,147





Assets
and Liabilities Measured at Fair Value on a Recurring Basis as of December 31,
2008


APCoLevel
      1
                  
                  
                  Level
      2
                  
                  
                  Level
      3
                  
                  
                  Other
                  
                  
                  TotalAssets:
                  
                  (in
      thousands)Other
      Cash Deposits (d)
                  
                  $
                  656
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  52
                  
                  
                  $
                  708Risk
      Management AssetsRisk
      Management Contracts (a)
                  
                  
                  16,105
                  
                  
                  
                  667,748
                  
                  
                  
                  11,981
                  
                  
                  
                  (597,676
                  )
                  
                  
                  98,158Cash
      Flow and Fair Value Hedges (a)
                  
                  
                  -
                  
                  
                  
                  6,634
                  
                  
                  
                  -
                  
                  
                  
                  (1,413
                  )
                  
                  
                  5,221Dedesignated
      Risk Management Contracts (b)
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  12,856
                  
                  
                  
                  12,856Total
      Risk Management Assets
                  
                  
                  16,105
                  
                  
                  
                  674,382
                  
                  
                  
                  11,981
                  
                  
                  
                  (586,233
                  )
                  
                  
                  116,235Total
      Assets
                  
                  $
                  16,761
                  
                  
                  $
                  674,382
                  
                  
                  $
                  11,981
                  
                  
                  $
                  (586,181
                  )
                  
                  $
                  116,943Liabilities:Risk
      Management LiabilitiesRisk
      Management Contracts (a)
                  
                  $
                  18,808
                  
                  
                  $
                  628,974
                  
                  
                  $
                  3,972
                  
                  
                  $
                  (601,108
                  )
                  
                  $
                  50,646Cash
      Flow and Fair Value Hedges (a)
                  
                  
                  -
                  
                  
                  
                  2,545
                  
                  
                  
                  -
                  
                  
                  
                  (1,413
                  )
                  
                  
                  1,132DETM
      Assignment (c)
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  5,230
                  
                  
                  
                  5,230Total
      Risk Management Liabilities
                  
                  $
                  18,808
                  
                  
                  $
                  631,519
                  
                  
                  $
                  3,972
                  
                  
                  $
                  (597,291
                  )
                  
                  $
                  57,008





Assets
and Liabilities Measured at Fair Value on a Recurring Basis as of March 31,
2009


CSPCoLevel
      1
                  
                  
                  Level
      2
                  
                  
                  Level
      3
                  
                  
                  Other
                  
                  
                  TotalAssets:
                  
                  (in
      thousands)Other
      Cash Deposits (d)
                  
                  $
                  20,036
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  1,171
                  
                  
                  $
                  21,207Risk
      Management AssetsRisk
      Management Contracts (a)
                  
                  
                  9,662
                  
                  
                  
                  481,211
                  
                  
                  
                  8,679
                  
                  
                  
                  (435,732
                  )
                  
                  
                  63,820Cash
      Flow and Fair Value Hedges (a)
                  
                  
                  -
                  
                  
                  
                  4,594
                  
                  
                  
                  -
                  
                  
                  
                  (984
                  )
                  
                  
                  3,610Dedesignated
      Risk Management Contracts (b)
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  6,465
                  
                  
                  
                  6,465Total
      Risk Management Assets
                  
                  
                  9,662
                  
                  
                  
                  485,805
                  
                  
                  
                  8,679
                  
                  
                  
                  (430,251
                  )
                  
                  
                  73,895Total
      Assets
                  
                  $
                  29,698
                  
                  
                  $
                  485,805
                  
                  
                  $
                  8,679
                  
                  
                  $
                  (429,080
                  )
                  
                  $
                  95,102Liabilities:Risk
      Management LiabilitiesRisk
      Management Contracts (a)
                  
                  $
                  10,649
                  
                  
                  $
                  462,306
                  
                  
                  $
                  2,385
                  
                  
                  $
                  (441,545
                  )
                  
                  $
                  33,795Cash
      Flow and Fair Value Hedges (a)
                  
                  
                  -
                  
                  
                  
                  1,272
                  
                  
                  
                  -
                  
                  
                  
                  (984
                  )
                  
                  
                  288DETM
      Assignment (c)
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  2,401
                  
                  
                  
                  2,401Total
      Risk Management Liabilities
                  
                  $
                  10,649
                  
                  
                  $
                  463,578
                  
                  
                  $
                  2,385
                  
                  
                  $
                  (440,128
                  )
                  
                  $
                  36,484





Assets
and Liabilities Measured at Fair Value on a Recurring Basis as of December 31,
2008


CSPCoLevel
      1
                  
                  
                  Level
      2
                  
                  
                  Level
      3
                  
                  
                  Other
                  
                  
                  TotalAssets:
                  
                  (in
      thousands)Other
      Cash Deposits (d)
                  
                  $
                  31,129
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  1,171
                  
                  
                  $
                  32,300Risk
      Management AssetsRisk
      Management Contracts (a)
                  
                  
                  9,042
                  
                  
                  
                  366,557
                  
                  
                  
                  6,724
                  
                  
                  
                  (328,027
                  )
                  
                  
                  54,296Cash
      Flow and Fair Value Hedges (a)
                  
                  
                  -
                  
                  
                  
                  3,725
                  
                  
                  
                  -
                  
                  
                  
                  (794
                  )
                  
                  
                  2,931Dedesignated
      Risk Management Contracts (b)
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  7,218
                  
                  
                  
                  7,218Total
      Risk Management Assets
                  
                  
                  9,042
                  
                  
                  
                  370,282
                  
                  
                  
                  6,724
                  
                  
                  
                  (321,603
                  )
                  
                  
                  64,445Total
      Assets
                  
                  $
                  40,171
                  
                  
                  $
                  370,282
                  
                  
                  $
                  6,724
                  
                  
                  $
                  (320,432
                  )
                  
                  $
                  96,745Liabilities:Risk
      Management LiabilitiesRisk
      Management Contracts (a)
                  
                  $
                  10,559
                  
                  
                  $
                  344,860
                  
                  
                  $
                  2,227
                  
                  
                  $
                  (329,954
                  )
                  
                  $
                  27,692Cash
      Flow and Fair Value Hedges (a)
                  
                  
                  -
                  
                  
                  
                  1,429
                  
                  
                  
                  -
                  
                  
                  
                  (794
                  )
                  
                  
                  635DETM
      Assignment (c)
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  2,937
                  
                  
                  
                  2,937Total
      Risk Management Liabilities
                  
                  $
                  10,559
                  
                  
                  $
                  346,289
                  
                  
                  $
                  2,227
                  
                  
                  $
                  (327,811
                  )
                  
                  $
                  31,264





Assets
and Liabilities Measured at Fair Value on a Recurring Basis as of March 31,
2009


I&MLevel
      1
                  
                  
                  Level
      2
                  
                  
                  Level
      3
                  
                  
                  Other
                  
                  
                  TotalAssets:
                  
                  (in
      thousands)Risk
      Management AssetsRisk
      Management Contracts (a)
                  
                  $
                  9,351
                  
                  
                  $
                  470,390
                  
                  
                  $
                  8,401
                  
                  
                  $
                  (425,852
                  )
                  
                  $
                  62,290Cash
      Flow and Fair Value Hedges (a)
                  
                  
                  -
                  
                  
                  
                  4,446
                  
                  
                  
                  -
                  
                  
                  
                  (952
                  )
                  
                  
                  3,494Dedesignated
      Risk Management Contracts (b)
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  6,256
                  
                  
                  
                  6,256Total
      Risk Management Assets
                  
                  
                  9,351
                  
                  
                  
                  474,836
                  
                  
                  
                  8,401
                  
                  
                  
                  (420,548
                  )
                  
                  
                  72,040Spent
      Nuclear Fuel and Decommissioning TrustsCash
      and Cash Equivalents (e)
                  
                  
                  -
                  
                  
                  
                  14,591
                  
                  
                  
                  -
                  
                  
                  
                  9,114
                  
                  
                  
                  23,705Debt
      Securities (f)
                  
                  
                  -
                  
                  
                  
                  763,963
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  763,963Equity
      Securities (g)
                  
                  
                  418,876
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  418,876Total Spent Nuclear Fuel and
      Decommissioning
                    Trusts
                  
                  
                  418,876
                  
                  
                  
                  778,554
                  
                  
                  
                  -
                  
                  
                  
                  9,114
                  
                  
                  
                  1,206,544Total
      Assets
                  
                  $
                  428,227
                  
                  
                  $
                  1,253,390
                  
                  
                  $
                  8,401
                  
                  
                  $
                  (411,434
                  )
                  
                  $
                  1,278,584Liabilities:Risk
      Management LiabilitiesRisk
      Management Contracts (a)
                  
                  $
                  10,306
                  
                  
                  $
                  451,801
                  
                  
                  $
                  2,309
                  
                  
                  $
                  (431,482
                  )
                  
                  $
                  32,934Cash
      Flow and Fair Value Hedges (a)
                  
                  
                  -
                  
                  
                  
                  1,236
                  
                  
                  
                  -
                  
                  
                  
                  (953
                  )
                  
                  
                  283DETM
      Assignment (c)
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  2,324
                  
                  
                  
                  2,324Total
      Risk Management Liabilities
                  
                  $
                  10,306
                  
                  
                  $
                  453,037
                  
                  
                  $
                  2,309
                  
                  
                  $
                  (430,111
                  )
                  
                  $
                  35,541





Assets
and Liabilities Measured at Fair Value on a Recurring Basis as of December 31,
2008


I&MLevel
      1
                  
                  
                  Level
      2
                  
                  
                  Level
      3
                  
                  
                  Other
                  
                  
                  TotalAssets:
                  
                  (in
      thousands)Risk
      Management AssetsRisk
      Management Contracts (a)
                  
                  $
                  8,750
                  
                  
                  $
                  357,405
                  
                  
                  $
                  6,508
                  
                  
                  $
                  (319,857
                  )
                  
                  $
                  52,806Cash
      Flow and Fair Value Hedges (a)
                  
                  
                  -
                  
                  
                  
                  3,605
                  
                  
                  
                  -
                  
                  
                  
                  (768
                  )
                  
                  
                  2,837Dedesignated
      Risk Management Contracts (b)
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  6,985
                  
                  
                  
                  6,985Total
      Risk Management Assets
                  
                  
                  8,750
                  
                  
                  
                  361,010
                  
                  
                  
                  6,508
                  
                  
                  
                  (313,640
                  )
                  
                  
                  62,628Spent
      Nuclear Fuel and Decommissioning TrustsCash
      and Cash Equivalents (e)
                  
                  
                  -
                  
                  
                  
                  7,818
                  
                  
                  
                  -
                  
                  
                  
                  11,845
                  
                  
                  
                  19,663Debt
      Securities (f)
                  
                  
                  -
                  
                  
                  
                  771,216
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  771,216Equity
      Securities (g)
                  
                  
                  468,654
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  468,654Total Spent Nuclear Fuel and
      Decommissioning
                    Trusts
                  
                  
                  468,654
                  
                  
                  
                  779,034
                  
                  
                  
                  -
                  
                  
                  
                  11,845
                  
                  
                  
                  1,259,533Total
      Assets
                  
                  $
                  477,404
                  
                  
                  $
                  1,140,044
                  
                  
                  $
                  6,508
                  
                  
                  $
                  (301,795
                  )
                  
                  $
                  1,322,161Liabilities:Risk
      Management LiabilitiesRisk
      Management Contracts (a)
                  
                  $
                  10,219
                  
                  
                  $
                  336,280
                  
                  
                  $
                  2,156
                  
                  
                  $
                  (321,722
                  )
                  
                  $
                  26,933Cash
      Flow and Fair Value Hedges (a)
                  
                  
                  -
                  
                  
                  
                  1,383
                  
                  
                  
                  -
                  
                  
                  
                  (768
                  )
                  
                  
                  615DETM
      Assignment (c)
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  2,842
                  
                  
                  
                  2,842Total
      Risk Management Liabilities
                  
                  $
                  10,219
                  
                  
                  $
                  337,663
                  
                  
                  $
                  2,156
                  
                  
                  $
                  (319,648
                  )
                  
                  $
                  30,390





Assets
and Liabilities Measured at Fair Value on a Recurring Basis as of March 31,
2009


OPCoLevel
      1
                  
                  
                  Level
      2
                  
                  
                  Level
      3
                  
                  
                  Other
                  
                  
                  TotalAssets:
                  
                  (in
      thousands)Other
      Cash Deposits (e)
                  
                  $
                  1,071
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  1,674
                  
                  
                  $
                  2,745Risk
      Management AssetsRisk
      Management Contracts (a)
                  
                  
                  11,968
                  
                  
                  
                  710,179
                  
                  
                  
                  10,793
                  
                  
                  
                  (637,725
                  )
                  
                  
                  95,215Cash
      Flow and Fair Value Hedges (a)
                  
                  
                  -
                  
                  
                  
                  7,021
                  
                  
                  
                  -
                  
                  
                  
                  (1,219
                  )
                  
                  
                  5,802Dedesignated
      Risk Management Contracts (b)
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  8,008
                  
                  
                  
                  8,008Total
      Risk Management Assets
                  
                  
                  11,968
                  
                  
                  
                  717,200
                  
                  
                  
                  10,793
                  
                  
                  
                  (630,936
                  )
                  
                  
                  109,025Total
      Assets
                  
                  $
                  13,039
                  
                  
                  $
                  717,200
                  
                  
                  $
                  10,793
                  
                  
                  $
                  (629,262
                  )
                  
                  $
                  111,770Liabilities:Risk
      Management LiabilitiesRisk
      Management Contracts (a)
                  
                  $
                  13,191
                  
                  
                  $
                  685,375
                  
                  
                  $
                  2,991
                  
                  
                  $
                  (644,937
                  )
                  
                  $
                  56,620Cash
      Flow and Fair Value Hedges (a)
                  
                  
                  -
                  
                  
                  
                  2,514
                  
                  
                  
                  -
                  
                  
                  
                  (1,219
                  )
                  
                  
                  1,295DETM
      Assignment (c)
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  2,975
                  
                  
                  
                  2,975Total
      Risk Management Liabilities
                  
                  $
                  13,191
                  
                  
                  $
                  687,889
                  
                  
                  $
                  2,991
                  
                  
                  $
                  (643,181
                  )
                  
                  $
                  60,890





Assets
and Liabilities Measured at Fair Value on a Recurring Basis as of December 31,
2008


OPCoLevel
      1
                  
                  
                  Level
      2
                  
                  
                  Level
      3
                  
                  
                  Other
                  
                  
                  TotalAssets:
                  
                  (in
      thousands)Other
      Cash Deposits (e)
                  
                  $
                  4,197
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  2,431
                  
                  
                  $
                  6,628Risk
      Management AssetsRisk
      Management Contracts (a)
                  
                  
                  11,200
                  
                  
                  
                  575,415
                  
                  
                  
                  8,364
                  
                  
                  
                  (515,162
                  )
                  
                  
                  79,817Cash
      Flow and Fair Value Hedges (a)
                  
                  
                  -
                  
                  
                  
                  4,614
                  
                  
                  
                  -
                  
                  
                  
                  (983
                  )
                  
                  
                  3,631Dedesignated
      Risk Management Contracts (b)
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  8,941
                  
                  
                  
                  8,941Total
      Risk Management Assets
                  
                  
                  11,200
                  
                  
                  
                  580,029
                  
                  
                  
                  8,364
                  
                  
                  
                  (507,204
                  )
                  
                  
                  92,389Total
      Assets
                  
                  $
                  15,397
                  
                  
                  $
                  580,029
                  
                  
                  $
                  8,364
                  
                  
                  $
                  (504,773
                  )
                  
                  $
                  99,017Liabilities:Risk
      Management LiabilitiesRisk
      Management Contracts (a)
                  
                  $
                  13,080
                  
                  
                  $
                  550,278
                  
                  
                  $
                  2,801
                  
                  
                  $
                  (517,548
                  )
                  
                  $
                  48,611Cash
      Flow and Fair Value Hedges (a)
                  
                  
                  -
                  
                  
                  
                  1,770
                  
                  
                  
                  -
                  
                  
                  
                  (983
                  )
                  
                  
                  787DETM
      Assignment (c)
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  3,637
                  
                  
                  
                  3,637Total
      Risk Management Liabilities
                  
                  $
                  13,080
                  
                  
                  $
                  552,048
                  
                  
                  $
                  2,801
                  
                  
                  $
                  (514,894
                  )
                  
                  $
                  53,035





Assets
and Liabilities Measured at Fair Value on a Recurring Basis as of March 31,
2009


PSOLevel
      1
                  
                  
                  Level
      2
                  
                  
                  Level
      3
                  
                  
                  Other
                  
                  
                  TotalAssets:
                  
                  (in
      thousands)Risk
      Management AssetsRisk
      Management Contracts (a)
                  
                  $
                  4,031
                  
                  
                  $
                  43,779
                  
                  
                  $
                  11
                  
                  
                  $
                  (39,589
                  )
                  
                  $
                  8,232Liabilities:Risk
      Management LiabilitiesRisk
      Management Contracts (a)
                  
                  $
                  4,471
                  
                  
                  $
                  41,387
                  
                  
                  $
                  10
                  
                  
                  $
                  (39,982
                  )
                  
                  $
                  5,886Cash
      Flow Hedges (a)
                  
                  
                  -
                  
                  
                  
                  33
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  33DETM
      Assignment (c)
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  168
                  
                  
                  
                  168Total
      Risk Management Liabilities
                  
                  $
                  4,471
                  
                  
                  $
                  41,420
                  
                  
                  $
                  10
                  
                  
                  $
                  (39,814
                  )
                  
                  $
                  6,087





Assets
and Liabilities Measured at Fair Value on a Recurring Basis as of December 31,
2008


PSOLevel
      1
                  
                  
                  Level
      2
                  
                  
                  Level
      3
                  
                  
                  Other
                  
                  
                  TotalAssets:
                  
                  (in
      thousands)Risk
      Management AssetsRisk
      Management Contracts (a)
                  
                  $
                  3,295
                  
                  
                  $
                  39,866
                  
                  
                  $
                  8
                  
                  
                  $
                  (36,422
                  )
                  
                  $
                  6,747Liabilities:Risk
      Management LiabilitiesRisk
      Management Contracts (a)
                  
                  $
                  3,664
                  
                  
                  $
                  37,835
                  
                  
                  $
                  10
                  
                  
                  $
                  (36,527
                  )
                  
                  $
                  4,982DETM
      Assignment (c)
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  149
                  
                  
                  
                  149Total
      Risk Management Liabilities
                  
                  $
                  3,664
                  
                  
                  $
                  37,835
                  
                  
                  $
                  10
                  
                  
                  $
                  (36,378
                  )
                  
                  $
                  5,131








Assets
and Liabilities Measured at Fair Value on a Recurring Basis as of March 31,
2009


SWEPCoLevel
      1
                  
                  
                  Level
      2
                  
                  
                  Level
      3
                  
                  
                  Other
                  
                  
                  TotalAssets:
                  
                  (in
      thousands)Risk
      Management AssetsRisk
      Management Contracts (a)
                  
                  $
                  4,751
                  
                  
                  $
                  64,116
                  
                  
                  $
                  18
                  
                  
                  $
                  (57,779
                  )
                  
                  $
                  11,106Cash
      Flow and Fair Value Hedges (a)
                  
                  
                  -
                  
                  
                  
                  59
                  
                  
                  
                  -
                  
                  
                  
                  (58
                  )
                  
                  
                  1Total
      Risk Management Assets
                  
                  $
                  4,751
                  
                  
                  $
                  64,175
                  
                  
                  $
                  18
                  
                  
                  $
                  (57,837
                  )
                  
                  $
                  11,107Liabilities:Risk
      Management LiabilitiesRisk
      Management Contracts (a)
                  
                  $
                  5,270
                  
                  
                  $
                  60,513
                  
                  
                  $
                  16
                  
                  
                  $
                  (58,235
                  )
                  
                  $
                  7,564Cash
      Flow and Fair Value Hedges (a)
                  
                  
                  -
                  
                  
                  
                  389
                  
                  
                  
                  -
                  
                  
                  
                  (58
                  )
                  
                  
                  331DETM
      Assignment (c)
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  198
                  
                  
                  
                  198Total
      Risk Management Liabilities
                  
                  $
                  5,270
                  
                  
                  $
                  60,902
                  
                  
                  $
                  16
                  
                  
                  $
                  (58,095
                  )
                  
                  $
                  8,093








Assets
and Liabilities Measured at Fair Value on a Recurring Basis as of December 31,
2008


SWEPCoLevel
      1
                  
                  
                  Level
      2
                  
                  
                  Level
      3
                  
                  
                  Other
                  
                  
                  TotalAssets:
                  
                  (in
      thousands)Risk
      Management AssetsRisk
      Management Contracts (a)
                  
                  $
                  3,883
                  
                  
                  $
                  61,471
                  
                  
                  $
                  14
                  
                  
                  $
                  (55,710
                  )
                  
                  $
                  9,658Cash
      Flow and Fair Value Hedges (a)
                  
                  
                  -
                  
                  
                  
                  107
                  
                  
                  
                  -
                  
                  
                  
                  (80
                  )
                  
                  
                  27Total
      Risk Management Assets
                  
                  $
                  3,883
                  
                  
                  $
                  61,578
                  
                  
                  $
                  14
                  
                  
                  $
                  (55,790
                  )
                  
                  $
                  9,685Liabilities:Risk
      Management LiabilitiesRisk
      Management Contracts (a)
                  
                  $
                  4,318
                  
                  
                  $
                  58,390
                  
                  
                  $
                  17
                  
                  
                  $
                  (55,834
                  )
                  
                  $
                  6,891Cash
      Flow and Fair Value Hedges (a)
                  
                  
                  -
                  
                  
                  
                  265
                  
                  
                  
                  -
                  
                  
                  
                  (80
                  )
                  
                  
                  185DETM
      Assignment (c)
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  175
                  
                  
                  
                  175Total
      Risk Management Liabilities
                  
                  $
                  4,318
                  
                  
                  $
                  58,655
                  
                  
                  $
                  17
                  
                  
                  $
                  (55,739
                  )
                  
                  $
                  7,251





(a)
            Amounts
      in “Other” column primarily represent counterparty netting of risk
      management contracts and associated cash collateral under FSP FIN
      39-1.(b)
            “Dedesignated
      Risk Management Contracts” are contracts that were originally MTM but were
      subsequently elected as normal under SFAS 133.  At the time of
      the normal election, the MTM value was frozen and no longer fair
      valued.  This will be amortized into revenues over the remaining
      life of the contract.(c)
            See
      “Natural Gas Contracts with DETM” section of Note 15 in the 2008 Annual
      Report.(d)
            Amounts
      in “Other” column primarily represent cash deposits with third
      parties.  Level 1 amounts primarily represent investments in
      money market funds.(e)
            Amounts
      in “Other” column primarily represent accrued interest receivables from
      financial institutions.  Level 2 amounts primarily represent
      investments in money market funds.(f)
            Amounts
      represent corporate, municipal and treasury bonds.(g)
            Amounts
      represent publicly traded equity securities and equity-based mutual
      funds.





The
following tables set forth a reconciliation of changes in the fair value of net
trading derivatives classified as level 3 in the fair value
hierarchy:





APCo
                    
                    
                    CSPCo
                    
                    
                    I&M
                    
                    
                    OPCo
                    
                    
                    PSO
                    
                    
                    SWEPCoThree
      Months Ended March 31, 2009
                    
                    (in
      thousands)Balance
      as of January 1, 2009
                    
                    $
                    8,009
                    
                    
                    $
                    4,497
                    
                    
                    $
                    4,352
                    
                    
                    $
                    5,563
                    
                    
                    $
                    (2
                    )
                    
                    $
                    (3
                    )Realized
      (Gain) Loss Included in Net Income (or Changes in Net Assets)
      (a)
                    
                    
                    (3,898
                    )
                    
                    
                    (2,189
                    )
                    
                    
                    (2,118
                    )
                    
                    
                    (2,700
                    )
                    
                    
                    3
                    
                    
                    
                    5Unrealized
      Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to
      Assets Still Held at the Reporting Date (a)
                    
                    
                    -
                    
                    
                    
                    3,264
                    
                    
                    
                    -
                    
                    
                    
                    4,045
                    
                    
                    
                    -
                    
                    
                    
                    -Realized
      and Unrealized Gains (Losses) Included in Other Comprehensive
      Income
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -Purchases,
      Issuances and Settlements
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -Transfers
      in and/or out of Level 3 (b)
                    
                    
                    (74
                    )
                    
                    
                    (42
                    )
                    
                    
                    (40
                    )
                    
                    
                    (52
                    )
                    
                    
                    -
                    
                    
                    
                    -Changes
      in Fair Value Allocated to RegulatedJurisdictions
      (c)
                    
                    
                    7,810
                    
                    
                    
                    764
                    
                    
                    
                    3,898
                    
                    
                    
                    946
                    
                    
                    
                    -
                    
                    
                    
                    -Balance
      as of March 31, 2009
                    
                    $
                    11,847
                    
                    
                    $
                    6,294
                    
                    
                    $
                    6,092
                    
                    
                    $
                    7,802
                    
                    
                    $
                    1
                    
                    
                    $
                    2





APCo
                  
                  
                  CSPCo
                  
                  
                  I&M
                  
                  
                  OPCo
                  
                  
                  PSO
                  
                  
                  SWEPCoThree
      Months Ended March 31, 2008
                  
                  (in
      thousands)Balance
      as of January 1, 2008
                  
                  $
                  (697
                  )
                  
                  $
                  (263
                  )
                  
                  $
                  (280
                  )
                  
                  $
                  (1,607
                  )
                  
                  $
                  (243
                  )
                  
                  $
                  (408
                  )Realized
      (Gain) Loss Included in Net Income (or Changes in Net Assets)
      (a)
                  
                  
                  (657
                  )
                  
                  
                  (414
                  )
                  
                  
                  (391
                  )
                  
                  
                  (176
                  )
                  
                  
                  29
                  
                  
                  
                  63Unrealized
      Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to
      Assets Still Held at the Reporting Date (a)
                  
                  
                  -
                  
                  
                  
                  721
                  
                  
                  
                  -
                  
                  
                  
                  1,639
                  
                  
                  
                  -
                  
                  
                  
                  106Realized
      and Unrealized Gains (Losses) Included in Other Comprehensive
      Income
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -Purchases,
      Issuances and Settlements
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -Transfers
      in and/or out of Level 3 (b)
                  
                  
                  (1,026
                  )
                  
                  
                  (596
                  )
                  
                  
                  (572
                  )
                  
                  
                  (693
                  )
                  
                  
                  -
                  
                  
                  
                  -Changes
      in Fair Value Allocated to Regulated Jurisdictions (c)
                  
                  
                  1,438
                  
                  
                  
                  -
                  
                  
                  
                  724
                  
                  
                  
                  -
                  
                  
                  
                  193
                  
                  
                  
                  204Balance
      as of March 31, 2008
                  
                  $
                  (942
                  )
                  
                  $
                  (552
                  )
                  
                  $
                  (519
                  )
                  
                  $
                  (837
                  )
                  
                  $
                  (21
                  )
                  
                  $
                  (35
                  )





(a)
            Included
      in revenues on the Statements of Income.(b)
            “Transfers
      in and/or out of Level 3” represent existing assets or liabilities that
      were either previously categorized as a higher level for which the inputs
      to the model became unobservable or assets and liabilities that were
      previously classified as level 3 for which the lowest significant input
      became observable during the period.(c)
            “Changes
      in Fair Value Allocated to Regulated Jurisdictions” relates to the net
      gains (losses) of those contracts that are not reflected on the Statements
      of Income.  These net gains (losses) are recorded as regulatory
      liabilities/assets.





8.
            INCOME
      TAXES





The
Registrant Subsidiaries are no longer subject to U.S. federal examination for
years before 2000.  The Registrant Subsidiaries have completed the
exam for the years 2001 through 2006 and have issues that are being pursued at
the appeals level.  Although the outcome of tax audits is uncertain,
in management’s opinion, adequate provisions for income taxes have been made for
potential liabilities resulting from such matters.  In addition, the
Registrant Subsidiaries accrue interest on these uncertain tax
positions.  Management is not aware of any issues for open tax years
that upon final resolution are expected to have a material adverse effect on net
income.





9.       FINANCING
ACTIVITIES





Long-term
Debt





Long-term
debt and other securities issued, retired and principal payments made during the
first three months of 2009 were:





Principal
              
              Interest
              
              DueCompany
              
              Type
      of Debt
              
              Amount
              
              Rate
              
              Date(in
      thousands)
              
              (%)Issuances:APCo
              
              Senior
      Unsecured Notes
              
              $
              350,000
              
              7.95
              
              2020I&M
              
              Senior
      Unsecured Notes
              
              
              475,000
              
              7.00
              
              2019I&M
              
              Pollution
      Control Bonds
              
              
              50,000
              
              6.25
              
              2025I&M
              
              Pollution
      Control Bonds
              
              
              50,000
              
              6.25
              
              2025PSO
              
              Pollution
      Control Bonds
              
              
              33,700
              
              5.25
              
              2014





Principal
              
              Interest
              
              DueCompany
              
              Type
      of Debt
              
              Amount
      Paid
              
              Rate
              
              Date(in
      thousands)
              
              (%)Retirements
      and
                Principal Payments:APCo
              
              Land
      Note
              
              $
              4
              
              13.718
              
              2026OPCo
              
              Notes
      Payable
              
              
              1,000
              
              6.27
              
              2009OPCo
              
              Notes
      Payable
              
              
              3,500
              
              7.21
              
              2009SWEPCo
              
              Notes
      Payable
              
              
              1,101
              
              4.47
              
              2011





In
January 2009, AEP Parent loaned I&M $25 million of 5.375% Notes Payable due
in 2010.





During
2008, the Registrant Subsidiaries chose to begin eliminating their auction-rate
debt position due to market conditions.  As of March 31, 2009, OPCo
had $218 million of tax-exempt long-term debt sold at auction rates (rates at
contractual maximum rate of 13%) that reset every 35 days.  OPCo’s
debt relates to a lease structure with JMG that OPCo is unable to refinance
without their consent.  The initial term for the JMG lease structure
matures on March 31, 2010 and management is evaluating whether to terminate this
facility prior to maturity.  Termination of this facility requires
approval from the PUCO.  As of March 31, 2009, SWEPCo had $53.5
million of tax-exempt long-term debt sold at auction rates (rate of 1.676%) that
reset every 35 days.  The instruments under which the bonds are issued
allow us to convert to other short-term variable-rate structures, term-put
structures and fixed-rate structures.





During
the first quarter of 2009, I&M and PSO issued $100 million of 6.25%
Pollution Control Bonds due in 2025 and $33.7 million of 5.25% Pollution Control
Bonds due in 2014, respectively, which were previously held by trustees on the
Registrant Subsidiaries’ behalf.  As of March 31, 2009, trustees held,
on the Registrant Subsidiaries’ behalf, $195 million of the remaining reacquired
auction-rate tax-exempt long-term debt which the Registrant Subsidiaries plan to
reissue to the public as market conditions permit.





Utility
Money Pool – 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.  The AEP
System Utility Money Pool operates in accordance with the terms and conditions
approved in a regulatory order.  The amount of outstanding loans
(borrowings) to/from the Utility Money Pool as of March 31, 2009 and December
31, 2008 are included in Advances to/from Affiliates on each of the Registrant
Subsidiaries’ balance sheets.  The Utility Money Pool participants’
money pool activity and their corresponding authorized borrowing limits for the
three months ended March 31, 2009 are described in the following
table:





LoansMaximum
                    
                    Maximum
                    
                    Average
                    
                    Average
                    
                    (Borrowings)
                    
                    AuthorizedBorrowings
                    
                    Loans
      to
                    
                    Borrowings
                    
                    Loans
      to
                    
                    to/from
      Utility
                    
                    Short-Termfrom
      Utility
                    
                    Utility
                    
                    from
      Utility
                    
                    Utility
      Money
                    
                    Money
      Pool as of
                    
                    BorrowingMoney
      Pool
                    
                    Money
      Pool
                    
                    Money
      Pool
                    
                    Pool
                    
                    March
      31, 2009
                    
                    LimitCompany
                    (in
      thousands)APCo
                    
                    $
                    420,925
                    
                    
                    $
                    -
                    
                    
                    $
                    248,209
                    
                    
                    $
                    -
                    
                    
                    $
                    (120,481
                    )
                    
                    $
                    600,000CSPCo
                    
                    
                    203,306
                    
                    
                    
                    -
                    
                    
                    
                    135,532
                    
                    
                    
                    -
                    
                    
                    
                    (177,736
                    )
                    
                    
                    350,000I&M
                    
                    
                    491,107
                    
                    
                    
                    22,979
                    
                    
                    
                    153,707
                    
                    
                    
                    16,201
                    
                    
                    
                    (16,421
                    )
                    
                    
                    500,000OPCo
                    
                    
                    406,354
                    
                    
                    
                    -
                    
                    
                    
                    281,950
                    
                    
                    
                    -
                    
                    
                    
                    (320,166
                    )
                    
                    
                    600,000PSO
                    
                    
                    77,976
                    
                    
                    
                    87,443
                    
                    
                    
                    58,549
                    
                    
                    
                    46,483
                    
                    
                    
                    7,009
                    
                    
                    
                    300,000SWEPCo
                    
                    
                    62,871
                    
                    
                    
                    63,539
                    
                    
                    
                    30,880
                    
                    
                    
                    29,381
                    
                    
                    
                    37,649
                    
                    
                    
                    350,000





The
maximum and minimum interest rates for funds either borrowed from or loaned to
the Utility Money Pool were as follows:


Three
      Months Ended March 31,2009
                
                2008Maximum
      Interest Rate
                
                2.28%
                
                5.37%Minimum
      Interest Rate
                
                1.22%
                
                3.39%





The
average interest rates for funds borrowed from and loaned to the Utility Money
Pool for the three months ended March 31, 2009 and 2008 are summarized for all
Registrant Subsidiaries in the following table:





Average
      Interest Rate for Funds
                
                
                Average
      Interest Rate for FundsBorrowed
      from the Utility Money
                
                
                Loaned
      to the Utility MoneyPool
      for the
                
                
                Pool
      for theThree
      Months Ended March 31,
                
                
                Three
      Months Ended March 31,2009
                
                2008
                
                
                2009
                
                2008CompanyAPCo
                
                1.76%
                
                4.21%
                
                
                -%
                
                3.46%CSPCo
                
                1.62%
                
                4.01%
                
                
                -%
                
                -%I&M
                
                1.86%
                
                3.99%
                
                
                1.76%
                
                -%OPCo
                
                1.65%
                
                4.29%
                
                
                -%
                
                -%PSO
                
                2.01%
                
                3.51%
                
                
                1.63%
                
                4.57%SWEPCo
                
                1.86%
                
                4.00%
                
                
                1.68%
                
                -%





Short-term
Debt





The
Registrant Subsidiaries’ outstanding short-term debt was as
follows:





March
      31, 2009
              
              December
      31, 2008Weighted
              
              
              
              WeightedAverage
              
              
              
              AverageOutstanding
              
              Interest
              
              Outstanding
              
              InterestType
      of Debt
              
              Amount
              
              Rate
              
              Amount
              
              RateCompany
              
              
              
              (in
      thousands)
              
              
              
              (in
      thousands)SWEPCo
              
              Line
      of Credit – Sabine Mining Company (a)
              
              $
              6,559
              
              1.82%
              
              $
              7,172
              
              1.54%





(a)
            Sabine
      Mining Company is consolidated under FIN
46R.





Credit
Facilities





The
Registrant Subsidiaries and certain other companies in the AEP System have a
$650 million 3-year credit agreement and a $350 million 364-day credit agreement
which were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $23
million and $12 million, respectively, following its
bankruptcy.  Under the facilities, letters of credit may be
issued.  In April 2009, the $350 million 364-day credit agreement
expired.  As of March 31, 2009, $372 million letters of credit were issued
by Registrant Subsidiaries under the $650 million 3-year credit agreement to
support variable rate Pollution Control Bonds as follow:





Letters
      of CreditAmount
      OutstandingAgainst
      $650 million3-Year
      AgreementCompany
                    (in
      thousands)APCo
                    
                    $
                    126,716I&M
                    
                    
                    77,886OPCo
                    
                    
                    166,899










COMBINED
MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT
SUBSIDIARIES





The
following is a combined presentation of certain components of the Registrant
Subsidiaries’ management’s discussion and analysis.  The information
in this section completes the information necessary for management’s discussion
and analysis of financial condition and net income 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 Registrant Subsidiaries section of the
2008 Annual Report should also be read in conjunction with this
report.





Economic
Slowdown





The
financial struggles of the U.S. economy continue to impact the Registrant
Subsidiaries’ industrial sales as well as sales opportunities in the wholesale
market.  Industrial sales in various sections of the service
territories are decreasing due to reduced shifts and suspended operations by
some of the Registrant Subsidiaries’ large industrial
customers.  Although many sections of the Registrant Subsidiaries’
service territories are experiencing slowdowns in new construction, their
residential and commercial customer base appears to be stable.  As a
result of these economic issues, management is currently monitoring the
following:





·
            Margins from
      Off-system Sales –  Margins from off-system sales for the
      AEP System continue to decrease due to reductions in sales volumes and
      weak market power prices, reflecting reduced overall demand for
      electricity.  Management currently forecasts that margins from
      off-system volumes will decrease by approximately 30% in
      2009.  These trends will most likely continue until the economy
      rebounds and electricity demand and prices
  increase.





·
            Industrial KWH
      Sales – The AEP System’s industrial KWH sales for the quarter
      ended March 31, 2009 were down 15% in comparison to the quarter ended
      March 31, 2008.  Approximately half of this decrease was due to
      cutbacks or closures by customers who produce primary metals served by
      APCo, CSPCo, I&M, OPCo and SWEPCo.  I&M, PSO and SWEPCo
      also experienced additional significant decreases in KWH sales to
      customers in the plastics, rubber and paper manufacturing
      industries.  Since the AEP System’s trends for industrial sales
      are usually similar to the nation’s industrial production, these trends
      will continue until industrial production
  improves.





·
            Risk of Loss of Major
      Customers – Management monitors the financial strength and
      viability of each major industrial customer individually.  The
      Registrant Subsidiaries have factored this analysis into their operational
      planning.  CSPCo’s and OPCo’s largest customer, Ormet, with a
      520 MW load, recently announced that it is in dispute with its sole
      customer which could potentially force Ormet to halt
      production.  In February 2009, Century Aluminum, a major
      industrial customer (325 MW load) of APCo, announced the curtailment of
      operations at its Ravenswood, WV
facility.





Credit
Markets





The
financial markets remain volatile at both a global and domestic
level.  This marketplace distress could impact the Registrant
Subsidiaries’ access to capital, liquidity and cost of capital.  The
uncertainties in the capital markets could have significant implications since
the Registrant Subsidiaries rely on continuing access to capital to fund
operations and capital expenditures.





Management
believes that the Registrant Subsidiaries have adequate liquidity, through the
Utility Money Pool and cash flows from their operations, to support planned
business operations and capital expenditures through 2009.  To support
operations, AEP has $3.9 billion in aggregate credit facility commitments as of
March 31, 2009.  These commitments include 27 different banks with no
one bank having more than 10% of the total bank
commitments.  Short-term funding for the Registrant Subsidiaries comes
from AEP’s credit facilities which support the Utility Money
Pool.  APCo, OPCo and PSO have $150 million, $73 million and $50
million, respectively, maturing in the remainder of 2009.  Long-term
debt of $200 million, $150 million, $680 million and $150 million will mature in
2010 for APCo, CSPCo, OPCo and PSO, respectively.  Management intends
to refinance debt maturities.  Management cannot predict the length of
time the current credit situation will continue or its impact on future
operations and the Registrant Subsidiaries’ ability to issue debt at reasonable
interest rates.





AEP
sponsors several trust funds with significant investments intended to provide
for future payments of pensions and OPEB.  I&M has significant
investments in several trust funds intended to provide for future payments of
nuclear decommissioning and spent nuclear fuel disposal.  Although all
of the trust funds’ investments are well-diversified and managed in compliance
with all laws and regulations, the value of the investments in these trusts
declined substantially over the past year due to decreases in domestic and
international equity markets.  Although the asset values are currently
lower, this has not affected the funds’ ability to make their required
payments.  The decline in pension asset values will not require the
AEP System to make a contribution under ERISA in 2009.  As of March
31, 2009, management estimates that the minimum contributions to the pension
trust will be $475 million in 2010 and $283 million in 2011.  These
amounts are allocated to companies in the AEP System, including the Registrant
Subsidiaries.  However, estimates may vary significantly based on
market returns, changes in actuarial assumptions and other factors.





On behalf
of the Registrant Subsidiaries, AEPSC enters into risk management contracts with
numerous counterparties.  Since open risk management contracts are
valued based on changes in market prices of the related commodities, exposures
change daily. AEP’s risk management organization monitors these exposures on a
daily basis to limit the Registrant Subsidiaries’ economic and financial
statement impact on a counterparty basis.





Budgeted Construction
Expenditures





Budgeted
construction expenditures for the Registrant Subsidiaries for 2010
are:





BudgetedConstructionExpendituresCompany
                        
                        (in
      millions)APCo
                        
                        $
                        297CSPCo
                        
                        
                        231I&M
                        
                        
                        246OPCo
                        
                        
                        294PSO
                        
                        
                        162SWEPCo
                        
                        
                        423





Budgeted
construction expenditures are subject to periodic review and modification and
may vary based on the ongoing effects of regulatory constraints, environmental
regulations, business opportunities, market volatility, economic trends,
weather, legal reviews and the ability to access capital.





LIQUIDITY





Sources of
Funding





Short-term
funding for the Registrant Subsidiaries comes from AEP’s commercial paper
program and revolving credit facilities through the Utility Money
Pool.  AEP and its Registrant Subsidiaries also operate a money pool
to minimize the AEP System’s external short-term funding requirements and sell
accounts receivable to provide liquidity.  The credit facilities that
support the Utility Money Pool were reduced by Lehman Brothers Holdings Inc.’s
commitment amount of $46 million following its bankruptcy.  In March
2008, these credit facilities were amended so that $750 million may be issued
under each credit facility as letters of credit (LOC).  The Registrant
Subsidiaries generally use short-term funding sources (the Utility Money Pool or
receivables sales) to provide for interim financing of capital expenditures that
exceed internally generated funds and periodically reduce their outstanding
short-term debt through issuances of long-term debt, sale-leasebacks, leasing
arrangements and additional capital contributions from Parent.





In April
2008, the Registrant Subsidiaries and certain other companies in the AEP System
entered into a $650 million 3-year credit agreement and a $350 million 364-day
credit agreement which were reduced by Lehman Brothers Holdings Inc.’s
commitment amount of $23 million and $12 million, respectively, following its
bankruptcy.  Management chose to allow the $350 million credit
agreement to expire in April 2009.  The Registrant Subsidiaries may
issue LOCs under the credit facility.  Each subsidiary has a
borrowing/LOC limit under the credit facility.  As of March 31, 2009,
a total of $372 million of LOCs were issued under the 3-year credit agreement to
support variable rate demand notes.  The following table shows each
Registrant Subsidiaries’ borrowing/LOC limit under the credit facility and the
outstanding amount of LOCs.





LOC
      AmountOutstanding$650
      million
                        
                        AgainstCredit
      Facility
                        
                        $650
      millionBorrowing/LOC
                        
                        Agreement
      atLimit
                        
                        March
      31, 2009Company
                        (in
      millions)APCo
                        
                        $
                        300
                        
                        
                        $
                        127CSPCo
                        
                        
                        230
                        
                        
                        
                        -I&M
                        
                        
                        230
                        
                        
                        
                        78OPCo
                        
                        
                        400
                        
                        
                        
                        167PSO
                        
                        
                        65
                        
                        
                        
                        -SWEPCo
                        
                        
                        230
                        
                        
                        
                        -





Dividend
Restrictions





Under the
Federal Power Act, the Registrant Subsidiaries are restricted from paying
dividends out of stated capital.





Sale of Receivables Through
AEP Credit





In 2008,
AEP Credit renewed its sale of receivables agreement through October
2009.  The sale of receivables agreement provides a commitment of $700
million from banks and commercial paper conduits to purchase receivables from
AEP Credit.  Management intends to extend or replace the sale of
receivables agreement.  At March 31, 2009, $578 million of commitments
to purchase accounts receivable were outstanding under the receivables
agreement.  AEP Credit purchases accounts receivable from the
Registrant Subsidiaries.





SIGNIFICANT
FACTORS





Ohio Electric Security Plan
Filings





In March
2009, the PUCO issued an order that modified and approved CSPCo’s and OPCo’s
ESPs which will be in effect through 2011.  The ESP order authorized
increases to revenues during the ESP period and capped the overall revenue
increases through a phase-in of the fuel adjustment clause (FAC).  The
ordered increases for CSPCo are 7% in 2009, 6% in 2010 and 6% in 2011 and for
OPCo are 8% in 2009, 7% in 2010 and 8% in 2011.  After final PUCO
review and approval of conforming rate schedules, CSPCo and OPCo implemented
rates for the April 2009 billing cycle.  CSPCo and OPCo will collect
the 2009 annualized revenue increase over the remainder of 2009.





The order
provides a FAC for the three-year period of the ESP.  The FAC increase
will be phased in to meet the ordered annual caps described
above.  The FAC increase before phase-in will be subject to quarterly
true-ups to actual recoverable FAC costs and to annual accounting audits and
prudency reviews.  The order allows CSPCo and OPCo to defer
unrecovered FAC costs resulting from the annual caps/phase-in plan and to accrue
carrying charges on such deferrals at CSPCo’s and OPCo’s weighted average cost
of capital.  The deferred FAC balance at the end of the ESP period
will be recovered through a non-bypassable surcharge over the period 2012
through 2018.  As of March 31, 2009, the FAC deferral balances were
$17 million and $66 million for CSPCo and OPCo, respectively, including carrying
charges.  The PUCO rejected a proposal by several intervenors to
offset the FAC costs with a credit for off-system sales margins.  As a
result, CSPCo and OPCo will retain the benefit of their share of the AEP
System’s off-system sales.  In addition, the ESP order provided for
both the FAC deferral credits and the off-system sales margins to be excluded
from the methodology for the Significantly Excessive Earnings Test
(SEET).  The SEET is discussed below.





Additionally,
the order addressed several other items, including:





·
            The
      approval of new distribution riders, subject to true-up for recovery of
      costs for enhanced vegetation management programs for CSPCo and OPCo and
      the proposed gridSMART advanced metering initial program roll out in a
      portion of CSPCo’s service territory.  The PUCO proposed that
      CSPCo mitigate the costs of gridSMART by seeking matching funds under the
      American Recovery and Reinvestment Act of 2009.  As a result, a
      rider was established to recover 50% or $32 million of the projected $64
      million revenue requirement related to gridSMART costs.  The
      PUCO denied the other distribution system reliability programs proposed by
      CSPCo and OPCo as part of their ESP filings.  The PUCO decided
      that those requests should be examined in the context of a complete
      distribution base rate case.  The order did not require CSPCo
      and/or OPCo to file a distribution base rate
  case.





·
            The
      approval of CSPCo’s and OPCo’s request to recover the incremental carrying
      costs related to environmental investments made from 2001 through 2008
      that are not reflected in existing rates.  Future recovery
      during the ESP period of incremental carrying charges on environmental
      expenditures incurred beginning in 2009 may be requested in annual
      filings.





·
            The
      approval of a $97 million and $55 million increase in CSPCo’s and OPCo’s
      Provider of Last Resort charges, respectively, to compensate for the risk
      of customers changing electric suppliers during the ESP
      period.





·
            The
      requirement that CSPCo’s and OPCo’s shareholders fund a combined minimum
      of $15 million in costs over the ESP period for low-income, at-risk
      customer programs.  This funding obligation was recognized as a
      liability and an unfavorable adjustment to Other Operation and Maintenance
      expense for the three-month period ending March 31,
  2009.





·
            The
      deferral of CSPCo’s and OPCo’s request to recover certain existing
      regulatory assets, including customer choice implementation and line
      extension carrying costs as part of the ESPs.  The PUCO decided
      it would be more appropriate to consider this request in the context of
      CSPCo’s and OPCo’s next distribution base rate case.  These
      regulatory assets, which were approved by prior PUCO orders, total $58
      million for CSPCo and $40 million for OPCo as of March 31,
      2009.  In addition, CSPCo and OPCo would recover and recognize
      as income, when collected, $35 million and $26 million, respectively, of
      related unrecorded equity carrying costs incurred through March
      2009.





Finally,
consistent with its decisions on ESP orders of other companies, the PUCO ordered
its staff to convene a workshop to determine the methodology for the SEET that
will be applicable to all electric utilities in Ohio.  The SEET
requires the PUCO to determine, following the end of each year of the ESP, if
any rate adjustments included in the ESP resulted in excessive earnings as
measured by whether the earned return on common equity of CSPCo and OPCo is
significantly in excess of the return on common equity that was earned during
the same period by publicly traded companies, including utilities, that have
comparable business and financial risk.  If the rate adjustments, in
the aggregate, result in significantly excessive earnings in comparison, the
PUCO must require that the amount of the excess be returned to
customers.  The PUCO’s decision on the SEET review of CSPCo’s and
OPCo’s 2009 earnings is not expected to be finalized until the second or third
quarter of 2010.





In March
2009, intervenors filed a motion to stay a portion of the ESP rates or
alternately make that portion subject to refund because the intervenors believed
that the ordered ESP rates for 2009 were retroactive and therefore
unlawful.  In March 2009, the PUCO approved CSPCo’s and OPCo’s tariffs
effective with the April 2009 billing cycle and rejected the intervenors’
motion.  The PUCO also clarified that the reference in its earlier
order to the January 1, 2009 date related to the term of the ESP, not to the
effective date of tariffs and clarified the tariffs were not
retroactive.  In March 2009, CSPCo and OPCo implemented the new ESP
tariffs effective with the start of the April 2009 billing cycle.  In
April 2009, CSPCo and OPCo filed a motion requesting rehearing of several
issues.  In April 2009, several intervenors filed motions requesting
rehearing of issues underlying the PUCO’s authorized rate increases and one
intervenor filed a motion requesting the PUCO to direct CSPCo and OPCo to cease
collecting rates under the order.  Certain intervenors also filed a
complaint for writ of prohibition with the Ohio Supreme Court to halt any
further collection from customers of what the intervenors claim is unlawful
retroactive rate increases.





Management
will evaluate whether it will withdraw the ESP applications after a final order,
thereby terminating the ESP proceedings.  If CSPCo and/or OPCo
withdraw the ESP applications, CSPCo and/or OPCo may file a Market Rate Offer
(MRO) or another ESP as permitted by the law.  The revenues collected
and recorded in 2009 under this PUCO order are subject to possible refund
through the SEET process.  Management is unable, due to the decision
of the PUCO to defer guidance on the SEET methodology to a future generic SEET
proceeding, to estimate the amount, if any, of a possible refund that could
result from the SEET process in 2010.





New Generation/Purchase
Power Agreement





In 2009,
AEP is in various stages of construction of the following generation
facilities:


CommercialTotal
              
              
              
              
              
              
              
              
              Nominal
              
              OperationOperating
              
              Project
              
              
              
              Projected
              
              
              
              
              
              
              
              
              MW
              
              DateCompany
              
              Name
              
              Location
              
              Cost
      (a)
              
              CWIP
      (b)
              
              Fuel
      Type
              
              Plant
      Type
              
              Capacity
              
              (Projected)(in
      millions)
              
              (in
      millions)AEGCo
              
              Dresden
              (c)
              Ohio
              
              $
              322
              
              $
              189
              
              Gas
              
              Combined-cycle
              
              580
              
              2013SWEPCo
              
              Stall
              
              Louisiana
              
              
              385
              
              
              291
              
              Gas
              
              Combined-cycle
              
              500
              
              2010SWEPCo
              
              Turk
              (d)
              Arkansas
              
              
              1,628
              (d)
              
              480
              
              Coal
              
              Ultra-supercritical
              
              600
              (d)
              2012APCo
              
              Mountaineer
              (e)
              West
      Virginia
              
              
              
              (e)
              
              
              
              Coal
              
              IGCC
              
              629
              
              
              (e)CSPCo/OPCo
              
              Great
      Bend
              (e)
              Ohio
              
              
              
              (e)
              
              
              
              Coal
              
              IGCC
              
              629
              
              
              (e)





(a)
            Amount
      excludes AFUDC.(b)
            Amount
      includes AFUDC.(c)
            In
      September 2007, AEGCo purchased the partially completed Dresden plant from
      Dresden Energy LLC, a subsidiary of Dominion Resources, Inc., for $85
      million, which is included in the “Total Projected Cost” section
      above.(d)
            SWEPCo
      plans to own approximately 73%, or 440 MW, totaling $1.2 billion in
      capital investment.  See “Turk Plant” section
    below.(e)
            Construction
      of IGCC plants is subject to regulatory approvals.  See “IGCC
      Plants” section below.





Turk
Plant





In
November 2007, the APSC granted approval to build the Turk
Plant.  Certain landowners have appealed the APSC’s decision to the
Arkansas State Court of Appeals.  In March 2008, the LPSC approved the
application to construct the Turk Plant.





In August
2008, the PUCT issued an order approving the Turk Plant with the following four
conditions: (a) the capping of capital costs for the Turk Plant at the
previously estimated $1.522 billion projected construction cost, excluding
AFUDC, (b) capping CO2 emission
costs at $28 per ton through the year 2030, (c) holding Texas ratepayers
financially harmless from any adverse impact related to the Turk Plant not being
fully subscribed to by other utilities or wholesale customers and (d) providing
the PUCT all updates, studies, reviews, reports and analyses as previously
required under the Louisiana and Arkansas orders.  In October 2008,
SWEPCo appealed the PUCT’s order regarding the two cost cap
restrictions.  If the cost cap restrictions are upheld and
construction or emissions costs exceed the restrictions, it could have a
material adverse effect on future net income and cash flows.  In
October 2008, an intervenor filed an appeal contending that the PUCT’s grant of
a conditional Certificate of Public Convenience and Necessity for the Turk Plant
was not necessary to serve retail customers.





A request
to stop pre-construction activities at the site was filed in federal court by
Arkansas landowners.  In July 2008, the federal court denied the
request and the Arkansas landowners appealed the denial to the U.S. Court of
Appeals.  In January 2009, SWEPCo filed a motion to dismiss the
appeal.  In March 2009, the motion was granted.





In
November 2008, SWEPCo received the required air permit approval from the
Arkansas Department of Environmental Quality and commenced
construction.  In December 2008, Arkansas landowners filed an appeal
with the Arkansas Pollution Control and Ecology Commission (APCEC) which caused
construction of the Turk Plant to halt until the APCEC took further
action.  In December 2008, SWEPCo filed a request with the APCEC to
continue construction of the Turk Plant and the APCEC ruled to allow
construction to continue while an appeal of the Turk Plant’s permit is
heard.  Hearings on the air permit appeal are scheduled for June
2009.  SWEPCo is also working with the U.S. Army Corps of Engineers
for the approval of a wetlands and stream impact permit.  In March
2009, SWEPCo reported to the U.S. Army Corps of Engineers a potential wetlands
impact on approximately 2.5 acres at the Turk Plant.  The U.S. Army
Corps of Engineers directed SWEPCo to cease further work impacting the wetland
areas.  Construction has continued on other areas of the Turk
Plant.  The impact on the construction schedule and workforce is
currently being evaluated by management.





In
January and July 2008, SWEPCo filed Certificate of Environmental Compatibility
and Public Need (CECPN) applications with the APSC to construct transmission
lines necessary for service from the Turk Plant.  Several landowners
filed for intervention status and one landowner also contended he should be
permitted to re-litigate Turk Plant issues, including the need for the
generation.  The APSC granted their intervention but denied the
request to re-litigate the Turk Plant issues.  In June 2008, the
landowner filed an appeal to the Arkansas State Court of Appeals requesting to
re-litigate Turk Plant issues.  SWEPCo responded and the appeal was
dismissed.  In January 2009, the APSC approved the CECPN
applications.





The
Arkansas Governor’s Commission on Global Warming issued its final report to the
Governor in October 2008.  The Commission was established to set a
global warming pollution reduction goal together with a strategic plan for
implementation in Arkansas.  The Commission’s final report included a
recommendation that the Turk Plant employ post combustion carbon capture and
storage measures as soon as it starts operating.  If legislation is
passed as a result of the findings in the Commission’s report, it could impact
SWEPCo’s proposal to build and operate the Turk Plant.





If SWEPCo
does not receive appropriate authorizations and permits to build the Turk Plant,
SWEPCo could incur significant cancellation fees to terminate its commitments
and would be responsible to reimburse OMPA, AECC and ETEC for their share of
costs incurred plus related shutdown costs.  If that occurred, SWEPCo
would seek recovery of its capitalized costs including any cancellation fees and
joint owner reimbursements.  As of March 31, 2009, SWEPCo has
capitalized approximately $480 million of expenditures (including AFUDC) and has
contractual construction commitments for an additional $655
million.  As of March 31, 2009, if the plant had been cancelled,
SWEPCo would have incurred cancellation fees of $100 million.  If the
Turk Plant does not receive all necessary approvals on reasonable terms and
SWEPCo cannot recover its capitalized costs, including any cancellation fees, it
would have an adverse effect on future net income, cash flows and possibly
financial condition.





IGCC
Plants





The
construction of the West Virginia and Ohio IGCC plants are pending regulatory
approvals.  In April 2008, the Virginia SCC issued an order denying
APCo’s request to recover initial costs associated with a proposed IGCC plant in
West Virginia.  In July 2008, the WVPSC issued a notice seeking
comments from parties on how the WVPSC should proceed regarding its earlier
approval of the IGCC plant.  Comments were filed by various parties,
including APCo, but the WVPSC has not taken any action.  In July 2008,
the IRS allocated $134 million in future tax credits to APCo for the planned
IGCC plant contingent upon the commencement of construction, qualifying expenses
being incurred and certification of the IGCC plant prior to July
2010.  Through March 2009, APCo deferred for future recovery
preconstruction IGCC costs of $20 million.  If the West Virginia IGCC
plant is cancelled, APCo plans to seek recovery of its prudently incurred
deferred pre-construction costs.  If the plant is cancelled and if the
deferred costs are not recoverable, it would have an adverse effect on future
net income and cash flows.





In Ohio,
neither CSPCo nor OPCo are engaged in a continuous course of construction on the
IGCC plant.  However, CSPCo and OPCo continue to pursue the ultimate
construction of the IGCC plant.  In September 2008, the Ohio
Consumers’ Counsel filed a motion with the PUCO requesting all pre-construction
cost recoveries be refunded to Ohio ratepayers with interest.  CSPCo
and OPCo filed a response with the PUCO that argued the Ohio Consumers’
Counsel’s motion was without legal merit and contrary to past
precedent.  If CSPCo and OPCo were required to refund some or all of
the $24 million collected for IGCC pre-construction costs and those costs were
not recoverable in another jurisdiction in connection with the construction of
an IGCC plant, it would have an adverse effect on future net income and cash
flows.





PSO
Purchase Power Agreement





PSO and
Exelon Generation Company LLC, a subsidiary of Exelon Corporation, executed a
long-term purchase power agreement (PPA) for which an application seeking its
approval is expected to be filed with the OCC.  The PPA is for the
purchase of up to 520 MW of electric generation from the 795 MW natural
gas-fired Green Country Generating Station, located in Jenks,
Oklahoma.  The agreement is the result of PSO’s 2008 Request for
Proposals following a December 2007 OCC order that found PSO had a need for new
baseload generation by 2012.





Environmental
Matters





The
Registrant Subsidiaries are implementing a substantial capital investment
program and incurring additional operational costs to comply with new
environmental control requirements.  The sources of these requirements
include:





·
            Requirements
      under the CAA to reduce emissions of SO2,
      NOx,
      particulate matter (PM) and mercury from fossil fuel-fired power plants;
      and·
            Requirements
      under the Clean Water Act (CWA) to reduce the impacts of water intake
      structures on aquatic species at certain power
  plants.





In
addition, the Registrant Subsidiaries are engaged in litigation with respect to
certain environmental matters, have been notified of potential responsibility
for the clean-up of contaminated sites and incur costs for disposal of spent
nuclear fuel and future decommissioning of I&M’s nuclear
units.  Management is also involved in the development of possible
future requirements to reduce CO2 and other
greenhouse gases (GHG) emissions to address concerns about global climate
change.  All of these matters are discussed in the “Environmental
Matters” section of “Combined Management’s Discussion and Analysis of Registrant
Subsidiaries” in the 2008 Annual Report.





Clean
Water Act Regulation





In 2004,
the Federal EPA issued a final rule requiring all large existing power plants
with once-through cooling water systems to meet certain standards to reduce
mortality of aquatic organisms pinned against the plant’s cooling water intake
screen or entrained in the cooling water.  The standards vary based on
the water bodies from which the plants draw their cooling
water.  Management expected additional capital and operating expenses,
which the Federal EPA estimated could be $193 million for the AEP System’s
plants.  The Registrant Subsidiaries undertook site-specific studies
and have been evaluating site-specific compliance or mitigation measures that
could significantly change these cost estimates.  The following table
shows the investment amount per Registrant Subsidiary.





EstimatedComplianceInvestmentsCompany
                  (in
      millions)APCo
                  
                  $
                  21CSPCo
                  
                  
                  19I&M
                  
                  
                  118OPCo
                  
                  
                  31





In 2007,
the Federal EPA suspended the 2004 rule, except for the requirement that
permitting agencies develop best professional judgment (BPJ) controls for
existing facility cooling water intake structures that reflect the best
technology available for minimizing adverse environmental impact.  The
result is that the BPJ control standard for cooling water intake structures in
effect prior to the 2004 rule is the applicable standard for permitting agencies
pending finalization of revised rules by the Federal EPA.  The
Registrant Subsidiaries sought further review and filed for relief from the
schedules included in their permits.





In April
2009, the U.S. Supreme Court issued a decision that allows the Federal EPA the
discretion to rely on cost-benefit analysis in setting national performance
standards and in providing for cost-benefit variances from those standards as
part of the regulations.  Management cannot predict if or how the
Federal EPA will apply this decision to any revision of the regulations or what
effect it may have on similar requirements adopted by the states.





Potential
Regulation of CO2 and Other
GHG Emissions





As
discussed in the 2008 Annual Report, CO2 and other
GHG are alleged to contribute to climate change.  In April 2009, the
Federal EPA issued a proposed endangerment finding under the CAA regarding GHG
emissions from motor vehicles.  The proposed endangerment finding is
subject to public comment.  This finding could lead to regulation of
CO2
and other gases under existing laws.  Congress continues to discuss
new legislation related to the control of these emissions.  Some
policy approaches being discussed would have significant and widespread negative
consequences for the national economy and major U.S. industrial enterprises,
including the AEP System.  Because of these adverse consequences,
management believes that these more extreme policies will not ultimately be
adopted.  Even if reasonable CO2 and other
GHG emission standards are imposed, they will still require the Registrant
Subsidiaries to make material expenditures.  Management believes that
costs of complying with new CO2 and other
GHG emission standards will be treated like all other reasonable costs of
serving customers, and should be recoverable from customers as costs of doing
business including capital investments with a return on investment.





Adoption of New Accounting
Pronouncements





The FASB
issued SFAS 141R (revised “Business Combinations” 2007) improving financial
reporting about business combinations and their effects.  SFAS 141R
can affect tax positions on previous acquisitions.  The Registrant
Subsidiaries do not have any such tax positions that result in
adjustments.  The Registrant Subsidiaries adopted SFAS 141R effective
January 1, 2009.  The Registrant Subsidiaries will apply it to any
future business combinations.





The FASB
issued SFAS 160 “Noncontrolling Interest in Consolidated Financial Statements”
(SFAS 160), modifying reporting for noncontrolling interest (minority interest)
in consolidated financial statements.  The statement requires
noncontrolling interest be reported in equity and establishes a new framework
for recognizing net income or loss and comprehensive income by the controlling
interest.  The Registrant Subsidiaries adopted SFAS 160
retrospectively effective January 1, 2009.  See Note 2.





The FASB
issued SFAS 161 “Disclosures about Derivative Instruments and Hedging
Activities” (SFAS 161), enhancing disclosure requirements for derivative
instruments and hedging activities.  The standard requires that
objectives for using derivative instruments be disclosed in terms of underlying
risk and accounting designation.  This standard increased disclosure
requirements related to derivative instruments and hedging activities in future
reports.  The Registrant Subsidiaries adopted SFAS 161 effective
January 1, 2009.





The FASB
ratified EITF Issue No. 08-5 “Issuer’s Accounting for Liabilities Measured at
Fair Value with a Third-Party Credit Enhancement” (EITF 08-5) a consensus on
liabilities with third-party credit enhancements when the liability is measured
and disclosed at fair value.  The consensus treats the liability and
the credit enhancement as two units of accounting.  The Registrant
Subsidiaries adopted EITF 08-5 effective January 1, 2009.  It will be
applied prospectively with the effect of initial application included as a
change in fair value of the liability.





The FASB
ratified EITF Issue No. 08-6 “Equity Method Investment Accounting
Considerations” (EITF 08-6), a consensus on equity method investment accounting
including initial and allocated carrying values and subsequent
measurements.  The Registrant Subsidiaries prospectively adopted EITF
08-6 effective January 1, 2009 with no impact on their financial
statements.





The FASB
issued FSP SFAS 142-3 “Determination of the Useful Life of Intangible
Assets”amending
factors that should be considered in developing renewal or extension assumptions
used to determine the useful life of a recognized intangible
asset.  The Registrant Subsidiaries adopted the rule effective January
1, 2009.  The guidance is prospectively applied to intangible assets
acquired after the effective date.  The standard’s disclosure
requirements are applied prospectively to all intangible assets as of January 1,
2009.  The adoption of this standard had no impact on the
financial statements.





The FASB
issued SFAS 157-2 which delays the effective date of SFAS 157 to fiscal years
beginning after November 15, 2008 for all nonfinancial assets and nonfinancial
liabilities, except those that are recognized or disclosed at fair value in the
financial statements on a recurring basis (at least annually).  As
defined in SFAS 157, fair value is the price that would be received to sell an
asset or paid to transfer a liability in an orderly transaction between market
participants at the measurement date.  The fair value hierarchy gives
the highest priority to unadjusted quoted prices in active markets for identical
assets or liabilities and the lowest priority to unobservable
inputs.  In the absence of quoted prices for identical or similar
assets or investments in active markets, fair value is estimated using various
internal and external valuation methods including cash flow analysis and
appraisals.  The Registrant Subsidiaries adopted SFAS 157-2 effective
January 1, 2009.  The Registrant Subsidiaries will apply these
requirements to applicable fair value measurements which include new asset
retirement obligations and impairment analysis related to long-lived assets,
equity investments, goodwill and intangibles.  The Registrant
Subsidiaries did not record any fair value measurements for nonrecurring
nonfinancial assets and liabilities in the first quarter of 2009.














CONTROLS
AND PROCEDURES





During
the first quarter of 2009, management, including the principal executive officer
and principal financial officer of each of AEP, APCo, CSPCo, I&M, OPCo, PSO
and SWEPCo (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 SEC’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, 2009 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 the Registrants’ 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 2009 that materially affected, or is reasonably likely to
materially affect, the Registrants’ internal control over financial
reporting.







PART II.  OTHER INFORMATION





Item
1.     Legal
Proceedings





For a
discussion of material legal proceedings, see “Commitments, Guarantees and
Contingencies” section of Note 4incorporated herein by
reference.





Item
1A.  Risk
Factors





Our
Annual Report on Form 10-K for the year ended December 31, 2008 includes a
detailed discussion of our risk factors.  The information presented
below amends and restates in their entirety certain of those risk factors that
have been updated and should be read in conjunction with the risk factors and
information disclosed in our 2008 Annual Report on Form 10-K.





General
Risks of Our Regulated Operations





Rate recovery approved in Ohio may be
overturned on appeal.(Applies to AEP, OPCo and
CSPCo)





In March
2009, the PUCO issued an order that modified and approved CSPCo’s and OPCo’s
ESPs.  The ESPs will be in effect through 2011.  The ESP
order authorized increases to revenues during the ESP period and capped the
overall revenue increases through a phase-in of the FAC.  The ordered
rate cap increases for CSPCo are 7% in 2009, 6% in 2010 and 6% in 2011 and for
OPCo are 8% in 2009, 7% in 2010 and 8% in 2011.  The order provides a
FAC for the three-year period of the ESP.  The FAC increase will be
phased in to meet the ordered annual caps.  The order allows CSPCo and
OPCo to defer unrecovered FAC costs resulting from the annual caps/phase-in plan
and to accrue carrying charges on such deferrals at CSPCo’s and OPCo’s weighted
average cost of capital.  The deferred FAC balance at the end of the
ESP period will be recovered through a non-bypassable surcharge over the period
2012 through 2018.  In April 2009, several intervenors filed motions
requesting rehearing of issues underlying the PUCO’s authorized rate increase
and one intervenor filed a motion requesting the PUCO to direct CSPCo and OPCo
to cease collecting rates under the order.  Certain intervenors also
filed a complaint for writ of prohibition with the Ohio Supreme Court to halt
any further collection from customers of what the intervenors claim is unlawful
retroactive rate increase.  If the PUCO reverses all or part of the
rate recovery, it could have an adverse effect on future net income, cash flows
and financial condition.





Rate recovery approved in Texas may
be overturned on appeal.(Applies to AEP)





In March
2008, the PUCT issued an order approving a $20 million base rate increase based
on a return on common equity of 9.96% and an additional $20 million increase in
revenues related to the expiration of TCC’s merger credits.  In
addition, depreciation expense was decreased by $7 million and discretionary fee
revenues were increased by $3 million.  TCC estimates the order will
increase TCC’s annual pretax income by $50 million.  Various parties
appealed the PUCT decision.





In
February 2009, the Texas District Court affirmed the PUCT in most
respects.  In March 2009, various intervenors appealed the Texas
District Court decision to the Texas Court of Appeals.  Management is
unable to predict the outcome of these proceedings. If the PUCT and/or the Texas
Court of Appeals reverse all or part of the rate recovery, it could have an
adverse effect on future net income, cash flows and financial
condition.





Rate recovery approved in Oklahoma
may be overturned on appeal.  (Applies to AEP and
PSO)





In
January 2009, the OCC issued a final order approving an $81 million increase in
PSO’s non-fuel base revenues and a 10.5% return on equity.  In
February 2009, the Oklahoma Attorney General and several intervenors filed
appeals with the Oklahoma Supreme Court raising several issues.  If
the OCC and/or the Oklahoma Supreme Court reverse all or part of the rate
recovery, it could have an adverse effect on future net income, cash flows and
financial condition.





Our request for rate recovery in
Arkansas may not be approved in its entirety.  (Applies to
SWEPCo)





In
February 2009, SWEPCo filed an application with the APSC for a base rate
increase of $25 million based on a requested return on equity of
11.5%.  SWEPCo also requested a separate rider to concurrently recover
financing costs related to the Stall and Turk construction
projects.  If the APSC denies all or part of the requested rate
recovery, it could have an adverse effect on future net income, cash flows and
financial condition.





Risks
Related to Market, Economic or Financial Volatility





Downgrades in our credit ratings
could negatively affect our ability to access capital and/or to operate our
power trading businesses.(Applies to each
registrant)





Since the
bankruptcy of Enron, the credit ratings agencies have periodically reviewed our
capital structure and the quality and stability of our earnings.  Any
negative ratings actions could constrain the capital available to our industry
and could limit our access to funding for our operations.  Our
business is capital intensive, and we are dependent upon our ability to access
capital at rates and on terms we determine to be attractive.  If our
ability to access capital becomes significantly constrained, our interest costs
will likely increase and our financial condition could be harmed and future net
income could be adversely affected.





If
Moody’s or S&P were to downgrade the long-term rating of any of the
securities of the registrants, particularly below
investment grade, the borrowing costs of that registrant would increase, which
would diminish its financial results.  In addition, the registrant’s
potential pool of investors and funding sources could decrease.  In
the first quarter of 2009, Fitch downgraded the senior unsecured debt rating of
I&M to BBB with stable outlook.





Our power
trading business relies on the investment grade ratings of our individual public
utility subsidiaries’ senior unsecured long-term debt.  Most of our
counterparties require the creditworthiness of an investment grade entity to
stand behind transactions.  If those ratings were to decline below
investment grade, our ability to operate our power trading business profitably
would be diminished because we would likely have to deposit cash or cash-related
instruments which would reduce our profits.





Risks
Relating to State Restructuring





There is uncertainty related to Texas
restructuring.(Applies
to SWEPCo)





In August
2006, the PUCT adopted a rule extending the delay in implementation of customer
choice in SWEPCo’s SPP area of Texas until no sooner than January 1,
2011.  In April 2009, the Texas Senate passed a bill related to
SWEPCo’s SPP area of Texas that requires cost of service regulation until
certain stages have been completed and approved by the PUCT such that fair
competition is available to all retail customer classes.  The bill is
expected to be reviewed by the Texas House of Representatives which, if passed,
would be sent to the Governor of Texas for approval.  If the bill is
signed, management may be required to re-apply SFAS 71 for the generation
portion of SWEPCo’s Texas jurisdiction.  The initial reapplication of
SFAS 71 regulatory accounting is expected to have a material adverse effect on
net income.





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, 2009 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
                          
                          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 Programs01/01/09
      – 01/31/09
                          
                          -
                          
                          $
                          -
                          
                          -
                          
                          $
                          -02/01/09
      – 02/28/09
                          
                          35
                          (a)
                          
                          65.03
                          
                          -
                          
                          
                          -03/01/09
      – 03/31/09
                          
                          -
                          
                          
                          -
                          
                          -
                          
                          
                          -





(a)
            I&M
      repurchased 34 shares of its 4.125% cumulative preferred stock in a
      privately-negotiated transaction outside of an announced
      program.  OPCo repurchased 1 share of its 4.50% cumulative
      preferred stock in a privately-negotiated transaction outside of an
      announced program.







Item
5.  Other
Information





NONE




Item
6.  Exhibits




AEP,
APCo, CSPCo, I&M, OPCo, PSO and SWEPCo




12 –
Computation of Consolidated Ratio of Earnings to Fixed Charges.




AEP,
APCo, CSPCo, I&M, OPCo, PSO and SWEPCo




31(a) –
Certification of Chief Executive Officer Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.


31(b) –
Certification of Chief Financial Officer Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.




AEP,
APCo, CSPCo, I&M, OPCo, PSO and SWEPCo




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














APPALACHIAN
POWER COMPANY


COLUMBUS
SOUTHERN POWER COMPANY


INDIANA
MICHIGAN 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
1, 2009