UNITED
STATES
 SECURITIES
AND EXCHANGE COMMISSION
 WASHINGTON,
D.C.  20549
 FORM
10-Q
 [X]
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
 OF THE
SECURITIES EXCHANGE ACT OF 1934
 For The
Quarterly Period Ended September 30,
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 during the preceding 12 months (or for such shorter
      period that the registrant was required to submit and post such
      files).Yes
              X
              
              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 have
      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 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
      filerNon-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
      filerNon-accelerated
      filer
              X
              
              Smaller
      reporting company
 
 Indicate
      by check mark whether the registrants are shell companies (as defined in
      Rule 12b-2 of the Exchange Act).Yes
              
              
              No
              X
 
 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
                October
      28, 2009American
      Electric Power Company, Inc.
              
              477,658,465($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
 September
30, 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
      4.
              Submission
      Matters to a Vote of Security HoldersItem
      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.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.AEPSC
              
              American
      Electric Power Service Corporation, a service subsidiary providing
      management and professional services to AEP and its
      subsidiaries.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.ASU
              
              Accounting
      Standards Update issued by the Financial Accounting Standards
      Board.CAA
              
              Clean
      Air Act.CO2
              
              Carbon
      Dioxide.Cook
      Plant
              
              Donald
      C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by
      I&M.CSPCo
              
              Columbus
      Southern Power Company, an AEP electric utility
  subsidiary.CSW
              
              Central
      and South West Corporation, a subsidiary of AEP (Effective January 21,
      2003, the legal name of Central and South West Corporation was changed to
      AEP Utilities, Inc.).CSW
      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.DHLC
              
              Dolet
      Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of
      SWEPCo that is a consolidated variable interest entity.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 captive insurance company that
      is a consolidated variable interest entity.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.EPS
              
              Earnings
      Per Share.ERCOT
              
              Electric
      Reliability Council of Texas.ERISA
              
              Employee
      Retirement Income Security Act of 1974, as amended.ESP
              
              Electric
      Security Plan.
 ETT
              
              Electric
      Transmission Texas, LLC, a 50% equity interest joint venture with
      MidAmerican Energy Holdings Company formed to own and operate electric
      transmission facilities in ERCOT.FAC
              
              Fuel
      Adjustment Clause.FASB
              
              Financial
      Accounting Standards Board.Federal
      EPA
              
              United
      States Environmental Protection Agency.FERC
              
              Federal
      Energy Regulatory Commission.FSP
              
              FASB
      Staff Position.FSP
      SFAS 107-1 andAPB
      28-1
              
              FSP
      SFAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of
      Financial Instruments.”FTR
              
              Financial
      Transmission Right, a financial instrument that entitles the holder to
      receive compensation for certain congestion-related transmission charges
      that arise when the power grid is congested resulting in differences in
      locational prices.GAAP
              
              Accounting
      Principles Generally Accepted in the United States of
    America.GHG
              
              Greenhouse
      gases.I&M
              
              Indiana
      Michigan Power Company, an AEP electric utility
  subsidiary.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.JBR
              
              Jet
      Bubbling Reactor.JMG
              
              JMG
      Funding LP.KGPCo
              
              Kingsport
      Power Company, an AEP electric distribution 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.OVEC
              
              Ohio
      Valley Electric Corporation, which is 43.47% owned by
  AEP.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.REP
              
              Texas
      Retail Electric Provider.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
      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.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.VIE
              
              Variable
      Interest Entity.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 necessary generating capacity and the performance of our generating
      plants including our ability to restore I&M’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, including the Turk Plant,
      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 that could impact the continued
      operation of our plants.·
              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 the dispute with Bank of
  America).·
              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
      and demand 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
 
 Our
residential and commercial KWH sales appear to be relatively stable;
nevertheless, some segments of our service territories are experiencing
slowdowns.  We are currently monitoring the following
trends:
 
 ·
              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.  For the
      first nine months of 2009 in comparison to the first nine months of 2008,
      off-system sales volumes decreased by 58%.·
              Industrial KWH
      Sales - Industrial KWH sales for both the three months and nine
      months ended September 30, 2009 were down 17%.  Approximately
      half of the decrease in the first nine months of 2009 was due to cutbacks
      or closures by 10 of our large metals producing customers.  We
      also experienced continued significant decreases in KWH sales to customers
      in the transportation, plastics, rubber and paper manufacturing
      industries.·
              Risk of Loss of Major
      Industrial Customers - We maintain close contact with each of our
      major industrial customers individually with respect to their expected
      electric needs.  We factor our industrial customer analyses into
      our operational planning.  In September 2009, Ormet, a major
      industrial customer currently operating at a reduced load of approximately
      330 MW (Ormet operated at an approximate 500 MW load in 2008), announced
      that it will continue operations at this reduced level at least through
      the end of 2009.
 
 Regulatory
Activity
 
 Our
significant 2009 rate proceedings include:
 
 ·
              Arkansas - In
      September 2009, SWEPCo reached a rate change settlement agreement that
      provides for an $18 million increase in revenues based upon a return on
      equity of 10.25% and a decrease in annual depreciation rates of $10
      million.  The combination of these factors should contribute an
      additional $28 million in annual pretax income to SWEPCo
      annually.  The settlement agreement also includes a separate
      rider of approximately $11 million annually for the recovery of carrying
      costs, depreciation and operation and maintenance expenses on the Stall
      Unit once it is placed in service as expected in
      mid-2010.  Approval of the settlement by the APSC is expected in
      the fourth quarter of 2009.·
              Indiana - In
      March 2009, the IURC approved a modified rate settlement agreement 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.
  ·
                Ohio- In March 2009, and as amended in July 2009, the
      PUCO issued an order that modified and approved CSPCo’s and OPCo’s ESP
      filings.  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 FAC costs incurred in excess of the caps, that will be
      trued-up, subject to annual caps.  The projected revenue
      increases for CSPCo and OPCo are listed
  below:


Projected
      Revenue Increases2009
                
                2010
                
                2011(in
      millions)CSPCo
                
                $
                94
                
                
                $
                109
                
                
                $
                116OPCo
                
                
                103
                
                
                
                125
                
                
                
                153





In
addition to the revenue increases, net income will be positively affected by the
material noncash FAC deferrals from 2009 through 2011.  These
deferrals will be collected through a non-bypassable surcharge from 2012 through
2018.




·
            Oklahoma -
      In October 2009, all but two of the parties to PSO’s Capital Reliability
      Rider filing agreed to a stipulation that was filed with the OCC for PSO
      to collect no more than $30 million under the CRR on an annual basis
      beginning January 2010 until PSO’s next base rate
order.·
            Texas - In
      August 2009, SWEPCo filed a rate case with the PUCT to increase non-fuel
      base rates by approximately $75 million annually including return on
      equity of 11.5%.  The filing includes financing cost riders of
      $32 million related to construction of the Stall Unit and Turk Plant, a
      vegetation management rider of $16 million and other requested increases
      of $27 million.  The proposed filing would increase SWEPCo’s
      annual pretax income by approximately $51 million.·
            Virginia - In
      July 2009, APCo requested a base rate increase with the Virginia SCC of
      $169 million annually (later adjusted to $154 million) based on a 13.35%
      return on common equity.  The new rates will become effective,
      subject to refund, no later than December 2009.
              
              In
      August 2009, the Virginia SCC issued an order which provides for a $130
      million fuel revenue increase.  If actual fuel costs are greater
      or less than the projected fuel costs, APCo will seek appropriate
      adjustments in APCo’s next fuel factor proceeding.·
            West Virginia -
      In September 2009, the WVPSC issued an order granting a $355 million
      increase over a four-year phase-in period.  The order lowered
      annual coal cost projections by $27 million and deferred recovery of
      unrecovered ENEC deferrals related to price increases on certain
      renegotiated coal contracts.  The WVPSC indicated that it would
      review the prudency of these additional costs in the next ENEC proceeding
      and APCo will adjust rates
appropriately.





Mountaineer
Carbon Capture and Storage Project





In
January 2008, APCo and ALSTOM Power, Inc., an unrelated third party, entered
into an agreement to jointly construct a CO2 capture
demonstration facility.  APCo will also construct and own the
necessary facilities to store CO2.  APCo’s
combined estimated cost for its necessary storage facilities and its share of
the CO2 capture
demonstration facility is $74 million.  In September 2009, the capture
portion of the project was placed into service and in October 2009, APCo started
injecting CO2
successfully in underground storage.





In August
2009, APCo applied for federal grant funding for a new commercial project at the
1,300 MW Mountaineer Plant to capture and store carbon for 235 MW of generation
by 2015.  The total cost of this proposed project is currently
estimated to be $668 million.





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 owns 73% of the Turk
Plant and will operate the completed facility.





In
November 2007, March 2008 and August 2008, the APSC, LPSC and PUCT,
respectively, approved SWEPCo’s application to build the Turk
Plant.  In June 2009, the Arkansas Court of Appeals issued a unanimous
decision that, if upheld by the Arkansas Supreme Court, would reverse the APSC’s
grant of the Certificate of Environmental Compatibility and Public Need (CECPN)
permitting construction of the Turk Plant to serve Arkansas retail
customers.  In October 2009, the Arkansas Supreme Court granted the
petitions filed by SWEPCo and the APSC to review the Arkansas Court of Appeals
decision.  While the appeal is pending, SWEPCo is continuing
construction of the Turk Plant.





In
November 2008, SWEPCo received the required air permit approval from the
Arkansas Department of Environmental Quality and commenced construction at the
site.  In December 2008, certain parties filed an appeal of the air
permit approval with the Arkansas Pollution Control and Ecology Commission
(APCEC).  The APCEC decision is still pending and not expected until
2010.  These same parties have filed a petition with the Federal EPA
to review the air permit.  The petition will be acted on by December
2009, according to the terms of a recent settlement between the petitioners and
the Federal EPA.  The Turk Plant cannot be placed in service without
an air permit.





Pension
Trust Fund





Recent
recovery in our pension asset values and the IRS modification of interest
calculation rules reduced our estimated 2010 contribution for both qualified and
nonqualified pension plans to $62 million from our previously disclosed
estimated contribution of $453 million.  The present estimated
contribution for both qualified and nonqualified pension plans for 2011 is $389
million.  These estimates may vary significantly based on market
returns, changes in actuarial assumptions, management discretion to contribute
more than the minimum requirement and other factors.





Risk
Management Contracts





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 September 30,
2009, our credit exposure net of collateral was approximately $886 million of
which approximately 88% is to investment grade counterparties.  At
September 30, 2009, our exposure to financial institutions was $26 million (all
investment grade), which represents 3% of our total credit exposure net of
collateral.





Capital
Expenditures





In
October 2009, we revised our 2010 capital expenditure budget for our Utility
Operations segment from $1,846 million to $1,993 million primarily as a result
of deferring 2009 expenditures to 2010.





Fuel
Inventory





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





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.





Generation
and Marketing


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





The table
below presents our consolidated Income Before Discontinued Operations and
Extraordinary Loss by segment for the three and nine months ended September 30,
2009 and 2008.




Three
      Months Ended September 30,
            
            Nine
      Months Ended September 30,2009
            
            2008
            
            2009
            
            2008(in
      millions)Utility
      Operations
            
            $
            448
            
            
            $
            359
            
            
            $
            1,121
            
            
            $
            1,036AEP
      River Operations
            
            
            10
            
            
            
            11
            
            
            
            22
            
            
            
            21Generation
      and Marketing
            
            
            5
            
            
            
            16
            
            
            
            33
            
            
            
            43All
      Other (a)
            
            
            (17
            )
            
            
            (10
            )
            
            
            (45
            )
            
            
            133Income
      Before Discontinued Operations and Extraordinary Loss
            
            $
            446
            
            
            $
            376
            
            
            $
            1,131
            
            
            $
            1,233





(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





Third Quarter of 2009
Compared to Third Quarter of 2008





Income
Before Discontinued Operations and Extraordinary Loss in 2009 increased $70
million compared to 2008 primarily due to an increase in Utility Operations
segment earnings of $89 million.  The increase in Utility Operations
segment net income primarily relates to rate increases in our Indiana, Ohio,
Oklahoma and Virginia service territories partially offset by lower retail sales
volumes as well as lower off-system sales margins due to lower sales volumes and
lower market prices.





Average
basic shares outstanding increased to 477 million in 2009 from 402 million in
2008 primarily due to the April 2009 issuance of 69 million shares of AEP common
stock.  Actual shares outstanding were 477 million as of September 30,
2009.





Nine Months Ended September
30, 2009 Compared to Nine Months Ended September 30, 2008





Income
Before Discontinued Operations and Extraordinary Loss in 2009 decreased $102
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.  For our Utility Operations segment, Income Before Discontinued
Operations and Extraordinary Loss increased $85 million primarily due to rate
increases in our Indiana, Ohio, Oklahoma and Virginia service territories
partially offset by lower retail sales volumes as well as lower off-system sales
margins due to lower sales volumes and lower market prices.





Average
basic shares outstanding increased to 452 million in 2009 from 402 million in
2008 primarily due to the April 2009 issuance of 69 million shares of AEP common
stock.  Actual shares outstanding were 477 million as of September 30,
2009.


Utility
Operations





Our
Utility Operations segment primarily includes 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 Ended
              September
      30,
            
            
            Nine
      Months Ended
              September
      30,2009
            
            
            2008
            
            
            2009
            
            
            2008(in
      millions)Revenues
            
            $
            3,389
            
            
            $
            3,968
            
            
            $
            9,712
            
            
            $
            10,575Fuel
      and Purchased Power
            
            
            1,145
            
            
            
            1,841
            
            
            
            3,337
            
            
            
            4,428Gross
      Margin
            
            
            2,244
            
            
            
            2,127
            
            
            
            6,375
            
            
            
            6,147Depreciation
      and Amortization
            
            
            412
            
            
            
            379
            
            
            
            1,173
            
            
            
            1,099Other
      Operating Expenses
            
            
            988
            
            
            
            1,034
            
            
            
            2,975
            
            
            
            3,001Operating
      Income
            
            
            844
            
            
            
            714
            
            
            
            2,227
            
            
            
            2,047Other
      Income, Net
            
            
            42
            
            
            
            47
            
            
            
            97
            
            
            
            138Interest
      Expense
            
            
            232
            
            
            
            224
            
            
            
            679
            
            
            
            650Income
      Tax Expense
            
            
            206
            
            
            
            178
            
            
            
            524
            
            
            
            499Income
      Before Discontinued Operations and Extraordinary Loss
            
            $
            448
            
            
            $
            359
            
            
            $
            1,121
            
            
            $
            1,036





Summary
of KWH Energy Sales


For
Utility Operations


For
the Three and Nine Months Ended September 30, 2009 and 2008





Three
      Months Ended
              September
      30,
            
            Nine
      Months Ended
              September
      30,Energy/Delivery Summary
            2009
            
            2008
            
            2009
            
            2008(in
      millions of KWH)Retail:Residential
            15,967
            
            
            15,965
            
            44,731
            
            44,986Commercial
            13,569
            
            
            13,731
            
            37,773
            
            38,099Industrial
            13,641
            
            
            16,409
            
            40,564
            
            48,915Miscellaneous
            800
            
            
            846
            
            2,289
            
            2,381Total
      Retail (a)
            43,977
            
            
            46,951
            
            125,357
            
            134,381Wholesale
            8,289
            
            
            13,165
            
            22,233
            
            35,904Total
      KWHs
            52,266
            
            
            60,116
            
            147,590
            
            170,285





(a)
            Energy
      delivered to customers served by AEP’s Texas Wires
    Companies.


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 and
nine months ended September 30, 2009 and 2008 were as follows:


Summary
of Heating and Cooling Degree Days for Utility Operations


For
the Three and Nine Months Ended September 30, 2009 and 2008





Three
      Months Ended
              September
      30,
            
            Nine
      Months Ended
              September
      30,2009
            
            2008
            
            2009
            
            2008(in
      degree days)Weather
      SummaryEastern RegionActual
      – Heating (a)
            6
            
            
            -
            
            2,062
            
            1,966Normal
      – Heating (b)
            7
            
            
            7
            
            1,969
            
            1,950Actual
      – Cooling (c)
            509
            
            
            659
            
            813
            
            936Normal
      – Cooling (b)
            703
            
            
            687
            
            993
            
            969Western Region
      (d)Actual
      – Heating (a)
            -
            
            
            -
            
            902
            
            981Normal
      – Heating (b)
            2
            
            
            2
            
            941
            
            967Actual
      – Cooling (c)
            1,170
            
            
            1,251
            
            1,878
            
            1,955Normal
      – Cooling (b)
            1,401
            
            
            1,402
            
            2,080
            
            2,074





(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.





Third Quarter of 2009
Compared to Third Quarter of 2008





Reconciliation
of Third Quarter of 2008 to Third Quarter of 2009


Income
from Utility Operations Before Discontinued Operations and Extraordinary
Loss


(in
millions)





Third
      Quarter of 2008
            
            
            
            
            $
            359Changes
      in Gross Margin:Retail
      Margins
            
            
            281Off-system
      Sales
            
            
            (226
            )Transmission
      Revenues
            
            
            10Other
      Revenues
            
            
            52Total
      Change in Gross Margin
            
            
            
            
            
            
            117Total
      Expenses and Other:Other
      Operation and Maintenance
            
            
            52Gain
      on Sales of Assets, Net
            
            
            (2
            )Depreciation
      and Amortization
            
            
            (33
            )Taxes
      Other Than Income Taxes
            
            
            (4
            )Interest
      and Investment Income
            
            
            (8
            )Carrying
      Costs Income
            
            
            (9
            )Allowance
      for Equity Funds Used During Construction
            
            
            12Interest
      Expense
            
            
            (8
            )Total
      Expenses and Other
            
            
            
            
            
            
            -Income
      Tax Expense
            
            
            
            
            
            
            (28
            )Third
      Quarter of 2009
            
            
            
            
            
            $
            448





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 $281 million primarily due to the
    following:·
            An
      $87 million increase related to the PUCO’s approval of our Ohio ESPs, a
      $43 million increase related to base rates and recovery of E&R costs
      in Virginia and construction financing costs in West Virginia, a $22
      million increase in base rates in Oklahoma and a $7 million net rate
      increase for I&M.·
            A
      $151 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 deferral and recovery of fuel
      and related costs during the ESP period.  See “Ohio Electric
      Security Plan Filings” section of Note 3.·
            A
      $90 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.These
      increases were partially offset by:·
            A
      $61 million decrease in margins from industrial sales due to reduced
      operating levels and suspended operations by certain large industrial
      customers in our service territories.·
            A
      $42 million decrease in usage primarily due to a 23% decrease in cooling
      degree days in our eastern region.·
            A
      $19 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 $226 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 and
      marketing margins.·
            Transmission
      Revenues increased $10 million primarily due to increased rates in the
      ERCOT and SPP regions.


·
            Other
      Revenues increased $52 million primarily due to Cook Plant accidental
      outage insurance policy proceeds of $46 million.  Of these
      insurance proceeds, $19 million were used to reduce customer
      bills.  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.





Total
Expenses and Other and Income Taxes changed between years as
follows:





·
            Other
      Operation and Maintenance expenses decreased $52 million primarily due to
      the following:·
            A
      $37 million decrease in storm restoration expenses.·
            A
      $23 million decrease in plant operating and maintenance
      expenses.·
            A
      $10 million decrease in transmission expense including lower forestry
      expenses, RTO fees and reliability expenses.·
            An
      $8 million decrease related to the establishment of a regulatory asset in
      Virginia for the deferral of transmission costs.·
            A
      $7 million decrease in customer service expenses.These
      decreases were partially offset by:·
            A
      $30 million increase in administrative and general expenses, primarily
      employee medical expenses.·
            An
      $11 million increase in distribution reliability and other
      expenses.·
            Depreciation
      and Amortization increased $33 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
      and Investment Income decreased $8 million primarily due to the 2008
      favorable effect of interest income related to federal income tax refunds
      filed with the IRS.·
            Carrying
      Costs Income decreased $9 million primarily due to the completion of
      reliability deferrals in Virginia in December 2008 and the decrease of
      environmental deferrals in Virginia in 2009.·
            Allowance
      for Equity Funds Used During Construction increased $12 million as a
      result of construction at SWEPCo’s Turk Plant and Stall Unit and the
      reapplication of “Regulated Operations” accounting guidance for the
      generation portion of SWEPCo’s Texas retail jurisdiction effective April
      2009.  See “Texas Rate Matters – Texas Restructuring – SPP”
      section of Note 3.·
            Interest
      Expense increased $8 million primarily due to increased long-term
      debt.·
            Income
      Tax Expense increased $28 million primarily due to an increase in pretax
      income, partially offset by state income taxes and changes in certain
      book/tax differences accounted for on a flow-through
  basis.





Nine Months Ended September
30, 2009 Compared to Nine Months Ended September 30, 2008





Reconciliation
of Nine Months Ended September 30, 2008 to Nine Months Ended September 30,
2009


Income
from Utility Operations Before Discontinued Operations and Extraordinary
Loss


(in
millions)





Nine
      Months Ended September 30, 2008
            
            
            
            
            $
            1,036Changes
      in Gross Margin:Retail
      Margins
            
            
            570Off-system
      Sales
            
            
            (517
            )Transmission
      Revenues
            
            
            22Other
      Revenues
            
            
            153Total
      Change in Gross Margin
            
            
            
            
            
            
            228Total
      Expenses and Other:Other
      Operation and Maintenance
            
            
            31Gain
      on Sales of Assets, Net
            
            
            (1
            )Depreciation
      and Amortization
            
            
            (74
            )Taxes
      Other Than Income Taxes
            
            
            (4
            )Interest
      and Investment Income
            
            
            (37
            )Carrying
      Costs Income
            
            
            (31
            )Allowance
      for Equity Funds Used During Construction
            
            
            27Interest
      Expense
            
            
            (29
            )Total
      Expenses and Other
            
            
            
            
            
            
            (118
            )Income
      Tax Expense
            
            
            
            
            
            
            (25
            )Nine
      Months Ended September 30, 2009
            
            
            
            
            
            $
            1,121





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 $570 million primarily due to the
    following:·
            A
      $183 million increase related to the PUCO’s approval of our Ohio ESPs, a
      $147 million increase related to base rates and recovery of E&R costs
      in Virginia and construction financing costs in West Virginia, a $63
      million increase in base rates in Oklahoma and a $32 million net rate
      increase for I&M.·
            A
      $207 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
      $199 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 deferral and 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
      $150 million decrease in margins from industrial sales due to reduced
      operating levels and suspended operations by certain large industrial
      customers in our service territories.·
            A
      $59 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.·
            A
      $34 million decrease in usage primarily due to a 13% decrease in cooling
      degree days in our eastern region.·
            A
      $29 million decrease related to favorable coal contract amendments in
      2008.·
            Margins
      from Off-system Sales decreased $517 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 and
      marketing margins.·
            Transmission
      Revenues increased $22 million primarily due to increased rates in the
      ERCOT and SPP regions.·
            Other
      Revenues increased $153 million primarily due to Cook Plant accidental
      outage insurance policy proceeds of $145 million.  Of these
      insurance proceeds, $59 million were used to reduce customer
      bills.  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.





Total
Expenses and Other and Income Taxes changed between years as
follows:





·
            Other
      Operation and Maintenance expenses decreased $31 million primarily due to
      the following:·
            An
      $80 million decrease in plant outage and other plant operating and
      maintenance expenses.·
            A
      $55 million decrease in tree trimming, reliability and other transmission
      and distribution expenses.·
            The
      write-off in the first quarter of 2008 of $10 million of unrecoverable
      pre-construction costs for PSO’s cancelled Red Rock Generating
      Facility.These
      decreases were partially offset by:·
            The
      deferral of $72 million of Oklahoma ice storm costs in 2008 resulting from
      an OCC order approving recovery of January and December 2007 ice storm
      expenses.·
            A
      $37 million increase in administrative and general expenses, primarily
      employee medical expenses.·
            Depreciation
      and Amortization increased $74 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
      and Investment Income decreased $37 million primarily due to the 2008
      favorable effect of interest income related to federal income tax refunds
      filed with the IRS and the second quarter 2009 recognition of
      other-than-temporary losses related to equity investments held by
      EIS.·
            Carrying
      Costs Income decreased $31 million primarily due to the completion of
      reliability deferrals in Virginia in December 2008 and the decrease of
      environmental deferrals in Virginia in 2009.·
            Allowance
      for Equity Funds Used During Construction increased $27 million as a
      result of construction at SWEPCo’s Turk Plant and Stall Unit and the
      reapplication of “Regulated Operations” accounting guidance for the
      generation portion of SWEPCo’s Texas retail jurisdiction effective April
      2009.  See “Texas Rate Matters – Texas Restructuring – SPP”
      section of Note 3.·
            Interest
      Expense increased $29 million primarily due to increased long-term
      debt.·
            Income
      Tax Expense increased $25 million primarily due to an increase in pretax
      book income.





AEP River
Operations





Third Quarter of 2009
Compared to Third Quarter of 2008





Income
Before Discontinued Operations and Extraordinary Loss from our AEP River
Operations segment decreased from $11 million in 2008 to $10 million in 2009
primarily due to lower revenues as a result of a weak import
market.





Nine Months Ended September
30, 2009 Compared to Nine Months Ended September 30, 2008





Income
Before Discontinued Operations and Extraordinary Loss from our AEP River
Operations segment increased from $21 million in 2008 to $22 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 as
a result of a weak import market.





Generation and
Marketing





Third Quarter of 2009
Compared to Third Quarter of 2008





Income
Before Discontinued Operations and Extraordinary Loss from our Generation and
Marketing segment decreased from $16 million in 2008 to $5 million in 2009
primarily due to lower gross margins at the Oklaunion Plant as a result of lower
power prices in ERCOT.


Nine Months Ended September
30, 2009 Compared to Nine Months Ended September 30, 2008





Income
Before Discontinued Operations and Extraordinary Loss from our Generation and
Marketing segment decreased from $43 million in 2008 to $33 million in 2009
primarily due to lower gross margins at the Oklaunion Plant as a result of lower
power prices in ERCOT.





All
Other





Third Quarter of 2009
Compared to Third Quarter of 2008





Income
Before Discontinued Operations and Extraordinary Loss from All Other decreased
from a loss of $10 million in 2008 to a loss of $17 million in
2009.





Nine Months Ended September
30, 2009 Compared to Nine Months Ended September 30, 2008





Income
Before Discontinued Operations and Extraordinary Loss from All Other decreased
from income of $133 million in 2008 to a loss of $45 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.  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 increased $16 million in the third quarter of 2009 compared to the
third quarter of 2008 primarily due to an increase in pretax book income,
partially offset by state income taxes and changes in certain book/tax
differences accounted for on a flow-through basis.





Income
Tax Expense decreased $73 million in the nine-month period ended September 30,
2009 compared to the nine-month period ended September 30, 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
    CapitalizationSeptember
      30, 2009
            
            December
      31, 2008($
      in millions)Long-term
      Debt, including amounts due within one year
            
            $
            17,253
            
            56.2%
            
            $
            15,983
            
            55.6%Short-term
      Debt
            
            
            352
            
            1.1
            
            
            1,976
            
            6.9Total
      Debt
            
            
            17,605
            
            57.3
            
            
            17,959
            
            62.5Preferred
      Stock of Subsidiaries
            
            
            61
            
            0.2
            
            
            61
            
            0.2AEP
      Common Equity
            
            
            13,064
            
            42.5
            
            
            10,693
            
            37.2Noncontrolling
      Interests
            
            
            -
            
            -
            
            
            17
            
            0.1Total
      Debt and Equity Capitalization
            
            $
            30,730
            
            100.0%
            
            $
            28,730
            
            100.0%





Our ratio
of debt-to-total capital decreased from 62.5% in 2008 to 57.3% in 2009 primarily
due to the issuance of 69 million new common shares and the application of the
proceeds to reduce debt.





Liquidity





Liquidity,
or access to cash, is an important factor in determining our financial
stability.  We believe we have adequate liquidity under our existing
credit facilities.  At September 30, 2009, we had $3.6 billion in
aggregate credit facility commitments to support our
operations.  Additional liquidity is available from cash from
operations and a sale of receivables agreement.  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





The
financial markets were volatile at both a global and domestic level during the
last quarter of 2008 and first half of 2009.  We issued $1.9 billion
of long-term debt in the first nine months of 2009 and $1.64 billion (net
proceeds) of AEP common stock in April 2009.  These actions help to
support our investment grade ratings and maintain financial
flexibility.





Approximately
$1.7 billion of our $17 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.  In September 2009, OPCo issued $500 million of 5.375%
senior unsecured notes which may be used to pay at maturity some of its
outstanding debt due in 2010.  We believe that our projected cash
flows from operating activities are sufficient to support our ongoing
operations.





Credit
Facilities





We manage
our liquidity by maintaining adequate external financing
commitments.  At September 30, 2009, our available liquidity was
approximately $3.6 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
      2011Total
            
            
            3,581Cash
      and Cash Equivalents
            
            
            877Total
      Liquidity Sources
            
            
            4,458Less: AEP
      Commercial Paper Outstanding
            
            
            347Letters
      of Credit Issued
            
            
            470Net
      Available Liquidity
            
            $
            3,641





(a)
            Net
      of contractually terminated Lehman Brothers Bank’s commitment amount of
      $69 million.





As of
September 30, 2009, we had credit facilities totaling $3.6 billion, of which two
$1.5 billion credit facilities support our commercial paper
program.  The two $1.5 billion credit facilities allow for the
issuance of up to $750 million as letters of credit under each credit
facility.  We also have a $627 million credit facility which can be
utilized for letters of credit or draws.  The $3.6 billion in combined
credit facilities were reduced by Lehman Brothers Bank’s commitment amount of
$69 million following its parent company’s bankruptcy.





We use
our commercial paper program to meet the short-term borrowing needs of our
subsidiaries.  The program is used to fund both a Utility Money Pool,
which funds the utility subsidiaries, and a Nonutility Money Pool, which funds
the majority of the nonutility subsidiaries.  In addition, the program
also funds, as direct borrowers, the short-term debt requirements of other
subsidiaries that are not participants in either money pool for regulatory or
operational reasons.  In 2009, we repaid the $2 billion borrowed under
the credit facilities during 2008 primarily with proceeds from our equity
offering.  The maximum amount of commercial paper outstanding during
2009 was $614 million.  The weighted-average interest rate for our
commercial paper during 2009 was 0.63%.





Sales
of Receivables





In July
2009, we renewed and increased our sale of receivables agreement.  The
sale of receivables agreement provides a commitment of $750 million from bank
conduits to purchase receivables.  This agreement will expire in July
2010.  The previous sale of receivables agreement provided a
commitment of $700 million.




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 September 30, 2009, this
contractually-defined percentage was 53.4%.  Nonperformance under
these covenants could result in an event of default under these credit
agreements.  At September 30, 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 in a majority of our non-exchange
traded commodity contracts which would permit the lenders and counterparties to
declare the outstanding amounts payable.  However, a default under our
non-exchange traded commodity contracts does not cause an event of default under
our revolving credit agreements.





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 September 30, 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 398 consecutive quarters.  The Board of Directors
declared a quarterly dividend of $0.41per share in October
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 or financial condition or limit any
dividend payments in the foreseeable future.





Credit
Ratings





Our
credit ratings as of September 30, 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.·
            Affirmed
      the Baa2 rating for TCC and downgraded TNC to Baa2.  Both
      companies were also placed on stable outlook.·
            Affirmed
      the stable rating outlooks for CSPCo, I&M, KPCo and
    PSO.·
            Changed
      the rating outlook for APCo from negative to stable.·
            Downgraded
      SWEPCo to Baa3 and placed it on stable outlook.·
            Downgraded
      OPCo to Baa1 and placed it on stable
outlook.





In 2009,
Fitch:





·
            Affirmed
      its stable rating outlook for I&M, PSO and TNC.·
            Changed
      its rating outlook for SWEPCo and TCC from stable to
    negative.·
            Downgraded
      APCo’s senior unsecured rating to BBB and placed it on stable
      outlook.





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.


Nine
      Months EndedSeptember
      30,2009
            
            2008(in
      millions)Cash
      and Cash Equivalents at Beginning of Period
            
            $
            411
            
            
            $
            178Net
      Cash Flows from Operating Activities
            
            
            1,871
            
            
            
            2,059Net
      Cash Flows Used for Investing Activities
            
            
            (2,097
            )
            
            
            (3,061
            )Net
      Cash Flows from Financing Activities
            
            
            692
            
            
            
            1,162Net
      Increase in Cash and Cash Equivalents
            
            
            466
            
            
            
            160Cash
      and Cash Equivalents at End of Period
            
            $
            877
            
            
            $
            338





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





Nine
      Months EndedSeptember
      30,2009
            
            2008(in
      millions)Net
      Income
            
            $
            1,126
            
            
            $
            1,234Less:  Discontinued
      Operations, Net of Tax
            
            
            -
            
            
            
            (1
            )Income
      Before Discontinued Operations
            
            
            1,126
            
            
            
            1,233Depreciation
      and Amortization
            
            
            1,200
            
            
            
            1,123Other
            
            
            (455
            )
            
            
            (297
            )Net
      Cash Flows from Operating Activities
            
            $
            1,871
            
            
            $
            2,059





Net Cash
Flows from Operating Activities decreased in 2009 primarily due to a decline in
net income and an increase in fuel inventory which should be recoverable through
future fuel rates as the inventory is consumed.





Net Cash
Flows from Operating Activities were $1.9 billion in 2009 consisting primarily
of Net Income of $1.1 billion and $1.2 billion 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 include the
negative impact on cash of an increase in coal inventory reflecting decreased
customer demand for electricity as the result of the economic slowdown and
unfavorable weather conditions and an increase in under-recovered fuel primarily
in Ohio and West Virginia.




Net Cash
Flows from Operating Activities were $2.1 billion in 2008 consisting primarily
of Income Before Discontinued Operations of $1.2 billion and $1.1 billion 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 include an increase in under-recovered fuel reflecting higher
coal and natural gas prices.





Investing
Activities


Nine
      Months EndedSeptember
      30,2009
            
            2008(in
      millions)Construction
      Expenditures
            
            $
            (2,123
            )
            
            $
            (2,576
            )Purchases/Sales
      of Investment Securities, Net
            
            
            (49
            )
            
            
            (474
            )Acquisitions
      of Nuclear Fuel
            
            
            (153
            )
            
            
            (99
            )Acquisitions
      of Assets
            
            
            (70
            )
            
            
            (97
            )Proceeds
      from Sales of Assets
            
            
            258
            
            
            
            83Other
            
            
            40
            
            
            
            102Net
      Cash Flows Used for Investing Activities
            
            $
            (2,097
            )
            
            $
            (3,061
            )





Net Cash
Flows Used for Investing Activities were $2.1 billion in 2009 and $3.1 billion
in 2008 and primarily relate to Construction Expenditures for our new
generation, environmental and distribution investment plan.  Proceeds
from Sales of Assets in 2009 includes $104 million relating to the sale of a
portion of Turk Plant to joint owners as planned and $95 million for sales
of transmission assets in Texas to ETT based upon the original partner
agreement.





In our
normal course of business, we purchase and sell investment securities including
variable rate demand notes with cash available for short-term investments and
purchase and sell securities within our nuclear trusts and protected cell
captive insurance company.





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


Nine
      Months EndedSeptember
      30,2009
            
            2008(in
      millions)Issuance
      of Common Stock, Net
            
            $
            1,706
            
            
            $
            106Issuance/Retirement
      of Debt, Net
            
            
            (371
            )
            
            
            1,621Dividends
      Paid on Common Stock
            
            
            (564
            )
            
            
            (500
            )Other
            
            
            (79
            )
            
            
            (65
            )Net
      Cash Flows from Financing Activities
            
            $
            692
            
            
            $
            1,162





Net Cash
Flows from Financing Activities in 2009 were $692 million.  Issuance
of Common Stock, Net of $1.7 billion is comprised of our issuance of 69 million
shares of common stock with net proceeds of $1.64 billion and additional shares
through our dividend reinvestment, employee savings and incentive
programs.  Our net debt retirements were $371 million. These
retirements included a repayment of $2 billion outstanding under our credit
facilities primarily from the proceeds of our common stock issuance and
issuances of $1.6 billion of senior unsecured and debt notes and $327 million of
pollution control bonds.  See Note 11 – Financing Activities for a
complete discussion of long-term debt issuances and retirements.





Net Cash
Flows from Financing Activities in 2008 were $1.2 billion.  Our net
debt issuances were $1.6 billion.  These issuances included net
increases of $1.3 billion in senior unsecured notes, $642 million of short-term
debt and $315 million of junior subordinated debentures.  These net
increases in outstanding debt were partially offset by a net reacquisition of
$370 million of pollution control bonds and retirements of $53 million of
mortgage notes and $125 million of securitization bonds.





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:





September
      30,
            
            December
      31,2009
            
            2008(in
      millions)AEP
      Credit Accounts Receivable Purchase Commitments
            
            $
            530
            
            
            $
            650Rockport
      Plant Unit 2 Future Minimum Lease Payments
            
            
            1,996
            
            
            
            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, which was amended by a rehearing entry in July
2009, that modified and approved CSPCo’s and OPCo’s ESPs that established
standard service offer rates.  The ESPs will be in effect through
2011.  The ESP order authorized revenue increases during the ESP
period and capped the overall revenue increases for CSPCo to 7% in 2009, 6% in
2010 and 6% in 2011 and for OPCo to 8% in 2009, 7% in 2010 and 8% in
2011.  CSPCo and OPCo implemented rates for the April 2009 billing
cycle.  In its July 2009 rehearing entry, the PUCO required CSPCo and
OPCo to reduce rates implemented in April 2009 by $22 million and $27 million,
respectively, on an annualized basis.  CSPCo and OPCo are collecting
the 2009 annualized revenue increase over the last nine months of
2009.





The order
provides a FAC for the three-year period of the ESP.  The FAC increase
will be phased in to avoid having the resultant rate increases exceed 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 three-year ESP period will be recovered through a non-bypassable
surcharge over the period 2012 through 2018.  The FAC deferrals at
September 30, 2009 were $36 million and $238 million for CSPCo and OPCo,
respectively, inclusive of carrying charges at the weighted average cost of
capital.





In August
2009, an intervenor filed for rehearing requesting, among other things, that the
PUCO order CSPCo and OPCo to cease and desist from charging ESP rates, to revert
to the rate stabilization plan rates and to compel a refund, including interest,
of the amounts collected by CSPCo and OPCo.  CSPCo and OPCo filed a
response stating the rates being charged by CSPCo and OPCo have been authorized
by the PUCO and there was no basis for precluding CSPCo and OPCo from continuing
to charge those rates.  In September 2009, certain intervenors filed
appeals of the March 2009 order and the July 2009 rehearing entry with the
Supreme Court of Ohio.  One of the intervenors, the Ohio Consumers’
Counsel, has asked the court to stay, pending the outcome of its appeal, a
portion of the authorized ESP rates which the Ohio Consumers’ Counsel
characterizes as being retroactive.  In October 2009, the Supreme
Court of Ohio denied the Ohio Consumers' Counsel's request for a stay and
granted motions to dismiss both appeals.




In
September 2009, CSPCo and OPCo filed their initial quarterly FAC filing with the
PUCO.  An order approving the FAC 2009 filings will not be issued
until a financial audit and prudency review is performed by independent third
parties and reviewed by the PUCO.





In
October 2009, the PUCO convened a workshop to begin to determine the methodology
for the Significantly Excessive Earnings Test (SEET).  The SEET
requires the PUCO to determine, following the end of each year of the ESP, if
rate adjustments included in the ESP resulted in significantly excessive
earnings.  This will be determined by measuring whether the utility’s
earned return on common equity is significantly in excess of the return on
common equity that was earned during the same period by publicly traded
companies, including utilities, which have comparable business and financial
risk.  In the March 2009 ESP order, the PUCO determined that
off-system sales margins and FAC deferral phase-in credits should be excluded
from the SEET methodology.  However, the July 2009 PUCO rehearing
entry deferred those issues to the SEET workshop.  If the rate
adjustments, in the aggregate, result in significantly excessive earnings, the
excess amount would 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 workshop is completed, the PUCO issues SEET guidelines, a
SEET filing is made by CSPCo and OPCo in 2010 and the PUCO issues an order
thereon. The SEET workshop will also determine whether CSPCo’s and OPCo’s
earnings will be measured on an individual company basis or on a combined
CSPCo/OPCo basis.





In
October 2009, an intervenor filed a complaint for writ of prohibition with the
Supreme Court of Ohio requesting the Court to prohibit CSPCo and OPCo from
billing and collecting any ESP rate increases that the PUCO authorized as the
intervenor believes the PUCO's statutory jurisdiction over CSPCo's and OPCo's
ESP application ended on December 28, 2008, which was 150 days after the filing
of the ESP applications.  CSPCo and OPCo plan on filing a response in
opposition to the complaint for writ of prohibition.





Management
is unable to predict the outcome of the various ongoing proceedings and
litigation discussed above including the SEET, the FAC filing review and the
various appeals to the Supreme Court of Ohio relating to the ESP
order.  If these proceedings result in adverse rulings, it could have
an adverse effect on future net income and cash flows.





Cook Plant Unit 1 Fire and
Shutdown





In
September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine
vibrations, 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.  I&M is repairing
Unit 1 to resume operations as early as the fourth quarter of 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 September 30, 2009, we recorded $122 million in
Prepayments and Other Current Assets on our Condensed Consolidated Balance
Sheets representing recoverable amounts under the property insurance
policy.  Through September 30, 2009, I&M received partial payments
of $72 million 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 2009, I&M
recorded $145 million in revenues and applied $59 million of the accidental
outage insurance proceeds to reduce customer bills.




NEIL is
reviewing claims made under the insurance policies to ensure that claims
associated with the outage are covered by the policies.  The treatment
of property damage costs, replacement power costs and insurance proceeds will be
the subject of future regulatory proceedings in Indiana and
Michigan.  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 or if any future regulatory
proceedings are adverse, 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 flows were adversely impacted for 2008, 2007
and 2006 by $75 million, $238 million and $69 million,
respectively.  Municipal customers and other intervenors appealed the
PUCT true-up orders seeking to further reduce TCC’s true-up
recoveries.  TCC also 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.





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.  The favorable
commercial unreasonableness judgment entered by the District Court was not
reversed.  In June 2008, the Texas Court of Appeals denied
intervenors’ motions for rehearing.  In August 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 which concluded in June
2009.





TNC
received its final true-up order in May 2005 that resulted in refunds via a CTC
which have been completed.  TNC appealed its final true-up order,
which 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
possibly 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





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
            
            $
            321
            (d)
            $
            199
            (d)
            Gas
            
            Combined-cycle
            
            580
            
            2013SWEPCo
            
            Stall
            
            Louisiana
            
            
            386
            
            
            364
            
            Gas
            
            Combined-cycle
            
            500
            
            2010SWEPCo
            
            Turk
            (e)
            Arkansas
            
            
            1,633
            (e)
            
            622
            (f)
            Coal
            
            Ultra-supercritical
            
            600
            (e)
            2012APCo
            
            Mountaineer
            (g)
            West
      Virginia
            
            
            
            (g)
            
            
            
            Coal
            
            IGCC
            
            629
            
            
            (g)CSPCo/OPCo
            
            Great
      Bend
            (g)
            Ohio
            
            
            
            (g)
            
            
            
            Coal
            
            IGCC
            
            629
            
            
            (g)





(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)
            During
      2009, AEGCo suspended construction of the Dresden Plant.  As a
      result, AEGCo has stopped recording AFUDC and will resume recording AFUDC
      once construction is resumed.(e)
            SWEPCo
      owns approximately 73%, or 440 MW, totaling $1.2 billion in capital
      investment.  See “Turk Plant” section below.(f)
            Amount
      represents SWEPCo’s CWIP balance only.(g)
            Construction
      of IGCC plants is subject to regulatory
  approvals.





Turk
Plant





In
November 2007, the APSC granted approval for SWEPCo to build the Turk Plant in
Arkansas by issuing a Certificate of Environmental Compatibility and Public Need
(CECPN).  Certain intervenors appealed the APSC’s decision to grant
the CECPN to the Arkansas Court of Appeals.  In January 2009, the APSC
granted additional CECPNs allowing SWEPCo to construct Turk-related transmission
facilities.  Intervenors also appealed these CECPN orders to the
Arkansas Court of Appeals.





In June
2009, the Arkansas Court of Appeals issued a unanimous decision that, if upheld
by the Arkansas Supreme Court, would reverse the APSC’s grant of the CECPN
permitting construction of the Turk Plant to serve Arkansas retail
customers.  The decision was based upon the Arkansas Court of Appeals’
interpretation of the statute that governs the certification process and its
conclusion that the APSC did not fully comply with that process.  The
Arkansas Court of Appeals concluded that SWEPCo’s need for base load capacity,
the construction and financing of the Turk generating plant and the proposed
transmission facilities’ construction and location should all have been
considered by the APSC in a single docket instead of separate
dockets.  In October 2009, the Arkansas Supreme Court granted the
petitions filed by SWEPCo and the APSC to review the Arkansas Court of Appeals’
decision.  While the appeal is pending, SWEPCo is continuing
construction of the Turk Plant.





If the
decision of the Court of Appeals is not reversed by the Supreme Court of
Arkansas, SWEPCo and the other joint owners of the Turk Plant will evaluate
their options.  Depending on the time taken by the Arkansas Supreme
Court to consider the case and the reasoning of the Arkansas Supreme Court when
it acts on SWEPCo’s and the APSC’s petitions, the construction schedule and/or
the cost could be adversely affected.  Should the appeals by the APSC
and SWEPCo be unsuccessful, additional proceedings or alternative contractual
ownership and operational responsibilities could be required.





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 and related transmission costs, (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 as
being unlawful.  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. If the cost cap restrictions are upheld and construction or CO2 emission
costs exceed the restrictions or if the intervenor appeal is successful, it
could have an adverse effect on net income, cash flows and possibly financial
condition.




A request
to stop pre-construction activities at the site was filed in Federal District
Court by certain 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, which was granted in March 2009.





In
November 2008, SWEPCo received the required air permit approval from the
Arkansas Department of Environmental Quality and commenced construction at the
site.  In December 2008, certain parties filed an appeal of the air
permit approval 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 the appeal of the Turk Plant’s air permit is
heard.  In June 2009, hearings on the air permit appeal were held at
the APCEC.  A decision is still pending and not expected until
2010.  These same parties have filed a petition with the Federal EPA
to review the air permit.  The petition will be acted on by December
2009 according to the terms of a recent settlement between the petitioners and
the Federal EPA.  The Turk Plant cannot be placed into service without
an air permit.  In August 2009, these same parties filed a petition
with the APCEC to halt construction of the Turk Plant.  In September
2009, the APCEC voted to allow construction of the Turk Plant to continue and
rejected the request for a stay.  If the air permit were to be
remanded or ultimately revoked, construction of the Turk Plant would be
suspended or cancelled.





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 an inadvertent impact on approximately 2.5
acres of wetlands at the Turk Plant construction site prior to the receipt of
the permit.  The U.S. Army Corps of Engineers directed SWEPCo to cease
further work impacting the wetland areas.  Construction has continued
on other areas outside of the proposed Army Corps of Engineers permitted areas
of the Turk Plant pending the Army Corps of Engineers’ review.  SWEPCo
has entered into a Consent Agreement and Final Order with the Federal EPA to
resolve liability for the inadvertent impact and agreed to pay a civil penalty
of approximately $29 thousand.





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.  To date, the
report’s effect is only advisory, but if legislation is passed as a result of
the findings in the Commission’s report, it could impact SWEPCo’s ability to
complete construction on schedule in 2012 and on budget.





If the
Turk Plant cannot be completed and placed in service, SWEPCo would seek approval
to recover its prudently incurred capitalized construction costs including any
cancellation fees and a return on unrecovered balances through rates in all of
its jurisdictions.  As of September 30, 2009, and excluding costs
attributable to its joint owners, SWEPCo has capitalized approximately $646
million of expenditures (including AFUDC and capitalized interest and related
transmission costs of $24 million) and has contractual construction commitments
for an additional $515 million (including related transmission costs of $1
million).  As of September 30, 2009, if the plant had been cancelled,
SWEPCo would have incurred cancellation fees of $136 million (including
related transmission cancellation fees of $1 million).





Management
believes that SWEPCo’s planning, certification and construction of the Turk
Plant to date have been in material compliance with all applicable laws and
regulations, except for the inadvertent wetlands intrusion discussed
above.  Further, management expects that SWEPCo will ultimately be
able to complete construction of the Turk Plant and related transmission
facilities and place those facilities in service.  However, if for any
reason SWEPCo is unable to complete the Turk Plant construction and place the
Turk Plant in service, it would adversely impact net income, cash flows and
possibly financial condition unless the resultant losses can be fully recovered,
with a return on unrecovered balances, through rates in all of its
jurisdictions.




PSO
Purchase Power Agreement





As a
result of the 2008 Request for Proposals following a December 2007 OCC order
that found PSO had a need for new base load generation by 2012, PSO and Exelon
Generation Company LLC, a subsidiary of Exelon Corporation, executed a long-term
purchase power agreement (PPA).  The PPA is for the annual purchase of
approximately 520 MW of electric generation from the 795 MW natural gas-fired
generating plant in Jenks, Oklahoma for a term of approximately ten years
beginning in June 2012.  In May 2009, an application seeking approval
was filed with the OCC.  In July 2009, OCC staff, the Independent
Evaluator and the Oklahoma Industrial Energy Consumers filed responsive
testimony in support of PSO’s proposed PPA with Exelon.  In August
2009, a settlement agreement was filed with the OCC.  In September
2009, the OCC approved the settlement agreement including the recovery of these
purchased power costs through a separate base load purchased power
rider.





The American Recovery and
Reinvestment Act of 2009





The
American Recovery and Reinvestment Act of 2009 was signed into law by the
President in February 2009.  It provided for several new grant
programs and expanded tax credits and an extension of the 50% bonus depreciation
provision enacted in the Economic Stimulus Act of 2008.  The enacted
provisions are not expected to have a material impact on net income or financial
condition.  However, we forecast the bonus depreciation provision
could provide a significant favorable cash flow benefit of approximately $300
million in 2009.





In August
2009, AEP applied with the U.S. Department of Energy (DOE) for $566 million in
federal stimulus money for gridSMART, clean coal technology and hydro generation
projects.  If granted, the funds will provide capital and reduce the
amount of money sought from customers.  Management is unable to
predict the likelihood of the DOE granting the federal stimulus money to AEP or
the timing of the DOE’s decision.  The requested federal stimulus
money is proposed for the following projects:





Company
            
            Proposed
      Project
            
            Federal
      Stimulus
              Funds
      Requested(in
      millions)APCo
            
            Carbon
      Capture and Sequestration Demonstration Project at the Mountaineer
      Plant
            
            $
            334APCo
            
            Hydro Generation
      Modernization Project in London, W.V.
            
            
            2CSPCo
            
            gridSMART
            
            
            75TCC
            
            gridSMART
            
            
            123
            (a)TNC
            
            gridSMART
            
            
            32
            (a)ETT
            
            gridSMART
            
            
            12





(a)
            In
      October 2009, these applications were not selected by the DOE for
      award.





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
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 and mercury from fossil fuel-fired power plants;
      and·
            Requirements
      under the Clean Water Act 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
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





In June
2009, the U.S. House of Representatives passed the American Clean Energy and
Security Act (ACES).  ACES is a comprehensive energy and climate
change bill that includes a number of provisions that would directly affect our
business.  ACES contains a combined energy efficiency and renewable
electricity standard beginning at 6% in 2012 and increasing to 20% by 2020 of
our retail sales.  The proposed legislation would also create a carbon
capture and sequestration (CCS) program funded through rates to accelerate the
development of this technology as well as significant funding through bonus
allowances provided to CCS and establishes GHG emission standards for new fossil
fuel-fired electric generating plants.  ACES creates an economy-wide
cap and trade program for large sources of GHG emissions that would reduce
emissions by 17% in 2020 and just over 80% by 2050 from 2005
levels.  A portion of the allowances under the cap and trade program
would be allocated to retail electric and gas utilities, certain
energy-intensive industries, small refiners and state
governments.  Some allowances would be auctioned.  Bonus
allowances would be available to encourage energy efficiency, renewable energy
and carbon sequestration projects.  Consideration of climate
legislation has now moved to the Senate and the Senate released draft cap and
trade legislation on September 30.  Until legislation is final, we are
unable to predict its impact on net income, cash flows and financial
condition.


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.  In September 2009, the Federal EPA issued
a final mandatory GHG reporting rule covering a broad range of facilities
emitting in excess of 25,000 tons of GHG emissions per year.  The
Federal EPA has also issued proposed light duty vehicle GHG emissions standards
for model years 2012-2016, and a proposed scheme to streamline and phase in
regulation of stationary source GHG emissions through the NSR’s prevention of
significant deterioration and CAA’s Title V permitting programs.  The
Federal EPA stated its intent to finalize the vehicle standards and permitting
rule in conjunction with or following a final endangerment finding, and is
reconsidering whether to include GHG emissions in a number of stationary source
standards, including standards that apply to electric utility
units.  Some of the policy approaches being discussed by the Federal
EPA 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 and that reasonable and comprehensive
legislative action is preferable.  Even if reasonable CO2 and other
GHG emission standards are imposed, the standards could require significant
increases in capital expenditures and operating costs which would impact the
ultimate retirement of older, less-efficient, coal-fired
units.  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.





Proposed Health Care
Legislation





The U.S.
Congress, supported by President Obama, is debating health care reform that
could have a significant impact on our benefits and costs.  The
discussion centers around universal coverage, revenue sources to keep it deficit
neutral and changes to Medicare that could significantly impact our employees
and retirees and the benefits and costs of our benefit plans.  Until
legislation is final, the impact is impossible to predict.





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 “Business Combinations” improving financial reporting about
business combinations and their effects and FSP SFAS 141(R)-1.  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, including the FSP, effective January 1, 2009.  We will
apply it to any future business combinations.  SFAS 141R is included
in the “Business Combinations” accounting guidance.





The FASB
issued SFAS 160 “Noncontrolling Interests 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.  SFAS 160 is included in the “Consolidation” accounting
guidance.





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.  SFAS 161 is included in the “Derivatives and Hedging”
accounting guidance.




The FASB
issued SFAS 165 “Subsequent Events” (SFAS 165),incorporating guidance
on subsequent events into authoritative accounting literature and clarifying the
time following the balance sheet date which management reviewed for events and
transactions that may require disclosure in the financial
statements.  We adopted this standard effective second quarter of
2009.  The standard increased our disclosure by requiring disclosure
of the date through which subsequent events have been reviewed.  The
standard did not change our procedures for reviewing subsequent
events.  SFAS 165 is included in the “Subsequent Events” accounting
guidance.





The FASB
issued SFAS 168 “The FASB Accounting Standards CodificationTM and
the Hierarchy of Generally Accepted Accounting Principles” (SFAS 168)
establishing the FASB Accounting Standards CodificationTM as
the authoritative source of accounting principles for preparation of financial
statements and reporting in conformity with GAAP by nongovernmental
entities.  We adopted SFAS 168 effective third quarter of
2009.  It required an update of all references to authoritative
accounting literature.  SFAS 168 is included in the “Generally
Accepted Accounting Principles” accounting guidance.





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.  With the adoption of FSP SFAS 107-1
and APB 28-1, it is applied to the fair value of long-term debt.  The
application of this standard had an immaterial effect on the fair value of debt
outstanding.  EITF 08-5 is included in the “Fair Value Measurements
and Disclosures” accounting guidance.





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.  EITF 08-6 is
included in the “Investments – Equity Method and Joint Ventures” accounting
guidance.





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.  EITF
03-6-1 is included in the “Earnings Per Share” accounting guidance.





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.  We adopted the standard
effective second quarter of 2009.  This standard increased the
disclosure requirements related to financial instruments.  FSP SFAS
107-1 and APB 28-1 is included in the “Financial Instruments” accounting
guidance.





The FASB
issued FSP SFAS 115-2 and SFAS 124-2 “Recognition and Presentation of
Other-Than-Temporary Impairments”, 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.  We adopted the standard effective
second quarter of 2009 with no impact on our financial statements and increased
disclosure requirements related to financial instruments.  FSP SFAS
115-2 and SFAS 124-2 is included in the “Investments – Debt and Equity
Securities” accounting guidance.





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.  SFAS 142-3 is included in the “Intangibles – Goodwill and
Other” accounting guidance.





The FASB
issued SFAS 157-2 “Effective Date of FASB Statement No. 157” (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
2009.  SFAS 157-2 is included in the “Fair Value Measurements and
Disclosures” accounting guidance.





The FASB
issued 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), 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.  We adopted the standard effective second quarter of
2009.  This standard had no impact on our financial statements but
increased our disclosure requirements.  FSP SFAS 157-4 is included in
the “Fair Value Measurements and Disclosures” accounting guidance.





Pronouncements
Effective in the Future





The FASB
issued ASU 2009-05 “Measuring Liabilities at Fair Value” (ASU 2009-05) updating
the “Fair Value Measurement and Disclosures” accounting guidance.  The
guidance specifies the valuation techniques that should be used to fair value a
liability in the absence of a quoted price in an active market.  The
new accounting guidance is effective for interim and annual periods beginning
after the issuance date.  Although we have not completed our analysis,
we do not expect this update to have a material impact on our financial
statements.  We will adopt ASU 2009-05 effective fourth quarter of
2009.





The FASB
issued ASU 2009-12 “Investments in Certain Entities That Calculate Net Asset
Value per Share (or its Equivalent)” (ASU 2009-12) updating the “Fair Value
Measurement and Disclosures” accounting guidance for the fair value measurement
of investments in certain entities that calculate net asset value per share (or
its equivalent).  The guidance permits a reporting entity to measure
the fair value of an investment within its scope on the basis of the net asset
value per share of the investment (or its equivalent).  The new
accounting guidance is effective for interim and annual periods ending after
December 15, 2009.  Although we have not completed our analysis, we do
not expect this update to have a material impact on our financial
statements.  We will adopt ASU 2009-12 effective fourth quarter of
2009.





The FASB
issued ASU 2009-13 “Multiple-Deliverable Revenue Arrangements” (ASU 2009-13)
updating the “Revenue Recognition” accounting guidance by providing criteria for
separating consideration in multiple-deliverable arrangements.  It
establishes a selling price hierarchy for determining the price of a deliverable
and expands the disclosures related to a vendor’s multiple-deliverable revenue
arrangements.  The new accounting guidance is effective prospectively
for arrangements entered into or materially modified in years beginning after
June 15, 2010.  Although we have not completed our analysis, we do not
expect this update to have a material impact on our financial
statements.  We will adopt ASU 2009-13 effective January 1,
2011.


The FASB
issued SFAS 166 “Accounting for Transfers of Financial Assets” (SFAS 166)
clarifying when a transfer of a financial asset should be recorded as a
sale.  The standard defines participating interest to establish
specific conditions for a sale of a portion of a financial
asset.  This standard must be applied to all transfers after the
effective date.  SFAS 166 is effective for interim and annual
reporting in fiscal years beginning after November 15, 2009.  Early
adoption is prohibited.  We continue to review the impact of this
standard.  We will adopt SFAS 166 effective January 1,
2010.  SFAS 166 is included in the “Transfers and Servicing”
accounting guidance.





The FASB
issued SFAS 167 “Amendments to FASB Interpretation No. 46(R)” (SFAS 167)
amending the analysis an entity must perform to determine if it has a
controlling interest in a variable interest entity (VIE).  This new
guidance provides that the primary beneficiary of a VIE must have
both:





·
            The
      power to direct the activities of the VIE that most significantly impact
      the VIE’s economic performance.·
            The
      obligation to absorb the losses of the entity that could potentially be
      significant to the VIE or the right to receive benefits from the entity
      that could potentially be significant to the
  VIE.





The
standard also requires separate presentation on the face of the statement of
financial position for assets which can only be used to settle obligations of a
consolidated VIE and liabilities for which creditors do not have recourse to the
general credit of the primary beneficiary.  SFAS 167 is effective for
interim and annual reporting in fiscal years beginning after November 15,
2009.  Early adoption is prohibited.  We continue to review
the impact of the changes in the consolidation guidance on our financial
statements.  This standard will increase our disclosure requirements
related to transactions with VIEs and may change the presentation of
consolidated VIE’s assets and liabilities on our Condensed Consolidated Balance
Sheets.  We will adopt SFAS 167 effective January 1,
2010.  SFAS 167 is included in the “Consolidation” accounting
guidance.





The FASB
issued FSP SFAS 132R-1 “Employers’ Disclosures about Postretirement Benefit Plan
Assets” (FSP SFAS 132R-1)providing
additional disclosure guidance for pension and OPEB plan assets.  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.  We expect 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 132R-1 is included in the “Compensation – Retirement
Benefits” accounting guidance.





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 Executive Vice President -
Generation, 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
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 September 30, 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


September
30, 2009


(in
millions)





Utility
      Operations
            
            
            Generation
      and
              Marketing
            
            
            All
      Other
            
            
            Sub-Total
              MTM
      Risk Management Contracts
            
            
            Cash
      Flow Hedge Contracts
            
            
            Collateral
              Deposits
            
            
            TotalCurrent
      Assets
            
            $
            252
            
            
            $
            36
            
            
            $
            12
            
            
            $
            300
            
            
            $
            15
            
            
            $
            (15
            )
            
            $
            300Noncurrent
      Assets
            
            
            178
            
            
            
            210
            
            
            
            3
            
            
            
            391
            
            
            
            2
            
            
            
            (14
            )
            
            
            379Total
      Assets
            
            
            430
            
            
            
            246
            
            
            
            15
            
            
            
            691
            
            
            
            17
            
            
            
            (29
            )
            
            
            679Current
      Liabilities
            
            
            126
            
            
            
            23
            
            
            
            17
            
            
            
            166
            
            
            
            18
            
            
            
            (48
            )
            
            
            136Noncurrent
      Liabilities
            
            
            112
            
            
            
            79
            
            
            
            1
            
            
            
            192
            
            
            
            10
            
            
            
            (52
            )
            
            
            150Total
      Liabilities
            
            
            238
            
            
            
            102
            
            
            
            18
            
            
            
            358
            
            
            
            28
            
            
            
            (100
            )
            
            
            286Total MTMDerivative Contract Net Assets
      (Liabilities)
            
            $
            192
            
            
            $
            144
            
            
            $
            (3
            )
            
            $
            333
            
            
            $
            (11
            )
            
            $
            71
            
            
            $
            393





MTM
Risk Management Contract Net Assets (Liabilities)


Nine
Months Ended September 30, 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
            
            
            (77
            )
            
            
            (5
            )
            
            
            4
            
            
            
            (78
            )Fair
      Value of New Contracts at Inception When Entered During the Period
      (a)
            
            
            14
            
            
            
            61
            
            
            
            -
            
            
            
            75Net
      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)
            
            
            9
            
            
            
            (16
            )
            
            
            -
            
            
            
            (7
            )Changes
      in Fair Value Allocated to Regulated Jurisdictions
(c)
            
            
            71
            
            
            
            -
            
            
            
            -
            
            
            
            71Total
      MTM Risk Management Contract Net Assets (Liabilities)
      at September 30, 2009
            
            $
            192
            
            
            $
            144
            
            
            $
            (3
            )
            
            
            333Cash
      Flow HedgeContracts
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            (11
            )Collateral
      Deposits
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            71Total
      MTM Derivative Contract Net Assets at September 30, 2009
            
            
            
            
            
            
            
            
            
            
            
            
            
            $
            393





(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 or
(require) cash:


Maturity
and Source of Fair Value of MTM


Risk
Management Contract Net Assets (Liabilities)


September
30, 2009


(in
millions)





Remainder
              2009
            
            2010
            
            2011
            
            2012
            
            2013
            
            After
              2013
      (f)
            
            TotalUtility
      OperationsLevel
      1 (a)
            $
            (1)
            
            $
            -
            
            $
            -
            
            $
            -
            
            $
            -
            
            $
            -
            
            $
            (1)Level
      2 (b)
            
            24
            
            
            43
            
            
            18
            
            
            3
            
            
            8
            
            
            1
            
            
            97Level
      3 (c)
            
            19
            
            
            39
            
            
            6
            
            
            3
            
            
            -
            
            
            -
            
            
            67Total
            
            42
            
            
            82
            
            
            24
            
            
            6
            
            
            8
            
            
            1
            
            
            163Generation
      and MarketingLevel
      1 (a)
            
            (2)
            
            
            1
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            (1)Level
      2 (b)
            
            1
            
            
            14
            
            
            17
            
            
            16
            
            
            19
            
            
            41
            
            
            108Level
      3 (c)
            
            -
            
            
            1
            
            
            1
            
            
            2
            
            
            3
            
            
            30
            
            
            37Total
            
            (1)
            
            
            16
            
            
            18
            
            
            18
            
            
            22
            
            
            71
            
            
            144All
      OtherLevel
      1 (a)
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Level
      2 (b)
            
            (1)
            
            
            (4)
            
            
            2
            
            
            -
            
            
            -
            
            
            -
            
            
            (3)Level
      3 (c)
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Total
            
            (1)
            
            
            (4)
            
            
            2
            
            
            -
            
            
            -
            
            
            -
            
            
            (3)TotalLevel
      1 (a)
            
            (3)
            
            
            1
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            (2)Level
      2 (b)
            
            24
            
            
            53
            
            
            37
            
            
            19
            
            
            27
            
            
            42
            
            
            202Level
      3 (c) (d)
            
            19
            
            
            40
            
            
            7
            
            
            5
            
            
            3
            
            
            30
            
            
            104Total
            
            40
            
            
            94
            
            
            44
            
            
            24
            
            
            30
            
            
            72
            
            
            304Dedesignated
      Risk Management Contracts (e)
            
            4
            
            
            14
            
            
            6
            
            
            5
            
            
            -
            
            
            -
            
            
            29Total
      MTM Risk Management Contract Net Assets
            $
            44
            
            $
            108
            
            $
            50
            
            $
            29
            
            $
            30
            
            $
            72
            
            $
            333




(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 normal under the accounting guidance for “Derivatives
      and Hedging.”  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 $72 million in individual periods beyond
      2013.  $51 million of this mark-to-market value is in periods
      2014-2018, $14 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 September 30,
2009, our credit exposure net of collateral to sub investment grade
counterparties was approximately 11.5%, 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 September 30, 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
            
            $
            775
            
            
            $
            69
            
            
            $
            706
            
            
            
            2
            
            
            $
            228Split
      Rating
            
            
            7
            
            
            
            -
            
            
            
            7
            
            
            
            2
            
            
            
            7Noninvestment
      Grade
            
            
            4
            
            
            
            2
            
            
            
            2
            
            
            
            2
            
            
            
            1No
      External Ratings:Internal
      Investment Grade
            
            
            75
            
            
            
            4
            
            
            
            71
            
            
            
            4
            
            
            
            56Internal
      Noninvestment Grade
            
            
            112
            
            
            
            12
            
            
            
            100
            
            
            
            3
            
            
            
            86Total
      as of September 30, 2009
            
            $
            973
            
            
            $
            87
            
            
            $
            886
            
            
            
            13
            
            
            $
            378Total
      as of December 31, 2008
            
            $
            793
            
            
            $
            29
            
            
            $
            764
            
            
            
            9
            
            
            $
            284





See Note
8 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 September 30, 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





Nine
      Months Ended
            
            
            Twelve
      Months EndedSeptember
      30, 2009
            
            
            December
      31, 2008(in
      millions)
            
            
            (in
      millions)End
            
            
            High
            
            
            Average
            
            
            Low
            
            
            End
            
            
            High
            
            
            Average
            
            
            Low$
            1
            
            
            $
            2
            
            
            $
            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 back-testing 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 four 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.  As calculated on debt
outstanding as of September 30, 2009, the estimated EaR on our debt portfolio
for the following twelve months was $12 million.





AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY
COMPANIES


CONDENSED
CONSOLIDATED STATEMENTS OF INCOME


For
the Three and Nine Months Ended September 30, 2009 and 2008


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


(Unaudited)


Three
      Months Ended
            
            
            Nine
      Months EndedREVENUES
            
            2009
            
            
            2008
            
            
            2009
            
            
            2008Utility
      Operations
            
            $
            3,364
            
            
            $
            4,108
            
            
            $
            9,666
            
            
            $
            10,318Other
      Revenues
            
            
            183
            
            
            
            83
            
            
            
            541
            
            
            
            886TOTAL
      REVENUES
            
            
            3,547
            
            
            
            4,191
            
            
            
            10,207
            
            
            
            11,204EXPENSESFuel
      and Other Consumables Used for Electric Generation
            
            
            931
            
            
            
            1,480
            
            
            
            2,624
            
            
            
            3,513Purchased
      Electricity for Resale
            
            
            247
            
            
            
            394
            
            
            
            800
            
            
            
            1,023Other
      Operation and Maintenance
            
            
            899
            
            
            
            1,010
            
            
            
            2,724
            
            
            
            2,870Gain
      on Sales of Assets, Net
            
            
            (2
            )
            
            
            (6
            )
            
            
            (13
            )
            
            
            (14
            )Asset
      Impairments and Other Related Charges
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            (255
            )Depreciation
      and Amortization
            
            
            421
            
            
            
            387
            
            
            
            1,200
            
            
            
            1,123Taxes
      Other Than Income Taxes
            
            
            193
            
            
            
            189
            
            
            
            582
            
            
            
            578TOTAL
      EXPENSES
            
            
            2,689
            
            
            
            3,454
            
            
            
            7,917
            
            
            
            8,838OPERATING
      INCOME
            
            
            858
            
            
            
            737
            
            
            
            2,290
            
            
            
            2,366Other
      Income (Expense):Interest
      and Investment Income
            
            
            5
            
            
            
            14
            
            
            
            5
            
            
            
            45Carrying
      Costs Income
            
            
            12
            
            
            
            21
            
            
            
            33
            
            
            
            64Allowance
      for Equity Funds Used During Construction
            
            
            23
            
            
            
            11
            
            
            
            59
            
            
            
            32Interest
      Expense
            
            
            (248
            )
            
            
            (216
            )
            
            
            (726
            )
            
            
            (669
            )INCOME
      BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS
            
            
            650
            
            
            
            567
            
            
            
            1,661
            
            
            
            1,838Income
      Tax Expense
            
            
            208
            
            
            
            192
            
            
            
            535
            
            
            
            608Equity
      Earnings of Unconsolidated Subsidiaries
            
            
            4
            
            
            
            1
            
            
            
            5
            
            
            
            3INCOME
      BEFORE DISCONTINUED OPERATIONS AND EXTRAORDINARY LOSS
            
            
            446
            
            
            
            376
            
            
            
            1,131
            
            
            
            1,233DISCONTINUED
      OPERATIONS, NET OF TAX
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            1INCOME
      BEFORE EXTRAORDINARY LOSS
            
            
            446
            
            
            
            376
            
            
            
            1,131
            
            
            
            1,234EXTRAORDINARY
      LOSS, NET OF TAX
            
            
            -
            
            
            
            -
            
            
            
            (5
            )
            
            
            -NET
      INCOME
            
            
            446
            
            
            
            376
            
            
            
            1,126
            
            
            
            1,234Less:  Net
      Income Attributable to Noncontrolling Interests
            
            
            2
            
            
            
            1
            
            
            
            5
            
            
            
            4NET
      INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS
            
            
            444
            
            
            
            375
            
            
            
            1,121
            
            
            
            1,230Less:  Preferred
      Stock Dividend Requirements of Subsidiaries
            
            
            1
            
            
            
            1
            
            
            
            2
            
            
            
            2EARNINGS
      ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
            
            $
            443
            
            
            $
            374
            
            
            $
            1,119
            
            
            $
            1,228WEIGHTED
      AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING
            
            
            476,948,143
            
            
            
            402,286,779
            
            
            
            452,255,119
            
            
            
            401,535,661BASIC
      EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON
      SHAREHOLDERSIncome
      Before Discontinued Operations and Extraordinary Loss
            
            $
            0.93
            
            
            $
            0.93
            
            
            $
            2.48
            
            
            $
            3.06Discontinued
      Operations, Net of Tax
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Income
      Before Extraordinary Loss
            
            
            0.93
            
            
            
            0.93
            
            
            
            2.48
            
            
            
            3.06Extraordinary
      Loss, Net of Tax
            
            
            -
            
            
            
            -
            
            
            
            (0.01
            )
            
            
            -TOTAL
      BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
      SHAREHOLDERS
            
            $
            0.93
            
            
            $
            0.93
            
            
            $
            2.47
            
            
            $
            3.06WEIGHTED
      AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING
            
            
            477,111,144
            
            
            
            403,910,309
            
            
            
            452,495,494
            
            
            
            402,925,534DILUTED
      EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON
      SHAREHOLDERSIncome
      Before Discontinued Operations and Extraordinary Loss
            
            $
            0.93
            
            
            $
            0.93
            
            
            $
            2.48
            
            
            $
            3.05Discontinued
      Operations, Net of Tax
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Income
      Before Extraordinary Loss
            
            
            0.93
            
            
            
            0.93
            
            
            
            2.48
            
            
            
            3.05Extraordinary
      Loss, Net of Tax
            
            
            -
            
            
            
            -
            
            
            
            (0.01
            )
            
            
            -TOTAL
      DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
      SHAREHOLDERS
            
            $
            0.93
            
            
            $
            0.93
            
            
            $
            2.47
            
            
            $
            3.05CASH
      DIVIDENDS PAID PER SHARE
            
            $
            0.41
            
            
            $
            0.41
            
            
            $
            1.23
            
            
            $
            1.23See
      Condensed Notes to Condensed consolidated Financial
    Statements








AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES


CONDENSED
CONSOLIDATED BALANCE SHEETS


ASSETS


September
30, 2009 and December 31, 2008


(in
millions)


(Unaudited)





2009
            
            
            2008CURRENT
      ASSETSCash
      and Cash Equivalents
            
            $
            877
            
            
            $
            411Other
      Temporary Investments
            
            
            259
            
            
            
            327Accounts
      Receivable:Customers
            
            
            600
            
            
            
            569Accrued
      Unbilled Revenues
            
            
            402
            
            
            
            449Miscellaneous
            
            
            63
            
            
            
            90Allowance
      for Uncollectible Accounts
            
            
            (36
            )
            
            
            (42
            )Total
      Accounts Receivable
            
            
            1,029
            
            
            
            1,066Fuel
            
            
            998
            
            
            
            634Materials
      and Supplies
            
            
            569
            
            
            
            539Risk
      Management Assets
            
            
            300
            
            
            
            256Regulatory
      Asset for Under-Recovered Fuel Costs
            
            
            103
            
            
            
            284Margin
      Deposits
            
            
            101
            
            
            
            86Prepayments
      and Other Current Assets
            
            
            243
            
            
            
            172TOTAL
      CURRENT ASSETS
            
            
            4,479
            
            
            
            3,775PROPERTY,
      PLANT AND EQUIPMENTElectric:Production
            
            
            22,552
            
            
            
            21,242Transmission
            
            
            8,198
            
            
            
            7,938Distribution
            
            
            13,336
            
            
            
            12,816Other
      Property, Plant and Equipment (including coal mining and nuclear
      fuel)
            
            
            3,821
            
            
            
            3,741Construction
      Work in Progress
            
            
            3,251
            
            
            
            3,973Total
      Property, Plant and Equipment
            
            
            51,158
            
            
            
            49,710Accumulated
      Depreciation and Amortization
            
            
            17,337
            
            
            
            16,723TOTAL
      PROPERTY, PLANT AND EQUIPMENT - NET
            
            
            33,821
            
            
            
            32,987OTHER
      NONCURRENT ASSETSRegulatory
      Assets
            
            
            4,360
            
            
            
            3,783Securitized
      Transition Assets
            
            
            1,940
            
            
            
            2,040Spent
      Nuclear Fuel and Decommissioning Trusts
            
            
            1,364
            
            
            
            1,260Goodwill
            
            
            76
            
            
            
            76Long-term
      Risk Management Assets
            
            
            379
            
            
            
            355Deferred
      Charges and Other Noncurrent Assets
            
            
            774
            
            
            
            879TOTAL
      OTHER NONCURRENT ASSETS
            
            
            8,893
            
            
            
            8,393TOTAL
      ASSETS
            
            $
            47,193
            
            
            $
            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


September
30, 2009 and December 31, 2008


(Unaudited)





2009
            
            2008CURRENT
      LIABILITIES
            
            (in
      millions)Accounts
      Payable
            
            $
            1,004
            
            $
            1,297Short-term
      Debt
            
            
            352
            
            
            1,976Long-term
      Debt Due Within One Year
            
            
            1,540
            
            
            447Risk
      Management Liabilities
            
            
            136
            
            
            134Customer
      Deposits
            
            
            265
            
            
            254Accrued
      Taxes
            
            
            470
            
            
            634Accrued
      Interest
            
            
            232
            
            
            270Regulatory
      Liability for Over-Recovered Fuel Costs
            
            
            107
            
            
            66Other
      Current Liabilities
            
            
            881
            
            
            1,219TOTAL
      CURRENT LIABILITIES
            
            
            4,987
            
            
            6,297NONCURRENT
      LIABILITIESLong-term
      Debt
            
            
            15,713
            
            
            15,536Long-term
      Risk Management Liabilities
            
            
            150
            
            
            170Deferred
      Income Taxes
            
            
            5,824
            
            
            5,128Regulatory
      Liabilities and Deferred Investment Tax Credits
            
            
            2,901
            
            
            2,789Asset
      Retirement Obligations
            
            
            1,197
            
            
            1,154Employee
      Benefits and Pension Obligations
            
            
            2,168
            
            
            2,184Deferred
      Credits and Other Noncurrent Liabilities
            
            
            1,128
            
            
            1,126TOTAL
      NONCURRENT LIABILITIES
            
            
            29,081
            
            
            28,087TOTAL
      LIABILITIES
            
            
            34,068
            
            
            34,384Cumulative
      Preferred Stock Not Subject to Mandatory Redemption
            
            
            61
            
            
            61Commitments
      and Contingencies (Note 4)EQUITYCommon
      Stock – Par Value – $6.50 Per Share:2009
            
            2008Shares
      Authorized
            600,000,000
            
            600,000,000Shares
      Issued
            497,649,344
            
            426,321,248(20,249,992
      shares were held in treasury at September 30, 2009 and December 31,
      2008)
            
            
            3,235
            
            
            2,771Paid-in
      Capital
            
            
            5,826
            
            
            4,527Retained
      Earnings
            
            
            4,407
            
            
            3,847Accumulated
      Other Comprehensive Income (Loss)
            
            
            (404)
            
            
            (452)TOTAL
      AEP COMMON SHAREHOLDERS’ EQUITY
            
            
            13,064
            
            
            10,693Noncontrolling
      Interests
            
            
            -
            
            
            17TOTAL
      EQUITY
            
            
            13,064
            
            
            10,710TOTAL
      LIABILITIES AND EQUITY
            
            $
            47,193
            
            $
            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 Nine Months Ended September 30, 2009 and 2008


(in
millions)


(Unaudited)





2009
            
            
            2008OPERATING
      ACTIVITIESNet
      Income
            
            $
            1,126
            
            
            $
            1,234Less:  Discontinued
      Operations, Net of Tax
            
            
            -
            
            
            
            (1
            )Income
      Before Discontinued Operations
            
            
            1,126
            
            
            
            1,233Adjustments
      to Reconcile Net Income to Net Cash Flows from Operating
      Activities:Depreciation
      and Amortization
            
            
            1,200
            
            
            
            1,123Deferred
      Income Taxes
            
            
            662
            
            
            
            397Extraordinary
      Loss, Net of Tax
            
            
            5
            
            
            
            -Carrying
      Costs Income
            
            
            (33
            )
            
            
            (64
            )Allowance
      for Equity Funds Used During Construction
            
            
            (59
            )
            
            
            (32
            )Mark-to-Market
      of Risk Management Contracts
            
            
            (99
            )
            
            
            14Amortization
      of Nuclear Fuel
            
            
            41
            
            
            
            72Deferred
      Property Taxes
            
            
            144
            
            
            
            136Fuel
      Over/Under-Recovery, Net
            
            
            (377
            )
            
            
            (284
            )Gain
      on Sales of Assets, Net
            
            
            (13
            )
            
            
            (14
            )Change
      in Other Noncurrent Assets
            
            
            26
            
            
            
            (160
            )Change
      in Other Noncurrent Liabilities
            
            
            164
            
            
            
            (74
            )Changes
      in Certain Components of Working Capital:Accounts
      Receivable, Net
            
            
            68
            
            
            
            (69
            )Fuel,
      Materials and Supplies
            
            
            (394
            )
            
            
            (49
            )Margin
      Deposits
            
            
            (15
            )
            
            
            (20
            )Accounts
      Payable
            
            
            (29
            )
            
            
            77Customer
      Deposits
            
            
            11
            
            
            
            (14
            )Accrued
      Taxes, Net
            
            
            (165
            )
            
            
            (40
            )Accrued
      Interest
            
            
            (38
            )
            
            
            (5
            )Other
      Current Assets
            
            
            (71
            )
            
            
            (43
            )Other
      Current Liabilities
            
            
            (283
            )
            
            
            (125
            )Net
      Cash Flows from Operating Activities
            
            
            1,871
            
            
            
            2,059INVESTING
      ACTIVITIESConstruction
      Expenditures
            
            
            (2,123
            )
            
            
            (2,576
            )Change
      in Other Temporary Investments, Net
            
            
            72
            
            
            
            106Purchases
      of Investment Securities
            
            
            (573
            )
            
            
            (1,386
            )Sales
      of Investment Securities
            
            
            524
            
            
            
            912Acquisitions
      of Nuclear Fuel
            
            
            (153
            )
            
            
            (99
            )Acquisitions
      of Assets
            
            
            (70
            )
            
            
            (97
            )Proceeds
      from Sales of Assets
            
            
            258
            
            
            
            83Other
      Investing Activities
            
            
            (32
            )
            
            
            (4
            )Net
      Cash Flows Used for Investing Activities
            
            
            (2,097
            )
            
            
            (3,061
            )FINANCING
      ACTIVITIESIssuance
      of Common Stock, Net
            
            
            1,706
            
            
            
            106Issuance
      of Long-term Debt
            
            
            1,912
            
            
            
            2,561Change
      in Short-term Debt, Net
            
            
            (1,624
            )
            
            
            642Retirement
      of Long-term Debt
            
            
            (659
            )
            
            
            (1,582
            )Principal
      Payments for Capital Lease Obligations
            
            
            (62
            )
            
            
            (76
            )Dividends
      Paid on Common Stock
            
            
            (564
            )
            
            
            (500
            )Dividends
      Paid on Cumulative Preferred Stock
            
            
            (2
            )
            
            
            (2
            )Other
      Financing Activities
            
            
            (15
            )
            
            
            13Net
      Cash Flows from Financing Activities
            
            
            692
            
            
            
            1,162Net
      Increase in Cash and Cash Equivalents
            
            
            466
            
            
            
            160Cash
      and Cash Equivalents at Beginning of Period
            
            
            411
            
            
            
            178Cash
      and Cash Equivalents at End of Period
            
            $
            877
            
            
            $
            338SUPPLEMENTARY
      INFORMATIONCash
      Paid for Interest, Net of Capitalized Amounts
            
            $
            744
            
            
            $
            657Net
      Cash Paid (Received) for Income Taxes
            
            
            (74
            )
            
            
            126Noncash
      Acquisitions Under Capital Leases
            
            
            53
            
            
            
            47Noncash
      Acquisition of Land/Mineral Rights
            
            
            -
            
            
            
            42Construction
      Expenditures Included in Accounts Payable at September 30,
            
            
            229
            
            
            
            373Acquisition
      of Nuclear Fuel Included in Accounts Payable at September
    30,
            
            
            -
            
            
            
            66See
      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 Nine Months Ended September 30, 2009 and 2008


(in
millions)


(Unaudited)





AEP
      Common ShareholdersCommon
      Stock
            
            
            
            
            
            AccumulatedOtherPaid-in
            
            Retained
            
            Comprehensive
            
            NoncontrollingShares
            
            Amount
            
            Capital
            
            Earnings
            
            Income
      (Loss)
            
            Interests
            
            TotalTOTAL
      EQUITY – DECEMBER 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
            
            3
            
            
            17
            
            
            89
            
            
            
            
            
            
            
            
            
            
            
            106Common
      Stock Dividends
            
            
            
            
            
            
            
            
            
            
            (494)
            
            
            
            
            
            (6)
            
            
            (500)Preferred
      Stock Dividends
            
            
            
            
            
            
            
            
            
            
            (2)
            
            
            
            
            
            
            
            
            (2)Other
      Changes in Equity
            
            
            
            
            
            
            
            3
            
            
            
            
            
            
            
            
            1
            
            
            4SUBTOTAL
      – EQUITY
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            9,694COMPREHENSIVE
      INCOMEOther
      Comprehensive Income (Loss), Net of Taxes:Cash
      Flow Hedges, Net of Tax of $4
            
            
            
            
            
            
            
            
            
            
            
            
            
            7
            
            
            
            
            
            7Securities
      Available for Sale, Net of Tax of $5
            
            
            
            
            
            
            
            
            
            
            
            
            
            (10)
            
            
            
            
            
            (10)Amortization
      of Pension and OPEB Deferred Costs, Net of Tax of $5
            
            
            
            
            
            
            
            
            
            
            
            
            
            9
            
            
            
            
            
            9NET
      INCOME
            
            
            
            
            
            
            
            
            
            
            1,230
            
            
            
            
            
            4
            
            
            1,234TOTAL
      COMPREHENSIVE INCOME
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            1,240TOTAL
      EQUITY – SEPTEMBER 30, 2008
            
            425
            
            $
            2,760
            
            $
            4,444
            
            $
            3,861
            
            $
            (148)
            
            $
            17
            
            $
            10,934TOTAL
      EQUITY – DECEMBER 31, 2008
            
            426
            
            $
            2,771
            
            $
            4,527
            
            $
            3,847
            
            $
            (452)
            
            $
            17
            
            $
            10,710Issuance
      of Common Stock
            
            71
            
            
            464
            
            
            1,294
            
            
            
            
            
            
            
            
            
            
            
            1,758Common
      Stock Dividends
            
            
            
            
            
            
            
            
            
            
            (559)
            
            
            
            
            
            (5)
            
            
            (564)Preferred
      Stock Dividends
            
            
            
            
            
            
            
            
            
            
            (2)
            
            
            
            
            
            
            
            
            (2)Purchase
      of JMG
            
            
            
            
            
            
            
            55
            
            
            
            
            
            
            
            
            (18)
            
            
            37Other
      Changes in Equity
            
            
            
            
            
            
            
            (50)
            
            
            
            
            
            
            
            
            1
            
            
            (49)SUBTOTAL
      – EQUITY
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            11,890COMPREHENSIVE
      INCOMEOther
      Comprehensive Income, Net of Taxes:Cash
      Flow Hedges, Net of Tax of $3
            
            
            
            
            
            
            
            
            
            
            
            
            
            5
            
            
            
            
            
            5Securities
      Available for Sale, Net of Tax of $5
            
            
            
            
            
            
            
            
            
            
            
            
            
            10
            
            
            
            
            
            10Amortization
      of Pension and OPEB Deferred Costs, Net of Tax of $18
            
            
            
            
            
            
            
            
            
            
            
            
            
            33
            
            
            
            
            
            33NET
      INCOME
            
            
            
            
            
            
            
            
            
            
            1,121
            
            
            
            
            
            5
            
            
            1,126TOTAL
      COMPREHENSIVE INCOME
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            1,174TOTAL
      EQUITY – SEPTEMBER 30, 2009
            
            497
            
            $
            3,235
            
            $
            5,826
            
            $
            4,407
            
            $
            (404)
            
            $
            -
            
            $
            13,064





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 Pronouncements and Extraordinary Item3.
            Rate
      Matters4.
            Commitments,
      Guarantees and Contingencies5.
            Acquisitions
      and Discontinued Operations6.
            Benefit
      Plans7.
            Business
      Segments8.
            Derivatives
      and Hedging9.
            Fair
      Value Measurements10.
            Income
      Taxes11.
            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 condensed consolidated 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.  Net income for the three and nine months ended
September 30, 2009 is not necessarily indicative of results that may be expected
for the year ending December 31, 2009.  We reviewed subsequent events
through our Form 10-Q issuance date of October 30, 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 Current Report on Form
8-K as filed with the SEC on May 1, 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 September 30,2009
            
            
            2008(in
      millions, except per share data)$/share
            
            
            
            
            
            $/shareEarnings
      Applicable to AEP Common Shareholders
            
            $
            443
            
            
            
            
            
            $
            374Weighted
      Average Number of Basic Shares Outstanding
            
            
            476.9
            
            
            $
            0.93
            
            
            
            402.3
            
            
            $
            0.93Weighted
      Average Dilutive Effect of:Performance
      Share Units
            
            
            0.1
            
            
            
            -
            
            
            
            1.3
            
            
            
            -Stock
      Options
            
            
            -
            
            
            
            -
            
            
            
            0.1
            
            
            
            -Restricted
      Stock Units
            
            
            0.1
            
            
            
            -
            
            
            
            0.1
            
            
            
            -Restricted
      Shares
            
            
            -
            
            
            
            -
            
            
            
            0.1
            
            
            
            -Weighted
      Average Number of Diluted Shares Outstanding
            
            
            477.1
            
            
            $
            0.93
            
            
            
            403.9
            
            
            $
            0.93





Nine
      Months Ended September 30,2009
            
            
            2008(in
      millions, except per share data)$/share
            
            
            
            
            
            $/shareEarnings
      Applicable to AEP Common Shareholders
            
            $
            1,119
            
            
            
            
            
            $
            1,228Weighted
      Average Number of Basic Shares Outstanding
            
            
            452.3
            
            
            $
            2.47
            
            
            
            401.5
            
            
            $
            3.06Weighted
      Average Dilutive Effect of:Performance
      Share Units
            
            
            0.2
            
            
            
            -
            
            
            
            1.0
            
            
            
            (0.01
            )Stock
      Options
            
            
            -
            
            
            
            -
            
            
            
            0.2
            
            
            
            -Restricted
      Stock Units
            
            
            -
            
            
            
            -
            
            
            
            0.1
            
            
            
            -Restricted
      Shares
            
            
            -
            
            
            
            -
            
            
            
            0.1
            
            
            
            -Weighted
      Average Number of Diluted Shares Outstanding
            
            
            452.5
            
            
            $
            2.47
            
            
            
            402.9
            
            
            $
            3.05





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


Options
to purchase 612,916 and 146,900 shares of common stock were outstanding at
September 30, 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 average quarter market price of the common shares and,
therefore, the effect would be antidilutive.





Variable
Interest Entities





The
accounting guidance for “Variable Interest Entities” 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 the accounting guidance for “Variable Interest
Entities.”  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 were applied
consistently.





We are
the primary beneficiary of Sabine, DHLC, JMG, DCC Fuel LLC (DCC Fuel) and a
protected cell of EIS.  We hold a significant variable interest in
Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West
Virginia Series).  In addition, we have not provided material
financial or other support to Sabine, DHLC, DCC Fuel or EIS that was not
previously contractually required.  Refer to the discussion of JMG
below for details regarding payments that were not 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
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.  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 September 30, 2009 and 2008 were $34 million and $31 million,
respectively, and for the nine months ended September 30, 2009 and 2008 were $95
million and $79 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.  SWEPCo and Cleco Corporation equally approve
DHLC’s annual budget.  The creditors of DHLC have no recourse to any
AEP entity other than SWEPCo.  As SWEPCo is the sole equity owner of
DHLC it receives 100% of the management fee.  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 September 30, 2009 and 2008 were
$12 million and $11 million, respectively, and for the nine months ended
September 30, 2009 and 2008 were $31 million and $32 million,
respectively.  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 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.  Based on the
structure of the entity, management has concluded OPCo is the primary
beneficiary and is required to consolidate JMG.  In April 2009, OPCo
paid JMG $58 million which was used to retire certain long-term debt of
JMG.  While this payment was not contractually required, OPCo made
this payment in anticipation of purchasing the outstanding equity of
JMG.  In July 2009, OPCo purchased all of the outstanding equity
ownership of JMG for $28 million resulting in an elimination of OPCo’s
Noncontrolling Interest related to JMG and an increase in Common Shareholder’s
Equity of $54 million.  In August and September 2009, JMG reacquired
$218 million of auction rate debt, funded by OPCo capital contributions to
JMG.  These reacquisitions were not contractually
required.  JMG is a wholly-owned subsidiary of OPCo with a capital
structure of 85% equity, 15% debt.





OPCo
intends to cancel the lease and dissolve JMG in December 2009.  The
assets and liabilities of JMG will remain incorporated with OPCo’s
business.  OPCo’s total billings from JMG for the three months ended
September 30, 2009 and 2008 were $1 million and $13 million, respectively, and
for the nine months ended September 30, 2009 and 2008 were $50 million and $39
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 we are required to consolidate the protected
cell.  Our insurance premium payments to EIS for the three months
ended September 30, 2009 and 2008 were $13 million and $11 million,
respectively, and for the nine months ended September 30, 2009 and 2008 were $30
million and $28 million, respectively.  See the tables below for the
classification of EIS’s assets and liabilities on our Condensed Consolidated
Balance Sheets.





In
September 2009, I&M entered into a nuclear fuel sale and leaseback
transaction with DCC Fuel.  DCC Fuel was formed for the purpose of
acquiring, owning and leasing nuclear fuel to I&M.  DCC Fuel
purchased the nuclear fuel from I&M with funds received from the issuance of
notes to financial institutions.  DCC Fuel is a single-lessee leasing
arrangement with only one asset and is capitalized with all
debt.  Payments on the lease will be made semi-annually on April 1 and
October 1, beginning in April 2010.  As of September 30, 2009, no
payments have been made by I&M to DCC Fuel.  The lease was
recorded as a capital lease on I&M’s balance sheet as title to the nuclear
fuel transfers to I&M at the end of the 48 month lease
term.  Based on the structure, management has concluded that I&M
is the primary beneficiary and is required to consolidate DCC
Fuel.  The capital lease is eliminated upon
consolidation.  See the tables below for the classification of DCC
Fuel’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


September
30, 2009


(in
millions)





SWEPCo
              Sabine
            
            
            SWEPCo
              DHLC
            
            
            OPCo
              JMG
            
            
            I&M
              DCC
      Fuel
            
            
            EISASSETSCurrent
      Assets
            
            $
            38
            
            
            $
            19
            
            
            $
            18
            
            
            $
            38
            
            
            $
            125Net
      Property, Plant and Equipment
            
            
            133
            
            
            
            29
            
            
            
            407
            
            
            
            101
            
            
            
            -Other
      Noncurrent Assets
            
            
            30
            
            
            
            10
            
            
            
            -
            
            
            
            65
            
            
            
            2Total
      Assets
            
            $
            201
            
            
            $
            58
            
            
            $
            425
            
            
            $
            204
            
            
            $
            127LIABILITIES
      AND EQUITYCurrent
      Liabilities
            
            $
            27
            
            
            $
            15
            
            
            $
            20
            
            
            $
            38
            
            
            $
            38Noncurrent
      Liabilities
            
            
            174
            
            
            
            40
            
            
            
            46
            
            
            
            166
            
            
            
            75Equity
            
            
            -
            
            
            
            3
            
            
            
            359
            
            
            
            -
            
            
            
            14Total
      Liabilities and Equity
            
            $
            201
            
            
            $
            58
            
            
            $
            425
            
            
            $
            204
            
            
            $
            127





AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES


VARIABLE
INTEREST ENTITIES


December
31, 2008


(in
millions)





SWEPCo
              Sabine
            
            
            SWEPCo
              DHLC
            
            
            OPCo
              JMG
            
            
            I&M
              DCC
      Fuel
            
            
            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 AEP 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.  Neither the “Ohio Series” or “Allegheny Series” are
considered VIEs.  The other series is not considered a
VIE.  We are not required to consolidate PATH-WV as we are not the
primary beneficiary, although we hold a significant variable interest in
PATH-WV.  Our equity investment in PATH-WV is included in Deferred
Charges and Other Noncurrent Assets 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 should be consistent with other regulated
utilities.  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.  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:





September
      30, 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 AEP
            
            $
            11
            
            
            $
            11
            
            
            $
            4
            
            
            $
            4Retained
      Earnings
            
            
            2
            
            
            
            2
            
            
            
            2
            
            
            
            2Total
      Investment in PATH-WV
            
            $
            13
            
            
            $
            13
            
            
            $
            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 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 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.  In comparing 2009 and 2008, the change in depreciation
rates resulted in a net increase (decrease) in depreciation expense
of:





Total
      Depreciation Expense VarianceThree
      Months Ended
            
            Nine
      Months EndedSeptember
      30, 2009/2008
            
            September
      30, 2009/2008(in
      millions)CSPCo
            
            $
            (4
            )
            
            $
            (13
            )OPCo
            
            
            18
            
            
            
            52





The net
change in depreciation rates resulted in decreases to our net-of-tax, basic
earnings per share of $0.02 and $0.06 for the three months ended September 30,
2009 and nine months ended September 30, 2009, respectively.





Supplementary
Information


Three
      Months Ended
              September
      30,
            
            
            Nine
      Months Ended
              September
      30,2009
            
            
            2008
            
            
            2009
            
            
            2008Related
      Party Transactions
            
            (in
      millions)AEP
      Consolidated Revenues – Utility Operations:Power
      Pool Purchases – Ohio Valley Electric Corporation (43.47% owned)
      (a)
            
            $
            -
            
            
            $
            (14
            )
            
            $
            -
            
            
            $
            (40
            )AEP
      Consolidated Revenues – Other:Ohio
      Valley Electric Corporation – Barging and Other Transportation
      Services (43.47% Owned)
            
            
            7
            
            
            
            7
            
            
            
            22
            
            
            
            21AEP
      Consolidated Expenses – Purchased Energy for Resale:Ohio
      Valley Electric Corporation (43.47% Owned)
            
            
            71
            
            
            
            70
            
            
            
            213
            
            
            
            194





(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.





Shown
below are income statement amounts attributable to AEP common
shareholders:





Three
      Months Ended
              September
      30,
            
            Nine
      Months Ended
              September
      30,2009
            
            2008
            
            2009
            
            2008Amounts
      Attributable To AEP Common Shareholders
            (in
      millions)Income
      Before Discontinued Operations andExtraordinary
      Loss
            
            $
            443
            
            
            $
            374
            
            
            $
            1,124
            
            
            $
            1,227Discontinued
      Operations, Net of Tax
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            1Extraordinary
      Loss, Net of Tax
            
            
            -
            
            
            
            -
            
            
            
            (5
            )
            
            
            -Net
      Income
            
            $
            443
            
            
            $
            374
            
            
            $
            1,119
            
            
            $
            1,228





2.
            NEW ACCOUNTING
      PRONOUNCEMENTS AND EXTRAORDINARY
ITEM





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 2009





The
following standards were effective during the first nine months 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 had no business combinations in
2009.  We will apply it to any future business
combinations.  SFAS 141R is included in the “Business Combinations”
accounting guidance.





SFAS
160 “Noncontrolling Interests 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.  SFAS 160 is included in the
“Consolidation” accounting guidance.  The retrospective application of
this standard:





·
            Reclassifies
      Minority Interest Expense of $1 million and $3 million and Interest
      Expense of $0 million and $1 million for the three and nine months ended
      September 30, 2008, respectively, 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 and $2
      million for the three and nine months ended September 30, 2008,
      respectively, 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 Noncurrent Liabilities and Total
      Liabilities as Noncontrolling Interests in Total Equity on our Condensed
      Consolidated Balance Sheets.·
            Separately
      reflects changes in Noncontrolling Interests on the Condensed Consolidated
      Statements of Changes in Equity and Comprehensive Income
      (Loss).·
            Reclassifies
      dividends paid to noncontrolling interests of $6 million for the nine
      months ended September 30, 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 Note 8.  SFAS 161 is included in the
“Derivatives and Hedging” accounting guidance.





SFAS
165 “Subsequent Events” (SFAS 165)





In May
2009, the FASB issued SFAS 165 incorporating guidance on subsequent events into
authoritative accounting literature and clarifying the time following the
balance sheet date which management reviewed for events and transactions that
may require disclosure in the financial statements.





We
adopted this standard effective second quarter of 2009.  The standard
increased our disclosure by requiring disclosure of the date through which
subsequent events have been reviewed.  The standard did not change our
procedures for reviewing subsequent events.  SFAS 165 is included in
the “Subsequent Events” accounting guidance.





SFAS
      168 “The FASB Accounting Standards CodificationTMand the Hierarchy of Generally Accepted Accounting Principles”
      (SFAS 168)





In June
2009, the FASB issued SFAS 168 establishing the FASB Accounting Standards
CodificationTM as
the authoritative source of accounting principles for preparation of financial
statements and reporting in conformity with GAAP by nongovernmental
entities.





We
adopted SFAS 168 effective third quarter of 2009.  It required an
update of all references to authoritative accounting literature.  SFAS
168 is included in the “Generally Accepted Accounting Principles” accounting
guidance.





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.  With the adoption of FSP
SFAS 107-1 and APB 28-1, it is applied to the fair value of long-term
debt.  The application of this standard had an immaterial effect on
the fair value of debt outstanding.  EITF 08-5 is included in the
“Fair Value Measurements and Disclosures” accounting guidance.





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.  EITF 08-6 is
included in the “Investments – Equity Method and Joint Ventures” accounting
guidance.





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.  EITF
03-6-1 is included in the “Earnings Per Share” accounting guidance.





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.





We
adopted the standard effective second quarter of 2009.  This standard
increased the disclosure requirements related to financial
instruments.  See “Fair Value Measurements of Long-term Debt” section
of Note 9.  FSP SFAS 107-1 and APB 28-1 is included in the “Financial
Instruments” accounting guidance.





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.





We
adopted the standard effective second quarter of 2009 with no impact on our
financial statements and increased disclosure requirements related to financial
instruments.  See “Fair Value Measurements of Other Temporary
Investments” and “Fair Value Measurements of Trust Assets for Decommissioning
and SNF Disposal” sections of Note 9.  FSP SFAS 115-2 and SFAS 124-2
is included in the “Investments – Debt and Equity Securities” accounting
guidance.





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.  SFAS 142-3 is included in the “Intangibles – Goodwill and
Other” accounting guidance.





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 analyses 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 nine months of 2009.  SFAS 157-2 is included in the “Fair
Value Measurements and Disclosures” accounting guidance.





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.





We
adopted the standard effective second quarter of 2009.  This standard
had no impact on our financial statements but increased our disclosure
requirements.  See “Fair Value Measurements of Financial Assets and
Liabilities” section of Note 9.  FSP SFAS 157-4 is included in the
“Fair Value Measurements and Disclosures” accounting guidance.





Pronouncements Effective in
the Future





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





ASU
2009-05 “Measuring Liabilities at Fair Value” (ASU 2009-05)





In August
2009, the FASB issued ASU 2009-05 updating the “Fair Value Measurement and
Disclosures” accounting guidance.  The guidance specifies the
valuation techniques that should be used to fair value a liability in the
absence of a quoted price in an active market.





The new
accounting guidance is effective for interim and annual periods beginning after
the issuance date.  Although we have not completed our analysis, we do
not expect this update to have a material impact on our financial
statements.  We will adopt ASU 2009-05 effective fourth quarter of
2009.





ASU
      2009-12 “Investments in Certain Entities That Calculate Net Asset Value
      per Share (or its Equivalent)” (ASU
2009-12)





In
September 2009, the FASB issued ASU 2009-12 updating the “Fair Value Measurement
and Disclosures” accounting guidance for the fair value measurement of
investments in certain entities that calculate net asset value per share (or its
equivalent).  The guidance permits a reporting entity to measure the
fair value of an investment within its scope on the basis of the net asset value
per share of the investment (or its equivalent).





The new
accounting guidance is effective for interim and annual periods ending after
December 15, 2009.  Although we have not completed our analysis, we do
not expect this update to have a material impact on our financial
statements.  We will adopt ASU 2009-12 effective fourth quarter of
2009.





ASU
2009-13 “Multiple-Deliverable Revenue Arrangements” (ASU 2009-13)





In
October 2009, the FASB issued ASU 2009-13 updating the “Revenue Recognition”
accounting guidance by providing criteria for separating consideration in
multiple-deliverable arrangements.  It establishes a selling price
hierarchy for determining the price of a deliverable and expands the disclosures
related to a vendor’s multiple-deliverable revenue arrangements.





The new
accounting guidance is effective prospectively for arrangements entered into or
materially modified in years beginning after June 15, 2010.  Although
we have not completed our analysis, we do not expect this update to have a
material impact on our financial statements.  We will adopt ASU
2009-13 effective January 1, 2011.





SFAS
166 “Accounting for Transfers of Financial Assets” (SFAS 166)





In June
2009, the FASB issued SFAS 166 clarifying when a transfer of a financial asset
should be recorded as a sale.  The standard defines participating
interest to establish specific conditions for a sale of a portion of a financial
asset.  This standard must be applied to all transfers after the
effective date.





SFAS 166
is effective for interim and annual reporting in fiscal years beginning after
November 15, 2009.  Early adoption is prohibited.  We
continue to review the impact of this standard.  We will adopt SFAS
166 effective January 1, 2010.  SFAS 166 is included in the “Transfers
and Servicing” accounting guidance.





SFAS
167 “Amendments to FASB Interpretation No. 46(R)” (SFAS 167)





In June
2009, the FASB issued SFAS 167 amending the analysis an entity must perform to
determine if it has a controlling interest in a variable interest entity
(VIE).  This new guidance provides that the primary beneficiary of a
VIE must have both:





·
            The
      power to direct the activities of the VIE that most significantly impact
      the VIE’s economic performance.·
            The
      obligation to absorb the losses of the entity that could potentially be
      significant to the VIE or the right to receive benefits from the entity
      that could potentially be significant to the
  VIE.





The
standard also requires separate presentation on the face of the statement of
financial position for assets which can only be used to settle obligations of a
consolidated VIE and liabilities for which creditors do not have recourse to the
general credit of the primary beneficiary.





SFAS 167
is effective for interim and annual reporting in fiscal years beginning after
November 15, 2009.  Early adoption is prohibited.  We
continue to review the impact of the changes in the consolidation guidance on
our financial statements.  This standard will increase our disclosure
requirements related to transactions with VIEs and may change the presentation
of consolidated VIE’s assets and liabilities on our Condensed Consolidated
Balance Sheets.  We will adopt SFAS 167 effective January 1,
2010.  SFAS 167 is included in the “Consolidation” accounting
guidance.





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 policies 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 132R-1 is included in
the “Compensation – Retirement Benefits” accounting guidance.





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, financial instruments, emission
allowances, earnings per share calculations, leases, insurance, hedge
accounting, consolidation policy, discontinued operations and income
tax.  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.





EXTRAORDINARY
ITEM





SWEPCo
Texas Restructuring





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 May 2009, the governor of Texas signed a bill related to
SWEPCo’s SPP area of Texas that requires continued cost of service regulation
until certain stages have been completed and approved by the PUCT such that fair
competition is available to all Texas retail customer classes.  Based
upon the signing of the bill, SWEPCo re-applied “Regulated Operations”
accounting guidance for the generation portion of SWEPCo’s Texas retail
jurisdiction effective second quarter of 2009.  Management believes
that a switch to competition in the SPP area of Texas will not
occur.  The reapplication of “Regulated Operations” accounting
guidance resulted in an $8 million ($5 million, net of tax) extraordinary
loss.





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 March
2009, the PUCO issued an order, which was amended by a rehearing entry in July
2009, that modified and approved CSPCo’s and OPCo’s ESPs that established
standard service offer rates.  The ESPs will be in effect through
2011.  The ESP order authorized revenue increases during the ESP
period and capped the overall revenue increases for CSPCo to 7% in 2009, 6% in
2010 and 6% in 2011 and for OPCo to 8% in 2009, 7% in 2010 and 8% in
2011.  CSPCo and OPCo implemented rates for the April 2009 billing
cycle.  In its July 2009 rehearing entry, the PUCO required CSPCo and
OPCo to reduce rates implemented in April 2009 by $22 million and $27 million,
respectively, on an annualized basis.  CSPCo and OPCo are collecting
the 2009 annualized revenue increase over the last nine months of
2009.





The order
provides a FAC for the three-year period of the ESP.  The FAC increase
will be phased in to avoid having the resultant rate increases exceed 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 three-year ESP period will be recovered through a non-bypassable
surcharge over the period 2012 through 2018.





The FAC
deferrals at September 30, 2009 were $36 million and $238 million for CSPCo and
OPCo, respectively, inclusive of carrying charges at the weighted average cost
of capital.  In the July 2009 rehearing order, the PUCO once again
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.





The
PUCO’s July 2009 rehearing entry among other things reversed the prior
authorization to recover the cost of CSPCo’s recently acquired Waterford and
Darby Plants.  In July 2009, CSPCo filed an application for rehearing
with the PUCO seeking authorization to sell or transfer the Waterford and Darby
Plants.





The PUCO
also addressed several additional matters in the ESP order, which are described
below:





·
            CSPCo
      should attempt to mitigate the costs of its gridSMART advanced metering
      proposal that will affect portions of its service territory by seeking
      funds under the American Recovery and Reinvestment Act of
      2009.  As a result, a rider was established to recover $32
      million related to gridSMART during the three-year ESP
      period.  In August 2009, CSPCo filed for $75 million in federal
      grant funding under the American Recovery and Reinvestment Act of
      2009.




·
            CSPCo
      and OPCo can recover their 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.





·
            CSPCo’s
      and OPCo’s Provider of Last Resort revenues were increased by $97 million
      and $55 million, respectively, to compensate for the risk of customers
      changing electric suppliers during the ESP
  period.





·
            CSPCo
      and OPCo must fund a combined minimum of $15 million in costs over the ESP
      period for low-income, at-risk customer programs.  In March
      2009, this funding obligation was recognized as a liability and charged to
      Other Operation and Maintenance expense.  At September 30, 2009,
      CSPCo’s and OPCo’s remaining liability balances were $6 million
      each.





In June
2009, intervenors filed a motion in the ESP proceeding with the PUCO requesting
CSPCo and OPCo to refund deferrals allegedly collected by CSPCo and OPCo which
were created by the PUCO’s approval of a temporary special arrangement between
CSPCo, OPCo and Ormet, a large industrial customer.  In addition, the
intervenors requested that the PUCO prevent CSPCo and OPCo from collecting these
revenues in the future.  In June 2009, CSPCo and OPCo filed a response
noting that the difference in the amount deferred between the PUCO-determined
market price for 2008 and the rate paid by Ormet was not collected, but instead
was deferred, with PUCO authorization, as a regulatory asset for future
recovery.  In the rehearing entry, the PUCO did not order an
adjustment to rates based on this issue.  See “Ormet” section
below.





In August
2009, an intervenor filed for rehearing requesting, among other things, that the
PUCO order CSPCo and OPCo to cease and desist from charging ESP rates, to revert
to the rate stabilization plan rates and to compel a refund, including interest,
of the amounts collected by CSPCo and OPCo.  CSPCo and OPCo filed a
response stating the rates being charged by CSPCo and OPCo have been authorized
by the PUCO and there was no basis for precluding CSPCo and OPCo from continuing
to charge those rates.  In September 2009, certain intervenors filed
appeals of the March 2009 order and the July 2009 rehearing entry with the
Supreme Court of Ohio.  One of the intervenors, the Ohio Consumers’
Counsel, has asked the court to stay, pending the outcome of its appeal, a
portion of the authorized ESP rates which the Ohio Consumers’ Counsel
characterizes as being retroactive.  In October 2009, the Supreme
Court of Ohio denied the Ohio Consumers' Counsel's request for a stay and
granted motions to dismiss both appeals.





In
September 2009, CSPCo and OPCo filed their initial quarterly FAC filing with the
PUCO.  An order approving the FAC 2009 filings will not be issued
until a financial audit and prudency review is performed by independent third
parties and reviewed by the PUCO.





In
October 2009, the PUCO convened a workshop to begin to determine the methodology
for the Significantly Excessive Earnings Test (SEET).  The SEET
requires the PUCO to determine, following the end of each year of the ESP, if
rate adjustments included in the ESP resulted in significantly excessive
earnings.  This will be determined by measuring whether the utility’s
earned return on common equity is significantly in excess of the return on
common equity that was earned during the same period by publicly traded
companies, including utilities, which have comparable business and financial
risk.  In the March 2009 ESP order, the PUCO determined that
off-system sales margins and FAC deferral phase-in credits should be excluded
from the SEET methodology.  However, the July 2009 PUCO rehearing
entry deferred those issues to the SEET workshop.  If the rate
adjustments, in the aggregate, result in significantly excessive earnings, the
excess amount would 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 workshop is completed, the PUCO issues SEET guidelines, a
SEET filing is made by CSPCo and OPCo in 2010 and the PUCO issues an order
thereon. The SEET workshop will also determine whether CSPCo’s and OPCo’s
earnings will be measured on an individual company basis or on a combined
CSPCo/OPCo basis.





In
October 2009, an intervenor filed a complaint for writ of prohibition with the
Supreme Court of Ohio requesting the Court to prohibit CSPCo and OPCo from
billing and collecting any ESP rate increases that the PUCO authorized as the
intervenor believes the PUCO's statutory jurisdiction over CSPCo's and OPCo's
ESP application ended on December 28, 2008, which was 150 days after the filing
of the ESP applications.  CSPCo and OPCo plan on filing a response in
opposition to the complaint for writ of prohibition.





Management
is unable to predict the outcome of the various ongoing proceedings and
litigation discussed above including the SEET, the FAC filing review and the
various appeals to the Supreme Court of Ohio relating to the ESP
order.  If these proceedings result in adverse rulings, it could have
an adverse effect on future net income and cash flows.




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 June
2006 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 jurisdictions 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 response 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 required CSPCo and OPCo to 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 CSPCo and
OPCo believe there exist real statutory barriers to the construction of any new
base load generation in Ohio, including the IGCC plant.  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.





In
September 2009, an intervenor filed a motion with the PUCO requesting that CSPCo
and OPCo be required to refund all pre-construction cost revenue to Ohio
ratepayers with interest or show cause as to why the amount for the proposed
IGCC plant should not be immediately refunded based upon the PUCO’s June 2006
order.  The intervenor contends that the most recent integrated
resource plan filed for the AEP East companies’ zone does not reflect the
construction of an IGCC plant.  In October 2009, CSPCo and OPCo filed
a response opposing the intervenor’s request to refund revenues collected
stating that an integrated resource plan is a planning tool and does not prevent
CSPCo and OPCo from meeting the PUCO’s five-year time limit.





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





Ormet





In
December 2008, CSPCo, OPCo and Ormet, a large aluminum company currently
operating at a reduced load of approximately 330 MW (Ormet operated at an
approximate 500 MW load in 2008), filed an application with the PUCO for
approval of an interim arrangement governing the provision of generation service
to Ormet.  The interim arrangement was effective January 1, 2009 and
expired in September 2009 upon the filing of a new PUCO-approved long-term power
contract between Ormet and CSPCo/OPCo that was effective prospectively through
2018.  Under the interim arrangement, Ormet would pay the then-current
applicable generation tariff rates and riders and CSPCo and OPCo would 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 new FAC phased-in mechanism that 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 the PUCO’s July 2009 order discussed below, CSPCo and
OPCo were directed to file an application to recover the appropriate amounts of
the deferrals under the interim agreement and for the remainder of
2009.





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 for the differential in the approved market price of
$53.03 versus the rate paid by Ormet until the effective date of the 2009-2018
power contract.





In May
2009, intervenors filed a motion with the PUCO that contends CSPCo and OPCo
should be charging Ormet the new ESP rate and that no additional deferrals
between the approved market price and the rate paid by Ormet should be
calculated and recovered through the FAC since Ormet will be paying the new ESP
rate.  In May 2009, CSPCo and OPCo filed a Memorandum Contra
recommending the PUCO deny the motion to cease additional Ormet FAC
under-recovery deferrals.  In June 2009, intervenors filed a motion
with the PUCO related to Ormet in the ESP proceeding.  See “Ohio
Electric Security Plan Filings” section above.





In July
2009, the PUCO approved Ormet’s application for a power contract through 2018
with several modifications.  As modified by the PUCO, rates billed to
Ormet by CSPCo and OPCo for the balance of 2009 would reflect an annual average
rate using $38 per MWH for the periods Ormet was in full production and $35 and
$34 per MWH at certain curtailed production levels.  The $35 and $34
MWH rates are contingent upon Ormet maintaining its employment levels at 900
employees for 2009.  The PUCO authorized CSPCo and OPCo to record
under-recovery deferrals computed as revenue foregone (the difference between
CSPCo’s and OPCo’s ESP tariff rates and the rate paid by Ormet) created by the
blended rate for the remainder of 2009.  For 2010 through 2018, the
PUCO approved the linkage of Ormet’s rate to the price of aluminum but modified
the agreement to include a maximum electric rate reduction for Ormet that
declines over time to zero in 2018 and a maximum amount of under-recovery
deferrals that ratepayers will be expected to pay via a rider in any given
year.  For 2010 and 2011, the PUCO set the maximum rate discount at
$60 million and the maximum amount of the rate discount other ratepayers should
pay at $54 million.  To the extent the under-recovery deferrals exceed
the amount collectible from ratepayers, the difference can be deferred, with a
long-term debt carrying charge, for future recovery.  In addition,
this rate is based upon Ormet maintaining at least 650 employees.  For
every 50 employees below that level, Ormet’s maximum electric rate reduction
will be lowered.  The new long-term power contract became effective in
September 2009 at which point CSPCo and OPCo began deferring as a regulatory
asset the unrecovered amounts less Provider of Last Resort (POLR)
charges.  Rehearing applications filed by CSPCo, OPCo and intervenors
were granted by the PUCO.  In September 2009 on rehearing, the PUCO
ordered that CSPCo and OPCo must credit all Ormet related POLR charges against
the under-recovery amounts that CSPCo and OPCo would otherwise
recover.  As of September 30, 2009, CSPCo and OPCo had $32 million and
$34 million, respectively, deferred as regulatory assets related to Ormet
under-recovery, which is included in CSPCo’s and OPCo’s FAC phase-in deferral
balance.





Ormet
indicated it will operate at reduced operations at least through the end of
2009.  Management cannot predict Ormet’s on-going electric consumption
levels, the resultant prices Ormet will pay and/or the amount that CSPCo and
OPCo will defer for future recovery from other customers.  If CSPCo
and OPCo are not ultimately permitted to recover their under-recovery deferrals,
it would have an adverse effect on future net income and cash
flows.





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, the PUCO
approved these regulatory assets along with a long-term debt only carrying cost
on these regulatory assets.  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 filings.  At September 30, 2009, CSPCo
and OPCo have accrued for future recovery regulatory assets of $18 million and
$10 million, respectively, including the approved long-term debt only carrying
costs.  If CSPCo and OPCo are not ultimately permitted to recover
their storm damage deferrals, 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 flows were adversely impacted for 2008, 2007
and 2006 by $75 million, $238 million and $69 million,
respectively.  Municipal customers and other intervenors appealed the
PUCT true-up orders seeking to further reduce TCC’s true-up
recoveries.  TCC also 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.





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.  In June 2008, the Texas Court of Appeals denied
intervenors’ motions for rehearing.  In August 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 which concluded in June
2009.  A decision is not expected from the Texas Supreme Court until
2010.





TNC
received its final true-up order in May 2005 that resulted in refunds via a CTC
which have been completed.  TNC appealed its final true-up order,
which 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
possibly 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 Accumulated
Deferred Investment Tax Credit (ADITC) and Excess Deferred Federal Income Tax
(EDFIT) tax benefits to customers.  Subsequent to the PUCT’s ordered
reduction to TCC’s securitized stranded costs for 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 was for subsequent carrying
costs.  The deferral of the CTC refunds is pending resolution on
whether the PUCT’s securitization refund is an IRS normalization
violation.





Since the
deferral through the CTC refund, the IRS issued a favorable final regulation in
March 2008 addressing the normalization requirements for the treatment of ADITC
and 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 in a final order
after all appeals to flow these 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 favorable additional evidence.





TCC
expects that the PUCT will allow TCC to retain the deferred
amounts.  This will have a favorable effect on future net income as
TCC will be able to amortize the deferred ADITC and EDFIT tax benefits to income
over the remaining securitization period.  Since management expects
that the PUCT will allow TCC to retain the deferred CTC refund amounts in order
to avoid an IRS normalization violation, no related interest expense has been
accrued related to refunds of these amounts.  If accrued, management
estimates interest expense would have been approximately $11 million higher for
the period July 2008 through September 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 $102 million as of September 30, 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 final order.  Management intends to
continue to work with the PUCT to favorably resolve this 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 May 2009, the governor of Texas signed a bill related to
SWEPCo’s SPP area of Texas that requires continued cost of service regulation
until certain stages have been completed and approved by the PUCT such that fair
competition is available to all Texas retail customer classes.  Based
upon the signing of the bill, SWEPCo re-applied “Regulated Operations”
accounting guidance for the generation portion of SWEPCo’s Texas retail
jurisdiction in the second quarter of 2009.  Management believes that
a switch to competition in the SPP area of Texas will not occur.  The
reapplication of “Regulated Operations” accounting guidance resulted in an $8
million ($5 million, net of tax) extraordinary loss.





In
addition, effective April 2009, the generation portion of SWEPCo’s Texas retail
jurisdiction began accruing AFUDC (debt and equity return) instead of
capitalized interest on its eligible construction balances including the Stall
Unit and the Turk Plant.  The accrual of AFUDC increased September
year to date 2009 net income by approximately $8 million using the last
PUCT-approved return on equity rate.





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 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 a $2
million balance in its catastrophe reserve account.  Therefore, TCC
established a net regulatory asset for $23 million.  The balance in
the net catastrophe reserve regulatory asset account as of September 30, 2009 is
approximately $22 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.  In connection with the filing of the next base rate case, TCC
will evaluate the existing catastrophe reserve ratepayer funding and review
potential future events to determine the appropriate increase in the funding
level to request both recovery of the then existing regulatory asset balance and
to 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 annual interim update
of wholesale-transmission rates.  The proposed new interim
transmission rates are estimated to increase annual transmission revenues by $9
million and $4 million for TCC and TNC, respectively.  In May 2008,
the PUCT and the FERC approved the new interim transmission rates as
filed.  TCC and TNC implemented the new rates effective May 2008,
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 requested transmission investment.  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 prudently incurred new transmission
investment.  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 annual
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 May 2009, the PUCT and the FERC approved the new
interim transmission rates as filed.  TCC and TNC implemented the new
rates effective May 2009, 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 requested transmission
investment.  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 prudently
incurred new transmission investment.  A refund of the interim
transmission rates would have an adverse impact on net income and cash
flows.





2007
Texas Base Rate Increase Appeal





In
November 2006, TCC filed a base rate case seeking to increase transmission and
distribution energy delivery services (wires) base rates 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 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.  The order increased TCC’s
annual pretax income by approximately $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.





2009
Texas Base Rate Filing





In August
2009, SWEPCo filed a base rate case with the PUCT to increase non-fuel base
rates by approximately $75 million annually based on a requested return on
common equity of 11.5%. The filing includes a base rate increase of $27 million,
a vegetation management rider for $16 million and financing cost riders of $32
million related to the construction of the Stall Unit and Turk
Plant.  In addition, the net merger savings credit of $7 million will
be removed from rates and depreciation expense is proposed to decrease by $17
million.  The proposed filing would increase SWEPCo’s annual pretax
income by approximately $51 million.





The
proposed Stall Unit rider would recover a return on the Stall Unit investment
while the Stall Unit is under construction and continuing after it is placed in
service plus recovery of depreciation when it is placed in service in
2010.  The proposed Turk Plant rider would recover a return on the
Turk Plant investment and will continue until such time that the Turk Plant is
included in base rates.  Both riders would terminate when base rates
are increased to include recovery of the Turk Plant’s and the Stall Unit’s
respective plant investments, plus a return thereon, and a recovery of their
related operating expenses.  Management is unable to predict the
outcome of this filing.





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 (CCN) 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 June 2009, the Texas governor signed a new law that
clarifies the PUCT’s authority to grant CCNs to transmission-only utilities such
as ETT.  In September 2009, ETT filed an application with the PUCT for
a CCN under the new law for the purpose of confirming its authority to operate
as a transmission-only utility regardless of the outcome of the pending
litigation.  The parties to the litigation pending at the Texas Court
of Appeals have stipulated agreement or indicated they are not opposed to ETT’s
request.





During
2009, TCC and TNC sold $93 million and $1 million, respectively, of additional
transmission facilities to ETT.  As of September 30, 2009, AEP’s net
investment in ETT was $47 million.  Depending upon ETT’s filing under
the new law, the ultimate outcome of the appeals and any resulting remands, TCC
and TNC may be required to reacquire transferred assets and projects under
construction by ETT if ETT cannot obtain the appropriate
approvals.  As of September 30, 2009, ETT’s net investment in
property, plant and equipment was $236 million, of which $100 million was under
construction.





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 and also initiated a proceeding to
develop a sequence of regulatory filings for routing the CREZ transmission
lines.  In June 2009, ETT and other parties entered into a settlement
agreement establishing dates for these filings.  Pursuant to the
settlement agreement, which is pending PUCT approval, ETT would make regulatory
filings in 2010 and initiate construction upon receipt of PUCT
approval.





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 October 2009, ETT, TCC and TNC filed joint applications
with the PUCT for approval to transfer from TCC and TNC to ETT approximately $69
million and $72 million, respectively, of transmission assets and
CWIP.  The transfers are planned to be completed by the end of the
first quarter of 2010.  A decision from the PUCT is
pending.





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 in-service E&R
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 filed an
application, in May 2009, to recover $102 million of unrecovered 2008
incremental deferred E&R costs plus its 2008 equity costs based on a 12.5%
return on equity on its E&R capital investments. However, APCo deferred and
recognized income under the E&R legislation based on a return on equity of
10.1%, which was the Virginia SCC staff’s recommendation in the prior E&R
case.  In October 2009, a stipulation agreement was reached between
the parties and filed with the Virginia SCC addressing all matters other than
rate design and customer class allocation issues.  The stipulation
agreement allows APCo to recover Virginia incremental E&R costs of $90
million, representing costs deferred during 2008 plus unrecognized 2008 equity
costs, using a 10.6% return on equity for collection in 2010.  This
will result in an immaterial adjustment which will be recorded in the fourth
quarter of 2009.  The Virginia SCC is expected to approve the
stipulation agreement in the fourth quarter of 2009.





As of
September 30, 2009, APCo had $88 million of deferred Virginia incremental
E&R costs excluding $17 million of unrecognized equity carrying
costs.  The $88 million consists of $6 million of over-recovered costs
collected under the 2008 surcharge, $14 million approved by the Virginia SCC
related to the 2009 surcharge and $80 million, representing costs deferred
during 2008, which were included in the May 2009 E&R filing for collection
in 2010.





Mountaineer
Carbon Capture and Storage 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, and the Electric
Power Research Institute are participating in the project and providing some
funding to offset APCo's costs.  APCo’s estimated cost for its share
of the constructed facilities is $74 million.  In May 2009, the West
Virginia Department of Environmental Protection issued a permit to inject
CO2
that requires, among other items, that APCo monitor the wells for at least 20
years following the cessation of CO2
injection.  In September 2009, the capture portion of the project was
placed into service and in October 2009, APCo started injecting CO2 in
underground storage.  The injection of CO2 required
the recordation of an asset retirement obligation and an offsetting regulatory
asset at its estimated net present value of $36 million in October
2009.  Through September 30, 2009, APCo incurred $71 million in
capitalized project costs which are included in Regulatory Assets.





APCo
currently earns a return on the Virginia portion of the capitalized project
costs incurred through June 30, 2008, as a result of a base rate case settlement
approved by the Virginia SCC in November 2008.  In APCo’s July 2009
Virginia base rate filing, APCo requested recovery of and a return on the
estimated increased Virginia jurisdictional share of its CO2 capture
and storage project costs including the related asset retirement obligation
expenses.  See the “Virginia Base Rate Filing” section
below.  Based on the favorable treatment related to the CO2capture
demonstration facility in APCo’s last Virginia base rate case, APCo is deferring
its carbon capture expense as a regulatory asset for future
recovery.  APCo plans to seek recovery of the West Virginia
jurisdictional costs in its next West Virginia base rate filing which is
expected to be filed in the first quarter of 2010.  If the deferred
project costs are disallowed in future Virginia or West Virginia rate
proceedings, it could have an adverse effect on future net income and cash
flows.





Virginia
Base Rate Filing





The 2007
amendments to Virginia’s electric utility restructuring law required that each
investor-owned utility, such as APCo, file a base rate case with the Virginia
SCC in 2009 in which the Virginia SCC will determine fair rates of return on
common equity (ROE) for the generation and distribution services of the
utility.  As a result, in July 2009, APCo filed a base rate case with
the Virginia SCC requesting an increase in the generation and distribution
portions of its base rates of $169 million annually based on a 2008 test year,
as adjusted, and a 13.35% ROE inclusive of a requested 0.85% ROE performance
incentive increase as permitted by law.  The recovery of APCo’s
transmission service costs in Virginia was requested in a separate and
simultaneous transmission rate adjustment clause filing.  See the
“Rate Adjustment Clauses” section below.  In August 2009, APCo filed
supplemental schedules and testimony that decreased the requested annual revenue
increase to $154 million which reflected a recent Virginia SCC order in an
unaffiliated utility’s base rate case concerning the appropriate capital
structure to be used in the determination of the revenue
requirement.  The new generation and distribution base rates will
become effective, subject to refund, in December 2009.





Rate
Adjustment Clauses





In 2007,
the Virginia law governing the regulation of electric utility service was
amended to, among other items, provide for rate adjustment clauses (RAC)
beginning in January 2009 for the timely and current recovery of costs of (a)
transmission services billed by an RTO, (b) demand side management and energy
efficiency programs, (c) renewable energy programs, (d) environmental compliance
projects and (e) new generation facilities including major unit
modifications.  In July 2009, APCo filed for approval of a
transmission RAC simultaneous with the 2009 base rate case filing in which the
Virginia jurisdictional share of transmission costs was requested for recovery
through the RAC instead of through base rates.  The transmission RAC
filing requested an initial $94 million annual revenue requirement representing
an annual increase of $24 million above the current level embedded in APCo’s
Virginia base rates.  APCo requested to implement the transmission RAC
concurrently with the new base rates in December 2009.  See the
“Virginia Base Rate Filing” section above.  In October 2009, the
Virginia SCC approved the stipulation agreement providing for an annual
incremental revenue increase in transmission rates of $22 million excluding $2
million of reasonable and prudent PJM administrative costs that may be recovered
in base rates.





APCo
plans to file for approval of an environmental RAC no later than the first
quarter of 2010 to recover any unrecovered environmental costs incurred after
December 2008.  APCo also plans to file for approval of a renewable
energy RAC before the end of the first quarter of 2010 to recover costs
associated with APCo’s wind power purchase agreements.  In accordance
with Virginia law, APCo is deferring any incremental transmission and
environmental costs incurred after December 2008 and any renewable energy costs
incurred after August 2009 which are not being recovered in current
revenues.  As of September 30, 2009, APCo has deferred for future
recovery $17 million of environmental costs (excluding $3 million of
unrecognized equity carrying costs), $14 million of transmission costs and $1
million of renewable energy costs.  Management is evaluating whether
to make other RAC filings at this time.  If the Virginia SCC were to
disallow a portion of APCo’s deferred RAC costs, it would have an adverse effect
on future net income and cash flows.





Virginia
Fuel Factor Proceeding





In May
2009, APCo filed an application with the Virginia SCC to increase its fuel
adjustment charge by approximately $227 million from July 2009 through August
2010.  The $227 million proposed increase related to a $104 million
projected under-recovery balance of fuel costs as of June 2009 and $123 million
of projected fuel costs for the period July 2009 through August
2010.  APCo’s actual under-recovered fuel balance at June 2009 was $93
million.  Due to the significance of the estimated required increase
in fuel rates, APCo’s application proposed an alternative method of collection
of actual incurred fuel costs.  The proposed alternative would allow
APCo to recover 100% of the $104 million prior period under-recovery deferral
and 50% of the $123 million increase from July 2009 through August 2010 with
recovery of any remaining actual under-recovered fuel costs in APCo’s next fuel
factor proceeding from September 2010 through August 2011.  In May
2009, the Virginia SCC ordered that neither of APCo’s proposed fuel factors
shall become effective, pending further review by the Virginia
SCC.  In August 2009, the Virginia SCC issued an order which provided
for a $130 million fuel revenue increase, effective August 2009.  The
reduction in revenues from the requested amount recognizes a lower than
projected under-recovery balance and a lower level of projected fuel costs to be
recovered through the approved fuel factor.  Any fuel under-recovery
due to the lower level of projected fuel costs should be deferred as a
regulatory asset for future recovery under the FAC true-up mechanism and
recoverable, if necessary, either in APCo’s next fuel factor proceeding for the
period September 2010 through August 2011 or through other statutory
mechanisms.





APCo’s
Filings for an IGCC Plant





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


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 to increase the
ENEC rates by approximately $442 million for incremental fuel, purchased power,
other energy related costs and environmental compliance project costs 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 and the significance of the projected required
increase.  The proposed modified ENEC mechanism provides that the ENEC
rate increase be phased in with unrecovered amounts deferred for future recovery
over a five-year period beginning in July 2009, 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 as well as the
phase-in deferrals.  The proposed modified ENEC mechanism also
provides that to the extent the phase-in deferrals exceed the deferred amounts
that would have otherwise existed under the traditional ENEC mechanism, the
phase-in deferrals are subject to a carrying charge based upon APCo’s and WPCo’s
weighted average cost of capital.  As proposed, the modified ENEC
mechanism would produce three annual increases, based upon projected fuel costs
and including carrying charges, of $189 million, $166 million and $172 million,
effective July 2009, 2010 and 2011, respectively.





In May
2009, various intervenors submitted testimony supporting adjustments to APCo’s
and WPCo’s actual and projected ENEC costs.  The intervenors also
proposed alternative rate phase-in plans ranging from three to five
years.  Specifically, the WVPSC staff and the West Virginia Consumer
Advocate recommended an increase of $376 million and $327 million, respectively,
with $132 million and $130 million, respectively, being collected during the
first year and suggested that the remaining rate increases for future years be
determined in subsequent ENEC filings.  In June 2009, APCo and WPCo
filed rebuttal testimony.  In the rebuttal testimony, APCo and WPCo
accepted certain intervenor adjustments to the forecasted ENEC costs and reduced
the requested increase to $398 million with a proposed first-year increase of
$160 million.  The intervenors’ forecast adjustments would not impact
earnings since the ENEC mechanism would continue to true-up to actual
costs.  The primary difference between the intervenors’ $130 million
first-year increase and APCo’s and WPCo’s $160 million first-year increase is
the intervenors’ proposed disallowance of up to $36 million of actual and
projected coal costs.





In
September 2009, the WVPSC issued an order granting a $355 million increase to be
phased in over the next four years with a first-year increase of $124
million.  As of September 30, 2009, APCo’s ENEC under-recovery balance
was $255 million which is included in Regulatory Assets.  The WVPSC
also approved a fixed annual carrying cost rate of 4%, effective October 1,
2009, to be applied to the incremental deferred regulatory asset balance that
will result from the phase-in plan.  The order disallowed an
immaterial amount of deferred ENEC costs which was recognized in September
2009.  It also lowered annual coal cost projections by $27 million and
deferred recovery of unrecovered ENEC deferrals related to price increases on
certain renegotiated coal contracts.  The WVPSC indicated that it
would review the prudency of these additional costs in the next ENEC
proceeding.  As of September 30, 2009, APCo has deferred $13 million
of unrecovered coal costs on the renegotiated coal contracts which is included
in APCo’s $255 million ENEC under-recovery regulatory asset and has an
additional $5 million in purchased fuel costs on the renegotiated coal contracts
which is recorded in Fuel on the Condensed Consolidated Balance
Sheets.  Although management believes the portion of its deferred ENEC
under-recovery balance attributable to renegotiated coal contracts is probable
of recovery, if the WVPSC were to disallow a portion of APCo’s and WPCo’s
deferred ENEC costs including any costs incurred in the future related to the
renegotiated coal contracts, it could 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 with 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 the 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 with the WVPSC.  In September 2009, the WVPSC
removed the IGCC case as an active case from its docket and indicated that the
conditional CPCN granted in 2008 must be reconsidered if and when APCo proceeds
forward with the IGCC plant.





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
September 30, 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 applicable to its Virginia jurisdiction.





Although
management continues to pursue consideration of 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, which if not recoverable, would have an adverse effect on future net
income and cash flows.





Mountaineer
Carbon Capture and Storage Project





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





Kentucky Rate
Matters





Kentucky
Storm Restoration Expenses





During
2009, KPCo experienced severe storms causing significant customer
outages.  In August 2009, KPCo filed a petition with the Kentucky
Public Service Commission (KPSC) for an order seeking authorization to defer
approximately $10 million of incremental storm restoration expense for review
and recovery in KPCo’s next base rate proceeding.  The requested
deferral of the previously expensed $10 million is in addition to the annual $2
million of storm-related operation and maintenance expense included in KPCo’s
current base rates.  Management is unable to predict the outcome of
this petition.  A decision is expected from the KPSC during the fourth
quarter of 2009.





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 based on
a return on equity of 11.5%.  The base rate increase included a $69
million annual reduction in rates due to an approved 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 its 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 the depreciation rate reduction in the development of
an agreed to revenue increase of $44 million, which included a $22 million
increase in base rates based on an authorized return on equity of 10.5% and a
$22 million initial increase in tracker rates for incremental PJM, net emission
allowance and demand side management (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
Plant.





In March
2009, the IURC modified and approved the settlement agreement that provides for
an annual increase in revenues of $42 million.  The $42 million
increase included a $19 million increase in base rates, net of the depreciation
rate reduction and a $23 million increase in tracker revenue.  The
IURC order modified the settlement agreement by removing from base rates the
recovery of DSM costs, establishing a tracker with an initial zero amount for
DSM costs, requiring I&M to collaborate with other affected parties
regarding the design and recovery of future I&M DSM programs, adjusting the
sharing of off-system sales margins to 50% above $37.5 million which it included
in base rates and approving the recovery of $7 million of previously expensed
NSR and OPEB costs which favorably affected 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. The new rates were implemented in March
2009.





Rockport
and Tanners Creek Plants Environmental Facilities





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
requested 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.  The petition requested to depreciate the ACI systems
over an accelerated 10-year period and the SNCR systems over the 11-year
remaining useful life of the Tanners Creek generating units.





I&M’s
petition also requested the IURC to approve a rate adjustment mechanism for
unrecovered carrying costs during the remaining construction period of these
environmental facilities and a return on investment, depreciation expense and
operation and maintenance costs, including consumables and new emission
allowance costs, once the facilities are placed in service.  I&M
also requested the IURC to authorize the deferral of the remaining construction
period carrying costs and any in-service cost of service for these facilities
until such costs can be recovered in the requested rate adjustment
mechanism.  Through September 30, 2009, I&M incurred $12 million
and $12 million in capitalized facilities cost related to the Rockport and
Tanners Creek Plants, respectively, which are included in
CWIP.  Subsequent to the filing of this petition, the Indiana base
rate order included recovery of emission allowance costs.  Therefore,
that portion of the emission allowances cost for the subject facilities will not
be recovered in this requested rate adjustment mechanism.





In May
2009, a settlement agreement (settlement) was filed with the IURC recommending
approval of a CPCN and a rider to recover a weighted average cost of capital on
I&M’s investment in the SNCR system and the ACI system at December 31, 2008,
plus future depreciation and operation and maintenance costs.  The
settlement will allow I&M to file subsequent requests in six month intervals
to update the rider for additional investments in the SNCR systems and the ACI
systems and for true-ups of the rider revenues to actual costs.  In
June 2009, the IURC approved the settlement which will result in an annualized
increase in rates of $8 million effective August 1, 2009.





Indiana
Fuel Clause Filing (Cook Plant Unit 1 Fire and Shutdown)





In
January 2009, I&M filed with the IURC an application to increase its fuel
adjustment charge by approximately $53 million for the period of April through
September 2009.  The filing included an under-recovery for the period
ended November 2008, mainly as a result of deferred under-recovered fuel costs,
the shutdown of the Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused
by blade failure, which resulted in a fire and a projection for the future
period of fuel costs increases including Unit 1 shutdown replacement power
costs.  See “Cook Plant Unit 1 Fire and Shutdown” section of Note
4.  The filing also included an adjustment, beginning coincident with
the receipt of accidental outage insurance proceeds in mid-December 2008, to
eliminate the incremental fuel cost of replacement power post mid-December 2008
with a portion of the insurance proceeds from the accidental outage
policy.  I&M reached an agreement in February 2009 with
intervenors, which was approved by the IURC in March 2009, to collect the prior
period under-recovery deferral balance over twelve months instead of over six
months as proposed.  Under the agreement, the fuel factor was placed
into effect, subject to refund, and a subdocket was established to consider
issues relating to the Unit 1 shutdown, the use of the insurance proceeds and
I&M’s fuel procurement practices.  The order also provided for the
shutdown issues to be resolved subsequent to the date Unit 1 returns to service,
which if temporary repairs are successful, could occur as early as the fourth
quarter of 2009.





Consistent
with the March 2009 IURC order, I&M made its semi-annual fuel filing in July
2009 requesting an increase of approximately $4 million for the period October
2009 through March 2010.  The projected fuel costs for the period
included the second half of the under-recovered deferral balance approved in the
March 2009 order plus recovery of an additional $12 million under-recovered
deferral balance from the reconciliation period of December 2008 through May
2009.





In August
2009, an intervenor filed testimony proposing that I&M should refund
approximately $11 million through the fuel adjustment clause, which is the
intervenor’s estimate of the Indiana retail jurisdictional portion of the
additional fuel cost during the accidental outage insurance policy deductible
period, which is the period from the date of the incident in September 2008 to
when the insurance proceeds began in December 2008.  In August 2009,
I&M and intervenors filed a settlement agreement with the IURC that included
the recovery of the $12 million under-recovered deferral balance, subject to
refund, over twelve months instead of over six months as originally proposed and
an agreement to delay all Unit 1 outage issues in this filing until after the
unit is returned to service.





Management
cannot predict the outcome of the pending proceedings, including the treatment
of the outage insurance proceeds, and whether any fuel clause revenues or
insurance proceeds will have to be refunded which could adversely affect future
net income and cash flows.





Michigan Rate
Matters





2008
Power Supply Cost Recovery (PSCR) Reconciliation (Cook Plant Unit 1 Fire and
Shutdown)





In March
2009, I&M filed with the Michigan Public Service Commission (MPSC) its 2008
PSCR reconciliation.  The filing also included an adjustment to reduce
the incremental fuel cost of replacement power due to the Cook Plant Unit 1
outage with a portion of the accidental insurance proceeds from the Cook Plant
Unit 1 outage policy, which began in mid-December 2008.  See “Cook
Plant Unit 1 Fire and Shutdown” section of Note 4.  In May 2009, the
MPSC set a procedural schedule for testimony and hearings to be held in the
fourth quarter of 2009.  A final order is anticipated in the first
quarter of 2010.  Management is unable to predict the outcome of this
proceeding and whether it will have an adverse 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 two issues.  The first issue relates to the allocation of
off-system sales margins (OSS) among the AEP operating companies in accordance
with a FERC-approved allocation agreement.  In June 2008, the Oklahoma
Industrial Energy Consumers (OIEC) appealed the ALJ recommendations that
concluded the FERC and not the OCC had jurisdiction over this
matter.  In August 2008, the OCC filed a complaint with the FERC
concerning this allocation of OSS issue.  In December 2008, under an
adverse FERC ruling, PSO recorded a regulatory liability to return the
reallocated OSS to customers.  Effective with the March 2009 billing
cycle, PSO began refunding the additional reallocated OSS to its
customers.  See “Allocation of Off-system Sales Margins” section
within “FERC Rate Matters.”





The
second issue concerns a 2002 under-recovery of $42 million of PSO 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 the June 2008 appeal by the OIEC of the ALJ
recommendations, the OIEC contended that PSO should not have collected the $42
million without specific OCC approval nor collected the $42 million before the
OSS allocation issue was resolved.  As such, the OIEC contends that
the OCC could and should require PSO to refund the $42 million it collected
through its fuel clause.  In August 2008, the OCC heard the OIEC
appeal and a decision is pending.  Although the OSS allocation issue
has been resolved at the FERC, if the OCC were to order PSO to make an
additional refund for all or a part of the $42 million, it would have an adverse
effect on future net income and cash flows.





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.  In August 2009, a
joint stipulation and settlement agreement (settlement) was filed with the OCC
requesting the OCC to issue an order accepting the fuel adjustment clause for
2007 and find that PSO’s fuel procurement practices, policies and decisions were
prudent.  In September 2009, the OCC issued a final order approving
the settlement.





2008
Oklahoma Base Rate Filing Appeal





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.  At the
time of the filing, PSO was recovering $16 million a year for 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 terminates and PSO recovers 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 based on 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 provided for the deferral of $6
million of generation maintenance expenses to be recovered over a six-year
period.  The deferral was recorded in the first quarter of
2009.  PSO was given authority to record additional under/over
recovery deferrals for future 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.  During 2009, PSO
accrued a regulatory liability of approximately $1 million related to a delay in
installing gridSMART technologies as the OCC final order had included $2 million
of additional revenues for this purpose.





PSO filed
an appeal with the Oklahoma Supreme Court challenging an adjustment contained
within the OCC final order to remove prepaid pension fund contributions from
rate base.  In February 2009, the Oklahoma Attorney General and
several intervenors also filed appeals with the Oklahoma Supreme Court raising
several rate case issues.  In July 2009, the Oklahoma Supreme Court
assigned the case to the Court of Civil Appeals.  If the Oklahoma
Attorney General or the intervenors’ appeals are successful, it could have an
adverse effect on future net income and cash flows.





Oklahoma
Capital Reliability Rider Filing





In August
2009, PSO filed an application with the OCC requesting a Capital Reliability
Rider (CRR) to recover depreciation, taxes and return on PSO’s net capital
investments for generation, transmission and distribution assets that have been
placed into service from September 1, 2008 to June 30, 2009.  If
approved, PSO would increase billings to customers during the first six months
of 2010 by $11 million related to the increase in revenue requirement and $9
million related to the lag between the investment cut-off of June 30, 2009 and
the date of the rider implementation of January 1, 2010.





In
October 2009, all but two of the parties to the CRR filing agreed to a
stipulation that was filed with the OCC to collect no more than $30 million of
revenues under the CRR on an annual basis beginning January 2010 until PSO’s
next base rate order.  The CRR revenues are subject to refund with
interest pending the OCC’s audit.  The stipulation also provides for
an offsetting fuel revenue reduction via a modification to the fuel adjustment
factor of Oklahoma jurisdictional customers on an annual basis by $30 million
beginning January 2010 and refunds of certain over-recovered fuel balances
during the first quarter of 2010.  Finally, the stipulation requires
that PSO shall file a base rate case no later than July
2010.  Management is unable to predict the outcome of this
application.





PSO
Purchase Power Agreement





As a
result of the 2008 Request for Proposals following a December 2007 OCC order
that found PSO had a need for new base load generation by 2012, PSO and Exelon
Generation Company LLC, a subsidiary of Exelon Corporation, executed a long-term
purchase power agreement (PPA).  The PPA is for the annual purchase of
approximately 520 MW of electric generation from the 795 MW natural gas-fired
generating plant in Jenks, Oklahoma for a term of approximately ten years
beginning in June 2012.  In May 2009, an application seeking approval
was filed with the OCC.  In July 2009, OCC staff, the Independent
Evaluator and the Oklahoma Industrial Energy Consumers filed responsive
testimony in support of PSO’s proposed PPA with Exelon.  In August
2009, a settlement agreement was filed with the OCC.  In September
2009, the OCC approved the settlement agreement including the recovery of these
purchased power costs through a separate base load purchased power
rider.





Louisiana Rate
Matters





2008
Formula Rate Filing





In April
2008, SWEPCo filed its first formula rate filing under an approved three-year
formula rate plan (FRP).  SWEPCo requested an increase in its annual
Louisiana retail rates of $11 million to be effective in August 2008 in order to
earn the approved formula return on common equity of 10.565%.  In
August 2008, as provided by the FRP, SWEPCo implemented the FRP rates, subject
to refund.  During 2009, SWEPCo recorded a provision for refund of
approximately $1 million after reaching a settlement in principle with
intervenors.  SWEPCo is currently working with the settlement parties
to prepare a written agreement to be filed with the LPSC.





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 effective in August 2009 pursuant to
the approved FRP.  SWEPCo implemented the FRP rate increase as filed
in August 2009, subject to refund.  In October 2009, consultants for
the LPSC objected to certain components of SWEPCo’s FRP
calculation.  The consultants also recommended refunding the SIA
through SWEPCo’s FRP.  See “Allocation of Off-system Sales Margins”
section within “FERC Rate Matters.”  SWEPCo will continue to work with
the LPSC regarding the issues raised in their objection.  SWEPCo
believes the rates as filed are in compliance with the FRP methodology
previously approved by the LPSC.  If the LPSC disagrees with SWEPCo,
it could result in material refunds.





Stall
Unit





In May
2006, SWEPCo announced plans to build an intermediate load, 500 MW, natural
gas-fired, combustion turbine, combined cycle generating unit at its existing
Arsenal Hill Plant location in Shreveport, Louisiana to be named the Stall
Unit.  SWEPCo submitted the appropriate filings to the LPSC, the PUCT,
the APSC and the Louisiana Department of Environmental Quality to seek approvals
to construct the Stall Unit.  The Stall Unit is currently estimated to
cost $435 million, including $49 million of 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 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 including AFUDC and
excluding related transmission costs.  In October 2008, the LPSC
issued a final order effectively approving the ALJ recommendation.  In
March 2007, the PUCT approved SWEPCo’s request for a certificate of necessity
for the facility based on a prior cost estimate.  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.  In June 2009, the APSC approved the
construction of the unit with a series of conditions consistent with those
designated by the LPSC, including a requirement for an independent monitor and a
$445 million cost cap including AFUDC and excluding related transmission
costs.





As of
September 30, 2009, SWEPCo has capitalized construction costs of $364 million,
including AFUDC, and has contractual construction commitments of an additional
$31million with
the total estimated cost to complete the unit at $435 million.  If the
final cost of the Stall Unit exceeds the $445 million cost cap, it could have an
adverse effect on net income and cash flows.  If for any other reason
SWEPCo cannot recover its capitalized costs, it would have an adverse effect on
future net income, cash flows and possibly financial condition.





Temporary
Funding of Financing Costs during Construction





In
October 2009, SWEPCo made a filing with the LPSC requesting temporary recovery
of financing costs related to the Louisiana jurisdiction portion of the Turk
Plant.  In the filing, SWEPCo would recover over three years of
an estimated $105 million of construction financing costs related to SWEPCo’s
ongoing Turk generation construction program through its existing Fuel
Adjustment Rider.  If approved as requested, recovery would start in
January 2010 and continue through 2012 when the Turk Plant is scheduled to be
placed in service.  According to the filing, the amount of financing
costs collected during construction would be refunded to customers, including
interest at SWEPCo’s long-term debt rate, after the Turk Plant is in
service.  As filed, the refund would occur over a period not to exceed
five years.  Finally, SWEPCo requested that both the Turk Plant and
the Stall Unit be placed in rates via the formula rate plan without regulatory
lag.  Management cannot predict the outcome of this
filing.





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.  In 2007, the Oklahoma
Municipal Power Authority (OMPA) acquired an approximate 7% ownership interest
in the Turk Plant, paid SWEPCo $13.5 million for its share of the accrued
construction costs and began paying its proportional share of ongoing costs.
During the first quarter of 2009, the Arkansas Electric Cooperative Corporation
(AECC) and the East Texas Electric Cooperative (ETEC) acquired ownership
interests in the Turk Plant representing approximately 12% and 8%, respectively,
paid SWEPCo $104 million in the aggregate for their shares of accrued
construction costs and began paying their proportional shares of ongoing
construction costs.  The joint owners are billed monthly for their
share of the on-going construction costs exclusive of AFUDC.  Through
September 30, 2009, the joint owners paid SWEPCo $196 million for their share of
the Turk Plant construction expenditures.  SWEPCo owns 73% of the Turk
Plant and will operate the completed facility.  The Turk Plant is
currently estimated to cost $1.6 billion, excluding AFUDC, with SWEPCo’s share
estimated to cost $1.2 billion, excluding AFUDC.  In addition, SWEPCo
will own 100% of the related transmission facilities which are currently
estimated to cost $131 million, excluding AFUDC.





In
November 2007, the APSC granted approval for SWEPCo to build the Turk Plant in
Arkansas by issuing a Certificate of Environmental Compatibility and Public Need
(CECPN).  Certain intervenors appealed the APSC’s decision to grant
the CECPN to the Arkansas Court of Appeals.  In January 2009, the APSC
granted additional CECPNs allowing SWEPCo to construct Turk-related transmission
facilities.  Intervenors also appealed these CECPN orders to the
Arkansas Court of Appeals.





In June
2009, the Arkansas Court of Appeals issued a unanimous decision that, if upheld
by the Arkansas Supreme Court, would reverse the APSC’s grant of the CECPN
permitting construction of the Turk Plant to serve Arkansas retail
customers.  The decision was based upon the Arkansas Court of Appeals’
interpretation of the statute that governs the certification process and its
conclusion that the APSC did not fully comply with that process.  The
Arkansas Court of Appeals concluded that SWEPCo’s need for base load capacity,
the construction and financing of the Turk generating plant and the proposed
transmission facilities’ construction and location should all have been
considered by the APSC in a single docket instead of separate
dockets.  In October 2009, the Arkansas Supreme Court granted the
petitions filed by SWEPCo and the APSC to review the Arkansas Court of Appeals
decision.  While the appeal is pending, SWEPCo is continuing
construction of the Turk Plant.





If the
decision of the Court of Appeals is not reversed by the Supreme Court of
Arkansas, SWEPCo and the other joint owners of the Turk Plant will evaluate
their options.  Depending on the time taken by the Arkansas Supreme
Court to consider the case and the reasoning of the Arkansas Supreme Court when
it acts on SWEPCo’s and the APSC’s petitions, the construction schedule and/or
the cost could be adversely affected.  Should the appeals by the APSC
and SWEPCo be unsuccessful, additional proceedings or alternative contractual
ownership and operational responsibilities could be required.





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 and related transmission costs, (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 as
being unlawful.  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. If the cost cap restrictions are upheld and construction or CO2 emission
costs exceed the restrictions or if the intervenor appeal is successful, it
could have an adverse effect on net income, cash flows and possibly financial
condition.


A request
to stop pre-construction activities at the site was filed in Federal District
Court by certain 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, which was granted in March 2009.





In
November 2008, SWEPCo received the required air permit approval from the
Arkansas Department of Environmental Quality and commenced construction at the
site.  In December 2008, certain parties filed an appeal of the air
permit approval 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 the appeal of the Turk Plant’s air permit is
heard.  In June 2009, hearings on the air permit appeal were held at
the APCEC.  A decision is still pending and not expected until
2010.  These same parties have filed a petition with the Federal EPA
to review the air permit.  The petition will be acted on by December
2009, according to the terms of a recent settlement between the petitioners and
the Federal EPA.  The Turk Plant cannot be placed into service without
an air permit.  In August 2009, these same parties filed a petition
with the APCEC to halt construction of the Turk Plant.  In September
2009, the APCEC voted to allow construction of the Turk Plant to continue and
rejected the request for a stay.  If the air permit were to be
remanded or ultimately revoked, construction of the Turk Plant would be
suspended or cancelled.





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 an inadvertent impact on approximately 2.5
acres of wetlands at the Turk Plant construction site prior to the receipt of
the permit.  The U.S. Army Corps of Engineers directed SWEPCo to cease
further work impacting the wetland areas.  Construction has continued
on other areas outside of the proposed Army Corps of Engineers permitted areas
of the Turk Plant pending the Army Corps of Engineers review.  SWEPCo
has entered into a Consent Agreement and Final Order with the Federal EPA to
resolve liability for the inadvertent impact and agreed to pay a civil penalty
of approximately $29 thousand.





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.  To date, the
report’s effect is only advisory, but if legislation is passed as a result of
the findings in the Commission’s report, it could impact SWEPCo’s ability to
complete construction on schedule in 2012 and on budget.





If the
Turk Plant cannot be completed and placed in service, SWEPCo would seek approval
to recover its prudently incurred capitalized construction costs including any
cancellation fees and a return on unrecovered balances through rates in all of
its jurisdictions.  As of September 30, 2009, and excluding costs
attributable to its joint owners, SWEPCo has capitalized approximately $646
million of expenditures (including AFUDC and capitalized interest, and related
transmission costs of $24 million).  As of September 30, 2009, the
joint owners and SWEPCo have contractual construction commitments of
approximately $515 million (including related transmission costs of $1 million)
and, if the plant had been cancelled, would have incurred cancellation fees of
$136million
(including related transmission cancellation fees of $1 million).





Management
believes that SWEPCo’s planning, certification and construction of the Turk
Plant to date have been in material compliance with all applicable laws and
regulations, except for the inadvertent wetlands intrusion discussed
above.  Further, management expects that SWEPCo will ultimately be
able to complete construction of the Turk Plant and related transmission
facilities and place those facilities in service.  However, if for any
reason SWEPCo is unable to complete the Turk Plant construction and place the
Turk Plant in service, it would adversely impact net income, cash flows and
possibly financial condition unless the resultant losses can be fully recovered,
with a return on unrecovered balances, through rates in all of its
jurisdictions.





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 Unit and Turk Plant.





In
September 2009, SWEPCo, the APSC staff and the Arkansas Attorney General entered
into a settlement agreement in which the settling parties agreed to an $18
million increase based on a return on equity of 10.25%.  In addition,
the settlement agreement will decrease depreciation expense by $10
million.  The settlement agreement would increase SWEPCo’s annual
pretax income by approximately $28 million.  The settlement agreement
also includes a separate rider of approximately $11 million annually that will
allow SWEPCo to recover carrying costs, depreciation and operation and
maintenance expenses on the Stall Unit once it is placed into
service.  Until then, SWEPCo will continue to accrue AFUDC on the
Stall Unit.  The other parties to the case do not oppose the
settlement agreement.  If the settlement agreement is approved by the
APSC, new base rates will become effective for all bills rendered on or after
November 25, 2009.





In
January 2009, an ice storm struck in northern Arkansas affecting SWEPCo’s
customers.  SWEPCo incurred incremental operation and maintenance
expenses above the estimated amount of storm restoration costs included in
existing base rates.  In May 2009, SWEPCo filed an application with
the APSC seeking authority to defer $4 million (later adjusted to $3 million) of
expensed incremental operation and maintenance costs and to address the recovery
of these deferred expenses in the pending base rate case.  In July
2009, the APSC issued an order approving the deferral request subject to
investigation, analysis and audit of the costs.  In August 2009, the
APSC staff filed testimony that recommended recovery of approximately $1 million
per year through amortization of the deferred ice storm costs over three years
in base rates.  This amount was included in the $18 million base rate
increase agreed upon in the settlement agreement.  In September 2009,
based upon the APSC audit and recommendation, management established a
regulatory asset of $3 million for the recovery of the ice storm restoration
costs.





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 refund of a portion or all of the 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 September 30, 2009 was $34 million.  As of September 30, 2009,
there were no in-process settlements.





Management
cannot predict the ultimate outcome of future settlement discussions or future
FERC proceedings or court appeals, if any.  However, 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 cannot be settled and 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.





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 even though other non-affiliated entities transmit
power over AEP’s lines.  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.  In August 2009, the United States Court of Appeals issued
an opinion affirming FERC’s refusal to implement a regional rate design in
PJM.





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.  The AEP East companies sought and received retail rate
increases in Ohio, Virginia, West Virginia and Kentucky.  In January
and March 2009, the AEP East companies received retail rate increases in
Tennessee and Indiana, respectively, which recognized the higher retail
transmission costs resulting from the loss of wholesale transmission revenues
from T&O transactions.  As a result, the AEP East companies are
now recovering approximately 98% of the lost T&O transmission revenues from
their retail customers.  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 the AEP East companies’
transmission by others in PJM and MISO and as a result the use of zonal rates
would be unfair and discriminatory to AEP’s East zone retail
customers.  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 wholesale transmission T&O revenues
reduction of transmission cost to retail customers.  This case is
pending before the U.S. Court of Appeals which in August 2009 ruled against AEP
in a similar case.  See “The FERC PJM Regional Transmission Rate
Proceeding” section above.





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.  Following authorized regulatory treatment, the AEP West
companies shared a portion of SIA margins with their customers during the period
June 2000 to March 2006.  In December 2008, the AEP West companies
recorded a provision for refund reflecting the sharing.  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.





In April
2009, TCC and TNC filed their Advanced Metering System (AMS) with the PUCT
proposing to invest in AMS to be recovered through customer surcharges beginning
in October 2009.  In the filing, TCC and TNC proposed to apply the SIA
recorded customer refunds including interest to reduce the AMS investment and
the resultant associated customer surcharge.  In July 2009,
consultants for the LPSC issued an audit report of SWEPCo’s Louisiana retail
fuel adjustment clause.  Within this report, the consultants for the
LPSC recommended that SWEPCo refund the SIA, including interest, through the
fuel adjustment clause.  In October 2009, other consultants for the
LPSC recommended refunding the SIA through SWEPCo’s formula rate
plan.  See “2009 Formula Rate Filing” section within “Louisiana 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 related future state regulatory proceedings is
adequate.





Modification
of the Transmission Agreement (TA)





APCo,
CSPCo, I&M, KPCo and OPCo are parties to the TA entered into in 1984, as
amended, that provides for a sharing of the cost of transmission lines operated
at 138-kV and above and transmission stations operated at 345kV and
above.  In June 2009, AEPSC, on behalf of the parties to the TA, filed
with the FERC a request to modify the TA.  Under the proposed
amendments, WPCo and KGPCo will be added as parties to the TA.  In
addition, the amendments would provide for the allocation of PJM transmission
costs on the basis of the TA parties’ 12-month coincident peak and reimburse the
majority of PJM transmission revenues based on individual cost of service
instead of the MLR method used in the present TA.  AEPSC requested the
effective date to be the first day of the month following a final non-appealable
FERC order.  The delayed effective date was approved by the FERC in
August 2009 when the FERC accepted the new TA for filing.  Settlement
discussions are in process.  Management is unable to predict the
effect, if any, it will have on future net income and cash flows due to timing
of the implementation by various state regulators of the FERC’s new approved
TA.





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 for guarantees in accordance with the accounting
guidance for “Guarantees.”  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 September 30,
2009, the maximum future payments for all the LOCs issued under the two $1.5
billion credit facilities are approximately $98 million with maturities ranging
from October 2009 to July 2010.





We have a
$627 million 3-year credit agreement.  As of September 30, 2009, $372
million of letters of credit with maturities ranging from May 2010 to June 2010
were issued by subsidiaries under the $627 million 3-year credit agreement to
support variable rate Pollution Control Bonds.  We had a $350 million
364-day credit agreement that expired in April 2009.





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), a consolidated variable interest entity.  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.  A new
study is in process to include new, expanded areas of the mine.  As of
September 30, 2009, SWEPCo has collected approximately $42 million through a
rider for final mine closure and reclamation costs, of which $2 million is
recorded in Other Current Liabilities, $23 million is recorded in Deferred
Credits and Other Noncurrent Liabilities and $17 million is recorded in Asset
Retirement Obligations on our 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





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 sale 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 $1.1
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 $439 million and is
recorded in Deferred Credits and Other Noncurrent Liabilities on our Condensed
Consolidated Balance Sheets as of September 30, 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 September 30, 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 $19 million for
I&M and $22 million for SWEPCo for the remaining railcars as of September
30, 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
a unit jointly owned by CSPCo, Dayton Power and Light Company and Duke Energy
Ohio, Inc. at the Beckjord Station was modified in violation of the NSR
requirements of the CAA.





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.  Following a second liability trial, the jury again
found no liability at the jointly-owned Beckjord unit.  In 2009, the
defendants and the plaintiffs filed appeals.  Beckjord is operated by
Duke Energy Ohio, Inc.





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.  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
GHG under the CAA.  The Second Circuit requested supplemental briefs
addressing the impact of the U.S. Supreme Court’s decision on this
case.





In
September 2009, the Second Circuit Court issued a ruling vacating the dismissal
and remanding the case to the Federal District Court for the Southern District
of New York.  The Second Circuit held that the issues of climate
change and global warming do not raise political questions and that Congress’
refusal to regulate GHG emissions does not mean that plaintiffs must wait for an
initial policy determination by Congress or the President’s administration to
secure the relief sought in their complaints.  The court stated that
Congress could enact comprehensive legislation to regulate CO2 emissions
or that the Federal EPA could regulate CO2 emissions
under existing CAA authorities, and that either of these actions could override
any decision made by the district court under federal common law.  The
Second Circuit did not rule on whether the plaintiffs could proceed with their
state common law nuisance claims.  We believe the actions are without
merit and intend to continue to defend against the claims including seeking
further review by the Second Circuit and, if necessary, the United States
Supreme Court.





In
October 2009, the Fifth Circuit Court of Appeals reversed a decision by the
Federal District Court for the District of Mississippi dismissing state common
law nuisance claims in a putative class action by Mississippi residents
asserting that GHG emissions exacerbated the effects of Hurricane
Katrina.  The Fifth Circuit held that there was no exclusive
commitment of the common law issues raised in plaintiffs’ complaint to a
coordinate branch of government, and that no initial policy determination was
required to adjudicate these claims.  We were initially dismissed from
this case without prejudice, but are named as a defendant in a pending fourth
amended complaint.





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
and 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.  In October 2009, the
judge dismissed plaintiffs’ federal common law claim for nuisance, finding the
claim barred by the political question doctrine and by plaintiffs’ lack of
standing to bring the claim.  The judge also dismissed plaintiffs’
state law claims without prejudice to refiling in state court.





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 $7 million in
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 and 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, 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.  I&M is repairing
Unit 1 to resume operations as early as the fourth quarter of 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 September 30, 2009, we recorded $122 million in
Prepayments and Other Current Assets on our Condensed Consolidated Balance
Sheets representing recoverable amounts under the property insurance
policy.  Through September 30, 2009, I&M received partial payments
of $72 million 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 2009, I&M
recorded $145 million in revenue and applied $59 million of the accidental
outage insurance proceeds to reduce customer bills.





NEIL is
reviewing claims made under the insurance policies to ensure that claims
associated with the outage are covered by the policies.  The treatment
of property damage costs, replacement power costs and insurance proceeds will be
the subject of future regulatory proceedings in Indiana and
Michigan.  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 or if any future regulatory
proceedings are adverse, it could have an adverse impact on net income, cash
flows and financial condition.





Fort
Wayne Lease





Since
1975 I&M has leased certain energy delivery assets from the City of Fort
Wayne, Indiana under a long-term lease that expires on February 28,
2010.  I&M has been negotiating with Fort Wayne to purchase the
assets at the end of the lease, but no agreement has been
reached.  Recent mediation with Fort Wayne was also
unsuccessful.  Fort Wayne issued a technical notice of default under
the lease to I&M in August 2009.  I&M responded to Fort Wayne
in October 2009 that it did not agree there was a default under the
lease.  In October 2009, I&M filed for declaratory and injunctive
relief in Indiana state court. I&M will seek
recovery in rates for any amount it may pay related to this
dispute.  At this time, management cannot predict the outcome of this
dispute or its potential impact on net income or cash flows.





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 pretax 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 on all claims,
including those that were pending trial in Texas, granting BOA summary judgment
and dismissing 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.  In May 2009, the judge
awarded $20 million of attorneys’ fees to BOA.  We appealed this award
and posted bond covering that amount.  In September 2009, the United
States Court of Appeals for the Second Circuit heard oral argument on our appeal
of the lower court’s decision.


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 $439 million and $433 million including interest at
September 30, 2009 and December 31, 2008, respectively.  These
liabilities are included in Deferred Credits and Other Noncurrent Liabilities 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.  In July 2009, at the plaintiff’s request, the court
ordered, without prejudice, the dismissal of the intervening plaintiff’s claims
and the withdrawal of the motion to certify a class.  We will continue
to defend against the remaining claim.





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.  Trial is scheduled for December 2009.  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.  In September 2009, the parties
reached a settlement.  We reversed a portion of a provision recorded
in 2008.





5.       ACQUISITIONS AND
DISCONTINUED OPERATIONS





ACQUISITIONS





2009





Oxbow
Mine Lignite (Utility Operations segment)





In April
2009, SWEPCo agreed to purchase 50% of the Oxbow Mine lignite reserves for $13
million and DHLC agreed to purchase 100% of all associated mining equipment and
assets for $16 million from the North American Coal Corporation and its
affiliates, Red River Mining Company and Oxbow Property Company,
LLC.  Cleco Power LLC (Cleco) will acquire the remaining 50% interest
in the lignite reserves for $13 million.  SWEPCo expects to complete
the transaction in the fourth quarter of 2009.  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.





2008





Erlbacher
companies (AEP River Operations segment)





In June
2008, AEP River Operations purchased certain barging assets from Missouri Barge
Line Company, Missouri Dry Dock and Repair Company and Cape Girardeau Fleeting,
Inc. (collectively known as Erlbacher companies) for $35
million.  These assets were incorporated into AEP River’s operations
diversifying its customer base.





DISCONTINUED
OPERATIONS





We
determined that certain of our operations were discontinued operations and
classified them as such for all periods presented.  We recorded the
following amounts in 2009 and 2008 related to discontinued
operations:





U.K. Generation (a)Three
      Months Ended September 30,
            
            (in
      millions)2009
      Revenue
            
            $
            -2009
      Pretax Income
            
            
            -2009
      Earnings, Net of Tax
            
            
            -2008
      Revenue
            
            $
            -2008
      Pretax Income
            
            
            -2008
      Earnings, Net of Tax
            
            
            -





U.K. Generation (a)Nine
      Months Ended September 30,
            
            (in
      millions)2009
      Revenue
            
            $
            -2009
      Pretax Income
            
            
            -2009
      Earnings, Net of Tax
            
            
            -2008
      Revenue
            
            $
            -2008
      Pretax Income
            
            
            22008
      Earnings, Net of Tax
            
            
            1





(a)
            The
      2008 amounts relate to final proceeds received for the sale of land
      related to the sale of U.K.
Generation.





There
were no cash flows used for or provided by operating, investing or financing
activities related to our discontinued operations for the nine months ended
September 30, 2009 and 2008.





6.       BENEFIT
PLANS





Components
of Net Periodic Benefit Cost





The
following tables provide the components of our net periodic benefit cost for the
plans for the three and nine months ended September 30, 2009 and
2008:





Other
      PostretirementPension
      Plans
            
            Benefit
      PlansThree
      Months Ended September 30,
            
            Three
      Months Ended September 30,2009
            
            2008
            
            2009
            
            2008(in
      millions)Service
      Cost
            
            $
            26
            
            
            $
            25
            
            
            $
            11
            
            
            $
            10Interest
      Cost
            
            
            64
            
            
            
            62
            
            
            
            27
            
            
            
            28Expected
      Return on Plan Assets
            
            
            (80
            )
            
            
            (84
            )
            
            
            (21
            )
            
            
            (27
            )Amortization
      of Transition Obligation
            
            
            -
            
            
            
            -
            
            
            
            7
            
            
            
            7Amortization
      of Net Actuarial Loss
            
            
            14
            
            
            
            10
            
            
            
            11
            
            
            
            3Net
      Periodic Benefit Cost
            
            $
            24
            
            
            $
            13
            
            
            $
            35
            
            
            $
            21





Other
      PostretirementPension
      Plans
            
            Benefit
      PlansNine
      Months Ended September 30,
            
            Nine
      Months Ended September 30,2009
            
            2008
            
            2009
            
            2008(in
      millions)Service
      Cost
            
            $
            78
            
            
            $
            75
            
            
            $
            32
            
            
            $
            31Interest
      Cost
            
            
            191
            
            
            
            187
            
            
            
            82
            
            
            
            84Expected
      Return on Plan Assets
            
            
            (241
            )
            
            
            (252
            )
            
            
            (61
            )
            
            
            (83
            )Amortization
      of Transition Obligation
            
            
            -
            
            
            
            -
            
            
            
            20
            
            
            
            21Amortization
      of Net Actuarial Loss
            
            
            44
            
            
            
            29
            
            
            
            32
            
            
            
            8Net
      Periodic Benefit Cost
            
            $
            72
            
            
            $
            39
            
            
            $
            105
            
            
            $
            61





7.       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.





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 and nine
months ended September 30, 2009 and 2008 and balance sheet information as of
September 30, 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 September 30, 2009Revenues
      from:External
      Customers
            
            $
            3,364
            (d)
            $
            113
            
            $
            68
            
            $
            2
            
            $
            -
            
            $
            3,547Other
      Operating Segments
            
            
            25
            (d)
            
            4
            
            
            -
            
            
            1
            
            
            (30)
            
            
            -Total
      Revenues
            
            $
            3,389
            
            $
            117
            
            $
            68
            
            $
            3
            
            $
            (30)
            
            $
            3,547Income
      (Loss) Before Discontinued Operations and Extraordinary
    Loss
            
            $
            448
            
            $
            10
            
            $
            5
            
            $
            (17)
            
            $
            -
            
            $
            446Extraordinary
      Loss, Net of Tax
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Net
      Income (Loss)
            
            
            448
            
            
            10
            
            
            5
            
            
            (17)
            
            
            -
            
            
            446Less:
      Net Income Attributable to Noncontrolling Interests
            
            
            2
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            2Net
      Income (Loss) Attributable to AEP Shareholders
            
            
            446
            
            
            10
            
            
            5
            
            
            (17)
            
            
            -
            
            
            444Less:
      Preferred Stock Dividend Requirements of Subsidiaries
            
            
            1
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            1Earnings
      (Loss) Attributable to AEP Common Shareholders
            
            $
            445
            
            $
            10
            
            $
            5
            
            $
            (17)
            
            $
            -
            
            $
            443





Nonutility
      OperationsUtility
      Operations
            
            AEP
      River
              Operations
            
            Generation
              and
              Marketing
            
            All
      Other (a)
            
            Reconciling
      Adjustments
            
            Consolidated(in
      millions)Three
      Months Ended September 30, 2008Revenues
      from:External
      Customers
            
            $
            4,108
            (d)
            $
            160
            
            $
            1
            
            $
            (78)
            
            $
            -
            
            $
            4,191Other
      Operating Segments
            
            
            (140)
            (d)
            
            7
            
            
            95
            
            
            83
            
            
            (45)
            
            
            -Total
      Revenues
            
            $
            3,968
            
            $
            167
            
            $
            96
            
            $
            5
            
            $
            (45)
            
            $
            4,191Income
      (Loss) Before Discontinued Operations and Extraordinary
      Loss
            
            $
            359
            
            $
            11
            
            $
            16
            
            $
            (10)
            
            $
            -
            
            $
            376Discontinued
      Operations, Net of Tax
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Net
      Income (Loss)
            
            
            359
            
            
            11
            
            
            16
            
            
            (10)
            
            
            -
            
            
            376Less:
      Net Income Attributable to Noncontrolling Interests
            
            
            1
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            1Net
      Income (Loss) Attributable to AEP Shareholders
            
            
            358
            
            
            11
            
            
            16
            
            
            (10)
            
            
            -
            
            
            375Less:
      Preferred Stock Dividend Requirements of Subsidiaries
            
            
            1
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            1Earnings
      (Loss) Attributable to AEP Common Shareholders
            
            $
            357
            
            $
            11
            
            $
            16
            
            $
            (10)
            
            $
            -
            
            $
            374





Nonutility
      OperationsUtility
      Operations
            
            AEP
      River
              Operations
            
            Generation
              and
              Marketing
            
            All
      Other (a)
            
            Reconciling
      Adjustments
            
            Consolidated(in
      millions)Nine
      Months Ended September 30, 2009Revenues
      from:External
      Customers
            
            $
            9,666
            (d)
            $
            341
            
            $
            213
            
            $
            (13)
            
            $
            -
            
            $
            10,207Other
      Operating Segments
            
            
            46
            (d)
            
            13
            
            
            6
            
            
            28
            
            
            (93)
            
            
            -Total
      Revenues
            
            $
            9,712
            
            $
            354
            
            $
            219
            
            $
            15
            
            $
            (93)
            
            $
            10,207Income
      (Loss) Before Discontinued Operations and Extraordinary
    Loss
            
            $
            1,121
            
            $
            22
            
            $
            33
            
            $
            (45)
            
            $
            -
            
            $
            1,131Extraordinary
      Loss, Net of Tax
            
            
            (5)
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            (5)Net
      Income (Loss)
            
            
            1,116
            
            
            22
            
            
            33
            
            
            (45)
            
            
            -
            
            
            1,126Less:
      Net Income Attributable to Noncontrolling Interests
            
            
            5
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            5Net
      Income (Loss) Attributable to AEP Shareholders
            
            
            1,111
            
            
            22
            
            
            33
            
            
            (45)
            
            
            -
            
            
            1,121Less:
      Preferred Stock Dividend Requirements of Subsidiaries
            
            
            2
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            2Earnings
      (Loss) Attributable to AEP Common Shareholders
            
            $
            1,109
            
            $
            22
            
            $
            33
            
            $
            (45)
            
            $
            -
            
            $
            1,119





Nonutility
      OperationsUtility
      Operations
            
            AEP
      River
              Operations
            
            Generation
              and
              Marketing
            
            All
      Other (a)
            
            Reconciling
      Adjustments
            
            Consolidated(in
      millions)Nine
      Months Ended September 30, 2008Revenues
      from:External
      Customers
            
            $
            10,318
            (d)
            $
            442
            
            $
            409
            
            $
            35
            
            $
            -
            
            $
            11,204Other
      Operating Segments
            
            
            257
            (d)
            
            18
            
            
            (143)
            
            
            (17)
            
            
            (115)
            
            
            -Total
      Revenues
            
            $
            10,575
            
            $
            460
            
            $
            266
            
            $
            18
            
            $
            (115)
            
            $
            11,204Income
      Before Discontinued Operations and Extraordinary Loss
            
            $
            1,036
            
            $
            21
            
            $
            43
            
            $
            133
            
            $
            -
            
            $
            1,233Discontinued
      Operations, Net of Tax
            
            
            -
            
            
            -
            
            
            -
            
            
            1
            
            
            -
            
            
            1Net
      Income
            
            
            1,036
            
            
            21
            
            
            43
            
            
            134
            
            
            -
            
            
            1,234Less:
      Net Income Attributable to Noncontrolling Interests
            
            
            4
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            4Net
      Income Attributable to AEP Shareholders
            
            
            1,032
            
            
            21
            
            
            43
            
            
            134
            
            
            -
            
            
            1,230Less:
      Preferred Stock Dividend Requirements of Subsidiaries
            
            
            2
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            2Earnings
      Attributable to AEP Common Shareholders
            
            $
            1,030
            
            $
            21
            
            $
            43
            
            $
            134
            
            $
            -
            
            $
            1,228




Nonutility
      OperationsUtility
      Operations
            
            AEP
      River
              Operations
            
            Generation
              and
              Marketing
            
            All
      Other (a)
            
            Reconciling
      Adjustments
              (c)
            
            Consolidated(in
      millions)September
      30, 2009Total
      Property, Plant and Equipment
            
            $
            50,392
            
            $
            423
            
            $
            570
            
            $
            10
            
            $
            (237)
            
            $
            51,158Accumulated
      Depreciation and Amortization
            
            
            17,114
            
            
            84
            
            
            161
            
            
            8
            
            
            (30)
            
            
            17,337Total
      Property, Plant and Equipment – Net
            
            $
            33,278
            
            $
            339
            
            $
            409
            
            $
            2
            
            $
            (207)
            
            $
            33,821Total
      Assets
            
            $
            45,776
            
            $
            467
            
            $
            791
            
            $
            15,436
            
            $
            (15,277)
            (b)
            $
            47,193





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 andAmortization
            
            
            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 $(113) thousand and $(95) million for the
      three months ended September 30, 2009 and 2008, respectively, and $(6)
      million and $143 million for the nine months ended September 30, 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.





8.       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 risks 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 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 the
accounting guidance for “Derivatives and Hedging.”  Derivative risk
management contracts elected normal under the normal purchases and normal sales
scope exception are not subject to the requirements of this accounting
guidance.





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 September 30, 2009:





Notional
      Volume of Derivative InstrumentsSeptember
      30, 2009Unit
      ofPrimary
      Risk Exposure
            
            Volume
            
            Measure(in
      millions)Commodity:Power
            
            
            544
            
            MWHsCoal
            
            
            61
            
            TonsNatural
      Gas
            
            
            153
            
            MMBtuHeating
      Oil and Gasoline
            
            
            8
            
            GallonsInterest
      Rate
            
            $
            216
            
            USDInterest
      Rate and Foreign Currency
            
            $
            89
            
            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 and barge operations are exposed to 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





The
accounting guidance for “Derivatives and Hedging” 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 the accounting guidance for “Derivatives and Hedging,” 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
September 30, 2009 and December 31, 2008 balance sheets, we netted $29 million
and $11 million, respectively, of cash collateral received from third parties
against short-term and long-term risk management assets and $100 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 September 30,
2009:





Fair
      Value of Derivative Instruments
              September
      30, 2009Risk
      ManagementContracts
            
            Hedging
      ContractsInterest
      Rateand
      Foreign
            
            OtherBalance
      Sheet Location
            
            Commodity
      (a)
            
            Commodity
      (a)
            
            Currency
      (a)
            
            (a)
      (b)
            
            Total(in
      millions)Current
      Risk Management Assets
            
            
            $
            1,518
            
            
            $
            24
            
            
            $
            -
            
            
            $
            (1,242
            )
            
            $
            300Long-term
      Risk Management Assets
            
            
            
            828
            
            
            
            4
            
            
            
            -
            
            
            
            (453
            )
            
            
            379Total
      Assets
            
            
            
            2,346
            
            
            
            28
            
            
            
            -
            
            
            
            (1,695
            )
            
            
            679Current
      Risk Management Liabilities
            
            
            
            1,399
            
            
            
            24
            
            
            
            3
            
            
            
            (1,290
            )
            
            
            136Long-term
      Risk Management Liabilities
            
            
            
            643
            
            
            
            10
            
            
            
            2
            
            
            
            (505
            )
            
            
            150Total
      Liabilities
            
            
            
            2,042
            
            
            
            34
            
            
            
            5
            
            
            
            (1,795
            )
            
            
            286Total
      MTM Derivative Contract Net Assets (Liabilities)
            
            
            $
            304
            
            
            $
            (6
            )
            
            $
            (5
            )
            
            $
            100
            
            
            $
            393





(a)
            Derivative
      instruments within these categories are reported gross.  These
      instruments are subject to master netting agreements and are presented on
      the Condensed Consolidated Balance Sheet on a net basis in accordance with
      the accounting guidance for “Derivatives and Hedging.”(b)
            Amounts
      represent counterparty netting of risk management contracts, associated
      cash collateral in accordance with the accounting guidance for
      “Derivatives and Hedging” and dedesignated risk management
      contracts.


The table
below presents our activity of derivative risk management contracts for the
three and nine months ended September 30, 2009:





Amount
      of Gain (Loss) Recognized on
              Risk
      Management Contracts





Three
      Months Ended
            
            Nine
      Months EndedSeptember
      30, 2009
            
            September
      30, 2009Location
      of Gain (Loss)
            
            (in
      millions)Utility
      Operations Revenue
            
            
            $
            25
            
            
            $
            124Other
      Revenue
            
            
            
            1
            
            
            
            19Regulatory
      Assets
            
            
            
            (1
            )
            
            
            (2
            )Regulatory
      Liabilities
            
            
            
            49
            
            
            
            130Total
      Gain on Risk Management Contracts
            
            
            $
            74
            
            
            $
            271





Certain
qualifying derivative instruments have been designated as normal purchase or
normal sale contracts, as provided in the accounting guidance for “Derivatives
and Hedging.”  Derivative contracts that have been designated as
normal purchases or normal sales under that accounting guidance are not subject
to MTM accounting treatment and are recognized on 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 on 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 some 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 the accounting guidance for
“Regulated Operations.”





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 and nine months ended September 30, 2009,
we did not employ any fair value hedging strategies.  During the three
and nine months ended September 30, 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 on our Condensed Consolidated Statements of Income, or
Regulatory Assets or Regulatory Liabilities on our Condensed Consolidated
Balance Sheet, 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 and nine months ended September 30,
2009 and 2008, we recognized immaterial amounts 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 and nine
months ended September 30, 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 and nine months ended September 30, 2009, we
recognized a $1 million loss and a $6 million gain, respectively, in Interest
Expense related to hedge ineffectiveness on interest rate derivatives designated
as cash flow hedges.  During the three and nine months ended September
30, 2008, we recognized immaterial amounts in Interest Expense 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 on 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 and nine months ended September 30, 2009
and 2008, we recognized no hedge ineffectiveness related to this hedge
strategy.





The
following tables provide 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 for the three and nine months ended September
30, 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 September 30, 2009Commodity
            
            
            Interest
      Rate and Foreign Currency
            
            
            Total(in
      millions)Beginning
      Balance in AOCI as of July 1, 2009
            
            $
            6
            
            
            $
            (11
            )
            
            $
            (5
            )Changes
      in Fair Value Recognized in AOCI
            
            
            (6
            )
            
            
            (4
            )
            
            
            (10
            )Amount
      of (Gain) or Loss Reclassified from AOCI  to Income
      Statement/within Balance SheetUtility
      Operations Revenue
            
            
            (7
            )
            
            
            -
            
            
            
            (7
            )Other
      Revenue
            
            
            (5
            )
            
            
            -
            
            
            
            (5
            )Purchased
      Electricity for Resale
            
            
            10
            
            
            
            -
            
            
            
            10Interest
      Expense
            
            
            -
            
            
            
            1
            
            
            
            1Regulatory
      Assets
            
            
            2
            
            
            
            -
            
            
            
            2Regulatory
      Liabilities
            
            
            (3
            )
            
            
            -
            
            
            
            (3
            )Ending
      Balance in AOCI as of September 30, 2009
            
            $
            (3
            )
            
            $
            (14
            )
            
            $
            (17
            )


Total
      Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow
      HedgesFor
      the Nine Months Ended September 30, 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
            
            
            (9
            )
            
            
            11
            
            
            
            2Amount
      of (Gain) or Loss Reclassified from AOCI  to Income
      Statement/within Balance SheetUtility
      Operations Revenue
            
            
            (13
            )
            
            
            -
            
            
            
            (13
            )Other
      Revenue
            
            
            (11
            )
            
            
            -
            
            
            
            (11
            )Purchased
      Electricity for Resale
            
            
            24
            
            
            
            -
            
            
            
            24Interest
      Expense
            
            
            -
            
            
            
            4
            
            
            
            4Regulatory
      Assets
            
            
            5
            
            
            
            -
            
            
            
            5Regulatory
      Liabilities
            
            
            (6
            )
            
            
            -
            
            
            
            (6
            )Ending
      Balance in AOCI as of September 30, 2009
            
            $
            (3
            )
            
            $
            (14
            )
            
            $
            (17
            )





Cash flow
hedges included in Accumulated Other Comprehensive Income (Loss) on our
Condensed Consolidated Balance Sheet at September 30, 2009 were:





Impact
      of Cash Flow Hedges on our Condensed Consolidated Balance
      Sheet
              September
      30, 2009Commodity
            
            Interest
      Rate and Foreign Currency
            
            Total(in
      millions)Hedging
      Assets (a)
            
            $
            17
            
            
            $
            -
            
            
            $
            17Hedging
      Liabilities (a)
            
            
            (23
            )
            
            
            (5
            )
            
            
            (28
            )AOCI
      Gain (Loss) Net of Tax
            
            
            (3
            )
            
            
            (14
            )
            
            
            (17
            )Portion
      Expected to be Reclassified to Net Income During the Next Twelve
      Months
            
            
            1
            
            
            
            (4
            )
            
            
            (3
            )





(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 September 30, 2009, the maximum length of time that we
are hedging (with contracts subject to the accounting guidance for “Derivatives
and Hedging”) our exposure to variability in future cash flows related to
forecasted transactions is 38 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 September 30, 2009, the aggregate
value of such contracts was $36 million and we were not required to post any
collateral.  We would have been required to post $36 million of
collateral at September 30, 2009 if our credit ratings had declined below
investment grade of which $30 million was attributable to our RTO and ISO
activities.





In
addition, a majority of our non-exchange traded commodity contracts contain
cross-default provisions that, if triggered, would permit the counterparty to
declare a default and require settlement of the outstanding
payable.  These cross-default provisions could be triggered if there
was a non-performance event under borrowed debt in excess of $50
million.  On an ongoing basis, our risk management organization
assesses the appropriateness of these cross-default provisions in our
contracts.  As of September 30, 2009, the fair value of derivative
liabilities subject to cross-default provisions totaled $852 million prior to
consideration of contractual netting arrangements.  This exposure has
been reduced by cash collateral posted of $14 million.  We believe
that a non-performance event under these provisions is unlikely.  If a
cross-default provision would have been triggered, a settlement of up to $240
million would be required after considering our contractual netting
arrangements.





9.       FAIR VALUE
MEASUREMENTS





With the
adoption of new accounting guidance, we are required to provide certain fair
value disclosures which we previously were only required to provide in our
annual report.  The new accounting guidance did not change the method
to calculate the amounts reported on the Condensed Consolidated Balance
Sheets.





Fair
Value Measurements of Long-term Debt





The fair
values of Long-term Debt are based on quoted market prices, without credit
enhancements, for the same or similar issues and the current interest rates
offered for instruments with similar maturities.  These instruments
are not marked-to-market.  The estimates presented are not necessarily
indicative of the amounts that we could realize in a current market
exchange.





The book
values and fair values of Long-term Debt at September 30, 2009 and December 31,
2008 are summarized in the following table:


September
      30, 2009
            
            
            December
      31, 2008Book
      Value
            
            
            Fair
      Value
            
            
            Book
      Value
            
            
            Fair
      Value(in
      millions)Long-term
      Debt
            
            $
            17,253
            
            
            $
            18,251
            
            
            $
            15,983
            
            
            $
            15,113





Fair
Value Measurements of Other Temporary Investments





Other
Temporary Investments include marketable securities that we intend to hold for
less than one year, investments by our protected cell captive insurance company
and funds held by trustees primarily for the payment of debt.





We
classify our investments in marketable securities in accordance with the
provisions of “Investments – Debt and Equity Securities” accounting
guidance.  We do not have any investments classified as trading or
held-to-maturity.





Available-for-sale
securities reflected in Other Temporary Investments are carried at fair value
with the unrealized gain or loss, net of tax, reported in
AOCI.  Held-to-maturity securities, if any, reflected in Other
Temporary Investments are carried at amortized cost.  The cost of
securities sold is based on specific identification or weighted average cost
method.  The fair value of most investment securities is determined by
currently available market prices.  Where quoted market prices are not
available, we use the market price of similar types of securities that are
traded in the market to estimate fair value.





In
evaluating potential impairment of equity securities with unrealized losses, we
considered, among other criteria, the current fair value compared to cost, the
length of time the security's fair value has been below cost, our intent and
ability to retain the investment for a period of time sufficient to allow for
any anticipated recovery in value and current economic conditions.





The
following is a summary of Other Temporary Investments:





September
      30, 2009
            
            December
      31, 2008Cost
            
            Gross
      Unrealized Gains
            
            Gross
      Unrealized Losses
            
            Estimated
              Fair
              Value
            
            Cost
            
            Gross
      Unrealized Gains
            
            Gross
      Unrealized Losses
            
            Estimated
              Fair
              ValueOther
      Temporary Investments
            
            (in
      millions)Cash
      (a)
            
            $
            167
            
            $
            -
            
            $
            -
            
            $
            167
            
            $
            243
            
            $
            -
            
            $
            -
            
            $
            243Debt
      Securities
            
            
            57
            
            
            -
            
            
            -
            
            
            57
            
            
            56
            
            
            -
            
            
            -
            
            
            56Equity
      Securities
            
            
            18
            
            
            17
            
            
            -
            
            
            35
            
            
            27
            
            
            11
            
            
            10
            
            
            28Total
      Other Temporary Investments
            
            $
            242
            
            $
            17
            
            $
            -
            
            $
            259
            
            $
            326
            
            $
            11
            
            $
            10
            
            $
            327





(a)
            Primarily
      represents amounts held for the payment of
debt.





The
following table provides the activity for our debt and equity securities within
Other Temporary Investments for the three and nine months ended September 30,
2009:


Gross
      RealizedProceeds
      From
            
            Purchases
            
            Gross
      Realized Gains
            
            Losses
      onInvestment
      Sales
            
            of
      Investments
            
            on
      Investment Sales
            
            Investment
      Sales(in
      millions)Three
      Months Ended
            
            $
            -
            
            $
            1
            
            $
            -
            
            $
            -Nine
      Months Ended
            
            
            -
            
            
            2
            
            
            -
            
            
            -





In June
2009, we recorded $9 million ($6 million, net of tax) of other-than-temporary
impairments of Other Temporary Investments for equity investments of our
protected cell captive insurance company.  At September 30, 2009, we
had no Other Temporary Investments with an unrealized loss
position.  At December 31, 2008, the fair value of corporate equity
securities with an unrealized loss position was $17 million and we had no
investments in a continuous unrealized loss position for more than twelve
months.  At September 30, 2009, the fair value of debt securities are
primarily debt based mutual funds with short and intermediate
maturities.





Fair
Value Measurements of Trust Assets for Decommissioning and SNF
Disposal





I&M
records securities held in trust funds for decommissioning nuclear facilities
and for the disposal of SNF at fair value.  I&M classifies
securities in the trust funds as available-for-sale due to their long-term
purpose.  The assessment of whether an investment in a debt security
has suffered an other-than-temporary impairment is based on whether the investor
has the intent to sell or more likely than not will be required to sell the debt
security before recovery of its amortized costs.  The assessment of
whether an investment in an equity security has suffered an other-than-temporary
impairment, among other things, is based on whether the  investor has
the ability and intent to hold the investment to recover its
value.  Other-than-temporary impairments for investments in both debt
and equity securities are considered realized losses as a result of securities
being managed by an external investment management firm.  The external
investment management firm makes specific investment decisions regarding the
equity and debt investments held in these trusts and generally intends to sell
debt securities in an unrealized loss position as part of a tax optimization
strategy.  I&M records unrealized gains and other-than-temporary
impairments from securities in these trust funds as adjustments to the
regulatory liability account for the nuclear decommissioning trust funds and to
regulatory assets or liabilities for the SNF disposal trust funds in accordance
with their treatment in rates.  The gains, losses or
other-than-temporary impairments shown below did not affect earnings or
AOCI.  The trust assets are recorded by jurisdiction and may not be
used for another jurisdictions’ liabilities.  Regulatory approval is
required to withdraw decommissioning funds.





The
following is a summary of nuclear trust fund investments at September 30, 2009
and December 31, 2008:





September
      30, 2009
            
            December
      31, 2008Estimated
              Fair
              Value
            
            Gross
              Unrealized
              Gains
            
            Other-Than-
              Temporary
              Impairments
            
            Estimated
              Fair
              Value
            
            Gross
              Unrealized
              Gains
            
            Other-Than-
              Temporary
              Impairments(in
      millions)Cash
            
            $
            19
            
            
            $
            -
            
            
            $
            -
            
            
            $
            18
            
            
            $
            -
            
            
            $
            -Debt
      Securities
            
            
            780
            
            
            
            35
            
            
            
            (2
            )
            
            
            773
            
            
            
            52
            
            
            
            (3
            )Equity
      Securities
            
            
            565
            
            
            
            223
            
            
            
            (135
            )
            
            
            469
            
            
            
            89
            
            
            
            (82
            )Spent
      Nuclear Fuel and Decommissioning Trusts
            
            $
            1,364
            
            
            $
            258
            
            
            $
            (137
            )
            
            $
            1,260
            
            
            $
            141
            
            
            $
            (85
            )





The
following table provides the securities activity within the decommissioning and
SNF trusts for the three and nine months ended September 30, 2009:





Gross
      RealizedProceeds
      From
            
            Purchases
            
            Gross
      Realized Gains
            
            Losses
      onInvestment
      Sales
            
            of
      Investments
            
            on
      Investment Sales
            
            Investment
      Sales(in
      millions)Three
      Months Ended
            
            $
            113
            
            
            $
            129
            
            
            $
            1
            
            
            $
            -Nine
      months Ended
            
            
            524
            
            
            
            571
            
            
            
            10
            
            
            
            (1
            )





The
adjusted cost of debt securities was $745 million and $721 million as of
September 30, 2009 and December 31, 2008, respectively.





The fair
value of debt securities held in the nuclear trust funds, summarized by
contractual maturities, at September 30, 2009 was as follows:


Fair
      Value
              of
      Debt
              Securities(in
      millions)Within
      1 year
            
            $
            271
      year – 5 years
            
            
            2175
      years – 10 years
            
            
            241After
      10 years
            
            
            295Total
            
            $
            780





Fair
Value Measurements of Financial Assets and Liabilities





As
described in our 2008 Annual Report, the accounting guidance for “Fair Value
Measurements and Disclosures” 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.


Exchange
traded derivatives, namely futures contracts, are generally fair valued based on
unadjusted quoted prices in active markets and are classified within Level
1.  Level 2 inputs primarily consist of OTC broker quotes in
moderately active or less active markets, as well as exchange traded contracts
where there is insufficient market liquidity to warrant inclusion in Level
1.  Where observable inputs are available for substantially the full
term of the asset or liability, the instrument is categorized in Level
2.  Certain OTC and bilaterally executed derivative instruments are
executed in less active markets with a lower availability of pricing
information.  In addition, long-dated and illiquid complex or
structured transactions and FTRs can introduce the need for internally developed
modeling inputs based upon extrapolations and assumptions of observable market
data to estimate fair value.  When such inputs have a significant
impact on the measurement of fair value, the instrument is categorized in Level
3.  Valuation models utilize various inputs that include quoted prices
for similar assets or liabilities in active markets, quoted prices for identical
or similar assets or liabilities in inactive markets, market corroborated inputs
(i.e. inputs derived principally from, or correlated to, observable market data)
and other observable inputs for the asset or liability.





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 September 30, 2009 and December 31, 2008.  As
required by the accounting guidance for “Fair Value Measurements and
Disclosures,” 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.  There have not been any significant changes in
AEP’s valuation techniques.





Assets
      and Liabilities Measured at Fair Value on a Recurring Basis as of
      September 30, 2009Level
      1
            
            Level
      2
            
            Level
      3
            
            Other
            
            TotalAssets:
            (in
      millions)Cash
      and Cash Equivalents (a)
            $
            799
            
            $
            -
            
            $
            -
            
            $
            78
            
            $
            877Other
      Temporary InvestmentsCash
      and Cash Equivalents (a)
            
            142
            
            
            -
            
            
            -
            
            
            25
            
            
            167Debt
      Securities (c)
            
            57
            
            
            -
            
            
            -
            
            
            -
            
            
            57Equity
      Securities (d)
            
            35
            
            
            -
            
            
            -
            
            
            -
            
            
            35Total Other Temporary
      Investments
            
            234
            
            
            -
            
            
            -
            
            
            25
            
            
            259Risk
      Management AssetsRisk
      Management Contracts (e)
            
            21
            
            
            2,195
            
            
            116
            
            
            (1,699)
            
            
            633Cash
      Flow Hedges (e)
            
            3
            
            
            24
            
            
            -
            
            
            (10)
            
            
            17Dedesignated
      Risk Management Contracts (f)
            
            -
            
            
            -
            
            
            -
            
            
            29
            
            
            29Total
      Risk Management Assets
            
            24
            
            
            2,219
            
            
            116
            
            
            (1,680)
            
            
            679Spent
      Nuclear Fuel and Decommissioning TrustsCash
      and Cash Equivalents (g)
            
            -
            
            
            10
            
            
            -
            
            
            9
            
            
            19Debt
      Securities (h)
            
            -
            
            
            780
            
            
            -
            
            
            -
            
            
            780Equity
      Securities (d)
            
            565
            
            
            -
            
            
            -
            
            
            -
            
            
            565Total Spent Nuclear Fuel and
      Decommissioning Trusts
            
            565
            
            
            790
            
            
            -
            
            
            9
            
            
            1,364Total
      Assets
            $
            1,622
            
            $
            3,009
            
            $
            116
            
            $
            (1,568)
            
            $
            3,179Liabilities:Risk
      Management LiabilitiesRisk
      Management Contracts (e)
            $
            23
            
            $
            1,993
            
            $
            12
            
            $
            (1,770)
            
            $
            258Cash
      Flow Hedges (e)
            
            5
            
            
            33
            
            
            -
            
            
            (10)
            
            
            28Total
      Risk Management Liabilities
            $
            28
            
            $
            2,026
            
            $
            12
            
            $
            (1,780)
            
            $
            286








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 the accounting
      guidance for “Derivatives and Hedging.”(f)
            “Dedesignated
      Risk Management Contracts” are contracts that were originally MTM but were
      subsequently elected as normal under the accounting guidance for
      “Derivatives and Hedging.”  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 September 30, 2009
            
            Net
      Risk Management Assets (Liabilities)
            
            Other
      Temporary Investments
            
            Investments
      in Debt Securities(in
      millions)Balance
      as of July 1, 2009
            
            $
            67
            
            $
            -
            
            $
            -Realized
      (Gain) Loss Included in Net Income (or Changes in Net Assets)
      (a)
            
            
            (8)
            
            
            -
            
            
            -Unrealized
      Gain (Loss) Included in Net Income (or Changes in Net
      Assets) Relating to Assets Still Held at the Reporting Date
      (a)
            
            
            10
            
            
            -
            
            
            -Realized
      and Unrealized Gains (Losses) Included in Other
      Comprehensive Income
            
            
            -
            
            
            -
            
            
            -Purchases,
      Issuances and Settlements (b)
            
            
            -
            
            
            -
            
            
            -Transfers
      in and/or out of Level 3 (c)
            
            
            7
            
            
            -
            
            
            -Changes
      in Fair Value Allocated to Regulated Jurisdictions (d)
            
            
            28
            
            
            -
            
            
            -Balance
      as of September 30, 2009
            
            $
            104
            
            $
            -
            
            $
            -








Nine
      Months Ended September 30, 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)
      (a)
            
            
            (21)
            
            
            -
            
            
            -Unrealized
      Gain (Loss) Included in Net Income (or Changes in Net
      Assets) Relating to AssetsStill
      Held at the Reporting Date (a)
            
            
            51
            
            
            -
            
            
            -Realized
      and Unrealized Gains (Losses) Included in Other
      Comprehensive Income
            
            
            -
            
            
            -
            
            
            -Purchases,
      Issuances and Settlements (b)
            
            
            -
            
            
            -
            
            
            -Transfers
      in and/or out of Level 3 (c)
            
            
            (26)
            
            
            -
            
            
            -Changes
      in Fair Value Allocated to Regulated Jurisdictions (d)
            
            
            51
            
            
            -
            
            
            -Balance
      as of September 30, 2009
            
            $
            104
            
            $
            -
            
            $
            -





Three
      Months Ended September 30, 2008
            
            Net
      Risk Management Assets (Liabilities)
            
            Other
      Temporary Investments
            
            Investments
      in Debt Securities(in
      millions)Balance
      as of July 1, 2008
            
            $
            (8)
            
            $
            -
            
            $
            -Realized
      (Gain) Loss Included in Net Income (or Changes in Net Assets)
      (a)
            
            
            17
            
            
            -
            
            
            -Unrealized
      Gain (Loss) Included in Net Income (or Changes in Net
      Assets) Relating to Assets Still Held at the Reporting Date
      (a)
            
            
            (7)
            
            
            -
            
            
            -Realized
      and Unrealized Gains (Losses) Included in Other
      Comprehensive Income
            
            
            -
            
            
            -
            
            
            -Purchases,
      Issuances and Settlements (b)
            
            
            -
            
            
            -
            
            
            -Transfers
      in and/or out of Level 3 (c)
            
            
            (10)
            
            
            -
            
            
            -Changes
      in Fair Value Allocated to Regulated Jurisdictions (d)
            
            
            15
            
            
            -
            
            
            -Balance
      as of September 30, 2008
            
            $
            7
            
            $
            -
            
            $
            -








Nine
      Months Ended September 30, 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)
      (a)
            
            
            -
            
            
            -
            
            
            -Unrealized
      Gain (Loss) Included in Net Income (or Changes in Net
      Assets) Relating to Assets Still Held at the Reporting Date
      (a)
            
            
            4
            
            
            -
            
            
            -Realized
      and Unrealized Gains (Losses) Included in Other
      Comprehensive Income
            
            
            -
            
            
            -
            
            
            -Purchases,
      Issuances and Settlements (b)
            
            
            -
            
            
            (118)
            
            
            (17)Transfers
      in and/or out of Level 3 (c)
            
            
            (35)
            
            
            118
            
            
            17Changes
      in Fair Value Allocated to Regulated Jurisdictions (d)
            
            
            (11)
            
            
            -
            
            
            -Balance
      as of September 30, 2008
            
            $
            7
            
            $
            -
            
            $
            -





(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.





10.   INCOME
      TAXES





We, along
with our subsidiaries, file a consolidated federal income tax
return.  The allocation of the AEP System’s current consolidated
federal income tax to the AEP System companies allocates the benefit of current
tax losses to the AEP System companies giving rise to such losses in determining
their current tax expense.  The tax benefit of the Parent is allocated
to our subsidiaries with taxable income.  With the exception of the
loss of the Parent, the method of allocation reflects a separate return result
for each company in the consolidated group.





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.  The years 2007 and 2008 are
currently under examination.  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.





We, along
with our subsidiaries, file income tax returns in various state, local and
foreign jurisdictions.  These taxing authorities routinely examine our
tax returns and we are currently under examination in several state and local
jurisdictions.  We believe that we have filed tax returns with
positions that may be challenged by these tax authorities.  However,
management does not believe that the ultimate resolution of these audits
will materially impact net income.  With few exceptions, we are no
longer subject to state, local or non-U.S. income tax examinations by tax
authorities for years before 2000.





We are
changing the tax method of accounting for the definition of a unit of property
for generation assets.  This change will provide a favorable cash flow
benefit in 2009 and 2010.





Federal
Tax Legislation





The
American Recovery and Reinvestment Act of 2009 was signed into law by the
President in February 2009.  It provided for several new grant
programs and expanded tax credits and an extension of the 50% bonus depreciation
provision enacted in the Economic Stimulus Act of 2008.  The enacted
provisions are not expected to have a material impact on net income or financial
condition.  However, we forecast the bonus depreciation provision
could provide a significant favorable cash flow benefit in
2009.


11.   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, which were primarily used to repay cash drawn under
our credit facilities in the second quarter of 2009.





Long-term
Debt


September
      30,
            
            
            December
      31,Type
      of Debt
            
            2009
            
            
            2008(in
      millions)Senior
      Unsecured Notes
            
            $
            12,316
            
            
            $
            11,069Pollution
      Control Bonds
            
            
            2,055
            
            
            
            1,946Notes
      Payable
            
            
            288
            
            
            
            233Securitization
      Bonds
            
            
            1,995
            
            
            
            2,132Junior
      Subordinated Debentures
            
            
            315
            
            
            
            315Spent
      Nuclear Fuel Obligation (a)
            
            
            264
            
            
            
            264Other
      Long-term Debt
            
            
            87
            
            
            
            88Unamortized
      Discount (net)
            
            
            (67
            )
            
            
            (64
            )Total
      Long-term Debt Outstanding
            
            
            17,253
            
            
            
            15,983Less
      Portion Due Within One Year
            
            
            1,540
            
            
            
            447Long-term
      Portion
            
            $
            15,713
            
            
            $
            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 $306 million and $301 million at September
      30, 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 nine 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
            
            2020CSPCo
            
            Pollution
      Control Bonds
            
            
            60
            
            3.875
            
            2038CSPCo
            
            Pollution
      Control Bonds
            
            
            32
            
            5.80
            
            2038I&M
            
            Senior
      Unsecured Notes
            
            
            475
            
            7.00
            
            2019I&M
            
            Notes
      Payable
            
            
            102
            
            5.44
            
            2013I&M
            
            Pollution
      Control Bonds
            
            
            50
            
            6.25
            
            2025I&M
            
            Pollution
      Control Bonds
            
            
            50
            
            6.25
            
            2025OPCo
            
            Senior
      Unsecured Notes
            
            
            500
            
            5.375
            
            2021PSO
            
            Pollution
      Control Bonds
            
            
            34
            
            5.25
            
            2014Non-Registrant:AEP
      River Operations
            
            Notes
      Payable
            
            
            49
            
            7.59
            
            2026KPCo
            
            Senior
      Unsecured Notes
            
            
            40
            
            7.25
            
            2021KPCo
            
            Senior
      Unsecured Notes
            
            
            30
            
            8.03
            
            2029KPCo
            
            Senior
      Unsecured Notes
            
            
            60
            
            8.13
            
            2039TCC
            
            Pollution
      Control Bonds
            
            
            101
            
            6.30
            
            2029Total
      Issuances
            
            
            
            $
            1,933
            (a)





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





(a)
            Amount
      indicated on the statement of cash flows of $1,912 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:APCo
            
            Senior
      Unsecured Notes
            
            $
            150
            
            6.60
            
            2009OPCo
            
            Pollution
      Control Bonds
            
            
            218
            
            Variable
            
            2028-2029OPCo
            
            Notes
      Payable
            
            
            1
            
            6.27
            
            2009OPCo
            
            Notes
      Payable
            
            
            7
            
            7.21
            
            2009OPCo
            
            Notes
      Payable
            
            
            70
            
            7.49
            
            2009PSO
            
            Senior
      Unsecured Notes
            
            
            50
            
            4.70
            
            2009SWEPCo
            
            Notes
      Payable
            
            
            3
            
            4.47
            
            2011Non-Registrant:AEP
      Subsidiaries
            
            Notes
      Payable
            
            
            11
            
            Variable
            
            2017AEP
      Subsidiaries
            
            Notes
      Payable
            
            
            4
            
            5.88
            
            2011AEGCo
            
            Senior
      Unsecured Notes
            
            
            7
            
            6.33
            
            2037TCC
            
            Securitization
      Bonds
            
            
            54
            
            5.56
            
            2010TCC
            
            Securitization
      Bonds
            
            
            84
            
            4.98
            
            2010Total
      Retirements and Principal Payments
            
            
            
            $
            659





In
October 2009, AEP River Operations issued $45 million of 8.03% Notes Payable due
in 2026.





During
2008, we chose to begin eliminating our auction-rate debt position due to market
conditions.  As of September 30, 2009, $54 million of our auction-rate
tax-exempt long-term debt remained outstanding at a rate of 0.862% that resets
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.  In the third quarter of 2009, we
reacquired $218 million of auction-rate debt related to JMG with interest rates
at the contractual maximum rate of 13%.  We were unable to refinance
the debt without JMG’s consent.  We sought approval from the PUCO to
terminate the JMG relationship and received the approval in June
2009.  In July 2009, we purchased the outstanding equity ownership of
JMG for $28 million which enabled us to reacquire this debt.





As of
September 30, 2009, trustees held, on our behalf, $321 million of our reacquired
auction-rate tax-exempt long-term debt, which includes the $218 million related
to JMG.  We plan to reissue the debt.





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:


September
      30, 2009
            
            December
      31, 2008Outstanding
              Amount
            
            Interest
              Rate
      (a)
            
            Outstanding
              Amount
            
            Interest
              Rate
      (a)Type
      of Debt
            
            (in
      thousands)
            
            
            
            (in
      thousands)Line
      of Credit – AEP (b)
            
            $
            -
            
            -
            
            $
            1,969,000
            
            2.28%
            (c)Line
      of Credit – Sabine Mining Company (d)
            
            
            5,273
            
            1.60%
            
            
            7,172
            
            1.54%Commercial
      Paper – AEP
            
            
            347,000
            
            0.45%
            
            
            -
            
            -Total
            
            $
            352,273
            
            
            
            $
            1,976,172





(a)
            Weighted
      average rate.(b)
            Paid
      primarily with proceeds from the April 2009 equity
    issuance.(c)
            Rate
      based on LIBOR.(d)
            Sabine
      Mining Company is a consolidated variable interest entity.  This
      line of credit does not reduce available liquidity under AEP’s credit
      facilities.





Credit
Facilities





As of
September 30, 2009, we have credit facilities totaling $3 billion to support our
commercial paper program.  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
$627 million 3-year credit agreement.  Under the facility, we may
issue letters of credit.  As of September 30, 2009, $372 million of
letters of credit were issued by subsidiaries under the $627 million 3-year
agreement to support variable rate Pollution Control Bonds.  We had a
$350 million 364-day credit agreement that expired in April 2009.





Sales
of Receivables





AEP
Credit has a sale of receivables agreement with banks and commercial paper
conduits.  Under the sale of  receivables agreement, AEP
Credit sells an interest in the receivables it acquires from affiliated utility
subsidiaries to the commercial paper conduits and banks and receives
cash.





In July
2009, we renewed and increased our sale of receivables agreement.  The
sale of receivables agreement provides a commitment of $750 million from bank
conduits to purchase receivables.  This agreement will expire in July
2010.  The previous sale of receivables agreement provided a
commitment of $700 million.





APPALACHIAN
POWER COMPANY
 AND
SUBSIDIARIES
 
  
  APPALACHIAN POWER COMPANY AND SUBSIDIARIES
 MANAGEMENT’S FINANCIAL
DISCUSSION AND ANALYSIS
 
 Results of
Operations
 Third Quarter of 2009
Compared to Third Quarter of 2008
 
 Reconciliation
of Third Quarter of 2008 to Third Quarter of 2009
 Net
Income
 (in
millions)
 
 Third
      Quarter of 2008
              
              
              
              
              $
              39Changes
      in Gross Margin:Retail
      Margins
              
              
              77Off-system
      Sales
              
              
              (65
              )Total
      Change in Gross Margin
              
              
              
              
              
              
              12Total
      Expenses and Other:Other
      Operation and Maintenance
              
              
              (4
              )Depreciation
      and Amortization
              
              
              (7
              )Carrying
      Costs Income
              
              
              (5
              )Other
      Income
              
              
              (3
              )Interest
      Expense
              
              
              (5
              )Total
      Expenses and Other
              
              
              
              
              
              
              (24
              )Third
      Quarter of 2009
              
              
              
              
              
              $
              27
 
 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 $77 million primarily due to the
    following:·
              A
      $54 million increase due to a decrease in off-system sales margins shared
      with customers in Virginia and West Virginia.·
              A
      $37 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.These
      increases were partially offset by:·
              A
      $9 million decrease due to higher capacity settlement expenses under the
      Interconnection Agreement net of recovery in West Virginia and
      environmental deferrals in Virginia.·
              A
      $5 million decrease in industrial sales primarily due to suspended
      operations by APCo’s largest customer, Century
Aluminum.·
              Margins
      from Off-system Sales decreased $65 million primarily due to lower
      physical sales volumes and lower margins as a result of lower market
      prices, partially offset by higher trading and marketing
      margins.
 
 Total
Expenses and Other changed between years as follows:
 
 ·
              Other
      Operation and Maintenance expenses increased $4 million primarily due to
      the following:·
              A
      $9 million increase related to the establishment of a regulatory asset in
      the third quarter of 2008 for Virginia’s share of previously expended NSR
      settlement costs.  See “Virginia Rate Matters – Virginia E&R
      Costs Recovery Filing” section of Note 3.·
              A
      $2 million increase related to generation plant
    maintenance.These
      increases were partially offset by:·
              An
      $8 million decrease related to the establishment of a regulatory asset for
      the deferral of transmission costs.  See “Virginia Rate Matters
      – Rate Adjustment Clauses” section of Note
3.
 ·
              Depreciation
      and Amortization expenses increased $7 million primarily due to increased
      assets to depreciate reflecting environmental upgrades at the Amos and
      Clinch River Plants.·
              Carrying
      Costs Income decreased $5 million due to completion of reliability
      deferrals in Virginia in December 2008 and a decrease of environmental
      deferrals in Virginia in 2009.·
              Interest
      Expense increased $5 million primarily due to an increase in long-term
      borrowings.
 
 Nine Months Ended September
30, 2009 Compared to Nine Months Ended September 30, 2008
 
 Reconciliation
of Nine Months Ended September 30, 2008 to Nine Months Ended September 30,
2009
 Net
Income
 (in
millions)
 
 Nine
      Months Ended September 30, 2008
              
              
              
              
              $
              121Changes
      in Gross Margin:Retail
      Margins
              
              
              230Off-system
      Sales
              
              
              (159
              )Total
      Change in Gross Margin
              
              
              
              
              
              
              71Total
      Expenses and Other:Other
      Operation and Maintenance
              
              
              16Depreciation
      and Amortization
              
              
              (17
              )Carrying
      Costs Income
              
              
              (23
              )Other
      Income
              
              
              (7
              )Interest
      Expense
              
              
              (15
              )Total
      Expenses and Other
              
              
              
              
              
              
              (46
              )Income
      Tax Expense
              
              
              
              
              
              
              (15
              )Nine
      Months Ended September 30, 2009
              
              
              
              
              
              $
              131
 
 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 $230 million primarily due to the
    following:·
              A
      $128 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
      $124 million increase due to a decrease in off-system sales margins shared
      with customers in Virginia and West Virginia.·
              A
      $19 million increase due to new rates effective January 2009 for a power
      supply contract with KGPCo.These
      increases were partially offset by:·
              A
      $37 million decrease due to higher capacity settlement expenses under the
      Interconnection Agreement net of recovery in West Virginia and
      environmental deferrals in Virginia.·
              A
      $15 million decrease in industrial sales primarily due to suspended
      operations by APCo’s largest customer, Century
Aluminum.·
              Margins
      from Off-system Sales decreased $159 million primarily due to lower
      physical sales volumes and lower margins as a result of lower market
      prices, partially offset by higher trading and marketing
      margins.
  Total
Expenses and Other and Income Tax Expense changed between years as
follows:
 
 ·
              Other
      Operation and Maintenance expenses decreased $16 million primarily due to
      the following:·
              A
      $14 million decrease related to the establishment of a regulatory asset in
      2009 for the deferral of transmission costs.  See “Virginia Rate
      Matters – Rate Adjustment Clauses” section of Note 3.·
              A
      $6 million decrease in employee benefit expenses.·
              A
      $2 million decrease in generation plant maintenance.These
      decreases were partially offset by:·
              A
      $9 million increase related to the establishment of a regulatory asset in
      the third quarter of 2008 for Virginia’s share of previously expended NSR
      settlement costs.  See “Virginia Rate Matters – Virginia E&R
      Costs Recovery Filing” section of Note 3.·
              Depreciation
      and Amortization expenses increased $17 million primarily due to increased
      assets to depreciate reflecting environmental upgrades at the Amos and
      Clinch River Plants and the amortization of carrying charges and
      depreciation expenses that are being collected through the Virginia
      E&R surcharges.·
              Carrying
      Costs Income decreased $23 million due to completion of reliability
      deferrals in Virginia in December 2008 and a decrease of environmental
      deferrals in Virginia in 2009.·
              Interest
      Expense increased $15 million primarily due to an increase in long-term
      borrowings.·
              Other
      Income decreased $7 million primarily due to higher interest income that
      was recorded in 2008 related to a tax refund and other tax
      adjustments.·
              Income
      Tax Expense increased $15 million primarily due to an increase in pretax
      book income and changes in certain book/tax differences accounted for on a
      flow-through basis.
 
 Financial
Condition
 
 Credit
Ratings
 
 APCo’s
credit ratings as of September 30, 2009 were as follows:
 
 Moody’s
              
              S&P
              
              FitchSenior
      Unsecured Debt
              Baa2
              
              BBB
              
              BBB
 
 S&P
has APCo on stable outlook.  In February 2009, Moody’s changed its
rating outlook for APCo from negative to stable.  In September 2009,
Fitch changed its rating outlook for APCo from negative to stable.  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 nine months ended September 30, 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
              
              
              (53,712)
              
              
              208,445Investing
      Activities
              
              
              (406,707)
              
              
              (472,029)Financing
      Activities
              
              
              460,237
              
              
              263,376Net
      Decrease in Cash and Cash Equivalents
              
              
              (182)
              
              
              (208)Cash
      and Cash Equivalents at End of Period
              
              $
              1,814
              
              $
              1,987
  Operating
Activities
 
 Net Cash
Flows Used for Operating Activities were $54 million in 2009.  APCo
produced Net Income of $131 million during the period and had noncash expense
items of $229 million for Deferred Income Taxes and $204 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 $160 million outflow from Fuel, Materials
and Supplies was primarily due to an increase in coal inventory.  The
$132 million outflow from Accounts Payable was primarily due to APCo’s provision
for revenue refund of $77 million which was paid in the first quarter of 2009 to
the AEP West companies as part of a FERC order on the SIA.  The $52
million inflow from Accounts Receivable, Net was primarily due to a decrease in
accrued revenues due to usual seasonal fluctuations and timing of settlements of
receivables from affiliated companies.  The $181 million change in
Fuel Over/Under-Recovery, Net resulted from a net under-recovery of fuel cost in
both Virginia and West Virginia.
 
 Net Cash
Flows from Operating Activities were $208 million in 2008.  APCo
produced Net Income of $121 million during the period and had noncash expense
items of $187 million for Depreciation and Amortization and $111 million for
Deferred Income Taxes, partially offset by $39 million in Carrying Costs
Income.  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 $42 million inflow from Accounts
Payable  primarily due to an increase in fuel costs.  The
$114 million change in Fuel Over/Under-Recovery, Net resulted from higher fuel
costs in Virginia and the 2009 approval of a four-year phase-in plan for ENEC
recovery in West Virginia.
 
 Investing
Activities
 
 Net Cash
Flows Used for Investing Activities during 2009 and 2008 were $407 million and
$472 million, respectively.  Construction Expenditures were $420
million and $488 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.
 
 Financing
Activities
 
 Net Cash
Flows from Financing Activities were $460 million in 2009.  APCo
issued $350 million of Senior Unsecured Notes in March 2009 and retired $150
million of Senior Unsecured Notes in May 2009.  APCo received capital
contributions from the Parent of $250 million in the second quarter of
2009.  APCo had a net increase of $37 million in borrowings from the
Utility Money Pool.  In addition, APCo paid $20 million in dividends
on common stock.
 
 Net Cash
Flows from Financing Activities were $263 million in 2008.  APCo
issued $500 million of Senior Unsecured Notes in March 2008, $125 million of
Pollution Control Bonds in June 2008 and $70 million of Pollution Control Bonds
in September 2008.  APCo retired $213 million of Pollution Control
Bonds and $200 million of Senior Unsecured Notes in the second quarter of
2008.  APCo had a net decrease of $182 million in borrowings from the
Utility Money Pool.  In addition, APCo received capital contributions
from the Parent of $175 million.
 
 Financing
Activity
 
 Long-term
debt issuances, retirements and principal payments made during the first nine
months of 2009 were:
 
 Issuances
 Principal
                Amount
              
              Interest
              
              DueType
      of Debt
              
              
              Rate
              
              Date(in
      thousands)
              
              (%)Senior
      Unsecured Notes
              
              $
              350,000
              
              7.95
              
              2020
 
  Retirements and Principal
Payments
 Principal
                Amount
      Paid
              
              Interest
              
              DueType
      of Debt
              
              
              Rate
              
              Date(in
      thousands)
              
              (%)Senior
      Unsecured Notes
              
              $
              150,000
              
              6.60
              
              2009Land
      Note
              
              
              12
              
              13.718
              
              2026
 
 Liquidity
 
 Although
the financial markets were volatile at both a global and domestic level, APCo
issued $350 million of Senior Unsecured Notes during the first nine months of
2009.  The credit situation appears to have improved but could impact
APCo’s future 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 relies 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 and
retirements 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 for
disclosures about risk management activities.  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 September 30, 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
 September
30, 2009
 (in
thousands)
 
 MTM
      Risk
              
              
              Cash
      Flow
              
              
              DETMManagement
              
              
              Hedge
              
              
              Assignment
              
              
              CollateralContracts
              
              
              Contracts
              
              
              (a)
              
              
              Deposits
              
              
              TotalCurrent
      Assets
              
              $
              85,559
              
              
              $
              2,818
              
              
              $
              -
              
              
              $
              (4,942
              )
              
              $
              83,435Noncurrent
      Assets
              
              
              61,936
              
              
              
              553
              
              
              
              -
              
              
              
              (4,737
              )
              
              
              57,752Total
      MTM Derivative Contract Assets
              
              
              147,495
              
              
              
              3,371
              
              
              
              -
              
              
              
              (9,679
              )
              
              
              141,187Current
      Liabilities
              
              
              42,005
              
              
              
              2,397
              
              
              
              2,767
              
              
              
              (16,167
              )
              
              
              31,002Noncurrent
      Liabilities
              
              
              38,585
              
              
              
              996
              
              
              
              697
              
              
              
              (16,624
              )
              
              
              23,654Total
      MTM Derivative Contract Liabilities
              
              
              80,590
              
              
              
              3,393
              
              
              
              3,464
              
              
              
              (32,791
              )
              
              
              54,656Total
      MTM Derivative Contract Net Assets (Liabilities)
              
              $
              66,905
              
              
              $
              (22
              )
              
              $
              (3,464
              )
              
              $
              23,112
              
              
              $
              86,531
 
 (a)
              See
      “Natural Gas Contracts with DETM” section of Note 15 of the 2008 Annual
      Report.
  MTM
Risk Management Contract Net Assets
 Nine
Months Ended September 30, 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
              
              
              (24,390
              )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
              
              
              (185
              )Change
      in Fair Value Due to Valuation Methodology Changes on Forward
      Contracts
              
              
              -Changes
      in Fair Value Due to Market Fluctuations During the Period
    (b)
              
              
              (530
              )Changes
      in Fair Value Allocated to Regulated Jurisdictions (c)
              
              
              35,074Total
      MTM Risk Management Contract Net Assets
              
              
              66,905Cash
      Flow Hedge Contracts
              
              
              (22
              )DETM
      Assignment (d)
              
              
              (3,464
              )Collateral
      Deposits
              
              
              23,112Total
      MTM Derivative Contract Net Assets at September 30, 2009
              
              $
              86,531
 
 (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 on 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 or
(require) cash:
 
 Maturity
and Source of Fair Value of MTM
 Risk
Management Contract Net Assets (Liabilities)
 September
30, 2009
 (in
thousands)
 
 Remainder
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              After2009
              
              
              2010
              
              
              2011
              
              
              2012
              
              
              2013
              
              
              2013
              
              
              TotalLevel
      1 (a)
              
              $
              (444
              )
              
              $
              (48
              )
              
              $
              1
              
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              (491
              )Level
      2 (b)
              
              
              8,411
              
              
              
              14,350
              
              
              
              6,979
              
              
              
              983
              
              
              
              2,758
              
              
              
              220
              
              
              
              33,701Level
      3 (c)
              
              
              6,659
              
              
              
              13,812
              
              
              
              2,118
              
              
              
              1,085
              
              
              
              (26
              )
              
              
              -
              
              
              
              23,648Total
              
              
              14,626
              
              
              
              28,114
              
              
              
              9,098
              
              
              
              2,068
              
              
              
              2,732
              
              
              
              220
              
              
              
              56,858Dedesignated
      Risk Management Contracts (d)
              
              
              1,444
              
              
              
              4,951
              
              
              
              1,928
              
              
              
              1,724
              
              
              
              -
              
              
              
              -
              
              
              
              10,047Total
      MTM Risk Management Contract Net Assets
              
              $
              16,070
              
              
              $
              33,065
              
              
              $
              11,026
              
              
              $
              3,792
              
              
              $
              2,732
              
              
              $
              220
              
              
              $
              66,905
 
 (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 the accounting guidance for
      “Derivatives and Hedging.”  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
8 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 September 30, 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:
 
 Nine
      Months Ended
              
              
              
              
              Twelve
      Months EndedSeptember
      30, 2009
              
              
              
              
              December
      31, 2008(in
      thousands)
              
              
              
              
              (in
      thousands)End
              
              High
              
              Average
              
              Low
              
              
              
              
              End
              
              High
              
              Average
              
              Low$258
              
              $699
              
              $353
              
              $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 back-testing 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
four 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.  As calculated on APCo’s
debt outstanding as of September 30, 2009, the estimated EaR on APCo’s debt
portfolio for the following twelve months was $3.5 million.
 
  
  APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
 CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
 For
the Three and Nine Months Ended September 30, 2009 and 2008
 (in
thousands)
 (Unaudited)
 
 
 Three
      Months Ended
              
              
              Nine
      Months Ended2009
              
              
              2008
              
              
              2009
              
              
              2008REVENUESElectric
      Generation, Transmission and Distribution
              
              $
              629,566
              
              
              $
              719,295
              
              
              $
              1,929,552
              
              
              $
              1,926,841Sales
      to AEP Affiliates
              
              
              63,645
              
              
              
              74,632
              
              
              
              181,914
              
              
              
              262,230Other
      Revenues
              
              
              2,462
              
              
              
              4,906
              
              
              
              6,348
              
              
              
              12,186TOTAL
      REVENUES
              
              
              695,673
              
              
              
              798,833
              
              
              
              2,117,814
              
              
              
              2,201,257EXPENSESFuel
      and Other Consumables Used for Electric Generation
              
              
              140,321
              
              
              
              220,955
              
              
              
              402,893
              
              
              
              554,022Purchased
      Electricity for Resale
              
              
              54,087
              
              
              
              71,075
              
              
              
              189,534
              
              
              
              167,205Purchased
      Electricity from AEP Affiliates
              
              
              202,043
              
              
              
              219,595
              
              
              
              570,231
              
              
              
              595,433Other
      Operation
              
              
              68,402
              
              
              
              66,316
              
              
              
              197,441
              
              
              
              210,262Maintenance
              
              
              53,164
              
              
              
              51,292
              
              
              
              158,552
              
              
              
              161,371Depreciation
      and Amortization
              
              
              69,701
              
              
              
              62,364
              
              
              
              203,844
              
              
              
              186,528Taxes
      Other Than Income Taxes
              
              
              24,257
              
              
              
              24,319
              
              
              
              72,156
              
              
              
              72,414TOTAL
      EXPENSES
              
              
              611,975
              
              
              
              715,916
              
              
              
              1,794,651
              
              
              
              1,947,235OPERATING
      INCOME
              
              
              83,698
              
              
              
              82,917
              
              
              
              323,163
              
              
              
              254,022Other
      Income (Expense):Interest
      Income
              
              
              301
              
              
              
              1,945
              
              
              
              1,078
              
              
              
              7,541Carrying
      Costs Income
              
              
              6,467
              
              
              
              11,924
              
              
              
              16,341
              
              
              
              38,921Allowance
      for Equity Funds Used During Construction
              
              
              1,897
              
              
              
              2,130
              
              
              
              5,734
              
              
              
              6,278Interest
      Expense
              
              
              (51,982
              )
              
              
              (47,385
              )
              
              
              (153,144
              )
              
              
              (138,644
              )INCOME
      BEFORE INCOME TAX EXPENSE
              
              
              40,381
              
              
              
              51,531
              
              
              
              193,172
              
              
              
              168,118Income
      Tax Expense
              
              
              13,011
              
              
              
              12,516
              
              
              
              62,225
              
              
              
              47,508NET
      INCOME
              
              
              27,370
              
              
              
              39,015
              
              
              
              130,947
              
              
              
              120,610Preferred
      Stock Dividend Requirements Including Capital StockExpense
              
              
              225
              
              
              
              238
              
              
              
              675
              
              
              
              714EARNINGS
      ATTRIBUTABLE TO COMMON STOCK
              
              $
              27,145
              
              
              $
              38,777
              
              
              $
              130,272
              
              
              $
              119,896
 
 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 Nine Months Ended September 30, 2009 and 2008
 (in
thousands)
 (Unaudited)
 
 Common
      Stock
              
              
              Paid-in
      Capital
              
              
              Retained
      Earnings
              
              
              Accumulated
      Other Comprehensive Income (Loss)
              
              
              TotalTOTAL COMMON SHAREHOLDER’S
      EQUITY–DECEMBER 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
              
              
              
              
              
              
              175,000
              
              
              
              
              
              
              
              
              
              
              
              175,000Preferred
      Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (599
              )
              
              
              
              
              
              
              (599
              )Capital
      Stock Expense
              
              
              
              
              
              
              115
              
              
              
              (115
              )
              
              
              
              
              
              
              -SUBTOTAL
      – COMMON SHAREHOLDER’S EQUITY
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              2,253,966COMPREHENSIVE
      INCOMEOther
      Comprehensive Income (Loss), Net of Taxes:Cash
      Flow Hedges, Net of Taxof
      $677
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              (1,258
              )
              
              
              (1,258
              )Amortization
      of Pension and OPEB Deferred Costs, Net of Tax of $1,346
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              2,499
              
              
              
              2,499NET
      INCOME
              
              
              
              
              
              
              
              
              
              
              120,610
              
              
              
              
              
              
              
              120,610TOTAL
      COMPREHENSIVE INCOME
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              121,851TOTAL COMMON SHAREHOLDER’S
      EQUITY–SEPTEMBER 30,
      2008
              
              $
              260,458
              
              
              $
              1,200,264
              
              
              $
              949,041
              
              
              $
              (33,946
              )
              
              $
              2,375,817TOTAL COMMON SHAREHOLDER’S
      EQUITY–DECEMBER 31,
      2008
              
              $
              260,458
              
              
              $
              1,225,292
              
              
              $
              951,066
              
              
              $
              (60,225
              )
              
              $
              2,376,591Capital
      Contribution from Parent
              
              
              
              
              
              
              250,000
              
              
              
              
              
              
              
              
              
              
              
              250,000Common
      Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (20,000
              )
              
              
              
              
              
              
              (20,000
              )Preferred
      Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (599
              )
              
              
              
              
              
              
              (599
              )Capital
      Stock Expense
              
              
              
              
              
              
              76
              
              
              
              (76
              )
              
              
              
              
              
              
              -SUBTOTAL
      – COMMON SHAREHOLDER’S EQUITY
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              2,605,992COMPREHENSIVE
      INCOMEOther
      Comprehensive Income (Loss), Net of Taxes:Cash
      Flow Hedges, Net of Taxof
      $545
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              (1,013
              )
              
              
              (1,013
              )Amortization
      of Pension and OPEB Deferred Costs, Net of Tax of $1,982
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              3,680
              
              
              
              3,680NET
      INCOME
              
              
              
              
              
              
              
              
              
              
              130,947
              
              
              
              
              
              
              
              130,947TOTAL
      COMPREHENSIVE INCOME
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              133,614TOTAL COMMON SHAREHOLDER’S
      EQUITY–SEPTEMBER 30,
      2009
              
              $
              260,458
              
              
              $
              1,475,368
              
              
              $
              1,061,338
              
              
              $
              (57,558
              )
              
              $
              2,739,606
 
 See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
 
  
  APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
 CONDENSED
CONSOLIDATED BALANCE SHEETS
 ASSETS
 September
30, 2009 and December 31, 2008
 (in
thousands)
 (Unaudited)
 
 
 2009
              
              
              2008CURRENT
      ASSETSCash
      and Cash Equivalents
              
              $
              1,814
              
              
              $
              1,996Accounts
      Receivable:Customers
              
              
              126,428
              
              
              
              175,709Affiliated
      Companies
              
              
              121,925
              
              
              
              110,982Accrued
      Unbilled Revenues
              
              
              47,736
              
              
              
              55,733Miscellaneous
              
              
              768
              
              
              
              498Allowance
      for Uncollectible Accounts
              
              
              (5,426
              )
              
              
              (6,176
              )Total
      Accounts Receivable
              
              
              291,431
              
              
              
              336,746Fuel
              
              
              282,835
              
              
              
              131,239Materials
      and Supplies
              
              
              84,568
              
              
              
              76,260Risk
      Management Assets
              
              
              83,435
              
              
              
              65,140Accrued
      Tax Benefits
              
              
              88,542
              
              
              
              15,599Regulatory
      Asset for Under-Recovered Fuel Costs
              
              
              92,629
              
              
              
              165,906Prepayments
      and Other Current Assets
              
              
              46,879
              
              
              
              45,657TOTAL
      CURRENT ASSETS
              
              
              972,133
              
              
              
              838,543PROPERTY,
      PLANT AND EQUIPMENTElectric:Production
              
              
              4,214,909
              
              
              
              3,708,850Transmission
              
              
              1,797,755
              
              
              
              1,754,192Distribution
              
              
              2,606,423
              
              
              
              2,499,974Other
      Property, Plant and Equipment
              
              
              358,696
              
              
              
              358,873Construction
      Work in Progress
              
              
              661,531
              
              
              
              1,106,032Total
      Property, Plant and Equipment
              
              
              9,639,314
              
              
              
              9,427,921Accumulated
      Depreciation and Amortization
              
              
              2,752,839
              
              
              
              2,675,784TOTAL PROPERTY, PLANT AND
      EQUIPMENT– NET
              
              
              6,886,475
              
              
              
              6,752,137OTHER
      NONCURRENT ASSETSRegulatory
      Assets
              
              
              1,329,527
              
              
              
              999,061Long-term
      Risk Management Assets
              
              
              57,752
              
              
              
              51,095Deferred
      Charges and Other Noncurrent Assets
              
              
              96,180
              
              
              
              121,828TOTAL
      OTHER NONCURRENT ASSETS
              
              
              1,483,459
              
              
              
              1,171,984TOTAL
      ASSETS
              
              $
              9,342,067
              
              
              $
              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
 September
30, 2009 and December 31, 2008
 (Unaudited)
 
 2009
              
              
              2008CURRENT
      LIABILITIES
              
              (in
      thousands)Advances
      from Affiliates
              
              $
              231,788
              
              
              $
              194,888Accounts
      Payable:General
              
              
              195,277
              
              
              
              358,081Affiliated
      Companies
              
              
              111,723
              
              
              
              206,813Long-term
      Debt Due Within One Year – Nonaffiliated
              
              
              200,018
              
              
              
              150,017Long-term
      Debt Due Within One Year – Affiliated
              
              
              100,000
              
              
              
              -Risk
      Management Liabilities
              
              
              31,002
              
              
              
              30,620Customer
      Deposits
              
              
              57,804
              
              
              
              54,086Deferred
      Income Taxes
              
              
              74,192
              
              
              
              -Accrued
      Taxes
              
              
              42,531
              
              
              
              65,550Accrued
      Interest
              
              
              69,748
              
              
              
              47,804Other
      Current Liabilities
              
              
              70,346
              
              
              
              113,655TOTAL
      CURRENT LIABILITIES
              
              
              1,184,429
              
              
              
              1,221,514NONCURRENT
      LIABILITIESLong-term
      Debt – Nonaffiliated
              
              
              3,072,342
              
              
              
              2,924,495Long-term
      Debt – Affiliated
              
              
              -
              
              
              
              100,000Long-term
      Risk Management Liabilities
              
              
              23,654
              
              
              
              26,388Deferred
      Income Taxes
              
              
              1,316,661
              
              
              
              1,131,164Regulatory
      Liabilities and Deferred Investment Tax Credits
              
              
              547,099
              
              
              
              521,508Employee
      Benefits and Pension Obligations
              
              
              323,237
              
              
              
              331,000Deferred
      Credits and Other Noncurrent Liabilities
              
              
              117,287
              
              
              
              112,252TOTAL
      NONCURRENT LIABILITIES
              
              
              5,400,280
              
              
              
              5,146,807TOTAL
      LIABILITIES
              
              
              6,584,709
              
              
              
              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
              
              
              1,475,368
              
              
              
              1,225,292Retained
      Earnings
              
              
              1,061,338
              
              
              
              951,066Accumulated
      Other Comprehensive Income (Loss)
              
              
              (57,558
              )
              
              
              (60,225
              )TOTAL
      COMMON SHAREHOLDER’S EQUITY
              
              
              2,739,606
              
              
              
              2,376,591TOTAL
      LIABILITIES AND SHAREHOLDERS’ EQUITY
              
              $
              9,342,067
              
              
              $
              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 Nine Months Ended September 30, 2009 and 2008
 (in
thousands)
 (Unaudited)
 
 2009
              
              
              2008OPERATING
      ACTIVITIESNet
      Income
              
              $
              130,947
              
              
              $
              120,610Adjustments
      to Reconcile Net Income to Net Cash Flows from (Used for) Operating
      Activities:Depreciation
      and Amortization
              
              
              203,844
              
              
              
              186,528Deferred
      Income Taxes
              
              
              229,246
              
              
              
              111,297Carrying
      Costs Income
              
              
              (16,341
              )
              
              
              (38,921
              )Allowance
      for Equity Funds Used During Construction
              
              
              (5,734
              )
              
              
              (6,278
              )Mark-to-Market
      of Risk Management Contracts
              
              
              (31,415
              )
              
              
              7,450Fuel
      Over/Under-Recovery, Net
              
              
              (181,241
              )
              
              
              (113,748
              )Change
      in Other Noncurrent Assets
              
              
              (38,470
              )
              
              
              (24,670
              )Change
      in Other Noncurrent Liabilities
              
              
              22,595
              
              
              
              (12,565
              )Changes
      in Certain Components of Working Capital:Accounts
      Receivable, Net
              
              
              51,667
              
              
              
              (12,313
              )Fuel,
      Materials and Supplies
              
              
              (159,904
              )
              
              
              3,483Accounts
      Payable
              
              
              (131,914
              )
              
              
              41,869Accrued
      Taxes, Net
              
              
              (95,962
              )
              
              
              (51,208
              )Other
      Current Assets
              
              
              (14,172
              )
              
              
              (17,202
              )Other
      Current Liabilities
              
              
              (16,858
              )
              
              
              14,113Net
      Cash Flows from (Used for) Operating Activities
              
              
              (53,712
              )
              
              
              208,445INVESTING
      ACTIVITIESConstruction
      Expenditures
              
              
              (420,075
              )
              
              
              (487,797
              )Change
      in Other Cash Deposits
              
              
              235
              
              
              
              (18
              )Acquisitions
      of Assets
              
              
              (1,024
              )
              
              
              -Proceeds
      from Sales of Assets
              
              
              14,157
              
              
              
              15,786Net
      Cash Flows Used for Investing Activities
              
              
              (406,707
              )
              
              
              (472,029
              )FINANCING
      ACTIVITIESCapital
      Contribution from Parent
              
              
              250,000
              
              
              
              175,000Issuance
      of Long-term Debt – Nonaffiliated
              
              
              345,658
              
              
              
              686,512Change
      in Advances from Affiliates, Net
              
              
              36,900
              
              
              
              (181,699
              )Retirement
      of Long-term Debt – Nonaffiliated
              
              
              (150,012
              )
              
              
              (412,786
              )Principal
      Payments for Capital Lease Obligations
              
              
              (2,582
              )
              
              
              (3,052
              )Dividends
      Paid on Common Stock
              
              
              (20,000
              )
              
              
              -Dividends
      Paid on Cumulative Preferred Stock
              
              
              (599
              )
              
              
              (599
              )Other
      Financing Activities
              
              
              872
              
              
              
              -Net
      Cash Flows from Financing Activities
              
              
              460,237
              
              
              
              263,376Net
      Decrease in Cash and Cash Equivalents
              
              
              (182
              )
              
              
              (208
              )Cash
      and Cash Equivalents at Beginning of Period
              
              
              1,996
              
              
              
              2,195Cash
      and Cash Equivalents at End of Period
              
              $
              1,814
              
              
              $
              1,987SUPPLEMENTARY
      INFORMATIONCash
      Paid for Interest, Net of Capitalized Amounts
              
              $
              148,745
              
              
              $
              110,349Net
      Cash Received for Income Taxes
              
              
              (14,679
              )
              
              
              (26,330
              )Noncash
      Acquisitions Under Capital Leases
              
              
              884
              
              
              
              1,246Construction
      Expenditures Included in Accounts Payable at September 30,
              
              
              56,989
              
              
              
              112,376
 
 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 and Extraordinary Item
              Note
      2Rate
      Matters
              Note
      3Commitments,
      Guarantees and Contingencies
              Note
      4Benefit
      Plans
              Note
      6Business
      Segments
              Note
      7Derivatives
      and Hedging
              Note
      8Fair
      Value Measurements
              Note
      9Income
      Taxes
              Note
      10Financing
      Activities
              Note
      11
 
 
  
  
 
 
 
 
 COLUMBUS
SOUTHERN POWER COMPANY
 AND
SUBSIDIARIES
 
  
  COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
 MANAGEMENT’S NARRATIVE
FINANCIAL DISCUSSION AND ANALYSIS
 
   Results of
Operations
 Third Quarter of 2009
Compared to Third Quarter of 2008
 
 Reconciliation
of Third Quarter of 2008 to Third Quarter of 2009
 Net
Income
 (in
millions)
 
 Third
      Quarter of 2008
              
              
              
              
              $
              82Changes
      in Gross Margin:Retail
      Margins
              
              
              33Off-system
      Sales
              
              
              (41
              )Total
      Change in Gross Margin
              
              
              
              
              
              
              (8
              )Total
      Expenses and Other:Other
      Operation and Maintenance
              
              
              18Depreciation
      and Amortization
              
              
              14Other
      Income
              
              
              (1
              )Interest
      Expense
              
              
              (1
              )Total
      Expenses and Other
              
              
              
              
              
              
              30Income
      Tax Expense
              
              
              
              
              
              
              (6
              )Third
      Quarter of 2009
              
              
              
              
              
              $
              98
 
 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 increased $33 million primarily due to:·
              A
      $37 million increase related to the implementation of higher rates set by
      the Ohio ESP.·
              A
      $35 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.These
      increases were partially offset by:·
              A
      $16 million decrease in residential and commercial revenue primarily due
      to a 30% decrease in cooling degree days.·
              A
      $13 million decrease in industrial sales primarily due to reduced
      operating levels by CSPCo’s largest industrial customer,
      Ormet.·
              A
      $13 million decrease related to the cessation of Restructuring Transition
      Charge (RTC) revenues with the implementation of rates under the Ohio
      ESP.·
              Margins
      from Off-system Sales decreased $41 million primarily due to lower
      physical sales volumes and lower margins as a result of lower market
      prices, partially offset by higher trading and marketing
      margins.
 
 Total
Expenses and Other and Income Tax Expense changed between years as
follows:
 
 ·
              Other
      Operation and Maintenance expenses decreased $18 million primarily due
      to:·
              An
      $8 million decrease in expenses related to CSPCo’s Unit Power Agreement
      for AEGCo’s Lawrenceburg Plant.  In 2008, these expenses were
      recorded in Other Operation and Maintenance.  With the March
      2009 ESP order, approval was granted to record these costs in purchased
      power and recover through the FAC.·
              A
      $6 million decrease in recoverable PJM expenses.·
              A
      $2 million decrease in employee benefit expenses.·
              Depreciation
      and Amortization decreased $14 million primarily due to the completed
      amortization of transition regulatory assets in December
    2008.·
              Income
      Tax Expense increased $6 million primarily due to an increase in pretax
      book income.
 
 Nine Months Ended September
30, 2009 Compared to Nine Months Ended September 30, 2008
 
 Reconciliation
of Nine Months Ended September 30, 2008 to Nine Months Ended September 30,
2009
 Net
Income
 (in
millions)
 
 Nine
      Months Ended September 30, 2008
              
              
              
              
              $
              214Changes
      in Gross Margin:Retail
      Margins
              
              
              63Off-system
      Sales
              
              
              (92
              )Transmission
      Revenues
              
              
              (1
              )Other
              
              
              (1
              )Total
      Change in Gross Margin
              
              
              
              
              
              
              (31
              )Total
      Expenses and Other:Other
      Operation and Maintenance
              
              
              29Depreciation
      and Amortization
              
              
              41Taxes
      Other Than Income Taxes
              
              
              (2
              )Other
      Income
              
              
              (4
              )Interest
      Expense
              
              
              (7
              )Total
      Expenses and Other
              
              
              
              
              
              
              57Income
      Tax Expense
              
              
              
              
              
              
              (9
              )Nine
      Months Ended September 30, 2009
              
              
              
              
              
              $
              231
 
 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 increased $63 million primarily due to:·
              An
      $80 million increase related to the implementation of higher rates set by
      the Ohio ESP.·
              A
      $57 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.These
      increases were partially offset by:·
              A
      $39 million decrease as a result of Restructuring Transition Charge (RTC)
      revenues.  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.  During the first quarter of 2009, these
      revenues were offset in fuel under-recovery.  In 2008, RTC
      revenues were recorded but were offset through the amortization of the
      transition regulatory assets as discussed below.  With the
      implementation of the Ohio ESP, RTC revenues ended.  See “Ohio
      Electric Security Plan Filings” section of Note 3.·
              A
      $25 million decrease in industrial sales primarily due to reduced
      operating levels by CSPCo’s largest industrial customer,
      Ormet.·
              A
      $10 million decrease in commercial revenue primarily due to reduced usage
      and an 18% decrease in cooling degree days.·
              Margins
      from Off-system Sales decreased $92 million primarily due to lower
      physical sales volumes and lower margins as a result of lower market
      prices, partially offset by higher trading and marketing
      margins.
  Total
Expenses and Other and Income Tax Expense changed between years as
follows:
 
 ·
              Other
      Operation and Maintenance expenses decreased $29 million primarily due
      to:·
              A
      $25 million decrease in expenses related to CSPCo’s Unit Power Agreement
      for AEGCo’s Lawrenceburg Plant.  In 2008, these expenses were
      recorded in Other Operation and Maintenance.  With the March
      2009 ESP order, approval was granted to record these costs in purchased
      power and recover through the FAC.·
              A
      $6 million decrease in employee benefit expenses.·
              A
      $4 million decrease in recoverable PJM expenses.·
              A
      $3 million decrease in net allocated transmission expenses related to the
      AEP Transmission Equalization Agreement.·
              A
      $2 million decrease in boiler plant maintenance expenses primarily related
      to work performed at the Conesville Plant in 2008.·
              A
      $2 million decrease in maintenance expenses for overhead transmission
      lines.These
      decreases were partially offset by:·
              A
      $13 million increase in overhead distribution line expenses primarily due
      to ice and wind storms in the first quarter of 2009 and increased
      vegetation management activities.·
              A
      $6 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.·
              Depreciation
      and Amortization decreased $41 million primarily due to the completed
      amortization of transition regulatory assets in December
    2008.·
              Taxes
      Other Than Income Taxes increased $2 million primarily due to an increase
      in property taxes partially offset by a decrease in state excise
      taxes.·
              Other
      Income decreased $4 million primarily due to interest income recorded in
      2008 on expected federal tax refund related to Simple Service Cost
      Method.·
              Interest
      Expense increased $7 million primarily due to an increase in long-term
      borrowings and adjustments recorded in 2008 related to tax reserves, which
      were partially offset by an increase in the debt component of
      AFUDC.·
              Income
      Tax Expense increased $9 million primarily due to an increase 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.  As calculated on
CSPCo’s debt outstanding as of September 30, 2009, the estimated EaR on CSPCo’s
debt portfolio for the following twelve months was
$112 thousand.
  
  COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
 CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
 For
the Three and Nine Months Ended September 30, 2009 and 2008
 (in
thousands)
 (Unaudited)
 
 Three
      Months Ended
              
              
              Nine
      Months Ended2009
              
              
              2008
              
              
              2009
              
              
              2008REVENUESElectric
      Generation, Transmission and Distribution
              
              $
              533,306
              
              
              $
              633,325
              
              
              $
              1,482,421
              
              
              $
              1,638,705Sales
      to AEP Affiliates
              
              
              22,143
              
              
              
              29,032
              
              
              
              51,514
              
              
              
              111,553Other
      Revenues
              
              
              694
              
              
              
              1,426
              
              
              
              1,820
              
              
              
              4,121TOTAL
      REVENUES
              
              
              556,143
              
              
              
              663,783
              
              
              
              1,535,755
              
              
              
              1,754,379EXPENSESFuel
      and Other Consumables Used for Electric Generation
              
              
              88,523
              
              
              
              112,566
              
              
              
              222,943
              
              
              
              283,946Purchased
      Electricity for Resale
              
              
              21,750
              
              
              
              63,441
              
              
              
              74,010
              
              
              
              150,637Purchased
      Electricity from AEP Affiliates
              
              
              105,120
              
              
              
              139,017
              
              
              
              294,280
              
              
              
              343,699Other
      Operation
              
              
              68,971
              
              
              
              87,358
              
              
              
              210,614
              
              
              
              245,379Maintenance
              
              
              23,926
              
              
              
              23,039
              
              
              
              86,558
              
              
              
              80,705Depreciation
      and Amortization
              
              
              36,292
              
              
              
              50,373
              
              
              
              105,863
              
              
              
              146,668Taxes
      Other Than Income Taxes
              
              
              44,149
              
              
              
              44,533
              
              
              
              132,576
              
              
              
              130,078TOTAL
      EXPENSES
              
              
              388,731
              
              
              
              520,327
              
              
              
              1,126,844
              
              
              
              1,381,112OPERATING
      INCOME
              
              
              167,412
              
              
              
              143,456
              
              
              
              408,911
              
              
              
              373,267Other
      Income (Expense):Interest
      Income
              
              
              144
              
              
              
              1,515
              
              
              
              618
              
              
              
              5,457Carrying
      Costs Income
              
              
              1,984
              
              
              
              1,566
              
              
              
              5,394
              
              
              
              4,870Allowance
      for Equity Funds Used During Construction
              
              
              914
              
              
              
              745
              
              
              
              2,799
              
              
              
              2,165Interest
      Expense
              
              
              (22,487
              )
              
              
              (21,127
              )
              
              
              (64,356
              )
              
              
              (57,612
              )INCOME
      BEFORE INCOME TAX EXPENSE
              
              
              147,967
              
              
              
              126,155
              
              
              
              353,366
              
              
              
              328,147Income
      Tax Expense
              
              
              50,374
              
              
              
              44,493
              
              
              
              122,737
              
              
              
              113,939NET
      INCOME
              
              
              97,593
              
              
              
              81,662
              
              
              
              230,629
              
              
              
              214,208Capital
      Stock Expense
              
              
              39
              
              
              
              39
              
              
              
              118
              
              
              
              118EARNINGS
      ATTRIBUTABLE TO COMMON STOCK
              
              $
              97,554
              
              
              $
              81,623
              
              
              $
              230,511
              
              
              $
              214,090
 
 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 Nine Months Ended September 30, 2009 and 2008
 (in
thousands)
 (Unaudited)
 
 Common
      Stock
              
              
              Paid-in
      Capital
              
              
              Retained
      Earnings
              
              
              Accumulated
                Other
                Comprehensive
      Income (Loss)
              
              
              TotalTOTAL COMMON SHAREHOLDER’S
      EQUITY– DECEMBER
      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
              
              
              
              
              
              
              
              
              
              
              (87,500
              )
              
              
              
              
              
              
              (87,500
              )Capital
      Stock Expense
              
              
              
              
              
              
              118
              
              
              
              (118
              )
              
              
              
              
              
              
              -SUBTOTAL
      – COMMON SHAREHOLDER’S EQUITY
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              1,075,366COMPREHENSIVE
      INCOMEOther
      Comprehensive Income, Net of Taxes:Cash
      Flow Hedges, Net of Tax of $582
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              1,080
              
              
              
              1,080Amortization
      of Pension and OPEB Deferred Costs, Net of Tax of $456
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              846
              
              
              
              846NET
      INCOME
              
              
              
              
              
              
              
              
              
              
              214,208
              
              
              
              
              
              
              
              214,208TOTAL
      COMPREHENSIVE INCOME
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              216,134TOTAL COMMON SHAREHOLDER’S
      EQUITY– SEPTEMBER
      30, 2008
              
              $
              41,026
              
              
              $
              580,467
              
              
              $
              686,875
              
              
              $
              (16,868
              )
              
              $
              1,291,500TOTAL COMMON SHAREHOLDER’S
      EQUITY– DECEMBER
      31, 2008
              
              $
              41,026
              
              
              $
              580,506
              
              
              $
              674,758
              
              
              $
              (51,025
              )
              
              $
              1,245,265Common
      Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (150,000
              )
              
              
              
              
              
              
              (150,000
              )Capital
      Stock Expense
              
              
              
              
              
              
              118
              
              
              
              (118
              )
              
              
              
              
              
              
              -Noncash
      Dividend of Property to Parent
              
              
              
              
              
              
              
              
              
              
              (8,123
              )
              
              
              
              
              
              
              (8,123
              )SUBTOTAL
      – COMMON SHAREHOLDER’S EQUITY
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              1,087,142COMPREHENSIVE
      INCOMEOther
      Comprehensive Income (Loss), Net of Taxes:Cash
      Flow Hedges, Net of Tax of $699
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              (1,299
              )
              
              
              (1,299
              )Amortization
      of Pension and OPEB Deferred Costs, Net of Tax of $894
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              1,661
              
              
              
              1,661NET
      INCOME
              
              
              
              
              
              
              
              
              
              
              230,629
              
              
              
              
              
              
              
              230,629TOTAL
      COMPREHENSIVE INCOME
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              230,991TOTAL COMMON SHAREHOLDER’S
      EQUITY– SEPTEMBER
      30, 2009
              
              $
              41,026
              
              
              $
              580,624
              
              
              $
              747,146
              
              
              $
              (50,663
              )
              
              $
              1,318,133
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
 
 
 
  
  COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
 CONDENSED
CONSOLIDATED BALANCE SHEETS
 ASSETS
 September
30, 2009 and December 31, 2008
 (in
thousands)
 (Unaudited)
 
 2009
              
              
              2008CURRENT
      ASSETSCash
      and Cash Equivalents
              
              $
              1,204
              
              
              $
              1,063Other
      Cash Deposits
              
              
              20,077
              
              
              
              32,300Accounts
      Receivable:Customers
              
              
              22,153
              
              
              
              56,008Affiliated
      Companies
              
              
              20,176
              
              
              
              44,235Accrued
      Unbilled Revenues
              
              
              24,878
              
              
              
              18,359Miscellaneous
              
              
              2,141
              
              
              
              11,546Allowance
      for Uncollectible Accounts
              
              
              (3,565
              )
              
              
              (2,895
              )Total
      Accounts Receivable
              
              
              65,783
              
              
              
              127,253Fuel
              
              
              72,204
              
              
              
              42,075Materials
      and Supplies
              
              
              38,886
              
              
              
              33,781Emission
      Allowances
              
              
              13,794
              
              
              
              20,211Risk
      Management Assets
              
              
              43,916
              
              
              
              35,984Accrued
      Tax Benefits
              
              
              18,023
              
              
              
              469Margin
      Deposits
              
              
              17,652
              
              
              
              13,613Prepayments
      and Other Current Assets
              
              
              9,616
              
              
              
              27,411TOTAL
      CURRENT ASSETS
              
              
              301,155
              
              
              
              334,160PROPERTY,
      PLANT AND EQUIPMENTElectric:Production
              
              
              2,372,111
              
              
              
              2,326,056Transmission
              
              
              610,824
              
              
              
              574,018Distribution
              
              
              1,699,698
              
              
              
              1,625,000Other
      Property, Plant and Equipment
              
              
              201,890
              
              
              
              211,088Construction
      Work in Progress
              
              
              399,388
              
              
              
              394,918Total
      Property, Plant and Equipment
              
              
              5,283,911
              
              
              
              5,131,080Accumulated
      Depreciation and Amortization
              
              
              1,844,261
              
              
              
              1,781,866TOTAL
      PROPERTY, PLANT AND EQUIPMENT – NET
              
              
              3,439,650
              
              
              
              3,349,214OTHER
      NONCURRENT ASSETSRegulatory
      Assets
              
              
              335,691
              
              
              
              298,357Long-term
      Risk Management Assets
              
              
              30,569
              
              
              
              28,461Deferred
      Charges and Other Noncurrent Assets
              
              
              72,798
              
              
              
              125,814TOTAL
      OTHER NONCURRENT ASSETS
              
              
              439,058
              
              
              
              452,632TOTAL
      ASSETS
              
              $
              4,179,863
              
              
              $
              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
 September
30, 2009 and December 31, 2008
 (Unaudited)
 
 2009
              
              
              2008CURRENT
      LIABILITIES
              
              (in
      thousands)Advances
      from Affiliates
              
              $
              20,095
              
              
              $
              74,865Accounts
      Payable:General
              
              
              88,992
              
              
              
              131,417Affiliated
      Companies
              
              
              84,743
              
              
              
              120,420Long-term
      Debt Due Within One Year – Affiliated
              
              
              100,000
              
              
              
              -Risk
      Management Liabilities
              
              
              16,275
              
              
              
              16,490Customer
      Deposits
              
              
              28,067
              
              
              
              30,145Accrued
      Taxes
              
              
              100,021
              
              
              
              185,293Accrued
      Interest
              
              
              26,776
              
              
              
              23,867Other
      Current Liabilities
              
              
              67,275
              
              
              
              58,811TOTAL
      CURRENT LIABILITIES
              
              
              532,244
              
              
              
              641,308NONCURRENT
      LIABILITIESLong-term
      Debt – Nonaffiliated
              
              
              1,436,291
              
              
              
              1,343,594Long-term
      Debt – Affiliated
              
              
              -
              
              
              
              100,000Long-term
      Risk Management Liabilities
              
              
              12,522
              
              
              
              14,774Deferred
      Income Taxes
              
              
              511,102
              
              
              
              435,773Regulatory
      Liabilities and Deferred Investment Tax Credits
              
              
              179,825
              
              
              
              161,102Employee
      Benefits and Pension Obligations
              
              
              142,020
              
              
              
              148,123Deferred
      Credits and Other Noncurrent Liabilities
              
              
              47,726
              
              
              
              46,067TOTAL
      NONCURRENT LIABILITIES
              
              
              2,329,486
              
              
              
              2,249,433TOTAL
      LIABILITIES
              
              
              2,861,730
              
              
              
              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
              
              
              580,624
              
              
              
              580,506Retained
      Earnings
              
              
              747,146
              
              
              
              674,758Accumulated
      Other Comprehensive Income (Loss)
              
              
              (50,663
              )
              
              
              (51,025
              )TOTAL
      COMMON SHAREHOLDER’S EQUITY
              
              
              1,318,133
              
              
              
              1,245,265TOTAL
      LIABILITIES AND SHAREHOLDER’S EQUITY
              
              $
              4,179,863
              
              
              $
              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 Nine Months Ended September 30, 2009 and 2008
 (in
thousands)
 (Unaudited)
 
 2009
              
              
              2008OPERATING
      ACTIVITIESNet
      Income
              
              $
              230,629
              
              
              $
              214,208Adjustments
      to Reconcile Net Income to Net Cash Flows from Operating
      Activities:Depreciation
      and Amortization
              
              
              105,863
              
              
              
              146,668Deferred
      Income Taxes
              
              
              97,279
              
              
              
              8,981Carrying
      Costs Income
              
              
              (5,394
              )
              
              
              (4,870
              )Allowance
      for Equity Funds Used During Construction
              
              
              (2,799
              )
              
              
              (2,165
              )Mark-to-Market
      of Risk Management Contracts
              
              
              (14,832
              )
              
              
              5,326Deferred
      Property Taxes
              
              
              67,012
              
              
              
              65,763Fuel
      Over/Under-Recovery, Net
              
              
              (36,401
              )
              
              
              -Change
      in Other Noncurrent Assets
              
              
              (18,365
              )
              
              
              (7,942
              )Change
      in Other Noncurrent Liabilities
              
              
              22,644
              
              
              
              (4,081
              )Changes
      in Certain Components of Working Capital:Accounts
      Receivable, Net
              
              
              62,244
              
              
              
              (13,757
              )Fuel,
      Materials and Supplies
              
              
              (28,817
              )
              
              
              7,415Accounts
      Payable
              
              
              (56,723
              )
              
              
              (2,650
              )Customer
      Deposits
              
              
              (2,078
              )
              
              
              (13,100
              )Accrued
      Taxes, Net
              
              
              (102,827
              )
              
              
              (26,358
              )Other
      Current Assets
              
              
              8,017
              
              
              
              (13,178
              )Other
      Current Liabilities
              
              
              (5,914
              )
              
              
              (14,018
              )Net
      Cash Flows from Operating Activities
              
              
              319,538
              
              
              
              346,242INVESTING
      ACTIVITIESConstruction
      Expenditures
              
              
              (216,737
              )
              
              
              (304,175
              )Change
      in Other Cash Deposits
              
              
              12,223
              
              
              
              21,796Change
      in Advances to Affiliates, Net
              
              
              -
              
              
              
              (21,833
              )Acquisitions
      of Assets
              
              
              (227
              )
              
              
              -Proceeds
      from Sales of Assets
              
              
              721
              
              
              
              1,287Net
      Cash Flows Used for Investing Activities
              
              
              (204,020
              )
              
              
              (302,925
              )FINANCING
      ACTIVITIESIssuance
      of Long-term Debt – Nonaffiliated
              
              
              91,204
              
              
              
              346,407Change
      in Advances from Affiliates, Net
              
              
              (54,770
              )
              
              
              (95,199
              )Retirement
      of Long-term Debt – Nonaffiliated
              
              
              -
              
              
              
              (204,245
              )Principal
      Payments for Capital Lease Obligations
              
              
              (2,017
              )
              
              
              (2,213
              )Dividends
      Paid on Common Stock
              
              
              (150,000
              )
              
              
              (87,500
              )Other
      Financing Activities
              
              
              206
              
              
              
              -Net
      Cash Flows Used for Financing Activities
              
              
              (115,377
              )
              
              
              (42,750
              )Net
      Increase in Cash and Cash Equivalents
              
              
              141
              
              
              
              567Cash
      and Cash Equivalents at Beginning of Period
              
              
              1,063
              
              
              
              1,389Cash
      and Cash Equivalents at End of Period
              
              $
              1,204
              
              
              $
              1,956SUPPLEMENTARY
      INFORMATIONCash
      Paid for Interest, Net of Capitalized Amounts
              
              $
              71,032
              
              
              $
              57,004Net
      Cash Paid for Income Taxes
              
              
              10,997
              
              
              
              53,682Noncash
      Acquisitions Under Capital Leases
              
              
              784
              
              
              
              1,374Construction
      Expenditures Included in Accounts Payable at September 30,
              
              
              26,688
              
              
              
              51,997Noncash
      Dividend of Property to Parent
              
              
              8,123
              
              
              
              -
 
 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 and Extraordinary Item
              Note
      2Rate
      Matters
              Note
      3Commitments,
      Guarantees and Contingencies
              Note
      4Benefit
      Plans
              Note
      6Business
      Segments
              Note
      7Derivatives
      and Hedging
              Note
      8Fair
      Value Measurements
              Note
      9Income
      Taxes
              Note
      10Financing
      Activities
              Note
      11
 
 
 
  
  
 
 
 
 
 INDIANA
MICHIGAN POWER COMPANY
 AND
SUBSIDIARIES
 
  
  INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
 MANAGEMENT’S NARRATIVE
FINANCIAL DISCUSSION AND ANALYSIS
 
 
 Results of
Operations
 
 Third Quarter of 2009
Compared to Third Quarter of 2008
 
 Reconciliation
of Third Quarter of 2008 to Third Quarter of 2009
 Net
Income
 (in
millions)
 
 Third
      Quarter of 2008
              
              
              
              
              $
              46Changes
      in Gross Margin:Retail
      Margins
              
              
              (2
              )FERC
      Municipals and Cooperatives
              
              
              1Off-system
      Sales
              
              
              (39
              )Other
              
              
              38Total
      Change in Gross Margin
              
              
              
              
              
              
              (2
              )Total
      Expenses and Other:Other
      Operation and Maintenance
              
              
              17Depreciation
      and Amortization
              
              
              (2
              )Other
      Income
              
              
              4Interest
      Expense
              
              
              (5
              )Total
      Expenses and Other
              
              
              
              
              
              
              14Income
      Tax Expense
              
              
              
              
              
              
              (3
              )Third
      Quarter of 2009
              
              
              
              
              
              $
              55
 
 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:
 
 ·
              Margins
      from Off-system Sales decreased $39 million primarily due to lower
      physical sales volumes and lower margins as a result of lower market
      prices, partially offset by higher trading and marketing
      margins.·
              Other
      revenues increased $38 million primarily due to Cook Plant accidental
      outage insurance policy proceeds of $46 million.  Of these
      insurance proceeds, $19 million were used to reduce customer bills which
      are primarily included in Retail Margins.  See “Cook Plant Unit
      1 Fire and Shutdown” section of Note 4.  A decrease in River
      Transportation Division (RTD) revenues partially offset the insurance
      proceeds.  RTD’s related expenses which offset the RTD revenues
      are included in Other Operation on the Condensed Consolidated Statements
      of Income.
 
 Total
Expenses and Other changed between years as follows:
 
 ·
              Other
      Operation and Maintenance expenses decreased $17 million primarily due to
      declines in operation and maintenance expenses of $9 million for nuclear
      operations and $8 million for RTD caused by decreased barging
      activity.·
              Other
      Income increased $4 million due to higher equity AFUDC.·
              Interest
      Expense increased $5 million primarily due to increased
      borrowings.  In January 2009, I&M issued $475 million of 7%
      Senior Unsecured Notes.
  Nine Months Ended September
30, 2009 Compared to Nine Months Ended September 30, 2008
 
 Reconciliation
of Nine Months Ended September 30, 2008 to Nine Months Ended September 30,
2009
 Net
Income
 (in
millions)
 
 Nine
      Months Ended September 30, 2008
              
              
              
              
              $
              151Changes
      in Gross Margin:Retail
      Margins
              
              
              (26
              )FERC
      Municipals and Cooperatives
              
              
              5Off-system
      Sales
              
              
              (94
              )Transmission
      Revenues
              
              
              (1
              )Other
              
              
              132Total
      Change in Gross Margin
              
              
              
              
              
              
              16Total
      Expenses and Other:Other
      Operation and Maintenance
              
              
              43Depreciation
      and Amortization
              
              
              (5
              )Taxes
      Other Than Income Taxes
              
              
              2Other
      Income
              
              
              8Interest
      Expense
              
              
              (18
              )Total
      Expenses and Other
              
              
              
              
              
              
              30Income
      Tax Expense
              
              
              
              
              
              
              (13
              )Nine
      Months Ended September 30, 2009
              
              
              
              
              
              $
              184
 
 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 $26 million primarily due to the
    following:·
              A
      $37 million decline due to a 16% decrease in industrial sales resulting
      from reduced operating levels and suspended operations by certain large
      industrial customers.·
              Lower
      fuel recoveries reflecting $59 million of Cook Plant accidental outage
      insurance proceeds allocated to customers under fuel
    clauses.These
      decreases were partially offset by:·
              A
      $29 million increase in capacity revenue reflecting MLR
      changes.·
              A
      $26 million increase from an Indiana rate settlement.  See
      “Indiana Base Rate Filing” section of Note 3.·
              A
      $17 million favorable impact for lower PJM charges reflecting a decline in
      sales volume.·
              Margins
      from Off-system Sales decreased $94 million primarily due to lower
      physical sales volumes and lower margins as a result of lower market
      prices, partially offset by higher trading and marketing
      margins.·
              Other
      revenues increased $132 million primarily due to Cook Plant accidental
      outage insurance policy proceeds of $145 million.  Of the
      insurance proceeds, $59 million were used to reduce customer bills which
      are primarily included in Retail Margins.  See “Cook Plant Unit
      1 Fire and Shutdown” section of Note 4.  A decrease in RTD
      revenues partially offset the insurance proceeds.  RTD’s related
      expenses which offset the RTD revenues are included in Other Operation on
      the Condensed Consolidated Statements of
Income.
  Total
Expenses and Other and Income Tax Expense changed between years as
follows:
 
 ·
              Other Operation
      and Maintenance expenses decreased $43 million primarily due to the
      following:·
              A
      $21 million decline for nuclear and coal-fired generating operation and
      maintenance expenses reflecting cost containment efforts, deferral of
      costs during outages and deferral of NSR costs provided in the rate
      settlement for recovery.  See “Indiana Base Rate Filing” section
      of Note 3.·
              An
      $11 million decline for RTD caused by decreased barging
      activity.·
              A
      $7 million decline in accretion expense reflecting a change in the annual
      decommissioning estimate at Cook Plant for an extension of its life
      authorized in the rate settlement.·
              Other
      Income increased $8 million due to higher equity AFUDC.·
              Interest
      Expense increased $18 million primarily due to increased
      borrowings.  In January 2009, I&M issued $475 million of 7%
      Senior Unsecured Notes.·
              Income
      Tax Expense increased $13 million primarily due to an increase in pretax
      book income, partially offset by a decrease in state income
      taxes.
 
 Cook Plant Unit 1 Fire and
Shutdown
 
 In
September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine
vibrations, 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.  I&M is repairing
Unit 1 to resume operations as early as the fourth quarter of 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 September 30, 2009, I&M recorded $122 million
in Prepayments and Other Current Assets on the Condensed Consolidated Balance
Sheets representing recoverable amounts under the property insurance
policy.  Through September 30, 2009, I&M received partial payments
of $72 million 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 2009, I&M
recorded $145 million in revenues and applied $59 million of the accidental
outage insurance proceeds to reduce customer bills.
 
 NEIL is
reviewing claims made under the insurance policies to ensure that claims
associated with the outage are covered by the policies.  The treatment
of property damage costs, replacement power costs and insurance proceeds will be
the subject of future regulatory proceedings in Indiana and
Michigan.  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 or if any future regulatory
proceedings are adverse, 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.  As calculated on
I&M’s debt outstanding as of September 30, 2009, the estimated EaR on
I&M’s debt portfolio for the following twelve months was $2.3
million.
  
  INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
 CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
 For
the Three and Nine Months Ended September 30, 2009 and 2008
 (in
thousands)
 (Unaudited)
 
 Three
      Months Ended
              
              
              Nine
      Months Ended2009
              
              
              2008
              
              
              2009
              
              
              2008REVENUESElectric
      Generation, Transmission and Distribution
              
              $
              435,399
              
              
              $
              513,548
              
              
              $
              1,257,673
              
              
              $
              1,370,158Sales
      to AEP Affiliates
              
              
              43,796
              
              
              
              72,295
              
              
              
              161,167
              
              
              
              232,734Other
      Revenues – Affiliated
              
              
              24,958
              
              
              
              31,792
              
              
              
              80,890
              
              
              
              84,268Other
      Revenues – Nonaffiliated
              
              
              48,114
              
              
              
              3,388
              
              
              
              149,997
              
              
              
              13,659TOTAL
      REVENUES
              
              
              552,267
              
              
              
              621,023
              
              
              
              1,649,727
              
              
              
              1,700,819EXPENSESFuel
      and Other Consumables Used for Electric Generation
              
              
              105,287
              
              
              
              141,563
              
              
              
              316,449
              
              
              
              351,300Purchased
      Electricity for Resale
              
              
              28,203
              
              
              
              39,427
              
              
              
              97,417
              
              
              
              87,351Purchased
      Electricity from AEP Affiliates
              
              
              93,093
              
              
              
              112,060
              
              
              
              253,964
              
              
              
              296,559Other
      Operation
              
              
              121,737
              
              
              
              136,875
              
              
              
              346,421
              
              
              
              381,928Maintenance
              
              
              50,650
              
              
              
              52,573
              
              
              
              148,412
              
              
              
              156,402Depreciation
      and Amortization
              
              
              34,032
              
              
              
              31,822
              
              
              
              100,406
              
              
              
              95,301Taxes
      Other Than Income Taxes
              
              
              19,122
              
              
              
              19,992
              
              
              
              58,071
              
              
              
              60,236TOTAL
      EXPENSES
              
              
              452,124
              
              
              
              534,312
              
              
              
              1,321,140
              
              
              
              1,429,077OPERATING
      INCOME
              
              
              100,143
              
              
              
              86,711
              
              
              
              328,587
              
              
              
              271,742Other
      Income (Expense):Other
      Income
              
              
              5,024
              
              
              
              880
              
              
              
              12,879
              
              
              
              4,621Interest
      Expense
              
              
              (25,668
              )
              
              
              (20,629
              )
              
              
              (75,372
              )
              
              
              (56,977
              )INCOME
      BEFORE INCOME TAX EXPENSE
              
              
              79,499
              
              
              
              66,962
              
              
              
              266,094
              
              
              
              219,386Income
      Tax Expense
              
              
              24,640
              
              
              
              21,326
              
              
              
              81,774
              
              
              
              68,348NET
      INCOME
              
              
              54,859
              
              
              
              45,636
              
              
              
              184,320
              
              
              
              151,038Preferred
      Stock Dividend Requirements
              
              
              85
              
              
              
              85
              
              
              
              255
              
              
              
              255EARNINGS
      ATTRIBUTABLE TO COMMON STOCK
              
              $
              54,774
              
              
              $
              45,551
              
              
              $
              184,065
              
              
              $
              150,783
 
 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 Nine Months Ended September 30, 2009 and 2008
 (in
thousands)
 (Unaudited)
 
 Common
      Stock
              
              
              Paid-in
      Capital
              
              
              Retained
      Earnings
              
              
              Accumulated
      Other Comprehensive Income (Loss)
              
              
              TotalTOTAL COMMON SHAREHOLDER’S
      EQUITY– DECEMBER
      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
              
              
              
              
              
              
              
              
              
              
              (56,250
              )
              
              
              
              
              
              
              (56,250
              )Preferred
      Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (255
              )
              
              
              
              
              
              
              (255
              )SUBTOTAL
      – COMMON SHAREHOLDER’S EQUITY
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              1,327,796COMPREHENSIVE
      INCOMEOther
      Comprehensive Income, Net of Taxes:Cash
      Flow Hedges, Net of Tax of $967
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              1,795
              
              
              
              1,795Amortization
      of Pension and OPEB Deferred
                Costs,
      Net of Tax of $178
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              331
              
              
              
              331NET
      INCOME
              
              
              
              
              
              
              
              
              
              
              151,038
              
              
              
              
              
              
              
              151,038TOTAL
      COMPREHENSIVE INCOME
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              153,164TOTAL COMMON SHAREHOLDER’S
      EQUITY– SEPTEMBER
      30, 2008
              
              $
              56,584
              
              
              $
              861,291
              
              
              $
              576,634
              
              
              $
              (13,549
              )
              
              $
              1,480,960TOTAL COMMON SHAREHOLDER’S
      EQUITY– DECEMBER
      31, 2008
              
              $
              56,584
              
              
              $
              861,291
              
              
              $
              538,637
              
              
              $
              (21,694
              )
              
              $
              1,434,818Capital
      Contribution from Parent
              
              
              
              
              
              
              120,000
              
              
              
              
              
              
              
              
              
              
              
              120,000Common
      Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (73,500
              )
              
              
              
              
              
              
              (73,500
              )Preferred
      Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (255
              )
              
              
              
              
              
              
              (255
              )Gain
      on Reacquired Preferred Stock
              
              
              
              
              
              
              1
              
              
              
              
              
              
              
              
              
              
              
              1SUBTOTAL
      – COMMON SHAREHOLDER’S EQUITY
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              1,481,064COMPREHENSIVE
      INCOMEOther
      Comprehensive Income (Loss), Net of Taxes:Cash
      Flow Hedges, Net of Tax of $265
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              (492
              )
              
              
              (492
              )Amortization
      of Pension and OPEB Deferred
                Costs,
      Net of Tax of $334
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              620
              
              
              
              620NET
      INCOME
              
              
              
              
              
              
              
              
              
              
              184,320
              
              
              
              
              
              
              
              184,320TOTAL
      COMPREHENSIVE INCOME
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              184,448TOTAL COMMON SHAREHOLDER’S
      EQUITY– SEPTEMBER
      30, 2009
              
              $
              56,584
              
              
              $
              981,292
              
              
              $
              649,202
              
              
              $
              (21,566
              )
              
              $
              1,665,512
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
 
 
  
  INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
 CONDENSED
CONSOLIDATED BALANCE SHEETS
 ASSETS
 September
30, 2009 and December 31, 2008
 (in
thousands)
 (Unaudited)
 
 2009
              
              
              2008CURRENT
      ASSETSCash
      and Cash Equivalents
              
              $
              843
              
              
              $
              728Advances
      to Affiliates
              
              
              160,749
              
              
              
              -Accounts
      Receivable:Customers
              
              
              54,690
              
              
              
              70,432Affiliated
      Companies
              
              
              117,941
              
              
              
              94,205Accrued
      Unbilled Revenues
              
              
              11,612
              
              
              
              19,260Miscellaneous
              
              
              2,477
              
              
              
              1,010Allowance
      for Uncollectible Accounts
              
              
              (2,113
              )
              
              
              (3,310
              )Total
      Accounts Receivable
              
              
              184,607
              
              
              
              181,597Fuel
              
              
              67,795
              
              
              
              67,138Materials
      and Supplies
              
              
              151,578
              
              
              
              150,644Risk
      Management Assets
              
              
              43,120
              
              
              
              35,012Regulatory
      Asset for Under-Recovered Fuel Costs
              
              
              9,965
              
              
              
              33,066Prepayments
      and Other Current Assets
              
              
              166,137
              
              
              
              66,733TOTAL
      CURRENT ASSETS
              
              
              784,794
              
              
              
              534,918PROPERTY,
      PLANT AND EQUIPMENTElectric:Production
              
              
              3,584,836
              
              
              
              3,534,188Transmission
              
              
              1,147,401
              
              
              
              1,115,762Distribution
              
              
              1,339,065
              
              
              
              1,297,482Other
      Property, Plant and Equipment (including nuclear fuel and coal
      mining)
              
              
              785,504
              
              
              
              703,287Construction
      Work in Progress
              
              
              308,039
              
              
              
              249,020Total
      Property, Plant and Equipment
              
              
              7,164,845
              
              
              
              6,899,739Accumulated
      Depreciation, Depletion and Amortization
              
              
              3,101,119
              
              
              
              3,019,206TOTAL
      PROPERTY, PLANT AND EQUIPMENT – NET
              
              
              4,063,726
              
              
              
              3,880,533OTHER
      NONCURRENT ASSETSRegulatory
      Assets
              
              
              495,305
              
              
              
              455,132Spent
      Nuclear Fuel and Decommissioning Trusts
              
              
              1,364,442
              
              
              
              1,259,533Long-term
      Risk Management Assets
              
              
              29,592
              
              
              
              27,616Deferred
      Charges and Other Noncurrent Assets
              
              
              88,894
              
              
              
              86,193TOTAL
      OTHER NONCURRENT ASSETS
              
              
              1,978,233
              
              
              
              1,828,474TOTAL
      ASSETS
              
              $
              6,826,753
              
              
              $
              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
 September
30, 2009 and December 31, 2008
 (Unaudited)
 
 2009
              
              
              2008CURRENT
      LIABILITIES
              
              (in
      thousands)Advances
      from Affiliates
              
              $
              -
              
              
              $
              476,036Accounts
      Payable:General
              
              
              144,806
              
              
              
              194,211Affiliated
      Companies
              
              
              73,395
              
              
              
              117,589Long-term
      Debt Due Within One Year – Nonaffiliated
              
              
              37,544
              
              
              
              -Long-term
      Debt Due Within One Year – Affiliated
              
              
              25,000
              
              
              
              -Risk
      Management Liabilities
              
              
              16,011
              
              
              
              16,079Customer
      Deposits
              
              
              27,493
              
              
              
              26,809Accrued
      Taxes
              
              
              54,358
              
              
              
              66,363Obligations
      Under Capital Leases
              
              
              30,347
              
              
              
              43,512Other
      Current Liabilities
              
              
              118,519
              
              
              
              141,160TOTAL
      CURRENT LIABILITIES
              
              
              527,473
              
              
              
              1,081,759NONCURRENT
      LIABILITIESLong-term
      Debt – Nonaffiliated
              
              
              2,015,155
              
              
              
              1,377,914Long-term
      Risk Management Liabilities
              
              
              12,121
              
              
              
              14,311Deferred
      Income Taxes
              
              
              583,183
              
              
              
              412,264Regulatory
      Liabilities and Deferred Investment Tax Credits
              
              
              738,889
              
              
              
              656,396Asset
      Retirement Obligations
              
              
              938,504
              
              
              
              902,920Deferred
      Credits and Other Noncurrent Liabilities
              
              
              337,839
              
              
              
              355,463TOTAL
      NONCURRENT LIABILITIES
              
              
              4,625,691
              
              
              
              3,719,268TOTAL
      LIABILITIES
              
              
              5,153,164
              
              
              
              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
              
              
              981,292
              
              
              
              861,291Retained
      Earnings
              
              
              649,202
              
              
              
              538,637Accumulated
      Other Comprehensive Income (Loss)
              
              
              (21,566
              )
              
              
              (21,694
              )TOTAL
      COMMON SHAREHOLDER’S EQUITY
              
              
              1,665,512
              
              
              
              1,434,818TOTAL
      LIABILITIES AND SHAREHOLDERS’ EQUITY
              
              $
              6,826,753
              
              
              $
              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 Nine Months Ended September 30, 2009 and 2008
 (in
thousands)
 (Unaudited)
 
 2009
              
              
              2008OPERATING
      ACTIVITIESNet
      Income
              
              $
              184,320
              
              
              $
              151,038Adjustments
      to Reconcile Net Income to Net Cash Flows from Operating
      Activities:Depreciation
      and Amortization
              
              
              100,406
              
              
              
              95,301Deferred
      Income Taxes
              
              
              133,959
              
              
              
              47,565Amortization
      (Deferral) of Incremental Nuclear Refueling Outage Expenses,
      Net
              
              
              (4,563
              )
              
              
              834Allowance
      for Equity Funds Used During Construction
              
              
              (7,830
              )
              
              
              (967
              )Mark-to-Market
      of Risk Management Contracts
              
              
              (14,580
              )
              
              
              4,876Amortization
      of Nuclear Fuel
              
              
              41,198
              
              
              
              72,453Change
      in Other Noncurrent Assets
              
              
              285
              
              
              
              5,678Change
      in Other Noncurrent Liabilities
              
              
              50,932
              
              
              
              38,568Changes
      in Certain Components of Working Capital:Accounts
      Receivable, Net
              
              
              (2,322
              )
              
              
              (2,422
              )Fuel,
      Materials and Supplies
              
              
              (1,591
              )
              
              
              12,736Accounts
      Payable
              
              
              (48,044
              )
              
              
              16,549Accrued
      Taxes, Net
              
              
              (15,005
              )
              
              
              2,550Other
      Current Assets
              
              
              (54,221
              )
              
              
              (24,736
              )Other
      Current Liabilities
              
              
              (20,598
              )
              
              
              1,393Net
      Cash Flows from Operating Activities
              
              
              342,346
              
              
              
              421,416INVESTING
      ACTIVITIESConstruction
      Expenditures
              
              
              (242,256
              )
              
              
              (221,538
              )Change
      in Advances to Affiliates, Net
              
              
              (160,749
              )
              
              
              -Purchases
      of Investment Securities
              
              
              (571,167
              )
              
              
              (413,538
              )Sales
      of Investment Securities
              
              
              523,927
              
              
              
              362,773Acquisitions
      of Nuclear Fuel
              
              
              (153,172
              )
              
              
              (99,110
              )Other
      Investing Activities
              
              
              18,990
              
              
              
              3,376Net
      Cash Flows Used for Investing Activities
              
              
              (584,427
              )
              
              
              (368,037
              )FINANCING
      ACTIVITIESCapital
      Contribution from Parent
              
              
              120,000
              
              
              
              -Issuance
      of Long-term Debt – Nonaffiliated
              
              
              670,060
              
              
              
              115,225Issuance
      of Long-term Debt – Affiliated
              
              
              25,000
              
              
              
              -Change
      in Advances from Affiliates, Net
              
              
              (476,036
              )
              
              
              179,007Retirement
      of Long-term Debt – Nonaffiliated
              
              
              -
              
              
              
              (262,000
              )Retirement
      of Cumulative Preferred Stock
              
              
              (2
              )
              
              
              -Principal
      Payments for Capital Lease Obligations
              
              
              (23,640
              )
              
              
              (28,917
              )Dividends
      Paid on Common Stock
              
              
              (73,500
              )
              
              
              (56,250
              )Dividends
      Paid on Cumulative Preferred Stock
              
              
              (255
              )
              
              
              (255
              )Other
      Financing Activities
              
              
              569
              
              
              
              -Net
      Cash Flows from (Used for) Financing Activities
              
              
              242,196
              
              
              
              (53,190
              )Net
      Increase in Cash and Cash Equivalents
              
              
              115
              
              
              
              189Cash
      and Cash Equivalents at Beginning of Period
              
              
              728
              
              
              
              1,139Cash
      and Cash Equivalents at End of Period
              
              $
              843
              
              
              $
              1,328SUPPLEMENTARY
      INFORMATIONCash
      Paid for Interest, Net of Capitalized Amounts
              
              $
              81,833
              
              
              $
              57,086Net
      Cash Paid (Received) for Income Taxes
              
              
              (21,414
              )
              
              
              7,482Noncash
      Acquisitions Under Capital Leases
              
              
              2,344
              
              
              
              3,279Construction
      Expenditures Included in Accounts Payable at September 30,
              
              
              42,576
              
              
              
              26,150Acquisition
      of Nuclear Fuel Included in Accounts Payable at September
    30,
              
              
              2
              
              
              
              66,127
 
 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 and Extraordinary Item
              Note
      2Rate
      Matters
              Note
      3Commitments,
      Guarantees and Contingencies
              Note
      4Benefit
      Plans
              Note
      6Business
      Segments
              Note
      7Derivatives
      and Hedging
              Note
      8Fair
      Value Measurements
              Note
      9Income
      Taxes
              Note
      10Financing
      Activities
              Note
      11
 
 
  
  
 
 
 
 
 OHIO
POWER COMPANY CONSOLIDATED
 
  
  OHIO POWER COMPANY CONSOLIDATED
 MANAGEMENT’S FINANCIAL
DISCUSSION AND ANALYSIS
 
 Results of
Operations
 
 Third Quarter of 2009
Compared to Third Quarter of 2008
 
 Reconciliation
of Third Quarter of 2008 to Third Quarter of 2009
 Net
Income
 (in
millions)
 Third
      Quarter of 2008
              
              
              
              
              $
              56Changes
      in Gross Margin:Retail
      Margins
              
              
              132Off-system
      Sales
              
              
              (57
              )Other
              
              
              (2
              )Total
      Change in Gross Margin
              
              
              
              
              
              
              73Total
      Expenses and Other:Other
      Operation and Maintenance
              
              
              9Depreciation
      and Amortization
              
              
              (17
              )Taxes
      Other Than Income Taxes
              
              
              1Carrying
      Costs Income
              
              
              (1
              )Other
      Income
              
              
              (1
              )Interest
      Expense
              
              
              (1
              )Total
      Expenses and Other
              
              
              
              
              
              
              (10
              )Income
      Tax Expense
              
              
              
              
              
              
              (22
              )Third
      Quarter of 2009
              
              
              
              
              
              $
              97
 
 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 $132 million primarily due to the
    following:·
              An
      $85 million increase in fuel margins primarily 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
      $50 million increase related to the implementation of higher rates set by
      the Ohio ESP.·
              An
      $18 million increase in capacity settlements under the Interconnection
      Agreement.These
      increases were partially offset by:·
              A
      $30 million decrease in industrial sales primarily due to reduced
      operating levels and suspended operations by certain large industrial
      customers in OPCo’s service territory.·
              Margins
      from Off-system Sales decreased $57 million primarily due to lower
      physical sales volumes and lower margins as a result of lower market
      prices, partially offset by higher trading and marketing
      margins.
 
 Total
Expenses and Other and Income Tax Expense changed between years as
follows:
 
 ·
              Other
      Operation and Maintenance expenses decreased $9 million primarily due
      to:·
              A
      $5 million decrease in maintenance and removal expenses from planned and
      forced outages at various plants.·
              A
      $2 million decrease in recoverable PJM expenses.·
              A
      $2 million decrease in recoverable customer account expenses due to
      decreased Universal Service Fund surcharge rates for customers who qualify
      for payment assistance.·
              A
      $2 million decrease in net allocated transmission expenses related to the
      AEP Transmission Equalization Agreement.These
      decreases were partially offset by:·
              A
      $2 million increase in maintenance of overhead lines primarily due to
      increased vegetation management activities slightly offset by reduced wind
      storm costs incurred in 2009 versus 2008.·
              Depreciation
      and Amortization increased $17 million primarily due
to:·
              A
      $21 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
      $3 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.The
      increase was partially offset by:·
              A
      $7 million decrease due to the completion of the amortization of
      regulatory assets in December 2008.·
              Income
      Tax Expense increased $22 million primarily due to an increase in pretax
      book income.
 
 Nine Months Ended September
30, 2009 Compared to Nine Months Ended September 30, 2008
 
 Reconciliation
of Nine Months Ended September 30, 2008 to Nine Months Ended September 30,
2009
 Net
Income
 (in
millions)
 
 Nine
      Months Ended September 30, 2008
              
              
              
              
              $
              248Changes
      in Gross Margin:Retail
      Margins
              
              
              176Off-system
      Sales
              
              
              (117
              )Other
              
              
              4Total
      Change in Gross Margin
              
              
              
              
              
              
              63Total
      Expenses and Other:Other
      Operation and Maintenance
              
              
              (15
              )Depreciation
      and Amortization
              
              
              (50
              )Carrying
      Costs Income
              
              
              (5
              )Other
      Income
              
              
              (6
              )Total
      Expenses and Other
              
              
              
              
              
              
              (76
              )Income
      Tax Expense
              
              
              
              
              
              
              (2
              )Nine
      Months Ended September 30, 2009
              
              
              
              
              
              $
              233
 
 
 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 $176 million primarily due to the
    following:·
              A
      $107 million increase in fuel margins primarily 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
      $103 million increase related to the implementation of higher rates set by
      the Ohio ESP.·
              A
      $40 million increase in capacity settlements under the Interconnection
      Agreement.These
      increases were partially offset by:·
              A
      $59 million decrease in industrial sales due to reduced operating levels
      and suspended operations by certain large industrial customers in OPCo’s
      service territory.·
              A
      $29 million decrease related to coal contract amendments recorded in
      2008.·
              Margins
      from Off-system Sales decreased $117 million primarily due to lower
      physical sales volumes and lower margins as a result of lower market
      prices, partially offset by higher trading and marketing
      margins.
  Total
Expenses and Other and Income Tax Expense changed between years as
follows:
 
 ·
              Other
      Operation and Maintenance expenses increased $15 million primarily due
      to:·
              A
      $15 million increase in maintenance of overhead lines primarily due to a
      $13 million increase in vegetation management activities and a $3 million
      increase in ice and wind storm costs incurred in 2009 versus
      2008.·
              A
      $6 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.These
      increases were partially offset by:·
              A
      $6 million decrease in recoverable customer account expenses due to
      decreased Universal Service Fund surcharge rates for customers who qualify
      for payment assistance.·
              Depreciation
      and Amortization increased $50 million primarily due
to:·
              A
      $61 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.·
              An
      $8 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
      $21 million decrease due to the completion of the amortization of
      regulatory assets in December 2008.·
              Income
      Tax Expense increased $2 million primarily due to changes in certain
      book/tax differences accounted for on a flow-through
  basis.
 
 Financial
Condition
 
 Credit
Ratings
 
 OPCo’s
credit ratings as of September 30, 2009 were as follows:
 
 Moody’s
              
              S&P
              
              FitchSenior
      Unsecured Debt
              Baa1
              
              BBB
              
              BBB+
 
 S&P
and Fitch have OPCo on stable outlook.  In August 2009, Moody’s
changed its rating outlook for OPCo from negative to stable.  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 nine months ended September 30, 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
              
              
              136,802
              
              
              
              435,406Investing
      Activities
              
              
              (674,647
              )
              
              
              (486,678
              )Financing
      Activities
              
              
              528,116
              
              
              
              53,694Net
      Increase (Decrease) in Cash and Cash Equivalents
              
              
              (9,729
              )
              
              
              2,422Cash
      and Cash Equivalents at End of Period
              
              $
              2,950
              
              
              $
              9,088
 
 Operating
Activities
 
 Net Cash
Flows from Operating Activities were $137 million in 2009.  OPCo
produced Net Income of $233 million during the period and had noncash expense
items of $263 million for Depreciation and Amortization, $213 million for
Deferred Income Taxes and $67 million for Deferred Property
Taxes.  The other changes in assets and liabilities represent items
that had a current period cash flow impact, such as changes in working capital,
as well as items that represent future rights or obligations to receive or pay
cash, such as regulatory assets and liabilities.  The current period
activity in working capital primarily relates to a number of
items.  Fuel, Materials and Supplies had a $181 million outflow
primarily due to an increase in coal inventory reflecting decreased customer
demand for electricity as a result of the economic slowdown.  Accounts
Payable had a $139 million 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 order on the SIA.  Accrued Taxes, Net
had a $104 million outflow due to  temporary timing differences of
payments for property taxes and a decrease of federal income tax related
accruals.  The $242 million change in Fuel Over/Under-Recovery, Net
reflects the deferral of fuel costs as a fuel clause was reactivated in 2009
under OPCo’s ESP.
 
 Net Cash
Flows from Operating Activities were $435 million in 2008.  OPCo
produced Net Income of $248 million during the period and a noncash expense item
of $212 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 and changes in the future rights or
obligations to receive or pay cash, such as regulatory assets and
liabilities.  Fuel, Materials and Supplies had a $48 million outflow
due to price increases.  Accounts Payable had a $45 million inflow
primarily due to increases in tonnage and prices per ton related to fuel and
consumable purchases.
 
 Investing
Activities
 
 Net Cash
Flows Used for Investing Activities were $675 million and $487 million in 2009
and 2008, respectively.  Construction Expenditures were $343 million
and $453 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 had a net increase of $368 million in loans to in the
Utility Money Pool in 2009.
 
 Financing
Activities
 
 Net Cash
Flows from Financing Activities were $528 million in 2009 primarily due to a
$550 million Capital Contribution from Parent as well as a $500 million issuance
of Senior Unsecured Notes.  These increases were partially offset by a
$218 million reacquisition of Pollution Control Bonds related to JMG and a $78
million retirement of  Notes Payable – Nonaffiliated.  OPCo
also had a net decrease in borrowings of $134 million from the Utility Money
Pool.
 
 Net Cash
Flows from Financing Activities were $54 million in 2008.  OPCo issued
$165 million of Pollution Control Bonds and $250 million of Senior Unsecured
Notes.  These increases were partially offset by the retirement of
$250 million of Pollution Control Bonds and $13 million of Notes Payable –
Nonaffiliated.  OPCo also had a net decrease in borrowings of $102
million from the Utility Money Pool.
 
 Financing
Activity
 
 Long-term
debt issuances, retirements and principal payments made during the first nine
months of 2009 were:
 
 Issuances
 Principal
                Amount
              
              Interest
              
              DueType
      of Debt
              
              
              Rate
              
              Date(in
      thousands)
              
              (%)Senior
      Unsecured Notes
              
              $
              500,000
              
              5.375
              
              2021
 
 
 Retirements and Principal
Payments
 Principal
                Amount
      Paid
              
              Interest
              
              DueType
      of Debt
              
              
              Rate
              
              Date(in
      thousands)
              
              (%)Notes
      Payable – Nonaffiliated
              
              $
              6,500
              
              7.21
              
              2009Notes
      Payable – Nonaffiliated
              
              
              1,000
              
              6.27
              
              2009Notes
      Payable – Nonaffiliated
              
              
              70,000
              
              7.49
              
              2009Pollution
      Control Bonds
              
              
              218,000
              
              Variable
              
              2028-2029
  Liquidity
 
 Although
the financial markets were volatile at both a global and domestic level, OPCo
issued $500 million of Senior Unsecured Notes during the first nine months of
2009.  The credit situation appears to have improved but could impact
OPCo’s future 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 relies 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 and
retirements discussed in “Cash Flow” and “Financing Activity”
above.
 
 Purchase of JMG Funding
Equity
 
 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 owns and leases
the FGD to OPCo.  In the third quarter of 2009, OPCo reacquired $218
million of auction-rate debt related to JMG with interest rates at the
contractual maximum rate of 13%.  OPCo was unable to refinance the
debt without JMG’s consent.  OPCo sought approval from the PUCO to
terminate the JMG relationship and received the approval in June
2009.  In July 2009, OPCo purchased the outstanding equity ownership
of JMG for $28 million which enabled OPCo to reacquire this
debt.  OPCo plans to reissue the debt.  Management’s intent
is to cancel the lease and dissolve JMG in December 2009.  The assets
and liabilities of JMG will remain incorporated with OPCo’s
business.
 
 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 for
disclosures about risk management activities.  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 September 30, 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
 September
30, 2009
 (in
thousands)
 
 MTM
      Risk Management Contracts
              
              
              Cash
      Flow Hedge
                Contracts
              
              
              DETM
      Assignment (a)
              
              
              Collateral
                Deposits
              
              
              TotalCurrent
      Assets
              
              $
              60,270
              
              
              $
              1,728
              
              
              $
              -
              
              
              $
              (3,004
              )
              
              $
              58,994Noncurrent
      Assets
              
              
              38,866
              
              
              
              338
              
              
              
              -
              
              
              
              (2,879
              )
              
              
              36,325Total
      MTM Derivative Contract Assets
              
              
              99,136
              
              
              
              2,066
              
              
              
              -
              
              
              
              (5,883
              )
              
              
              95,319Current
      Liabilities
              
              
              34,176
              
              
              
              1,457
              
              
              
              1,682
              
              
              
              (9,871
              )
              
              
              27,444Noncurrent
      Liabilities
              
              
              25,248
              
              
              
              605
              
              
              
              423
              
              
              
              (10,142
              )
              
              
              16,134Total
      MTM Derivative Contract Liabilities
              
              
              59,424
              
              
              
              2,062
              
              
              
              2,105
              
              
              
              (20,013
              )
              
              
              43,578Total
      MTM Derivative Contract Net Assets (Liabilities)
              
              $
              39,712
              
              
              $
              4
              
              
              $
              (2,105
              )
              
              $
              14,130
              
              
              $
              51,741
 
 
 (a)
              See
      “Natural Gas Contracts with DETM” section of Note 15 of the 2008 Annual
      Report.
 
  MTM
Risk Management Contract Net Assets
 Nine
Months Ended September 30, 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
              
              
              (17,126
              )Fair
      Value of New Contracts at Inception When Entered During the Period
      (a)
              
              
              7,733Net
      Option Premiums Paid/(Received) for Unexercised or Unexpired Option
      Contracts Entered During the Period
              
              
              (136
              )Change
      in Fair Value Due to Valuation Methodology Changes on Forward
      Contracts
              
              
              -Changes
      in Fair Value Due to Market Fluctuations During the Period
    (b)
              
              
              4,862Changes
      in Fair Value Allocated to Regulated Jurisdictions (c)
              
              
              6,618Total
      MTM Risk Management Contract Net Assets
              
              
              39,712Cash
      Flow Hedge Contracts
              
              
              4DETM
      Assignment (d)
              
              
              (2,105
              )Collateral
      Deposits
              
              
              14,130Total
      MTM Derivative Contract Net Assets at September 30, 2009
              
              $
              51,741
 
 (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 on 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 or
(require) cash:
 
 Maturity
and Source of Fair Value of MTM
 Risk
Management Contract Net Assets (Liabilities)
 September
30, 2009
 (in
thousands)
 
 Remainder
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              After2009
              
              
              2010
              
              
              2011
              
              
              2012
              
              
              2013
              
              
              2013
              
              
              TotalLevel
      1 (a)
              
              $
              (270
              )
              
              $
              (29
              )
              
              $
              1
              
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              (298
              )Level
      2 (b)
              
              
              5,330
              
              
              
              8,336
              
              
              
              3,404
              
              
              
              636
              
              
              
              1,676
              
              
              
              134
              
              
              
              19,516Level
      3 (c)
              
              
              4,055
              
              
              
              8,399
              
              
              
              1,288
              
              
              
              660
              
              
              
              (16
              )
              
              
              -
              
              
              
              14,386Total
              
              
              9,115
              
              
              
              16,706
              
              
              
              4,693
              
              
              
              1,296
              
              
              
              1,660
              
              
              
              134
              
              
              
              33,604Dedesignated
      Risk Management Contracts (d)
              
              
              877
              
              
              
              3,010
              
              
              
              1,172
              
              
              
              1,049
              
              
              
              -
              
              
              
              -
              
              
              
              6,108Total
      MTM Risk Management Contract Net Assets
              
              $
              9,992
              
              
              $
              19,716
              
              
              $
              5,865
              
              
              $
              2,345
              
              
              $
              1,660
              
              
              $
              134
              
              
              $
              39,712
 
 (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 the accounting guidance for
      “Derivatives and Hedging.”  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
8 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 September 30, 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:
 
 Nine
      Months Ended
              
              
              
              
              Twelve
      Months EndedSeptember
      30, 2009
              
              
              
              
              December
      31, 2008(in
      thousands)
              
              
              
              
              (in
      thousands)End
              
              High
              
              Average
              
              Low
              
              
              
              
              End
              
              High
              
              Average
              
              Low$186
              
              $530
              
              $259
              
              $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 back-testing 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
four 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.  As calculated on
OPCo’s debt outstanding as of September 30, 2009, the estimated EaR on OPCo’s
debt portfolio for the following twelve months was $2.4
million.
  
  
 OHIO
POWER COMPANY CONSOLIDATED
 CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
 For
the Three and Nine Months Ended September 30, 2009 and 2008
 (in
thousands)
 (Unaudited)
 
 Three
      Months Ended
              
              
              Nine
      Months Ended2009
              
              
              2008
              
              
              2009
              
              
              2008REVENUESElectric
      Generation, Transmission and Distribution
              
              $
              481,049
              
              
              $
              600,841
              
              
              $
              1,463,200
              
              
              $
              1,672,203Sales
      to AEP Affiliates
              
              
              276,947
              
              
              
              245,830
              
              
              
              714,639
              
              
              
              739,077Other
      Revenues – Affiliated
              
              
              5,646
              
              
              
              5,759
              
              
              
              19,415
              
              
              
              17,545Other
      Revenues – Nonaffiliated
              
              
              2,329
              
              
              
              4,584
              
              
              
              9,445
              
              
              
              12,738TOTAL
      REVENUES
              
              
              765,971
              
              
              
              857,014
              
              
              
              2,206,699
              
              
              
              2,441,563EXPENSESFuel
      and Other Consumables Used for Electric Generation
              
              
              238,574
              
              
              
              359,341
              
              
              
              681,523
              
              
              
              928,465Purchased
      Electricity for Resale
              
              
              42,160
              
              
              
              56,142
              
              
              
              138,398
              
              
              
              129,874Purchased
      Electricity from AEP Affiliates
              
              
              19,782
              
              
              
              48,867
              
              
              
              56,989
              
              
              
              116,540Other
      Operation
              
              
              91,162
              
              
              
              98,653
              
              
              
              287,009
              
              
              
              280,494Maintenance
              
              
              50,703
              
              
              
              51,791
              
              
              
              168,893
              
              
              
              159,706Depreciation
      and Amortization
              
              
              89,169
              
              
              
              72,180
              
              
              
              262,576
              
              
              
              211,919Taxes
      Other Than Income Taxes
              
              
              48,300
              
              
              
              49,019
              
              
              
              146,274
              
              
              
              146,534TOTAL
      EXPENSES
              
              
              579,850
              
              
              
              735,993
              
              
              
              1,741,662
              
              
              
              1,973,532OPERATING
      INCOME
              
              
              186,121
              
              
              
              121,021
              
              
              
              465,037
              
              
              
              468,031Other
      Income (Expense):Interest
      Income
              
              
              242
              
              
              
              2,252
              
              
              
              1,002
              
              
              
              6,910Carrying
      Costs Income
              
              
              3,143
              
              
              
              3,936
              
              
              
              7,152
              
              
              
              12,159Allowance
      for Equity Funds Used During Construction
              
              
              1,081
              
              
              
              555
              
              
              
              1,849
              
              
              
              1,801Interest
      Expense
              
              
              (40,614
              )
              
              
              (39,731
              )
              
              
              (114,536
              )
              
              
              (115,088
              )INCOME
      BEFORE INCOME TAX EXPENSE
              
              
              149,973
              
              
              
              88,033
              
              
              
              360,504
              
              
              
              373,813Income
      Tax Expense
              
              
              53,398
              
              
              
              31,601
              
              
              
              127,408
              
              
              
              125,782NET
      INCOME
              
              
              96,575
              
              
              
              56,432
              
              
              
              233,096
              
              
              
              248,031Less:
      Net Income Attributable to Noncontrolling Interest
              
              
              1,026
              
              
              
              233
              
              
              
              2,042
              
              
              
              1,111NET
      INCOME ATTRIBUTABLE TO OPCo SHAREHOLDERS
              
              
              95,549
              
              
              
              56,199
              
              
              
              231,054
              
              
              
              246,920Less:
      Preferred Stock Dividend Requirements
              
              
              183
              
              
              
              183
              
              
              
              549
              
              
              
              549EARNINGS
      ATTRIBUTABLE TO OPCo COMMON SHAREHOLDER
              
              $
              95,366
              
              
              $
              56,016
              
              
              $
              230,505
              
              
              $
              246,371
 
 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 Nine Months Ended September 30, 2009 and 2008
 (in
thousands)
 (Unaudited)
 
 OPCo
      Common ShareholderCommon
      Stock
              
              
              Paid-in
      Capital
              
              
              Retained
      Earnings
              
              
              Accumulated
                Other
                Comprehensive
                Income
      (Loss)
              
              
              Noncontrolling
                Interest
              
              
              TotalTOTAL
      EQUITY – DECEMBER 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
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              (1,111
              )
              
              
              (1,111
              )Preferred
      Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (549
              )
              
              
              
              
              
              
              
              
              
              
              (549
              )Other
      Changes in Equity
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              1,109
              
              
              
              1,109SUBTOTAL–EQUITY
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              2,304,243COMPREHENSIVE
      INCOMEOther
      Comprehensive Income, Net of Taxes:Cash
      Flow Hedges, Net of Tax of $337
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              625
              
              
              
              
              
              
              
              625Amortization
      of Pension and OPEB Deferred Costs, Net of Tax of
      $1,136
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              2,110
              
              
              
              
              
              
              
              2,110NET
      INCOME
              
              
              
              
              
              
              
              
              
              
              246,920
              
              
              
              
              
              
              
              1,111
              
              
              
              248,031TOTAL
      COMPREHENSIVE INCOME
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              250,766TOTAL EQUITY–SEPTEMBER 30,
      2008
              
              $
              321,201
              
              
              $
              536,640
              
              
              $
              1,713,942
              
              
              $
              (33,806
              )
              
              $
              17,032
              
              
              $
              2,555,009TOTAL EQUITY–DECEMBER 31,
      2008
              
              $
              321,201
              
              
              $
              536,640
              
              
              $
              1,697,962
              
              
              $
              (133,858
              )
              
              $
              16,799
              
              
              $
              2,438,744Capital
      Contribution from Parent
              
              
              
              
              
              
              550,000
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              550,000Common
      Stock Dividends – Affiliated
              
              
              
              
              
              
              
              
              
              
              (50,000
              )
              
              
              
              
              
              
              
              
              
              
              (50,000
              )Common
      Stock Dividends – Nonaffiliated
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              (2,042
              )
              
              
              (2,042
              )Preferred
      Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (549
              )
              
              
              
              
              
              
              
              
              
              
              (549
              )Purchase
      of JMG
              
              
              
              
              
              
              54,431
              
              
              
              
              
              
              
              
              
              
              
              (17,910
              )
              
              
              36,521Other
      Changes in Equity
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              1,111
              
              
              
              1,111SUBTOTAL–EQUITY
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              2,973,785COMPREHENSIVE
      INCOMEOther
      Comprehensive Income, Net of Taxes:Cash
      Flow Hedges, Net of Tax of $4,946
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              9,185
              
              
              
              
              
              
              
              9,185Amortization
      of Pension and OPEB Deferred Costs, Net of Tax of
      $2,566
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              4,765
              
              
              
              
              
              
              
              4,765NET
      INCOME
              
              
              
              
              
              
              
              
              
              
              231,054
              
              
              
              
              
              
              
              2,042
              
              
              
              233,096TOTAL
      COMPREHENSIVE INCOME
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              247,046TOTAL EQUITY–SEPTEMBER 30,
      2009
              
              $
              321,201
              
              
              $
              1,141,071
              
              
              $
              1,878,467
              
              
              $
              (119,908
              )
              
              $
              -
              
              
              $
              3,220,831
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
 
  
  OHIO
POWER COMPANY CONSOLIDATED
 CONDENSED
CONSOLIDATED BALANCE SHEETS
 ASSETS
 September
30, 2009 and December 31, 2008
 (in
thousands)
 (Unaudited)
 
 2009
              
              
              2008CURRENT
      ASSETSCash
      and Cash Equivalents
              
              $
              2,950
              
              
              $
              12,679Advances
      to Affiliates
              
              
              367,743
              
              
              
              -Accounts
      Receivable:Customers
              
              
              46,310
              
              
              
              91,235Affiliated
      Companies
              
              
              167,994
              
              
              
              118,721Accrued
      Unbilled Revenues
              
              
              15,821
              
              
              
              18,239Miscellaneous
              
              
              3,535
              
              
              
              23,393Allowance
      for Uncollectible Accounts
              
              
              (2,737
              )
              
              
              (3,586
              )Total
      Accounts Receivable
              
              
              230,923
              
              
              
              248,002Fuel
              
              
              364,195
              
              
              
              186,904Materials
      and Supplies
              
              
              110,642
              
              
              
              107,419Risk
      Management Assets
              
              
              58,994
              
              
              
              53,292Accrued
      Tax Benefits
              
              
              30,833
              
              
              
              13,568Prepayments
      and Other Current Assets
              
              
              34,613
              
              
              
              42,999TOTAL
      CURRENT ASSETS
              
              
              1,200,893
              
              
              
              664,863PROPERTY,
      PLANT AND EQUIPMENTElectric:Production
              
              
              6,672,504
              
              
              
              6,025,277Transmission
              
              
              1,158,700
              
              
              
              1,111,637Distribution
              
              
              1,536,856
              
              
              
              1,472,906Other
      Property, Plant and Equipment
              
              
              373,475
              
              
              
              391,862Construction
      Work in Progress
              
              
              238,525
              
              
              
              787,180Total
      Property, Plant and Equipment
              
              
              9,980,060
              
              
              
              9,788,862Accumulated
      Depreciation and Amortization
              
              
              3,280,362
              
              
              
              3,122,989TOTAL
      PROPERTY, PLANT AND EQUIPMENT – NET
              
              
              6,699,698
              
              
              
              6,665,873OTHER
      NONCURRENT ASSETSRegulatory
      Assets
              
              
              685,750
              
              
              
              449,216Long-term
      Risk Management Assets
              
              
              36,325
              
              
              
              39,097Deferred
      Charges and Other Noncurrent Assets
              
              
              114,151
              
              
              
              184,777TOTAL
      OTHER NONCURRENT ASSETS
              
              
              836,226
              
              
              
              673,090TOTAL
      ASSETS
              
              $
              8,736,817
              
              
              $
              8,003,826
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
 
 
  
  OHIO
POWER COMPANY CONSOLIDATED
 CONDENSED
CONSOLIDATED BALANCE SHEETS
 LIABILITIES
AND EQUITY
 September
30, 2009 and December 31, 2008
 (Unaudited)
 
 2009
              
              
              2008CURRENT
      LIABILITIES
              
              (in
      thousands)Advances
      from Affiliates
              
              $
              -
              
              
              $
              133,887Accounts
      Payable:General
              
              
              166,856
              
              
              
              193,675Affiliated
      Companies
              
              
              76,645
              
              
              
              206,984Long-term
      Debt Due Within One Year – Nonaffiliated
              
              
              479,450
              
              
              
              77,500Risk
      Management Liabilities
              
              
              27,444
              
              
              
              29,218Customer
      Deposits
              
              
              23,069
              
              
              
              24,333Accrued
      Taxes
              
              
              100,556
              
              
              
              187,256Accrued
      Interest
              
              
              35,514
              
              
              
              44,245Other
      Current Liabilities
              
              
              114,039
              
              
              
              163,702TOTAL
      CURRENT LIABILITIES
              
              
              1,023,573
              
              
              
              1,060,800NONCURRENT
      LIABILITIESLong-term
      Debt – Nonaffiliated
              
              
              2,562,849
              
              
              
              2,761,876Long-term
      Debt – Affiliated
              
              
              200,000
              
              
              
              200,000Long-term
      Risk Management Liabilities
              
              
              16,134
              
              
              
              23,817Deferred
      Income Taxes
              
              
              1,122,531
              
              
              
              927,072Regulatory
      Liabilities and Deferred Investment Tax Credits
              
              
              133,252
              
              
              
              127,788Employee
      Benefits and Pension Obligations
              
              
              278,635
              
              
              
              288,106Deferred
      Credits and Other Noncurrent Liabilities
              
              
              162,385
              
              
              
              158,996TOTAL
      NONCURRENT LIABILITIES
              
              
              4,475,786
              
              
              
              4,487,655TOTAL
      LIABILITIES
              
              
              5,499,359
              
              
              
              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
              
              
              1,141,071
              
              
              
              536,640Retained
      Earnings
              
              
              1,878,467
              
              
              
              1,697,962Accumulated
      Other Comprehensive Income (Loss)
              
              
              (119,908
              )
              
              
              (133,858
              )TOTAL
      COMMON SHAREHOLDER’S EQUITY
              
              
              3,220,831
              
              
              
              2,421,945Noncontrolling
      Interest
              
              
              -
              
              
              
              16,799TOTAL
      EQUITY
              
              
              3,220,831
              
              
              
              2,438,744TOTAL
      LIABILITIES AND EQUITY
              
              $
              8,736,817
              
              
              $
              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 Nine Months Ended September 30, 2009 and 2008
 (in
thousands)
 (Unaudited)
 2009
              
              
              2008OPERATING
      ACTIVITIESNet
      Income
              
              $
              233,096
              
              
              $
              248,031Adjustments
      to Reconcile Net Income to Net Cash Flows from Operating
      Activities:Depreciation
      and Amortization
              
              
              262,576
              
              
              
              211,919Deferred
      Income Taxes
              
              
              213,458
              
              
              
              45,424Carrying
      Costs Income
              
              
              (7,152
              )
              
              
              (12,159
              )Allowance
      for Equity Funds Used During Construction
              
              
              (1,849
              )
              
              
              (1,801
              )Mark-to-Market
      of Risk Management Contracts
              
              
              (15,226
              )
              
              
              (2,028
              )Deferred
      Property Taxes
              
              
              66,976
              
              
              
              63,867Fuel
      Over/Under-Recovery, Net
              
              
              (242,392
              )
              
              
              -Change
      in Other Noncurrent Assets
              
              
              12,690
              
              
              
              (52,788
              )Change
      in Other Noncurrent Liabilities
              
              
              40,709
              
              
              
              9,300Changes
      in Certain Components of Working Capital:Accounts
      Receivable, Net
              
              
              15,155
              
              
              
              16,947Fuel,
      Materials and Supplies
              
              
              (180,514
              )
              
              
              (48,197
              )Accounts
      Payable
              
              
              (138,828
              )
              
              
              45,252Accrued
      Taxes, Net
              
              
              (103,965
              )
              
              
              (56,936
              )Other
      Current Assets
              
              
              (4,164
              )
              
              
              (14,333
              )Other
      Current Liabilities
              
              
              (13,768
              )
              
              
              (17,092
              )Net
      Cash Flows from Operating Activities
              
              
              136,802
              
              
              
              435,406INVESTING
      ACTIVITIESConstruction
      Expenditures
              
              
              (342,633
              )
              
              
              (453,405
              )Change
      in Advances to Affiliates, Net
              
              
              (367,743
              )
              
              
              (39,758
              )Proceeds
      from Sales of Assets
              
              
              31,253
              
              
              
              6,872Other
      Investing Activities
              
              
              4,476
              
              
              
              (387
              )Net
      Cash Flows Used for Investing Activities
              
              
              (674,647
              )
              
              
              (486,678
              )FINANCING
      ACTIVITIESCapital
      Contribution from Parent
              
              
              550,000
              
              
              
              -Issuance
      of Long-term Debt – Nonaffiliated
              
              
              494,078
              
              
              
              412,389Change
      in Short-term Debt, Net – Nonaffiliated
              
              
              -
              
              
              
              (701
              )Change
      in Advances from Affiliates, Net
              
              
              (133,887
              )
              
              
              (101,548
              )Retirement
      of Long-term Debt – Nonaffiliated
              
              
              (295,500
              )
              
              
              (263,463
              )Retirement
      of Cumulative Preferred Stock
              
              
              (1
              )
              
              
              -Principal
      Payments for Capital Lease Obligations
              
              
              (3,435
              )
              
              
              (4,636
              )Dividends
      Paid on Common Stock – Nonaffiliated
              
              
              (2,042
              )
              
              
              (1,111
              )Dividends
      Paid on Common Stock – Affiliated
              
              
              (50,000
              )
              
              
              -Dividends
      Paid on Cumulative Preferred Stock
              
              
              (549
              )
              
              
              (549
              )Acquisition
      of JMG Noncontrolling Interest
              
              
              (28,221
              )
              
              
              -Other
      Financing Activities
              
              
              (2,327
              )
              
              
              13,313Net
      Cash Flows from Financing Activities
              
              
              528,116
              
              
              
              53,694Net
      Increase (Decrease) in Cash and Cash Equivalents
              
              
              (9,729
              )
              
              
              2,422Cash
      and Cash Equivalents at Beginning of Period
              
              
              12,679
              
              
              
              6,666Cash
      and Cash Equivalents at End of Period
              
              $
              2,950
              
              
              $
              9,088
 
 SUPPLEMENTARY
      INFORMATIONCash
      Paid for Interest, Net of Capitalized Amounts
              
              $
              119,763
              
              
              $
              112,321Net
      Cash Paid (Received) for Income Taxes
              
              
              (23,241
              )
              
              
              61,051Noncash
      Acquisitions Under Capital Leases
              
              
              2,022
              
              
              
              2,018Noncash
      Acquisition of Coal Land Rights
              
              
              -
              
              
              
              41,600Construction
      Expenditures Included in Accounts Payable at September 30,
              
              
              15,527
              
              
              
              25,839
 
 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 and Extraordinary Item
              Note
      2Rate
      Matters
              Note
      3Commitments,
      Guarantees and Contingencies
              Note
      4Benefit
      Plans
              Note
      6Business
      Segments
              Note
      7Derivatives
      and Hedging
              Note
      8Fair
      Value Measurements
              Note
      9Income
      Taxes
              Note
      10Financing
      Activities
              Note
      11
 
 
  
  
 
 
 
 
 
 PUBLIC
SERVICE COMPANY OF OKLAHOMA
 
  
  PUBLIC SERVICE COMPANY OF OKLAHOMA
 MANAGEMENT’S FINANCIAL
DISCUSSION AND ANALYSIS
 
 
 Results of
Operations
 
 Third Quarter of 2009
Compared to Third Quarter of 2008
 
 Reconciliation
of Third Quarter of 2008 to Third Quarter of 2009
 Net
Income
 (in
millions)
 
 Third
      Quarter of 2008
              
              
              
              
              $
              28Changes
      in Gross Margin:Retail
      and Off-system Sales Margins (a)
              
              
              20Transmission
      Revenue
              
              
              2Other
              
              
              (1
              )Total
      Change in Gross Margin
              
              
              
              
              
              
              21Total
      Expenses and Other:Other
      Operation and Maintenance
              
              
              6Taxes
      Other Than Income Taxes
              
              
              (2
              )Other
      Income
              
              
              (1
              )Total
      Expenses and Other
              
              
              
              
              
              
              3Income
      Tax Expense
              
              
              
              
              
              
              (8
              )Third
      Quarter of 2009
              
              
              
              
              
              $
              44
 
 (a)
              Includes
      firm wholesale sales to municipals and
  cooperatives.
 
 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 $20 million primarily due to an
      increase in retail sales margins resulting from base rate
      adjustments.
 
 Total
Expenses and Other and Income Tax Expense changed between years as
follows:
 
 ·
              Other
      Operation and Maintenance expenses decreased $6 million primarily due
      to:·
              A
      $4 million decrease in steam generation expense primarily due to higher
      planned maintenance in 2008.·
              A
      $2 million decrease primarily due to a decrease in sale of receivable
      expense from decreased revenues.·
              Taxes
      Other Than Income Taxes increased $2 million primarily due to an increase
      in state sales and use tax and an increase in real and personal property
      tax.·
              Income
      Tax Expense increased $8 million primarily due to an increase in pretax
      book income.
  Nine Months Ended September
30, 2009 Compared to Nine Months Ended September 30, 2008
 
 Reconciliation
of Nine Months Ended September 30, 2008 to Nine Months Ended September 30,
2009
 Net
Income
 (in
millions)
 
 Nine
      Months Ended September 30, 2008
              
              
              
              
              $
              69Changes
      in Gross Margin:Retail
      and Off-system Sales Margins (a)
              
              
              70Transmission
      Revenues
              
              
              3Other
              
              
              (10
              )Total
      Change in Gross Margin
              
              
              
              
              
              
              63Total
      Expenses and Other:Other
      Operation and Maintenance
              
              
              28Deferral
      of Ice Storm Costs
              
              
              (72
              )Depreciation
      and Amortization
              
              
              (6
              )Taxes
      Other Than Income Taxes
              
              
              (2
              )Other
      Income
              
              
              (4
              )Total
      Expenses and Other
              
              
              
              
              
              
              (56
              )Income
      Tax Expense
              
              
              
              
              
              
              (2
              )Nine
      Months Ended September 30, 2009
              
              
              
              
              
              $
              74
 
 (a)
              Includes
      firm wholesale sales to municipals and
  cooperatives.
 
 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 $70 million primarily due to an
      increase in retail sales margins resulting from base rate adjustments
      including riders of $25 million.  The $25 million increase in
      riders were offset by a corresponding $14 million increase in Other
      Operation and Maintenance expenses and a $6 million increase in
      Depreciation and Amortization expenses as discussed
  below.·
              Other
      revenues decreased $10 million primarily due to the sale of SO2
      allowances.  The decrease was offset by a corresponding $9
      million decrease in Other Operation and Maintenance expenses as discussed
      below.
 
 Total
Expenses and Other and Income Tax Expense changed between years as
follows:
 
 ·
              Other
      Operation and Maintenance expenses decreased $28 million primarily due
      to:·
              The
      write-off in the first quarter of 2008 of $10 million of unrecoverable
      pre-construction costs related to the cancelled Red Rock Generating
      Facility.·
              A
      $10 million decrease due to lower plant maintenance expense primarily due
      to the deferral of generation maintenance expenses as a result of PSO’s
      base rate filing.  See “2008 Oklahoma Base Rate Filing Appeal”
      section of Note 3.·
              A
      $9 million decrease in expense due to the amortization of regulatory
      assets related to the 2007 ice storm expense which is offset by a
      corresponding decrease in Other revenues as discussed
    above.·
              A
      $3 million decrease in employee-related expenses.·
              A
      $3 million decrease primarily due to a decrease in sale of receivable
      expense from decreased revenues.·
              A
      $2 million decrease in expense related to maintenance of overhead
      transmission lines.These
      decreases were partially offset by:·
              A
      $14 million increase in expense from amortization of regulatory assets
      related to the 2007 ice storm, demand side management and distribution
      vegetation management directly offset by a corresponding increase in
      revenue from the riders discussed
above.
 ·
              Deferral
      of Ice Storm Costs in 2008 of $72 million results from an OCC order
      approving recovery of ice storm costs related to ice storms in January and
      December 2007.·
              Depreciation
      and Amortization expenses increased $6 million primarily due to an
      increase in  amortization of regulatory assets, largest of which
      was related to the Generation Cost Recovery regulatory
      asset.  The increase is offset by a corresponding increase in
      revenues from riders as discussed above.·
              Taxes
      Other Than Income Taxes increased $2 million primarily due to an increase
      in real and personal property tax.·
              Other
      Income decreased $4 million primarily due to carrying charges related to
      the Generation Cost Recovery regulatory assets and a decrease in the
      equity component of AFUDC.·
              Income
      Tax Expense increased $2 million primarily due to an increase in pretax
      book income.
 
 Financial
Condition
 
 Credit
Ratings
 
 PSO’s
credit ratings as of September 30, 2009 were as follows:
 
 Moody’s
              
              S&P
              
              FitchSenior
      Unsecured Debt
              Baa1
              
              BBB
              
              BBB+
 
 S&P,
Moody’s and Fitch have PSO on stable outlook.  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 nine months ended September 30, 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
              
              
              232,759
              
              
              
              42,386Investing
      Activities
              
              
              (142,945
              )
              
              
              (161,523
              )Financing
      Activities
              
              
              (89,852
              )
              
              
              120,011Net
      Increase (Decrease) in Cash and Cash Equivalents
              
              
              (38
              )
              
              
              874Cash
      and Cash Equivalents at End of Period
              
              $
              1,307
              
              
              $
              2,244
 
 Operating
Activities
 
 Net Cash
Flows from Operating Activities were $233 million in 2009.  PSO
produced Net Income of $74 million during the period and had a noncash expense
item of $84 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 $86 million inflow from Accounts Receivable, Net was
primarily due to receiving the SIA refund from the AEP East companies and lower
customer receivables.  The $46 million inflow from Accrued Taxes, Net
was the result of increased accruals related to property and income
taxes.  The $38 million outflow from Accounts Payable was primarily
due to decreases in customer accounts factored, fuel and purchased power
payables.
 
 Net Cash
Flows from Operating Activities were $42 million in 2008.  PSO
produced Net Income of $69 million during the period and had noncash expense
items of $78 million for Depreciation and Amortization and $71 million for
Deferred Income Taxes.  PSO established a $72 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 activity in working capital relates to a number of
items.  The $81 million outflow from Accounts Payable was primarily
due to a decrease in accounts payable accruals and purchased power
payable.  The $36 million inflow from Accrued Taxes, Net was the
result of a refund for the 2007 overpayment of federal income taxes and
increased accruals related to property and income taxes.  The $47
million outflow from Fuel Over/Under-Recovery, Net resulted from rapidly
increasing natural gas costs which fuels the majority of PSO’s generating
facilities.
 
 Investing
Activities
 
 Net Cash
Flows Used for Investing Activities during 2009 and 2008 were $143 million and
$162 million, respectively.  Construction Expenditures of $135 million
and $214 million in 2009 and 2008, respectively, were primarily related to
projects for improved generation, transmission and distribution service
reliability.  During 2009, PSO had a net increase of $8 million in
loans to the Utility Money Pool.  During 2008, PSO had a net decrease
of $51 million in loans to the Utility Money Pool.
 
 Financing
Activities
 
 Net Cash
Flows Used for Financing Activities were $90 million during 2009.  PSO
had a net decrease of $70 million in borrowings from the Utility Money
Pool.  PSO retired $50 million of Senior Unsecured Notes in September
2009 and issued $34 million of Pollution Control Bonds in February
2009.  PSO paid $22 million in dividends on common
stock.  In addition, PSO received capital contributions from the
Parent of $20 million.
 
 Net Cash
Flows from Financing Activities were $120 million during 2008.  PSO
had a net increase of $125 million in borrowings from the Utility Money
Pool.  PSO repurchased $34 million in Pollution Control Bonds in May
2008.  PSO received capital contributions from the Parent of $30
million.
 
 Financing
Activity
 
 Long-term
debt issuances and retirements during the first nine months of 2009
were:
 
 Issuances
 Principal
              
              Interest
              
              DueType
      of Debt
              
              Amount
              
              Rate
              
              Date(in
      thousands)
              
              (%)Pollution
      Control Bonds
              
              $
              33,700
              
              5.25
              
              2014
 
 Retirements
 Principal
                Amount
      Paid
              
              Interest
              
              DueType
      of Debt
              
              
              Rate
              
              Date(in
      thousands)
              
              (%)Senior
      Unsecured Notes
              
              $
              50,000
              
              4.70
              
              2009
 
 Liquidity
 
 Although
the financial markets were volatile at both a global and domestic level, PSO
issued $34 million of Pollution Control Bonds during the first nine months of
2009.  The credit situation appears to have improved but could impact
PSO’s future 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 relies 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 and
retirements 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 for
disclosures about risk management activities.  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 September 30, 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
 September
30, 2009
 (in
thousands)
 
 MTM
      Risk Management Contracts
              
              
              Cash
      Flow
                Hedge
                Contracts
              
              
              Collateral
                Deposits
              
              
              TotalCurrent
      Assets
              
              $
              3,834
              
              
              $
              72
              
              
              $
              (1
              )
              
              $
              3,905Noncurrent
      Assets
              
              
              299
              
              
              
              13
              
              
              
              -
              
              
              
              312Total
      MTM Derivative Contract Assets
              
              
              4,133
              
              
              
              85
              
              
              
              (1
              )
              
              
              4,217Current
      Liabilities
              
              
              4,279
              
              
              
              501
              
              
              
              (15
              )
              
              
              4,765Noncurrent
      Liabilities
              
              
              447
              
              
              
              37
              
              
              
              (11
              )
              
              
              473Total
      MTM Derivative Contract Liabilities
              
              
              4,726
              
              
              
              538
              
              
              
              (26
              )
              
              
              5,238Total
      MTM Derivative Contract Net Assets (Liabilities)
              
              $
              (593
              )
              
              $
              (453
              )
              
              $
              25
              
              
              $
              (1,021
              )
 
 MTM
Risk Management Contract Net Assets
 Nine
Months Ended September 30, 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
              
              
              (750
              )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
              
              
              (17
              )Change
      in Fair Value Due to Valuation Methodology Changes on Forward
      Contracts
              
              
              -Changes
      in Fair Value Due to Market Fluctuations During the Period
    (b)
              
              
              (43
              )Changes
      in Fair Value Allocated to Regulated Jurisdictions (c)
              
              
              (1,443
              )Total
      MTM Risk Management Contract Net Assets (Liabilities)
              
              
              (593
              )Cash
      Flow Hedge Contracts
              
              
              (453
              )Collateral
      Deposits
              
              
              25Total
      MTM Derivative Contract Net Assets (Liabilities) at September 30,
      2009
              
              $
              (1,021
              )
 
 (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 on the Condensed
      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
 
 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 or
(require) cash:
 
 Maturity
and Source of Fair Value of MTM
 Risk
Management Contract Net Assets (Liabilities)
 September
30, 2009
 (in
thousands)
 
 Remainder
                2009
              
              
              2010
              
              
              2011
              
              
              2012
              
              
              2013
              
              
              After
                2013
              
              
              TotalLevel
      1 (a)
              
              $
              47
              
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              47Level
      2 (b)
              
              
              269
              
              
              
              (633
              )
              
              
              (287
              )
              
              
              6
              
              
              
              -
              
              
              
              -
              
              
              
              (645
              )Level
      3 (c)
              
              
              4
              
              
              
              1
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              5Total
      MTM Risk Management Contract Net Assets (Liabilities)
              
              $
              320
              
              
              $
              (632
              )
              
              $
              (287
              )
              
              $
              6
              
              
              $
              -
              
              
              $
              -
              
              
              $
              (593
              )
 
 (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
8 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 September 30, 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:
 
 Nine
      Months Ended
              
              
              
              
              Twelve
      Months EndedSeptember
      30, 2009
              
              
              
              
              December
      31, 2008(in
      thousands)
              
              
              
              
              (in
      thousands)End
              
              High
              
              Average
              
              Low
              
              
              
              
              End
              
              High
              
              Average
              
              Low$9
              
              $34
              
              $12
              
              $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 back-testing 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
four 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.  As calculated on
PSO’s debt outstanding as of September 30, 2009, the estimated EaR on PSO’s debt
portfolio for the following twelve months was $3.5 million.
 
 
 
  
  
 PUBLIC
SERVICE COMPANY OF OKLAHOMA
 CONDENSED
STATEMENTS OF INCOME
 For
the Three and Nine Months Ended September 30, 2009 and 2008
 (in
thousands)
 (Unaudited)
 
 Three
      Months Ended
              
              
              Nine
      Months Ended2009
              
              
              2008
              
              
              2009
              
              
              2008REVENUESElectric
      Generation, Transmission and Distribution
              
              $
              311,274
              
              
              $
              518,182
              
              
              $
              853,808
              
              
              $
              1,194,737Sales
      to AEP Affiliates
              
              
              6,668
              
              
              
              32,286
              
              
              
              34,181
              
              
              
              89,988Other
      Revenues
              
              
              613
              
              
              
              781
              
              
              
              2,994
              
              
              
              2,858TOTAL
      REVENUES
              
              
              318,555
              
              
              
              551,249
              
              
              
              890,983
              
              
              
              1,287,583EXPENSESFuel
      and Other Consumables Used for Electric Generation
              
              
              79,610
              
              
              
              288,027
              
              
              
              261,762
              
              
              
              584,769Purchased
      Electricity for Resale
              
              
              42,090
              
              
              
              77,834
              
              
              
              132,623
              
              
              
              230,432Purchased
      Electricity from AEP Affiliates
              
              
              5,424
              
              
              
              15,169
              
              
              
              14,755
              
              
              
              53,944Other
      Operation
              
              
              48,145
              
              
              
              51,432
              
              
              
              134,211
              
              
              
              152,617Maintenance
              
              
              24,601
              
              
              
              27,530
              
              
              
              77,996
              
              
              
              87,772Deferral
      of Ice Storm Costs
              
              
              -
              
              
              
              69
              
              
              
              -
              
              
              
              (71,610
              )Depreciation
      and Amortization
              
              
              27,799
              
              
              
              27,192
              
              
              
              84,278
              
              
              
              78,079Taxes
      Other Than Income Taxes
              
              
              9,534
              
              
              
              7,839
              
              
              
              31,243
              
              
              
              29,265TOTAL
      EXPENSES
              
              
              237,203
              
              
              
              495,092
              
              
              
              736,868
              
              
              
              1,145,268OPERATING
      INCOME
              
              
              81,352
              
              
              
              56,157
              
              
              
              154,115
              
              
              
              142,315Other
      Income (Expense):Other
      Income
              
              
              825
              
              
              
              34
              
              
              
              2,794
              
              
              
              4,004Carrying
      Costs Income
              
              
              986
              
              
              
              3,183
              
              
              
              3,716
              
              
              
              6,945Interest
      Expense
              
              
              (13,884
              )
              
              
              (13,713
              )
              
              
              (43,852
              )
              
              
              (43,179
              )INCOME
      BEFORE INCOME TAX EXPENSE
              
              
              69,279
              
              
              
              45,661
              
              
              
              116,773
              
              
              
              110,085Income
      Tax Expense
              
              
              25,702
              
              
              
              17,917
              
              
              
              43,036
              
              
              
              40,815NET
      INCOME
              
              
              43,577
              
              
              
              27,744
              
              
              
              73,737
              
              
              
              69,270Preferred
      Stock Dividend Requirements
              
              
              53
              
              
              
              53
              
              
              
              159
              
              
              
              159EARNINGS
      ATTRIBUTABLE TO COMMON STOCK
              
              $
              43,524
              
              
              $
              27,691
              
              
              $
              73,578
              
              
              $
              69,111
 
 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 Nine Months Ended September 30, 2009 and 2008
 (in
thousands)
 (Unaudited)
 
 Common
      Stock
              
              
              Paid-in
      Capital
              
              
              Retained
      Earnings
              
              
              Accumulated
      Other Comprehensive Income (Loss)
              
              
              TotalTOTAL
      COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2007
              
              $
              157,230
              
              
              $
              310,016
              
              
              $
              174,539
              
              
              $
              (887
              )
              
              $
              640,898EITF
      06-10 Adoption, Net of Tax of $596
              
              
              
              
              
              
              
              
              
              
              (1,107
              )
              
              
              
              
              
              
              (1,107
              )Capital
      Contribution from Parent
              
              
              
              
              
              
              30,000
              
              
              
              
              
              
              
              
              
              
              
              30,000Preferred
      Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (159
              )
              
              
              
              
              
              
              (159
              )SUBTOTAL
      – COMMON SHAREHOLDER’S EQUITY
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              669,632COMPREHENSIVE
      INCOMEOther Comprehensive
      Income, Net of
      Taxes:Cash
      Flow Hedges, Net of Tax of $74
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              137
              
              
              
              137NET
      INCOME
              
              
              
              
              
              
              
              
              
              
              69,270
              
              
              
              
              
              
              
              69,270TOTAL
      COMPREHENSIVE INCOME
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              69,407TOTAL
      COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2008
              
              $
              157,230
              
              
              $
              340,016
              
              
              $
              242,543
              
              
              $
              (750
              )
              
              $
              739,039TOTAL
      COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2008
              
              $
              157,230
              
              
              $
              340,016
              
              
              $
              251,704
              
              
              $
              (704
              )
              
              $
              748,246Capital
      Contribution from Parent
              
              
              
              
              
              
              20,000
              
              
              
              
              
              
              
              
              
              
              
              20,000Common
      Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (21,750
              )
              
              
              
              
              
              
              (21,750
              )Preferred
      Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (159
              )
              
              
              
              
              
              
              (159
              )Gain
      on Reacquired Preferred Stock
              
              
              
              
              
              
              1
              
              
              
              
              
              
              
              
              
              
              
              1Other
      Changes in Common Shareholder’s Equity
              
              
              
              
              
              
              4,214
              
              
              
              (4,214
              )
              
              
              
              
              
              
              -SUBTOTAL
      – COMMON SHAREHOLDER’S EQUITY
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              746,338COMPREHENSIVE
      INCOMEOther
      Comprehensive Loss, Net of Taxes:Cash
      Flow Hedges, Net of Tax of $78
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              (145
              )
              
              
              (145
              )NET
      INCOME
              
              
              
              
              
              
              
              
              
              
              73,737
              
              
              
              
              
              
              
              73,737TOTAL
      COMPREHENSIVE INCOME
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              73,592TOTAL
      COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2009
              
              $
              157,230
              
              
              $
              364,231
              
              
              $
              299,318
              
              
              $
              (849
              )
              
              $
              819,930
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
 
 
 
  
  PUBLIC
SERVICE COMPANY OF OKLAHOMA
 CONDENSED
BALANCE SHEETS
 ASSETS
 September
30, 2009 and December 31, 2008
 (in
thousands)
 (Unaudited)
 
 2009
              
              
              2008CURRENT
      ASSETSCash
      and Cash Equivalents
              
              $
              1,307
              
              
              $
              1,345Advances
      to Affiliates
              
              
              8,450
              
              
              
              -Accounts
      Receivable:Customers
              
              
              23,043
              
              
              
              39,823Affiliated
      Companies
              
              
              69,413
              
              
              
              138,665Miscellaneous
              
              
              5,871
              
              
              
              8,441Allowance
      for Uncollectible Accounts
              
              
              (340
              )
              
              
              (20
              )Total
      Accounts Receivable
              
              
              97,987
              
              
              
              186,909Fuel
              
              
              22,367
              
              
              
              27,060Materials
      and Supplies
              
              
              44,541
              
              
              
              44,047Risk
      Management Assets
              
              
              3,905
              
              
              
              5,830Deferred
      Tax Benefits
              
              
              34,177
              
              
              
              9,123Accrued
      Tax Benefits
              
              
              503
              
              
              
              3,876Prepayments
      and Other Current Assets
              
              
              7,083
              
              
              
              3,371TOTAL
      CURRENT ASSETS
              
              
              220,320
              
              
              
              281,561PROPERTY,
      PLANT AND EQUIPMENTElectric:Production
              
              
              1,294,115
              
              
              
              1,266,716Transmission
              
              
              638,645
              
              
              
              622,665Distribution
              
              
              1,551,382
              
              
              
              1,468,481Other
      Property, Plant and Equipment
              
              
              250,053
              
              
              
              248,897Construction
      Work in Progress
              
              
              59,356
              
              
              
              85,252Total
      Property, Plant and Equipment
              
              
              3,793,551
              
              
              
              3,692,011Accumulated
      Depreciation and Amortization
              
              
              1,228,141
              
              
              
              1,192,130TOTAL
      PROPERTY, PLANT AND EQUIPMENT – NET
              
              
              2,565,410
              
              
              
              2,499,881OTHER
      NONCURRENT ASSETSRegulatory
      Assets
              
              
              277,790
              
              
              
              304,737Long-term
      Risk Management Assets
              
              
              312
              
              
              
              917Deferred
      Charges and Other Noncurrent Assets
              
              
              20,979
              
              
              
              13,702TOTAL
      OTHER NONCURRENT ASSETS
              
              
              299,081
              
              
              
              319,356TOTAL
      ASSETS
              
              $
              3,084,811
              
              
              $
              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
 September
30, 2009 and December 31, 2008
 (Unaudited)
 
 2009
              
              
              2008CURRENT
      LIABILITIES
              
              (in
      thousands)Advances
      from Affiliates
              
              $
              -
              
              
              $
              70,308Accounts
      Payable:General
              
              
              52,529
              
              
              
              84,121Affiliated
      Companies
              
              
              69,287
              
              
              
              86,407Long-term
      Debt Due Within One Year – Nonaffiliated
              
              
              150,000
              
              
              
              50,000Risk
      Management Liabilities
              
              
              4,765
              
              
              
              4,753Customer
      Deposits
              
              
              42,622
              
              
              
              40,528Accrued
      Taxes
              
              
              61,746
              
              
              
              19,000Regulatory
      Liability for Over-Recovered Fuel Costs
              
              
              95,983
              
              
              
              58,395Provision
      for Revenue Refund
              
              
              -
              
              
              
              52,100Other
      Current Liabilities
              
              
              46,878
              
              
              
              61,194TOTAL
      CURRENT LIABILITIES
              
              
              523,810
              
              
              
              526,806NONCURRENT
      LIABILITIESLong-term
      Debt – Nonaffiliated
              
              
              718,738
              
              
              
              834,859Long-term
      Risk Management Liabilities
              
              
              473
              
              
              
              378Deferred
      Income Taxes
              
              
              553,261
              
              
              
              514,720Regulatory
      Liabilities and Deferred Investment Tax Credits
              
              
              325,694
              
              
              
              323,750Deferred
      Credits and Other Noncurrent Liabilities
              
              
              137,647
              
              
              
              146,777TOTAL
      NONCURRENT LIABILITIES
              
              
              1,735,813
              
              
              
              1,820,484TOTAL
      LIABILITIES
              
              
              2,259,623
              
              
              
              2,347,290Cumulative
      Preferred Stock Not Subject to Mandatory Redemption
              
              
              5,258
              
              
              
              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
              
              
              364,231
              
              
              
              340,016Retained
      Earnings
              
              
              299,318
              
              
              
              251,704Accumulated
      Other Comprehensive Income (Loss)
              
              
              (849
              )
              
              
              (704
              )TOTAL
      COMMON SHAREHOLDER’S EQUITY
              
              
              819,930
              
              
              
              748,246TOTAL
      LIABILITIES AND SHAREHOLDERS’ EQUITY
              
              $
              3,084,811
              
              
              $
              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 Nine Months Ended September 30, 2009 and 2008
 (in
thousands)
 (Unaudited)
 
 2009
              
              
              2008OPERATING
      ACTIVITIESNet
      Income
              
              $
              73,737
              
              
              $
              69,270Adjustments
      to Reconcile Net Income to Net Cash Flows from Operating
      Activities:Depreciation
      and Amortization
              
              
              84,278
              
              
              
              78,079Deferred
      Income Taxes
              
              
              13,103
              
              
              
              70,856Deferral
      of Ice Storm Costs
              
              
              -
              
              
              
              (71,610
              )Allowance
      for Equity Funds Used During Construction
              
              
              (1,224
              )
              
              
              (1,840
              )Mark-to-Market
      of Risk Management Contracts
              
              
              2,185
              
              
              
              6,973Fuel
      Over/Under-Recovery, Net
              
              
              (14,566
              )
              
              
              (47,192
              )Change
      in Other Noncurrent Assets
              
              
              (4,669
              )
              
              
              9,920Change
      in Other Noncurrent Liabilities
              
              
              (2,768
              )
              
              
              (34,426
              )Changes
      in Certain Components of Working Capital:Accounts
      Receivable, Net
              
              
              86,010
              
              
              
              21,846Fuel,
      Materials and Supplies
              
              
              4,199
              
              
              
              (6,881
              )Margin
      Deposits
              
              
              314
              
              
              
              8,554Accounts
      Payable
              
              
              (38,023
              )
              
              
              (81,228
              )Accrued
      Taxes, Net
              
              
              46,119
              
              
              
              35,624Other
      Current Assets
              
              
              (4,136
              )
              
              
              (1,676
              )Other
      Current Liabilities
              
              
              (11,800
              )
              
              
              (13,883
              )Net
      Cash Flows from Operating Activities
              
              
              232,759
              
              
              
              42,386INVESTING
      ACTIVITIESConstruction
      Expenditures
              
              
              (134,756
              )
              
              
              (214,319
              )Change
      in Advances to Affiliates, Net
              
              
              (8,450
              )
              
              
              51,202Other
      Investing Activities
              
              
              261
              
              
              
              1,594Net
      Cash Flows Used for Investing Activities
              
              
              (142,945
              )
              
              
              (161,523
              )FINANCING
      ACTIVITIESCapital
      Contribution from Parent
              
              
              20,000
              
              
              
              30,000Issuance
      of Long-term Debt – Nonaffiliated
              
              
              33,248
              
              
              
              -Change
      in Advances from Affiliates, Net
              
              
              (70,308
              )
              
              
              125,029Retirement
      of Long-term Debt – Nonaffiliated
              
              
              (50,000
              )
              
              
              (33,700
              )Retirement
      of Cumulative Preferred Stock
              
              
              (2
              )
              
              
              -Principal
      Payments for Capital Lease Obligations
              
              
              (1,128
              )
              
              
              (1,159
              )Dividends
      Paid on Common Stock
              
              
              (21,750
              )
              
              
              -Dividends
      Paid on Cumulative Preferred Stock
              
              
              (159
              )
              
              
              (159
              )Other
      Financing Activities
              
              
              247
              
              
              
              -Net
      Cash Flows from (Used for) Financing Activities
              
              
              (89,852
              )
              
              
              120,011Net
      Increase (Decrease) in Cash and Cash Equivalents
              
              
              (38
              )
              
              
              874Cash
      and Cash Equivalents at Beginning of Period
              
              
              1,345
              
              
              
              1,370Cash
      and Cash Equivalents at End of Period
              
              $
              1,307
              
              
              $
              2,244SUPPLEMENTARY
      INFORMATIONCash
      Paid for Interest, Net of Capitalized Amounts
              
              $
              55,152
              
              
              $
              39,739Net
      Cash Paid for Income Taxes
              
              
              4,423
              
              
              
              44,559Noncash
      Acquisitions Under Capital Leases
              
              
              2,802
              
              
              
              403Construction
      Expenditures Included in Accounts Payable at September 30,
              
              
              7,315
              
              
              
              12,251
 
 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 and Extraordinary Item
              Note
      2Rate
      Matters
              Note
      3Commitments,
      Guarantees and Contingencies
              Note 4Benefit
      Plans
              Note
      6Business
      Segments
              Note
      7Derivatives
      and Hedging
              Note
      8Fair
      Value Measurements
              Note
      9Income
      Taxes
              Note
      10Financing
      Activities
              Note 11
 
 
  
  
 
 
 
 
 
 SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
 
  
  SOUTHWESTERN ELECTRIC POWER COMPANY
CONSOLIDATED
 MANAGEMENT’S FINANCIAL
DISCUSSION AND ANALYSIS
 
 Results of
Operations
 
 Third Quarter of 2009
Compared to Third Quarter of 2008
 
 Reconciliation
of Third Quarter of 2008 to Third Quarter of 2009
 Income
Before Extraordinary Loss
 (in
millions)
 
 Third
      Quarter of 2008
              
              
              
              
              $
              48Changes
      in Gross Margin:Retail
      and Off-system Sales Margins (a)
              
              
              (16
              )Transmission
      Revenues
              
              
              2Other
              
              
              1Total
      Change in Gross Margin
              
              
              
              
              
              
              (13
              )Total
      Expenses and Other:Other
      Operation and Maintenance
              
              
              16Depreciation
      and Amortization
              
              
              (1
              )Taxes
      Other Than Income Taxes
              
              
              (1
              )Other
      Income
              
              
              4Interest
      Expense
              
              
              6Total
      Expenses and Other
              
              
              
              
              
              
              24Income
      Tax Expense
              
              
              
              
              
              
              6Third
      Quarter of 2009
              
              
              
              
              
              $
              65
 
 (a)
              Includes
      firm wholesale sales to municipals and
  cooperatives.
 
 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 $16 million primarily due to a $12
      million decrease in wholesale fuel recovery and a $7 million impairment of
      a fuel regulatory asset related to deferred mining costs in
      Arkansas.·
              Transmission
      Revenues increased $2 million primarily due to higher rates in the SPP
      region.
 
 Total
Expenses and Other and Income Tax Expense changed between years as
follows:
 
 ·
              Other
      Operation and Maintenance expenses decreased $16 million primarily due to
      storm recovery costs for Hurricanes Ike and Gustav in 2008 and the
      deferral in September 2009 of a portion of the January 2009 Northern
      Arkansas ice storm costs.·
              Other
      Income increased $4 million primarily due to an $8 million increase in the
      equity component of AFUDC as a result of construction at the Turk Plant
      and Stall Unit and the reapplication of the accounting guidance for
      “Regulated Operations” for the generation portion of SWEPCo’s Texas retail
      jurisdiction effective April 2009.  See “Texas Rate Matters –
      Texas Restructuring – SPP” section of Note 3.  This increase was
      partially offset by lower interest income.·
              Interest
      Expense decreased $6 million primarily due to higher AFUDC debt as a
      result of construction at the Turk Plant and Stall Unit and lower interest
      expense on debt and other.·
              Income
      Tax Expense decreased $6 million primarily due to changes in certain
      book/tax differences accounted for on a flow-through basis, partially
      offset by an increase in pretax book
income.
  Nine Months Ended September
30, 2009 Compared to Nine Months Ended September 30, 2008
 
 Reconciliation
of Nine Months Ended September 30, 2008 to Nine Months Ended September 30,
2009
 Income
Before Extraordinary Loss
 (in
millions)
 
 Nine
      Months Ended September 30, 2008
              
              
              
              
              $
              69Changes
      in Gross Margin:Retail
      and Off-system Sales Margins (a)
              
              
              (9
              )Transmission
      Revenues
              
              
              7Other
              
              
              (1
              )Total
      Change in Gross Margin
              
              
              
              
              
              
              (3
              )Total
      Expenses and Other:Other
      Operation and Maintenance
              
              
              30Taxes
      Other Than Income Taxes
              
              
              1Other
      Income
              
              
              15Interest
      Expense
              
              
              5Total
      Expenses and Other
              
              
              
              
              
              
              51Income
      Tax Expense
              
              
              
              
              
              
              (4
              )Nine
      Months Ended September 30, 2009
              
              
              
              
              
              $
              113
 
 (a)
              Includes
      firm wholesale sales to municipals and
  cooperatives.
 
 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 $9 million primarily due
      to:·
              An
      $8 million decrease in wholesale fuel recovery.·
              A
      $9 million decrease in industrial sales due to reduced operating levels
      and suspended operations by certain large industrial customers in SWEPCo’s
      service territory.·
              A
      $7 million impairment of a fuel regulatory asset related to deferred
      mining costs in Arkansas.These
      decreases were partially offset by:·
              An
      $8 million increase in rate relief related to the Louisiana Formula Rate
      Plan.  See “Louisiana Rate Matters – Formula Rate Filing”
      section of Note 3.·
              An
      $8 million increase in wholesale and municipal revenue due to higher
      prices and the annual true-up for formula rate
  customers.·
              Transmission
      Revenues increased $7 million primarily due to higher rates in the SPP
      region.·
              Other
      revenues decreased $1 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.  The
      decreased revenue from coal deliveries was offset by a corresponding
      decrease in Other Operation and Maintenance expenses from mining
      operations as discussed below.
 
 Total
Expenses and Other and Income Tax Expense changed between years as
follows:
 
 ·
              Other
      Operation and Maintenance expenses decreased $30 million primarily due
      to:·
              An
      $18 million decrease in distribution expenses related to storm recovery
      costs primarily for Hurricanes Ike and Gustav in 2008.·
              A
      $5 million decrease in steam plant maintenance expense primarily due to a
      reduction in planned and unplanned outages.·
              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.·
              A
      $2 million gain on sale of property related to the sale of percentage
      ownership of Turk Plant to nonaffiliated companies.·
              Other
      Income increased $15 million primarily due to an increase in the equity
      component of AFUDC as a result of construction at the Turk Plant and Stall
      Unit and the reapplication of the accounting guidance for “Regulated
      Operations” for the generation portion of SWEPCo’s Texas retail
      jurisdiction effective April 2009.  See “Texas Rate Matters –
      Texas Restructuring – SPP” section of Note 3.  This increase was
      partially offset by lower interest income.·
              Interest
      Expense decreased $5 million primarily due to higher AFUDC debt as a
      result of construction at the Turk Plant and Stall Unit, partially offset
      by higher interest expense on debt.·
              Income
      Tax Expense increased $4 million primarily due to an increase in pretax
      book income, partially offset by changes in certain book/tax differences
      accounted for on a flow-through
basis.
 
 Financial
Condition
 
 Credit
Ratings
 
 SWEPCo’s
credit ratings as of September 30, 2009 were as follows:
 
 Moody’s
              
              S&P
              
              FitchSenior
      Unsecured Debt
              Baa3
              
              BBB
              
              BBB+
 
 S&P
and Moody’s have SWEPCo on stable outlook.  In July 2009, Fitch
changed its rating outlook for SWEPCo from stable to negative.  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 nine months ended September 30, 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
              
              
              335,922
              
              
              
              134,516Investing
      Activities
              
              
              (472,183
              )
              
              
              (619,487
              )Financing
      Activities
              
              
              136,440
              
              
              
              485,981Net
      Increase in Cash and Cash Equivalents
              
              
              179
              
              
              
              1,010Cash
      and Cash Equivalents at End of Period
              
              $
              2,089
              
              
              $
              2,752
 
 Operating
Activities
 
 Net Cash
Flows from Operating Activities were $336 million in 2009.  SWEPCo
produced Net Income of $107 million during the period and had noncash items of
$109 million for Depreciation and Amortization, partially offset by $32 million
in Allowance for Equity Funds Used During Construction and $21 million 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 $81
million inflow from Accounts Receivable, Net was primarily due to the receipt of
payment for SIA from the AEP East companies.  The $53 million outflow
from Other Current Liabilities was due to a decrease in check clearing, a refund
to wholesale customers for the SIA and payments of employee-related
expenses.  The $50 million inflow from Accrued Taxes, Net was the
result of an increase in accruals related to federal and property
tax.  The $25 million inflow from Accounts Payable was primarily due
to increases related to accruals related to tax payments partially offset for a
decrease in customer accounts factored, net.  The $20 million outflow
from Accrued Interest was primarily due to timing between accruals and payments
for senior unsecured notes.  The $62 million inflow from Fuel
Over/Under-Recovery, Net was the result of a surcharge to customers in Texas for
under-recovered fuel cost and a decrease in fuel costs.
  Net Cash
Flows from Operating Activities were $135 million in 2008.  SWEPCo
produced Net Income of $69 million during the period and had a noncash expense
item of $109 million for Depreciation and Amortization and $37 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 $47
million inflow from Accounts Receivable, Net was primarily due to the assignment
of certain ERCOT contracts to an affiliate company.  The $35 million
outflow from Accounts Payable was primarily due to a decrease in purchased power
payables.  The $29 million inflow from Accrued Taxes, Net was due to a
refund for the 2007 overpayment of federal income taxes.  The $99
million outflow from Fuel Over/Under-Recovery, Net was the result of higher fuel
costs.
 
 Investing
Activities
 
 Net Cash
Flows Used for Investing Activities during 2009 and 2008 were $472 million and
$619 million, respectively.  Construction Expenditures of $470 million
and $424 million in 2009 and 2008, respectively, were primarily related to new
generation projects at the Turk Plant and Stall Unit.  SWEPCo’s net
increase in loans to the Utility Money Pool during 2009 and 2008 were $107
million and $196 million, respectively.  Proceeds from Sales of Assets
in 2009 primarily includes $104 million relating to the sale of a portion of
Turk Plant to joint owners.
 
 Financing
Activities
 
 Net Cash
Flows from Financing Activities were $136 million during 2009.  SWEPCo
received a Capital Contribution from Parent of $143 million and $12 million from
proceeds on sale leaseback of a utility property.
 
 Net Cash
Flows from Financing Activities were $486 million during 2008.  SWEPCo
issued $400 million of Senior Unsecured Notes.  SWEPCo received a
Capital Contribution from Parent of $100 million.  SWEPCo retired $46
million of Nonaffiliated Long-term Debt.
 
 Financing
Activity
 
 Long-term
debt issuances and principal payments made during the first nine months of 2009
were:
 
 Issuances
 
 None
 
 Principal
Payments
 Principal
                Amount
      Paid
              
              Interest
              
              DueType
      of Debt
              
              
              Rate
              
              Date(in
      thousands)
              
              (%)Notes
      Payable – Nonaffiliated
              
              $
              3,304
              
              4.47
              
              2011
 
 Liquidity
 
 The
financial markets were volatile at both a global and domestic
level.  The credit situation appears to have improved but could impact
SWEPCo’s future 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 relies 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.
 
 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 for
disclosures about risk management activities.  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 September 30,
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
 September
30, 2009
 (in
thousands)
 
 MTM
      Risk Management Contracts
              
              
              Cash
      Flow Hedge Contracts
              
              
              Collateral
                Deposits
              
              
              TotalCurrent
      Assets
              
              $
              5,260
              
              
              $
              69
              
              
              $
              (2
              )
              
              $
              5,327Noncurrent
      Assets
              
              
              462
              
              
              
              18
              
              
              
              -
              
              
              
              480Total
      MTM Derivative Contract Assets
              
              
              5,722
              
              
              
              87
              
              
              
              (2
              )
              
              
              5,807Current
      Liabilities
              
              
              3,446
              
              
              
              25
              
              
              
              (22
              )
              
              
              3,449Noncurrent
      Liabilities
              
              
              233
              
              
              
              -
              
              
              
              (19
              )
              
              
              214Total
      MTM Derivative Contract Liabilities
              
              
              3,679
              
              
              
              25
              
              
              
              (41
              )
              
              
              3,663Total
      MTM Derivative Contract Net Assets (Liabilities)
              
              $
              2,043
              
              
              $
              62
              
              
              $
              39
              
              
              $
              2,144
  MTM
Risk Management Contract Net Assets
 Nine
Months Ended September 30, 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
              
              
              (1,183
              )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
              
              
              (35
              )Change
      in Fair Value Due to Valuation Methodology Changes on Forward
      Contracts
              
              
              -Changes
      in Fair Value Due to Market Fluctuations During the Period
    (b)
              
              
              41Changes
      in Fair Value Allocated to Regulated Jurisdictions (c)
              
              
              577Total
      MTM Risk Management Contract Net Assets
              
              
              2,043Cash
      Flow Hedge Contracts
              
              
              62Collateral
      Deposits
              
              
              39Total
      MTM Derivative Contract Net Assets at September 30, 2009
              
              $
              2,144
 
 (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 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
 
 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 or
(require) cash:
 
 Maturity
and Source of Fair Value of MTM
 Risk
Management Contract Net Assets (Liabilities)
 September
30, 2009
 (in
thousands)
 
 Remainder
                2009
              
              
              2010
              
              
              2011
              
              
              2012
              
              
              2013
              
              
              After
                2013
              
              
              TotalLevel
      1 (a)
              
              $
              56
              
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              56Level
      2 (b)
              
              
              412
              
              
              
              1,996
              
              
              
              (439
              )
              
              
              12
              
              
              
              -
              
              
              
              -
              
              
              
              1,981Level
      3 (c)
              
              
              4
              
              
              
              2
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              6Total
      MTM Risk Management Contract Net Assets (Liabilities)
              
              $
              472
              
              
              $
              1,998
              
              
              $
              (439
              )
              
              $
              12
              
              
              $
              -
              
              
              $
              -
              
              
              $
              2,043
 
 (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
8 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 September 30, 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:
 
 Nine
      Months Ended
              
              
              
              
              Twelve
      Months EndedSeptember
      30, 2009
              
              
              
              
              December
      31, 2008(in
      thousands)
              
              
              
              
              (in
      thousands)End
              
              High
              
              Average
              
              Low
              
              
              
              
              End
              
              High
              
              Average
              
              Low$15
              
              $49
              
              $19
              
              $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 back-testing 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 four 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.  As calculated on
SWEPCo’s debt outstanding as of September 30, 2009, the estimated EaR on
SWEPCo’s debt portfolio for the following twelve months was $733
thousand.
 
 
  
  SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
 CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
 For
the Three and Nine Months Ended September 30, 2009 and 2008
 (in
thousands)
 (Unaudited)
 
 Three
      Months Ended
              
              
              Nine
      Months Ended2009
              
              
              2008
              
              
              2009
              
              
              2008REVENUESElectric
      Generation, Transmission and Distribution
              
              $
              392,616
              
              
              $
              489,014
              
              
              $
              1,021,991
              
              
              $
              1,200,356Sales
      to AEP Affiliates
              
              
              9,420
              
              
              
              11,508
              
              
              
              23,470
              
              
              
              42,692Lignite
      Revenues – Nonaffiliated
              
              
              12,334
              
              
              
              11,470
              
              
              
              30,572
              
              
              
              31,661Other
      Revenues
              
              
              604
              
              
              
              471
              
              
              
              1,525
              
              
              
              1,164TOTAL
      REVENUES
              
              
              414,974
              
              
              
              512,463
              
              
              
              1,077,558
              
              
              
              1,275,873EXPENSESFuel
      and Other Consumables Used for Electric Generation
              
              
              161,879
              
              
              
              197,474
              
              
              
              405,329
              
              
              
              462,282Purchased
      Electricity for Resale
              
              
              30,413
              
              
              
              50,449
              
              
              
              85,149
              
              
              
              145,097Purchased
      Electricity from AEP Affiliates
              
              
              6,865
              
              
              
              36,170
              
              
              
              30,395
              
              
              
              108,542Other
      Operation
              
              
              64,686
              
              
              
              64,377
              
              
              
              178,456
              
              
              
              186,713Maintenance
              
              
              17,267
              
              
              
              33,694
              
              
              
              67,283
              
              
              
              88,854Depreciation
      and Amortization
              
              
              36,714
              
              
              
              35,842
              
              
              
              109,065
              
              
              
              108,875Taxes
      Other Than Income Taxes
              
              
              14,127
              
              
              
              12,623
              
              
              
              44,995
              
              
              
              45,747TOTAL
      EXPENSES
              
              
              331,951
              
              
              
              430,629
              
              
              
              920,672
              
              
              
              1,146,110OPERATING
      INCOME
              
              
              83,023
              
              
              
              81,834
              
              
              
              156,886
              
              
              
              129,763Other
      Income (Expense):Interest
      Income
              
              
              388
              
              
              
              5,417
              
              
              
              1,205
              
              
              
              7,834Allowance
      for Equity Funds Used During Construction
              
              
              12,932
              
              
              
              4,152
              
              
              
              31,706
              
              
              
              10,167Interest
      Expense
              
              
              (16,605
              )
              
              
              (22,659
              )
              
              
              (51,894
              )
              
              
              (57,071
              )INCOME
      BEFORE INCOME TAX EXPENSE
              
              
              79,738
              
              
              
              68,744
              
              
              
              137,903
              
              
              
              90,693Income
      Tax Expense
              
              
              14,680
              
              
              
              20,353
              
              
              
              25,367
              
              
              
              21,717INCOME
      BEFORE EXTRAORDINARY LOSS
              
              
              65,058
              
              
              
              48,391
              
              
              
              112,536
              
              
              
              68,976EXTRAORDINARY
      LOSS, NET OF TAX
              
              
              -
              
              
              
              -
              
              
              
              (5,325
              )
              
              
              -NET
      INCOME
              
              
              65,058
              
              
              
              48,391
              
              
              
              107,211
              
              
              
              68,976Less:
      Net Income Attributable to Noncontrolling Interest
              
              
              1,022
              
              
              
              976
              
              
              
              2,971
              
              
              
              2,870NET
      INCOME ATTRIBUTABLE TO SWEPCo SHAREHOLDERS
              
              
              64,036
              
              
              
              47,415
              
              
              
              104,240
              
              
              
              66,106Less:
      Preferred Stock Dividend Requirements
              
              
              58
              
              
              
              58
              
              
              
              172
              
              
              
              172EARNINGS
      ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER
              
              $
              63,978
              
              
              $
              47,357
              
              
              $
              104,068
              
              
              $
              65,934
 
 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 Nine Months Ended September 30, 2009 and 2008
 (in
thousands)
 (Unaudited)
 
 SWEPCo
      Common ShareholderCommon
      Stock
              
              
              Paid-in
      Capital
              
              
              Retained
                Earnings
              
              
              Accumulated
                Other
                Comprehensive
                Income
      (Loss)
              
              
              Noncontrolling
                Interest
              
              
              TotalTOTAL
      EQUITY – DECEMBER 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
              
              
              
              
              
              
              100,000
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              100,000Common
      Stock Dividends – Nonaffiliated
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              (4,266
              )
              
              
              (4,266
              )Preferred
      Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (172
              )
              
              
              
              
              
              
              
              
              
              
              (172
              )SUBTOTAL
      – EQUITY
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              1,069,058COMPREHENSIVE
      INCOMEOther
      Comprehensive Income (Loss), Net of Taxes:Cash
      Flow Hedges, Net of Tax of $65
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              (127
              )
              
              
              7
              
              
              
              (120
              )Amortization
      of Pension and OPEB Deferred Costs, Net of Tax of $380
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              706
              
              
              
              
              
              
              
              706NET
      INCOME
              
              
              
              
              
              
              
              
              
              
              66,106
              
              
              
              
              
              
              
              2,870
              
              
              
              68,976TOTAL
      COMPREHENSIVE INCOME
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              69,562TOTAL
      EQUITY – SEPTEMBER 30, 2008
              
              $
              135,660
              
              
              $
              430,003
              
              
              $
              588,519
              
              
              $
              (15,860
              )
              
              $
              298
              
              
              $
              1,138,620TOTAL
      EQUITY – DECEMBER 31, 2008
              
              $
              135,660
              
              
              $
              530,003
              
              
              $
              615,110
              
              
              $
              (32,120
              )
              
              $
              276
              
              
              $
              1,248,929Capital
      Contribution from Parent
              
              
              
              
              
              
              142,500
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              142,500Common
      Stock Dividends – Nonaffiliated
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              (2,886
              )
              
              
              (2,886
              )Preferred
      Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (172
              )
              
              
              
              
              
              
              
              
              
              
              (172
              )Other
      Changes in Equity
              
              
              
              
              
              
              2,476
              
              
              
              (2,476
              )
              
              
              
              
              
              
              
              
              
              
              -SUBTOTAL
      – EQUITY
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              1,388,371COMPREHENSIVE
      INCOMEOther
      Comprehensive Income, Net of Taxes:Cash
      Flow Hedges, Net of Tax of $421
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              782
              
              
              
              
              
              
              
              782Amortization
      of Pension and OPEB Deferred Costs, Net of Tax of $8,919
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              16,563
              
              
              
              
              
              
              
              16,563NET
      INCOME
              
              
              
              
              
              
              
              
              
              
              104,240
              
              
              
              
              
              
              
              2,971
              
              
              
              107,211TOTAL
      COMPREHENSIVE INCOME
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              124,556TOTAL
      EQUITY – SEPTEMBER 30, 2009
              
              $
              135,660
              
              
              $
              674,979
              
              
              $
              716,702
              
              
              $
              (14,775
              )
              
              $
              361
              
              
              $
              1,512,927
 
 See
      Condensed Notes to Condensed Financial Statements of Registrant
      Subsidiaries.
 
 
 
  
  SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
 CONDENSED
CONSOLIDATED BALANCE SHEETS
 ASSETS
 September
30, 2009 and December 31, 2008
 (in
thousands)
 (Unaudited)
 
 2009
              
              
              2008CURRENT
      ASSETSCash
      and Cash Equivalents
              
              $
              2,089
              
              
              $
              1,910Advances
      to Affiliates
              
              
              106,662
              
              
              
              -Accounts
      Receivable:Customers
              
              
              46,018
              
              
              
              53,506Affiliated
      Companies
              
              
              48,708
              
              
              
              121,928Miscellaneous
              
              
              11,275
              
              
              
              12,052Allowance
      for Uncollectible Accounts
              
              
              (25
              )
              
              
              (135
              )Total
      Accounts Receivable
              
              
              105,976
              
              
              
              187,351Fuel
              
              
              91,641
              
              
              
              100,018Materials
      and Supplies
              
              
              53,705
              
              
              
              49,724Risk
      Management Assets
              
              
              5,327
              
              
              
              8,185Regulatory
      Asset for Under-Recovered Fuel Costs
              
              
              246
              
              
              
              75,006Prepayments
      and Other Current Assets
              
              
              37,068
              
              
              
              20,147TOTAL
      CURRENT ASSETS
              
              
              402,714
              
              
              
              442,341PROPERTY,
      PLANT AND EQUIPMENTElectric:Production
              
              
              1,817,505
              
              
              
              1,808,482Transmission
              
              
              838,137
              
              
              
              786,731Distribution
              
              
              1,451,365
              
              
              
              1,400,952Other
      Property, Plant and Equipment
              
              
              716,747
              
              
              
              711,260Construction
      Work in Progress
              
              
              1,098,069
              
              
              
              869,103Total
      Property, Plant and Equipment
              
              
              5,921,823
              
              
              
              5,576,528Accumulated
      Depreciation and Amortization
              
              
              2,091,205
              
              
              
              2,014,154TOTAL
      PROPERTY, PLANT AND EQUIPMENT – NET
              
              
              3,830,618
              
              
              
              3,562,374OTHER
      NONCURRENT ASSETSRegulatory
      Assets
              
              
              251,008
              
              
              
              210,174Long-term
      Risk Management Assets
              
              
              480
              
              
              
              1,500Deferred
      Charges and Other Noncurrent Assets
              
              
              44,090
              
              
              
              36,696TOTAL
      OTHER NONCURRENT ASSETS
              
              
              295,578
              
              
              
              248,370TOTAL
      ASSETS
              
              $
              4,528,910
              
              
              $
              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
 September
30, 2009 and December 31, 2008
 (Unaudited)
 
 2009
              
              
              2008CURRENT
      LIABILITIES
              
              (in
      thousands)Advances
      from Affiliates
              
              $
              -
              
              
              $
              2,526Accounts
      Payable:General
              
              
              114,990
              
              
              
              133,538Affiliated
      Companies
              
              
              77,565
              
              
              
              51,040Short-term
      Debt – Nonaffiliated
              
              
              5,273
              
              
              
              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
              
              
              3,449
              
              
              
              6,735Customer
      Deposits
              
              
              39,884
              
              
              
              35,622Accrued
      Taxes
              
              
              83,771
              
              
              
              33,744Accrued
      Interest
              
              
              16,831
              
              
              
              36,647Provision
      for Revenue Refund
              
              
              28,507
              
              
              
              54,100Other
      Current Liabilities
              
              
              61,419
              
              
              
              102,535TOTAL
      CURRENT LIABILITIES
              
              
              486,095
              
              
              
              468,065NONCURRENT
      LIABILITIESLong-term
      Debt – Nonaffiliated
              
              
              1,420,746
              
              
              
              1,423,743Long-term
      Debt – Affiliated
              
              
              -
              
              
              
              50,000Long-term
      Risk Management Liabilities
              
              
              214
              
              
              
              516Deferred
      Income Taxes
              
              
              427,181
              
              
              
              403,125Regulatory
      Liabilities and Deferred Investment Tax Credits
              
              
              334,570
              
              
              
              335,749Asset
      Retirement Obligations
              
              
              53,789
              
              
              
              53,433Employment
      Benefits and Pension Obligations
              
              
              122,309
              
              
              
              117,772Deferred
      Credits and Other Noncurrent Liabilities
              
              
              166,382
              
              
              
              147,056TOTAL
      NONCURRENT LIABILITIES
              
              
              2,525,191
              
              
              
              2,531,394TOTAL
      LIABILITIES
              
              
              3,011,286
              
              
              
              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
              
              
              674,979
              
              
              
              530,003Retained
      Earnings
              
              
              716,702
              
              
              
              615,110Accumulated
      Other Comprehensive Income (Loss)
              
              
              (14,775
              )
              
              
              (32,120
              )TOTAL
      COMMON SHAREHOLDER’S EQUITY
              
              
              1,512,566
              
              
              
              1,248,653Noncontrolling
      Interest
              
              
              361
              
              
              
              276TOTAL
      EQUITY
              
              
              1,512,927
              
              
              
              1,248,929TOTAL
      LIABILITIES AND EQUITY
              
              $
              4,528,910
              
              
              $
              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 Nine Months Ended September 30, 2009 and 2008
 (in
thousands)
 (Unaudited)
 
 2009
              
              
              2008OPERATING
      ACTIVITIESNet
      Income
              
              $
              107,211
              
              
              $
              68,976Adjustments
      to Reconcile Net Income to Net Cash Flows from Operating
      Activities:Depreciation
      and Amortization
              
              
              109,065
              
              
              
              108,875Deferred
      Income Taxes
              
              
              (20,571
              )
              
              
              37,162Extraordinary
      Loss, Net of Tax
              
              
              5,325
              
              
              
              -Allowance
      for Equity Funds Used During Construction
              
              
              (31,706
              )
              
              
              (10,167
              )Mark-to-Market
      of Risk Management Contracts
              
              
              510
              
              
              
              7,905Fuel
      Over/Under-Recovery, Net
              
              
              61,880
              
              
              
              (98,928
              )Change
      in Other Noncurrent Assets
              
              
              13,498
              
              
              
              (211
              )Change
      in Other Noncurrent Liabilities
              
              
              4,539
              
              
              
              (15,619
              )Changes
      in Certain Components of Working Capital:Accounts
      Receivable, Net
              
              
              81,322
              
              
              
              46,835Fuel,
      Materials and Supplies
              
              
              4,396
              
              
              
              (16,665
              )Accounts
      Payable
              
              
              24,584
              
              
              
              (34,819
              )Accrued
      Taxes, Net
              
              
              50,027
              
              
              
              29,271Accrued
      Interest
              
              
              (19,816
              )
              
              
              5,498Other
      Current Assets
              
              
              (1,017
              )
              
              
              6,929Other
      Current Liabilities
              
              
              (53,325
              )
              
              
              (526
              )Net
      Cash Flows from Operating Activities
              
              
              335,922
              
              
              
              134,516INVESTING
      ACTIVITIESConstruction
      Expenditures
              
              
              (470,379
              )
              
              
              (424,092
              )Change
      in Advances to Affiliates, Net
              
              
              (106,662
              )
              
              
              (195,628
              )Proceeds
      from Sales of Assets
              
              
              105,500
              
              
              
              483Other
      Investing Activities
              
              
              (642
              )
              
              
              (250
              )Net
      Cash Flows Used for Investing Activities
              
              
              (472,183
              )
              
              
              (619,487
              )FINANCING
      ACTIVITIESCapital
      Contribution from Parent
              
              
              142,500
              
              
              
              100,000Issuance
      of Long-term Debt – Nonaffiliated
              
              
              -
              
              
              
              437,113Change
      in Short-term Debt, Net – Nonaffiliated
              
              
              (1,899
              )
              
              
              9,234Change
      in Advances from Affiliates, Net
              
              
              (2,526
              )
              
              
              (1,565
              )Retirement
      of Long-term Debt – Nonaffiliated
              
              
              (3,304
              )
              
              
              (45,939
              )Principal
      Payments for Capital Lease Obligations
              
              
              (7,853
              )
              
              
              (8,424
              )Proceeds
      from Sale/Leaseback
              
              
              12,222
              
              
              
              -Dividends
      Paid on Common Stock – Nonaffiliated
              
              
              (2,971
              )
              
              
              (4,266
              )Dividends
      Paid on Cumulative Preferred Stock
              
              
              (172
              )
              
              
              (172
              )Other
      Financing Activities
              
              
              443
              
              
              
              -Net
      Cash Flows from Financing Activities
              
              
              136,440
              
              
              
              485,981Net
      Increase in Cash and Cash Equivalents
              
              
              179
              
              
              
              1,010Cash
      and Cash Equivalents at Beginning of Period
              
              
              1,910
              
              
              
              1,742Cash
      and Cash Equivalents at End of Period
              
              $
              2,089
              
              
              $
              2,752
 
 SUPPLEMENTARY
      INFORMATIONCash
      Paid for Interest, Net of Capitalized Amounts
              
              $
              82,033
              
              
              $
              44,255Net
      Cash Received for Income Taxes
              
              
              (6,196
              )
              
              
              (20,835
              )Noncash
      Acquisitions Under Capital Leases
              
              
              26,175
              
              
              
              21,807Construction
      Expenditures Included in Accounts Payable at September 30,
              
              
              60,219
              
              
              
              94,837
 
 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 and Extraordinary Item
              Note
      2Rate
      Matters
              Note 3Commitments,
      Guarantees and Contingencies
              Note
      4Acquisition
              Note 5Benefit
      Plans
              Note
      6Business
      Segments
              Note
      7Derivatives
      and Hedging
              Note
      8Fair
      Value Measurements
              Note
      9Income
      Taxes
              Note
      10Financing
      Activities
              Note
      11







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 and Extraordinary Item
              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.
              Acquisition
              SWEPCo6.
              Benefit
      Plans
              APCo,
      CSPCo, I&M, OPCo, PSO, SWEPCo7.
              Business
      Segments
              APCo,
      CSPCo, I&M, OPCo, PSO, SWEPCo8.
              Derivatives
      and Hedging
              APCo,
      CSPCo, I&M, OPCo, PSO, SWEPCo9.
              Fair
      Value Measurements
              APCo,
      CSPCo, I&M, OPCo, PSO, SWEPCo10.
              Income
      Taxes
              APCo,
      CSPCo, I&M, OPCo, PSO, SWEPCo11.
              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 of the information and
footnotes required by GAAP for complete annual financial
statements.
 
 In the
opinion of management, the unaudited condensed 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.  Net income for the
three and nine months ended September 30, 2009 is not necessarily indicative of
results that may be expected for the year ending December 31,
2009.  Management reviewed subsequent events through the Registrant
Subsidiaries’ Form 10-Q issuance date of October 30, 2009.  APCo’s,
CSPCo’s, I&M’s and PSO’s accompanying condensed financial statements are
unaudited and should be read in conjunction with their audited 2008 financial
statements and notes thereto, which are included in Annual Reports on Form 10-K
for the year ended December 31, 2008 as filed with the SEC on February 27,
2009.  OPCo’s and SWEPCo’s accompanying condensed financial statements
are unaudited and should be read in conjunction with their audited 2008
financial statements and notes thereto, which are included in Current Report on
Form 8-K as filed with the SEC on May 1, 2009.
 
 Variable
Interest Entities
 
 The
accounting guidance for “Variable Interest Entities” 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 the accounting guidance for “Variable Interest
Entities.”  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.  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.  I&M is the primary beneficiary of DCC Fuel
LLC (DCC Fuel).  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.  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 September 30, 2009 and 2008 were $34 million and $31 million,
respectively, and for the nine months ended September 30, 2009 and 2008 were $95
million and $79 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.  SWEPCo and Cleco Corporation equally approve
DHLC’s annual budget.  The creditors of DHLC have no recourse to any
AEP entity other than SWEPCo.  As SWEPCo is the sole equity owner of
DHLC it receives 100% of the management fee.  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 September 30, 2009 and 2008 were
$12 million and $11 million, respectively, and for the nine months ended
September 30, 2009 and 2008 were $31 million and $32 million,
respectively.  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
 September
30, 2009
 (in
millions)
 Sabine
              
              
              DHLCASSETSCurrent
      Assets
              
              $
              38
              
              
              $
              19Net
      Property, Plant and Equipment
              
              
              133
              
              
              
              29Other
      Noncurrent Assets
              
              
              30
              
              
              
              10Total
      Assets
              
              $
              201
              
              
              $
              58LIABILITIES
      AND EQUITYCurrent
      Liabilities
              
              $
              27
              
              
              $
              15Noncurrent
      Liabilities
              
              
              174
              
              
              
              40Equity
              
              
              -
              
              
              
              3Total
      Liabilities and Equity
              
              $
              201
              
              
              $
              58
 
 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 Flue Gas Desulfurization (FGD)
system installed on OPCo’s Gavin Plant.  The PUCO approved the
original lease agreement between OPCo and JMG.  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.  Based on the
structure of the entity, management has concluded OPCo is the primary
beneficiary and is required to consolidate JMG.  In April 2009, OPCo
paid JMG $58 million which was used to retire certain long-term debt of
JMG.  While this payment was not contractually required, OPCo made
this payment in anticipation of purchasing the outstanding equity of
JMG.  In July 2009, OPCo purchased all of the outstanding equity
ownership of JMG for $28 million resulting in an elimination of OPCo’s
Noncontrolling Interest related to JMG and an increase in Common Shareholder’s
Equity of $54 million.  In August and September 2009, JMG reacquired
$218 million of auction rate debt, funded by OPCo capital contributions to
JMG.  These reacquisitions were not contractually
required.  JMG is a wholly-owned subsidiary of OPCo with a capital
structure of 85% equity, 15% debt.
 
 OPCo’s
intent is to cancel the lease and dissolve JMG in December 2009.  The
assets and liabilities of JMG will remain incorporated with OPCo’s
business.  OPCo’s total billings from JMG for the three months ended
September 30, 2009 and 2008 were $1 million and $13 million, respectively, and
for the nine months ended September 30, 2009 and 2008 were $50 million and $39
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
 September
30, 2009
 (in
millions)
 JMGASSETSCurrent
      Assets
              
              $
              18Net
      Property, Plant and Equipment
              
              
              407Other
      Noncurrent Assets
              
              
              -Total
      Assets
              
              $
              425LIABILITIES
      AND EQUITYCurrent
      Liabilities
              
              $
              20Noncurrent
      Liabilities
              
              
              46Equity
              
              
              359Total
      Liabilities and Equity
              
              $
              425
 
 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
 
 In
September 2009, I&M entered into a nuclear fuel sale and leaseback
transaction with DCC Fuel.  DCC Fuel was formed for the purpose of
acquiring, owning and leasing nuclear fuel to I&M.  DCC Fuel
purchased the nuclear fuel from I&M with funds received from the issuance of
notes to financial institutions.  DCC Fuel is a single-lessee leasing
arrangement with only one asset and is capitalized with all
debt.  Payments on the lease will be made semi-annually on April 1 and
October 1, beginning in April 2010.  As of September 30, 2009, no
payments have been made by I&M to DCC Fuel.  The lease was
recorded as a capital lease on I&M’s balance sheet as title to the nuclear
fuel transfers to I&M at the end of the 48 month lease
term.  Based on the structure, management has concluded that I&M
is the primary beneficiary and is required to consolidate DCC
Fuel.  The capital lease is eliminated upon
consolidation.  See the tables below for the classification of DCC
Fuel’s assets and liabilities on I&M’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.
 
 INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
 VARIABLE
INTEREST ENTITIES
 September
30, 2009
 (in
millions)
 DCC
      FuelASSETSCurrent
      Assets
              
              $
              38Net
      Property, Plant and Equipment
              
              
              101Other
      Noncurrent Assets
              
              
              65Total
      Assets
              
              $
              204LIABILITIES
      AND EQUITYCurrent
      Liabilities
              
              $
              38Noncurrent
      Liabilities
              
              
              166Equity
              
              
              -Total
      Liabilities and Equity
              
              $
              204
 
 INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
 VARIABLE
INTEREST ENTITIES
 December
31, 2008
 (in
millions)
 DCC
      FuelASSETSCurrent
      Assets
              
              $
              -Net
      Property, Plant and Equipment
              
              
              -Other
      Noncurrent Assets
              
              
              -Total
      Assets
              
              $
              -LIABILITIES
      AND EQUITYCurrent
      Liabilities
              
              $
              -Noncurrent
      Liabilities
              
              
              -Equity
              
              
              -Total
      Liabilities and Equity
              
              $
              -
 
 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 September 30,
              
              
              Nine
      Months Ended September 30,2009
              
              
              2008
              
              
              2009
              
              
              2008Company
              
              (in
      millions)APCo
              
              $
              50
              
              
              $
              62
              
              
              $
              146
              
              
              $
              179CSPCo
              
              
              31
              
              
              
              34
              
              
              
              91
              
              
              
              98I&M
              
              
              32
              
              
              
              37
              
              
              
              93
              
              
              
              109OPCo
              
              
              43
              
              
              
              52
              
              
              
              130
              
              
              
              151PSO
              
              
              21
              
              
              
              28
              
              
              
              64
              
              
              
              87SWEPCo
              
              
              35
              
              
              
              35
              
              
              
              94
              
              
              
              101
 
 The
carrying amount and classification of variable interest in AEPSC’s accounts
payable are as follows:
 
 September
      30, 2009
              
              December
      31, 2008As
      Reported in the
              
              Maximum
              
              As
      Reported in the
              
              MaximumBalance
      Sheet
              
              Exposure
              
              Balance
      Sheet
              
              ExposureCompany
              (in
      millions)APCo
              
              $
              20
              
              
              $
              20
              
              
              $
              27
              
              
              $
              27CSPCo
              
              
              12
              
              
              
              12
              
              
              
              15
              
              
              
              15I&M
              
              
              13
              
              
              
              13
              
              
              
              14
              
              
              
              14OPCo
              
              
              17
              
              
              
              17
              
              
              
              21
              
              
              
              21PSO
              
              
              9
              
              
              
              9
              
              
              
              10
              
              
              
              10SWEPCo
              
              
              13
              
              
              
              13
              
              
              
              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 September 30,
              
              Nine
      Months Ended September 30,2009
              
              2008
              
              2009
              
              2008Company
              (in
      millions)CSPCo
              
              $
              28
              
              
              $
              47
              
              
              $
              60
              
              
              $
              96I&M
              
              
              59
              
              
              
              65
              
              
              
              183
              
              
              
              181
 
 The
carrying amount and classification of variable interest in AEGCo’s accounts
payable are as follows:
 
 September
      30, 2009
              
              December
      31, 2008As
      Reported in
              
              
              
              As
      Reported inthe
      Consolidated
              
              Maximum
              
              the
      Consolidated
              
              MaximumBalance
      Sheet
              
              Exposure
              
              Balance
      Sheet
              
              ExposureCompany
              (in
      millions)CSPCo
              
              $
              6
              
              
              $
              6
              
              
              $
              5
              
              
              $
              5I&M
              
              
              20
              
              
              
              20
              
              
              
              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 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 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.  In comparing 2009 and 2008, the change in depreciation
rates resulted in a net increase (decrease) in depreciation expense
of:
 
 Total
      Depreciation Expense VarianceThree
      Months Ended
              
              
              Nine
      Months EndedSeptember
      30,
              
              
              September
      30,2009/2008
              
              
              2009/2008(in
      thousands)CSPCo
              $
              
              (4,430
              )
              $
              
              
              (13,104
              )OPCo
              
              
              
              
              
              
              17,810
              
              
              
              
              
              
              
              52,040
 
 2.
              NEW ACCOUNTING
      PRONOUNCEMENTS AND EXTRAORDINARY
ITEM
 
 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 2009
 
 The
following standards were effective during the first nine months 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 had no business combinations in 2009.  The Registrant
Subsidiaries will apply it to any future business combinations.  SFAS
141R is included in the “Business Combination” accounting guidance.
 
 SFAS
160 “Noncontrolling Interests 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.  SFAS 160
is included in the “Consolidation” accounting guidance.  The
retrospective application of this standard impacted OPCo and SWEPCo as
follows:
 
 OPCo:
 ·
              Reclassifies
      Interest Expense of $233 thousand and $1.1 million for the three and nine
      months ended September 30, 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 as
      Noncontrolling Interest in Total Equity on its Condensed Consolidated
      Balance Sheets.·
              Separately
      reflects changes in Noncontrolling Interest in its Condensed Consolidated
      Statements of Changes in Equity and Comprehensive Income
      (Loss).·
              Reclassifies
      dividends paid to noncontrolling interests of $1.1 million for the nine
      months ended September 30, 2008 from Operating Activities to Financing
      Activities on the Condensed Consolidated Statements of Cash
      Flows.
 
 SWEPCo:
 ·
              Reclassifies
      Minority Interest Expense of $976 thousand and $2.9 million for the three
      and nine months ended September 30, 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 as
      Noncontrolling Interest in Total Equity on its Condensed Consolidated
      Balance Sheets.·
              Separately
      reflects changes in Noncontrolling Interest on the Condensed Consolidated
      Statements of Changes in Equity and Comprehensive Income
      (Loss).·
              Reclassifies
      dividends paid to noncontrolling interests of $4.3 million for the nine
      months ended September 30, 2008 from Operating Activities to Financing
      Activities on 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 Note 8.  SFAS 161
is included in the “Derivatives and Hedging” accounting guidance.
 
 SFAS
165 “Subsequent Events” (SFAS 165)
 
 In May
2009, the FASB issued SFAS 165 incorporating guidance on subsequent events into
authoritative accounting literature and clarifying the time following the
balance sheet date which management reviewed for events and transactions that
require disclosure in the financial statements.
 
 The
Registrant Subsidiaries adopted this standard effective second quarter of
2009.  The standard increased disclosure by requiring disclosure of
the date through which subsequent events have been reviewed.  The
standard did not change management’s procedures for reviewing subsequent
events.  SFAS 165 is included in the “Subsequent Events” accounting
guidance.
 
 SFAS
168 “The FASB Accounting Standards CodificationTMand
the Hierarchy of Generally Accepted Accounting Principles” (SFAS
168)
 
 In June
2009, the FASB issued SFAS 168 establishing the FASB Accounting Standards
CodificationTM as
the authoritative source of accounting principles for preparation of financial
statements and reporting in conformity with GAAP by nongovernmental
entities.
 
 The
Registrant Subsidiaries adopted SFAS 168 effective third quarter of
2009.  It required an update of all references to authoritative
accounting literature.  SFAS 168 is included in the “Generally
Accepted Accounting Principles” accounting guidance.
 
 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.  With the adoption of FSP SFAS 107-1 and APB 28-1, it is applied
to the fair value of long-term debt.  The application of this standard
had an immaterial effect on the fair value of debt outstanding.  EITF
08-5 is included in the “Fair Value Measurements and Disclosures” accounting
guidance.
 
 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.  EITF 08-6 is included in the “Investments – Equity
Method and Joint Ventures” accounting guidance.
 
 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.
 
 The
Registrant Subsidiaries adopted the standard effective second quarter of
2009.  This standard increased the disclosure requirements related to
financial instruments.  See “Fair Value Measurements of Long-term
Debt” section of Note 9.  FSP SFAS 107-1 and APB 28-1 is included in
the “Financial Instruments” accounting guidance.
 
 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.
 
 The
Registrant Subsidiaries adopted the standard effective second quarter of
2009.  The adoption had no impact on APCo, CSPCo, OPCo, PSO and
SWEPCo.  For I&M, the adoption had no impact on its financial
statements but increased disclosure requirements related to financial
instruments.  See “Fair Value Measurements of Trust Assets for
Decommissioning and SNF Disposal” section of Note 9.  FSP SFAS 115-2
and SFAS 124-2 is included in the “Investments – Debt and Equity Securities”
accounting guidance.
 
 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.  SFAS 142-3 is included in the “Intangibles – Goodwill and
Other” accounting guidance.
 
 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 analyses 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 nine months of 2009.  SFAS 157-2 is
included in the “Fair Value Measurements and Disclosures” accounting
guidance.
 
 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.
 
 The
Registrant Subsidiaries adopted the standard effective second quarter of
2009.  This standard had no impact on the financial statements but
increased the disclosure requirements.  See “Fair Value Measurements
of Financial Assets and Liabilities” section of Note 9.  FSP SFAS
157-4 is included in the “Fair Value Measurements and Disclosures” accounting
guidance.
  Pronouncements Effective in
the Future
 
 The
following standards will be effective in the future and their impacts will be
disclosed at that time.
 
 ASU
2009-05 “Measuring Liabilities at Fair Value” (ASU 2009-05)
 
 In August
2009, the FASB issued ASU 2009-05 updating the “Fair Value Measurement and
Disclosures” accounting guidance.  The guidance specifies the
valuation techniques that should be used to fair value a liability in the
absence of a quoted price in an active market.
 
 The new
accounting guidance is effective for interim and annual periods beginning after
the issuance date.  Although management has not completed an analysis,
management does not expect this update to have a material impact on the
financial statements.  The Registrant Subsidiaries will adopt ASU
2009-05 effective fourth quarter of 2009.
  ASU
2009-12 “Investments in Certain Entities That Calculate Net Asset Value per
Share (or its Equivalent)” (ASU 2009-12)
   In
September 2009, the FASB issued ASU 2009-12 updating the “Fair Value Measurement
and Disclosures” accounting guidance for the fair value measurement of
investments in certain entities that calculate net asset value per share (or its
equivalent).  The guidance permits a reporting entity to measure the
fair value of an investment within its scope on the basis of the net asset value
per share of the investment (or its equivalent).
 
 The new
accounting guidance is effective for interim and annual periods ending after
December 15, 2009.  Although management has not completed an analysis,
management does not expect this update to have a material impact on the
financial statements.  The Registrant Subsidiaries will adopt ASU
2009-12 effective fourth quarter of 2009.
 
 ASU
2009-13 “Multiple-Deliverable Revenue Arrangements” (ASU 2009-13)
 
 In
October 2009, the FASB issued ASU 2009-13 updating the “Revenue Recognition”
accounting guidance by providing criteria for separating consideration in
multiple-deliverable arrangements.  It establishes a selling price
hierarchy for determining the price of a deliverable and expands the disclosures
related to a vendor’s multiple-deliverable revenue arrangements.
 
 The new
accounting guidance is effective prospectively for arrangements entered into or
materially modified in years beginning after June 15, 2010.  Although
management has not completed an analysis, management does not expect this update
to have a material impact on the financial statements.  The Registrant
Subsidiaries will adopt ASU 2009-13 effective January 1, 2011.
 
 SFAS
166 “Accounting for Transfers of Financial Assets” (SFAS 166)
 
 In June
2009, the FASB issued SFAS 166 clarifying when a transfer of a financial asset
should be recorded as a sale.  The standard defines participating
interest to establish specific conditions for a sale of a portion of a financial
asset.  This standard must be applied to all transfers after the
effective date.
 
 SFAS 166
is effective for interim and annual reporting in fiscal years beginning after
November 15, 2009.  Early adoption is
prohibited.  Management continues to review the impact of this
standard.  The Registrant Subsidiaries will adopt SFAS 166 effective
January 1, 2010.  SFAS 166 is included in the “Transfers and
Servicing” accounting guidance.
  SFAS
167 “Amendments to FASB Interpretation No. 46(R)” (SFAS 167)
 
 In June
2009, the FASB issued SFAS 167 amending the analysis an entity must perform to
determine if it has a controlling interest in a variable interest entity
(VIE).  This new guidance provides that the primary beneficiary of a
VIE must have both:
 
 ·
              The
      power to direct the activities of the VIE that most significantly impact
      the VIE’s economic performance.·
              The
      obligation to absorb the losses of the entity that could potentially be
      significant to the VIE or the right to receive benefits from the entity
      that could potentially be significant to the
  VIE.
 
 The
standard also requires separate presentation on the face of the statement of
financial position for assets which can only be used to settle obligations of a
consolidated VIE and liabilities for which creditors do not have recourse to the
general credit of the primary beneficiary.
 
 SFAS 167
is effective for interim and annual reporting in fiscal years beginning after
November 15, 2009.  Early adoption is
prohibited.  Management continues to review the impact of the changes
in the consolidation guidance on the financial statements.  This
standard will increase disclosure requirements related to transactions with VIEs
and may change the presentation of consolidated VIE’s assets and liabilities on
the Registrant Subsidiaries’ balance sheets.  The Registrant
Subsidiaries will adopt SFAS 167 effective January 1, 2010.  SFAS 167
is included in the “Consolidation” accounting guidance.
 
 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 policies 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 132R-1 is included in the “Compensation – Retirement
Benefits” accounting guidance.
 
 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,
financial instruments, emission allowances, leases, insurance, hedge accounting,
discontinued operations and income tax.  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.
 
 EXTRAORDINARY
ITEM
 
 SWEPCo
Texas Restructuring
 
 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 May 2009, the governor of Texas signed a bill related to
SWEPCo’s SPP area of Texas that requires continued cost of service regulation
until certain stages have been completed and approved by the PUCT such that fair
competition is available to all Texas retail customer classes.  Based
upon the signing of the bill, SWEPCo re-applied “Regulated Operations”
accounting guidance for the generation portion of SWEPCo’s Texas retail
jurisdiction effective second quarter of 2009.  Management believes
that a switch to competition in the SPP area of Texas will not
occur.  The reapplication of “Regulated Operations” accounting
guidance resulted in an $8 million ($5 million, net of tax) extraordinary
loss.
  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 March
2009, the PUCO issued an order, which was amended by a rehearing entry in July
2009, that modified and approved CSPCo’s and OPCo’s ESPs that established
standard service offer rates.  The ESPs will be in effect through
2011.  The ESP order authorized revenue increases during the ESP
period and capped the overall revenue increases for CSPCo to 7% in 2009, 6% in
2010 and 6% in 2011 and for OPCo to 8% in 2009, 7% in 2010 and 8% in
2011.  CSPCo and OPCo implemented rates for the April 2009 billing
cycle.  In its July 2009 rehearing entry, the PUCO required CSPCo and
OPCo to reduce rates implemented in April 2009 by $22 million and $27 million,
respectively, on an annualized basis.  CSPCo and OPCo are collecting
the 2009 annualized revenue increase over the last nine months of
2009.
 
 The order
provides a FAC for the three-year period of the ESP.  The FAC increase
will be phased in to avoid having the resultant rate increases exceed 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 three-year ESP period will be recovered through a non-bypassable
surcharge over the period 2012 through 2018.
 
 The FAC
deferrals at September 30, 2009 were $36 million and $238 million for CSPCo and
OPCo, respectively, inclusive of carrying charges at the weighted average cost
of capital.  In the July 2009 rehearing order, the PUCO once again
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.
 
 The
PUCO’s July 2009 rehearing entry among other things reversed the prior
authorization to recover the cost of CSPCo’s recently acquired Waterford and
Darby Plants.  In July 2009, CSPCo filed an application for rehearing
with the PUCO seeking authorization to sell or transfer the Waterford and Darby
Plants.
 
 The PUCO
also addressed several additional matters in the ESP order, which are described
below:
 
 ·
              CSPCo
      should attempt to mitigate the costs of its gridSMART advanced metering
      proposal that will affect portions of its service territory by seeking
      funds under the American Recovery and Reinvestment Act of
      2009.  As a result, a rider was established to recover $32
      million related to gridSMART during the three-year ESP
      period.  In August 2009, CSPCo filed for $75 million in federal
      grant funding under the American Recovery and Reinvestment Act of
      2009.
  ·
              CSPCo
      and OPCo can recover their 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.
 
 ·
              CSPCo’s
      and OPCo’s Provider of Last Resort revenues were increased by $97 million
      and $55 million, respectively, to compensate for the risk of customers
      changing electric suppliers during the ESP
  period.
 
 ·
              CSPCo
      and OPCo must fund a combined minimum of $15 million in costs over the ESP
      period for low-income, at-risk customer programs.  In March
      2009, this funding obligation was recognized as a liability and charged to
      Other Operation expense.  At September 30, 2009, CSPCo’s and
      OPCo’s remaining liability balances were $6 million
  each.
 
 In June
2009, intervenors filed a motion in the ESP proceeding with the PUCO requesting
CSPCo and OPCo to refund deferrals allegedly collected by CSPCo and OPCo which
were created by the PUCO’s approval of a temporary special arrangement between
CSPCo, OPCo and Ormet, a large industrial customer.  In addition, the
intervenors requested that the PUCO prevent CSPCo and OPCo from collecting these
revenues in the future.  In June 2009, CSPCo and OPCo filed a response
noting that the difference in the amount deferred between the PUCO-determined
market price for 2008 and the rate paid by Ormet was not collected, but instead
was deferred, with PUCO authorization, as a regulatory asset for future
recovery.  In the rehearing entry, the PUCO did not order an
adjustment to rates based on this issue.  See “Ormet” section
below.
 
 In August
2009, an intervenor filed for rehearing requesting, among other things, that the
PUCO order CSPCo and OPCo to cease and desist from charging ESP rates, to revert
to the rate stabilization plan rates and to compel a refund, including interest,
of the amounts collected by CSPCo and OPCo.  CSPCo and OPCo filed a
response stating the rates being charged by CSPCo and OPCo have been authorized
by the PUCO and there was no basis for precluding CSPCo and OPCo from continuing
to charge those rates.  In September 2009, certain intervenors filed
appeals of the March 2009 order and the July 2009 rehearing entry with the
Supreme Court of Ohio.  One of the intervenors, the Ohio Consumers’
Counsel, has asked the court to stay, pending the outcome of its appeal, a
portion of the authorized ESP rates which the Ohio Consumers’ Counsel
characterizes as being retroactive.  In October 2009, the Supreme
Court of Ohio denied the Ohio Consumers' Counsel's request for a stay and
granted motions to dismiss both appeals.
 In
September 2009, CSPCo and OPCo filed their initial quarterly FAC filing with the
PUCO and adjusted their estimated phase-in deferrals to the amounts shown in the
filing, which was a decrease in the FAC deferral of $6 million for CSPCo and an
increase in the FAC deferral of $17 million for OPCo.  An order
approving the FAC 2009 filings will not be issued until a financial audit and
prudency review is performed by independent third parties and reviewed by the
PUCO.
 
 In
October 2009, the PUCO convened a workshop to begin to determine the methodology
for the Significantly Excessive Earnings Test (SEET).  The SEET
requires the PUCO to determine, following the end of each year of the ESP, if
rate adjustments included in the ESP resulted in significantly excessive
earnings.  This will be determined by measuring whether the utility’s
earned return on common equity is significantly in excess of the return on
common equity that was earned during the same period by publicly traded
companies, including utilities, which have comparable business and financial
risk.  In the March 2009 ESP order, the PUCO determined that
off-system sales margins and FAC deferral phase-in credits should be excluded
from the SEET methodology.  However, the July 2009 PUCO rehearing
entry deferred those issues to the SEET workshop.  If the rate
adjustments, in the aggregate, result in significantly excessive earnings, the
excess amount would 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 workshop is completed, the PUCO issues SEET guidelines, a
SEET filing is made by CSPCo and OPCo in 2010 and the PUCO issues an order
thereon. The SEET workshop will also determine whether CSPCo’s and OPCo’s
earnings will be measured on an individual company basis or on a combined
CSPCo/OPCo basis.
 
 In
October 2009, an intervenor filed a complaint for writ of prohibition with the
Supreme Court of Ohio requesting the Court to prohibit CSPCo and OPCo from
billing and collecting any ESP rate increases that the PUCO authorized as the
intervenor believes the PUCO's statutory jurisdiction over CSPCo's and OPCo's
ESP application ended on December 28, 2008, which was 150 days after the filing
of the ESP applications.  CSPCo and OPCo plan on filing a response in
opposition to the complaint for writ of prohibition.
 
 Management
is unable to predict the outcome of the various ongoing proceedings and
litigation discussed above including the SEET, the FAC filing review and the
various appeals to the Supreme Court of Ohio relating to the ESP
order.  If these proceedings result in adverse rulings, it could have
an adverse effect on future net income and cash flows.
  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 June
2006 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 jurisdictions 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 response 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 required CSPCo and OPCo to 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 CSPCo and
OPCo believe there exist real statutory barriers to the construction of any new
base load generation in Ohio, including the IGCC plant.  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.
 
 In
September 2009, an intervenor filed a motion with the PUCO requesting that CSPCo
and OPCo be required to refund all pre-construction cost revenue to Ohio
ratepayers with interest or show cause as to why the amount for the proposed
IGCC plant should not be immediately refunded based upon the PUCO’s June 2006
order.  The intervenor contends that the most recent integrated
resource plan filed for the AEP East companies’ zone does not reflect the
construction of an IGCC plant.  In October 2009, CSPCo and OPCo filed
a response opposing the intervenor’s request to refund revenues collected
stating that an integrated resource plan is a planning tool and does not prevent
CSPCo and OPCo from meeting the PUCO’s five-year time limit.
 
 Management
continues to pursue the consideration of construction of an IGCC plant in Ohio
although CSPCo and OPCo will not start construction of an IGCC plant until the
statutory barriers are addressed and sufficient assurance of regulatory cost
recovery exists.Management cannot
predict the outcome of the cost recovery litigation concerning the Ohio IGCC
plant or what effect, if any, the litigation will have on future net income and
cash flows.  However, if CSPCo and OPCo were required to refund the
$24 million collected and those costs were not recoverable in another
jurisdiction, it would have an adverse effect on future net income and cash
flows.
 
 Ormet
– Affecting CSPCo and OPCo
 
 In
December 2008, CSPCo, OPCo and Ormet, a large aluminum company currently
operating at a reduced load of approximately 330 MW (Ormet operated at an
approximate 500 MW load in 2008), filed an application with the PUCO for
approval of an interim arrangement governing the provision of generation service
to Ormet.  The interim arrangement was effective January 1, 2009 and
expired in September 2009 upon the filing of a new PUCO-approved long-term power
contract between Ormet and CSPCo/OPCo that was effective prospectively through
2018.  Under the interim arrangement, Ormet would pay the then-current
applicable generation tariff rates and riders and CSPCo and OPCo would 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 new FAC phased-in mechanism that 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 the PUCO’s July 2009 order discussed below, CSPCo and
OPCo were directed to file an application to recover the appropriate amounts of
the deferrals under the interim agreement and for the remainder of
2009.
 
 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 for the differential in the approved market price of
$53.03 versus the rate paid by Ormet until the effective date of the 2009-2018
power contract.
 
 In May
2009, intervenors filed a motion with the PUCO that contends CSPCo and OPCo
should be charging Ormet the new ESP rate and that no additional deferrals
between the approved market price and the rate paid by Ormet should be
calculated and recovered through the FAC since Ormet will be paying the new ESP
rate.  In May 2009, CSPCo and OPCo filed a Memorandum Contra
recommending the PUCO deny the motion to cease additional Ormet FAC
under-recovery deferrals.  In June 2009, intervenors filed a motion
with the PUCO related to Ormet in the ESP proceeding.  See “Ohio
Electric Security Plan Filings” section above.
 
 In July
2009, the PUCO approved Ormet’s application for a power contract through 2018
with several modifications.  As modified by the PUCO, rates billed to
Ormet by CSPCo and OPCo for the balance of 2009 would reflect an annual average
rate using $38 per MWH for the periods Ormet was in full production and $35 and
$34 per MWH at certain curtailed production levels.  The $35 and $34
MWH rates are contingent upon Ormet maintaining its employment levels at 900
employees for 2009.  The PUCO authorized CSPCo and OPCo to record
under-recovery deferrals computed as revenue foregone (the difference between
CSPCo’s and OPCo’s ESP tariff rates and the rate paid by Ormet) created by the
blended rate for the remainder of 2009.  For 2010 through 2018, the
PUCO approved the linkage of Ormet’s rate to the price of aluminum but modified
the agreement to include a maximum electric rate reduction for Ormet that
declines over time to zero in 2018 and a maximum amount of under-recovery
deferrals that ratepayers will be expected to pay via a rider in any given
year.  For 2010 and 2011, the PUCO set the maximum rate discount at
$60 million and the maximum amount of the rate discount other ratepayers should
pay at $54 million.  To the extent the under-recovery deferrals exceed
the amount collectible from ratepayers, the difference can be deferred, with a
long-term debt carrying charge, for future recovery.  In addition,
this rate is based upon Ormet maintaining at least 650 employees.  For
every 50 employees below that level, Ormet’s maximum electric rate reduction
will be lowered.  The new long-term power contract became effective in
September 2009 at which point CSPCo and OPCo began deferring as a regulatory
asset the unrecovered amounts less Provider of Last Resort (POLR)
charges.  Rehearing applications filed by CSPCo, OPCo and intervenors
were granted by the PUCO.  In September 2009 on rehearing, the PUCO
ordered that CSPCo and OPCo must credit all Ormet related POLR charges against
the under-recovery amounts that CSPCo and OPCo would otherwise
recover.  As of September 30, 2009, CSPCo and OPCo had $32 million and
$34 million, respectively, deferred as regulatory assets related to Ormet
under-recovery which is included in CSPCo’s and OPCo’s FAC phase-in deferral
balance.
 
 Ormet
indicated it will operate at reduced operations at least through the end of
2009.  Management cannot predict Ormet’s on-going electric consumption
levels, the resultant prices Ormet will pay and/or the amount that CSPCo and
OPCo will defer for future recovery from other customers.  If CSPCo
and OPCo are not ultimately permitted to recover their under-recovery deferrals,
it would have an adverse effect on future net income and cash
flows.
 
 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, the PUCO
approved these regulatory assets along with a long-term debt only carrying cost
on these regulatory assets.  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 filings.  At September 30, 2009, CSPCo
and OPCo have accrued for future recovery regulatory assets of $18 million and
$10 million, respectively, including the approved long-term debt only carrying
costs.  If CSPCo and OPCo are not ultimately permitted to recover
their storm damage deferrals, it would have an adverse effect on future net
income and cash flows.
 
 Texas Rate
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 May 2009, the governor of Texas signed a bill related to
SWEPCo’s SPP area of Texas that requires continued cost of service regulation
until certain stages have been completed and approved by the PUCT such that fair
competition is available to all Texas retail customer classes.  Based
upon the signing of the bill, SWEPCo re-applied “Regulated Operations”
accounting guidance for the generation portion of SWEPCo’s Texas retail
jurisdiction in the second quarter of 2009.  Management believes that
a switch to competition in the SPP area of Texas will not occur.  The
reapplication of “Regulated Operations” accounting guidance resulted in an $8
million ($5 million, net of tax) extraordinary loss.
 
 In
addition, effective April 2009, the generation portion of SWEPCo’s Texas retail
jurisdiction began accruing AFUDC (debt and equity return) instead of
capitalized interest on its eligible construction balances including the Stall
Unit and the Turk Plant.  The accrual of AFUDC increased September
year to date 2009 net income by approximately $8 million using the last
PUCT-approved return on equity rate.
 
 2009
Texas Base Rate Filing – Affecting SWEPCo
 
 In August
2009, SWEPCo filed a base rate case with the PUCT to increase non-fuel base
rates by approximately $75 million annually based on a requested return on
common equity of 11.5%. The filing includes a base rate increase of $27 million,
a vegetation management rider for $16 million and financing cost riders of $32
million related to the construction of the Stall Unit and Turk
Plant.  In addition, the net merger savings credit of $7 million will
be removed from rates and depreciation expense is proposed to decrease by $17
million.  The proposed filing would increase SWEPCo’s annual pretax
income by approximately $51 million.
 
 The
proposed Stall Unit rider would recover a return on the Stall Unit investment
while the Stall Unit is under construction and continuing after it is placed in
service plus recovery of depreciation when it is placed in service in
2010.  The proposed Turk Plant rider would recover a return on the
Turk Plant investment and will continue until such time that the Turk Plant is
included in base rates.  Both riders would terminate when base rates
are increased to include recovery of the Turk Plant’s and the Stall Unit’s
respective plant investments, plus a return thereon, and a recovery of their
related operating expenses.  Management is unable to predict the
outcome of this filing.
 
 Stall
Unit – Affecting SWEPCo
 
 See
“Stall Unit” section within “Louisiana Rate Matters” for
disclosure.
 
 Turk
Plant – Affecting SWEPCo
 
 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 in-service E&R
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 filed an
application, in May 2009, to recover $102 million of unrecovered 2008
incremental deferred E&R costs plus its 2008 equity costs based on a 12.5%
return on equity on its E&R capital investments. However, APCo deferred and
recognized income under the E&R legislation based on a return on equity of
10.1%, which was the Virginia SCC staff’s recommendation in the prior E&R
case.  In October 2009, a stipulation agreement was reached between
the parties and filed with the Virginia SCC addressing all matters other than
rate design and customer class allocation issues.  The stipulation
agreement allows APCo to recover Virginia incremental E&R costs of $90
million, representing costs deferred during 2008 plus unrecognized 2008 equity
costs, using a 10.6% return on equity for collection in 2010.  This
will result in an immaterial adjustment which will be recorded in the fourth
quarter of 2009.  The Virginia SCC is expected to approve the
stipulation agreement in the fourth quarter of 2009.
 
 As of
September 30, 2009, APCo had $88 million of deferred Virginia incremental
E&R costs excluding $17 million of unrecognized equity carrying
costs.  The $88 million consists of $6 million of over-recovered costs
collected under the 2008 surcharge, $14 million approved by the Virginia SCC
related to the 2009 surcharge and $80 million, representing costs deferred
during 2008, which were included in the May 2009 E&R filing for collection
in 2010.
 
 Mountaineer
Carbon Capture and Storage 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, and the Electric
Power Research Institute are participating in the project and providing some
funding to offset APCo's costs.  APCo’s combined estimated cost for
its necessary storage facilities and its share of the CO2 capture
demonstration facility is $74 million.  In May 2009, the West Virginia
Department of Environmental Protection issued a permit to inject CO2 that
requires, among other items, that APCo monitor the wells for at least 20 years
following the cessation of CO2
injection.  In September 2009, the capture portion of the project was
placed into service and in October 2009, APCo started injecting CO2 in
underground storage.  The injection of CO2 required
the recordation of an asset retirement obligation and an offsetting regulatory
asset at its estimated net present value of $36 million in October
2009.  Through September 30, 2009, APCo incurred $71 million in
capitalized project costs which are included in Regulatory Assets.
 
 APCo
currently earns a return on the Virginia portion of the capitalized project
costs incurred through June 30, 2008, as a result of a base rate case settlement
approved by the Virginia SCC in November 2008.  In APCo’s July 2009
Virginia base rate filing, APCo requested recovery of and a return on the
estimated increased Virginia jurisdictional share of its CO2 capture
and storage project costs including the related asset retirement obligation
expenses.  See the “Virginia Base Rate Filing” section
below.  Based on the favorable treatment related to the CO2capture
demonstration facility in APCo’s last Virginia base rate case, APCo is deferring
its carbon capture expense as a regulatory asset for future
recovery.  APCo plans to seek recovery of the West Virginia
jurisdictional costs in its next West Virginia base rate filing which is
expected to be filed in the first quarter of 2010.  If the deferred
project costs are disallowed in future Virginia or West Virginia rate
proceedings, it could have an adverse effect on future net income and cash
flows.
 
 Virginia
Base Rate Filing – Affecting APCo
 
 The 2007
amendments to Virginia’s electric utility restructuring law required that each
investor-owned utility, such as APCo, file a base rate case with the Virginia
SCC in 2009 in which the Virginia SCC will determine fair rates of return on
common equity (ROE) for the generation and distribution services of the
utility.  As a result, in July 2009, APCo filed a base rate case with
the Virginia SCC requesting an increase in the generation and distribution
portions of its base rates of $169 million annually based on a 2008 test year,
as adjusted, and a 13.35% ROE inclusive of a requested 0.85% ROE performance
incentive increase as permitted by law.  The recovery of APCo’s
transmission service costs in Virginia was requested in a separate and
simultaneous transmission rate adjustment clause filing.  See the
“Rate Adjustment Clauses” section below.  In August 2009, APCo filed
supplemental schedules and testimony that decreased the requested annual revenue
increase to $154 million which reflected a recent Virginia SCC order in an
unaffiliated utility’s base rate case concerning the appropriate capital
structure to be used in the determination of the revenue
requirement.  The new generation and distribution base rates will
become effective, subject to refund, in December 2009.
 
 Rate
Adjustment Clauses – Affecting APCo
 
 In 2007,
the Virginia law governing the regulation of electric utility service was
amended to, among other items, provide for rate adjustment clauses (RAC)
beginning in January 2009 for the timely and current recovery of costs of (a)
transmission services billed by an RTO, (b) demand side management and energy
efficiency programs, (c) renewable energy programs, (d) environmental compliance
projects and (e) new generation facilities including major unit
modifications.  In July 2009, APCo filed for approval of a
transmission RAC simultaneous with the 2009 base rate case filing in which the
Virginia jurisdictional share of transmission costs was requested for recovery
through the RAC instead of through base rates.  The transmission RAC
filing requested an initial $94 million annual revenue requirement representing
an annual increase of $24 million above the current level embedded in APCo’s
Virginia base rates.  APCo requested to implement the transmission RAC
concurrently with the new base rates in December 2009.  See the
“Virginia Base Rate Filing” section above.  In October 2009, the
Virginia SCC approved the stipulation agreement providing for an annual
incremental revenue increase in transmission rates of $22 million excluding $2
million of reasonable and prudent PJM administrative costs that may be recovered
in base rates.
 
 APCo
plans to file for approval of an environmental RAC no later than the first
quarter of 2010 to recover any unrecovered environmental costs incurred after
December 2008.  APCo also plans to file for approval of a renewable
energy RAC before the end of the first quarter of 2010 to recover costs
associated with APCo’s wind power purchase agreements.  In accordance
with Virginia law, APCo is deferring any incremental transmission and
environmental costs incurred after December 2008 and any renewable energy costs
incurred after August 2009 which are not being recovered in current
revenues.  As of September 30, 2009, APCo has deferred for future
recovery $17 million of environmental costs (excluding $3 million of
unrecognized equity carrying costs), $14 million of transmission costs and $1
million of renewable energy costs.  Management is evaluating whether
to make other RAC filings at this time.  If the Virginia SCC were to
disallow a portion of APCo’s deferred RAC costs, it would have an adverse effect
on future net income and cash flows.
 
 Virginia
Fuel Factor Proceeding – Affecting APCo
 
 In May
2009, APCo filed an application with the Virginia SCC to increase its fuel
adjustment charge by approximately $227 million from July 2009 through August
2010.  The $227 million proposed increase related to a $104 million
projected under-recovery balance of fuel costs as of June 2009 and $123 million
of projected fuel costs for the period July 2009 through August
2010.  APCo’s actual under-recovered fuel balance at June 2009 was $93
million.  Due to the significance of the estimated required increase
in fuel rates, APCo’s application proposed an alternative method of collection
of actual incurred fuel costs.  The proposed alternative would allow
APCo to recover 100% of the $104 million prior period under-recovery deferral
and 50% of the $123 million increase from July 2009 through August 2010 with
recovery of any remaining actual under-recovered fuel costs in APCo’s next fuel
factor proceeding from September 2010 through August 2011.  In May
2009, the Virginia SCC ordered that neither of APCo’s proposed fuel factors
shall become effective, pending further review by the Virginia
SCC.  In August 2009, the Virginia SCC issued an order which provided
for a $130 million fuel revenue increase, effective August 2009.  The
reduction in revenues from the requested amount recognizes a lower than
projected under-recovery balance and a lower level of projected fuel costs to be
recovered through the approved fuel factor.  Any fuel under-recovery
due to the lower level of projected fuel costs should be deferred as a
regulatory asset for future recovery under the FAC true-up mechanism and
recoverable, if necessary, either in APCo’s next fuel factor proceeding for the
period September 2010 through August 2011 or through other statutory
mechanisms.
 
 APCo’s
Filings for an IGCC Plant – Affecting APCo
 
 See
“APCo’s Filings for an IGCC Plant” section within “West Virginia Rate Matters”
for disclosure.
  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 to increase the ENEC rates
by approximately $398 million for incremental fuel, purchased power, other
energy related costs and environmental compliance project costs 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 and the significance of the projected required increase.  The
proposed modified ENEC mechanism provides that the ENEC rate increase be phased
in with unrecovered amounts deferred for future recovery over a five-year period
beginning in July 2009, 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 as well as the phase-in
deferrals.  The proposed modified ENEC mechanism also provides that to
the extent the phase-in deferrals exceed the deferred amounts that would have
otherwise existed under the traditional ENEC mechanism, the phase-in deferrals
are subject to a carrying charge based upon APCo’s weighted average cost of
capital.  As proposed, the modified ENEC mechanism would produce three
annual increases, based upon projected fuel costs and including carrying
charges, of $170 million, $149 million and $155 million, effective July 2009,
2010 and 2011, respectively.
 
 In May
2009, various intervenors submitted testimony supporting adjustments to APCo’s
actual and projected ENEC costs.  The intervenors also proposed
alternative rate phase-in plans ranging from three to five
years.  Specifically, the WVPSC staff and the West Virginia Consumer
Advocate recommended an increase of $338 million and $294 million, respectively,
with $119 million and $117 million, respectively, being collected during the
first year and suggested that the remaining rate increases for future years be
determined in subsequent ENEC filings.  In June 2009, APCo filed
rebuttal testimony.  In the rebuttal testimony, APCo accepted certain
intervenor adjustments to the forecasted ENEC costs and reduced the requested
increase to $358 million with a proposed first-year increase of $144
million.  The intervenors’ forecast adjustments would not impact
earnings since the ENEC mechanism would continue to true-up to actual
costs.  The primary difference between the intervenors’ $117 million
first-year increase and APCo’s $144 million first-year increase is the
intervenors’ proposed disallowance of up to $36 million of actual and projected
coal costs.
 
 In
September 2009, the WVPSC issued an order granting a $320 million increase to be
phased in over the next four years with a first-year increase of $112
million.  As of September 30, 2009, APCo’s ENEC under-recovery balance
was $255 million which is included in Regulatory Assets.  The WVPSC
also approved a fixed annual carrying cost rate of 4%, effective October 1,
2009, to be applied to the incremental deferred regulatory asset balance that
will result from the phase-in plan.  The order disallowed an
immaterial amount of deferred ENEC costs which was recognized in September
2009.  It also lowered annual coal cost projections by $27 million and
deferred recovery of unrecovered ENEC deferrals related to price increases on
certain renegotiated coal contracts.  The WVPSC indicated that it
would review the prudency of these additional costs in the next ENEC
proceeding.  As of September 30, 2009, APCo has deferred $13 million
of unrecovered coal costs on the renegotiated coal contracts which is included
in APCo’s $255 million ENEC under-recovery regulatory asset and has an
additional $5 million in purchased fuel costs on the renegotiated coal contracts
which is recorded in Fuel on the Condensed Consolidated Balance
Sheets.  Although management believes the portion of its deferred ENEC
under-recovery balance attributable to renegotiated coal contracts is probable
of recovery, if the WVPSC were to disallow a portion of APCo’s deferred ENEC
costs including any costs incurred in the future related to the renegotiated
coal contracts, it could 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 with 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 the 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 with the WVPSC.  In September 2009, the WVPSC
removed the IGCC case as an active case from its docket and indicated that the
conditional CPCN granted in 2008 must be reconsidered if and when APCo proceeds
forward with the IGCC plant.
 
 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
September 30, 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 applicable to its Virginia jurisdiction.
 
 Although
management continues to pursue consideration of 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, which if not recoverable, would have an adverse effect on future net
income and cash flows.
 
 Mountaineer
Carbon Capture and Storage Project – Affecting APCo
 
 See
“Mountaineer Carbon Capture and Storage 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 based on
a return on equity of 11.5%.  The base rate increase included a $69
million annual reduction in rates due to an approved 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 its 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 the depreciation rate reduction in the development of
an agreed to revenue increase of $44 million, which included a $22 million
increase in base rates based on an authorized return on equity of 10.5% and a
$22 million initial increase in tracker rates for incremental PJM, net emission
allowance and demand side management (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
Plant.
 
 In March
2009, the IURC modified and approved the settlement agreement that provides for
an annual increase in revenues of $42 million.  The $42 million
increase included a $19 million increase in base rates, net of the depreciation
rate reduction and a $23 million increase in tracker revenue.  The
IURC order modified the settlement agreement by removing from base rates the
recovery of DSM costs, establishing a tracker with an initial zero amount for
DSM costs, requiring I&M to collaborate with other affected parties
regarding the design and recovery of future I&M DSM programs, adjusting the
sharing of off-system sales margins to 50% above $37.5 million which it included
in base rates and approving the recovery of $7 million of previously expensed
NSR and OPEB costs which favorably affected 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. The new rates were implemented in March
2009.
 
 Rockport
and Tanners Creek Plants Environmental Facilities – 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
requested 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.  The petition requested to depreciate the ACI systems
over an accelerated 10-year period and the SNCR systems over the 11-year
remaining useful life of the Tanners Creek generating units.
 
 I&M’s
petition also requested the IURC to approve a rate adjustment mechanism for
unrecovered carrying costs during the remaining construction period of these
environmental facilities and a return on investment, depreciation expense and
operation and maintenance costs, including consumables and new emission
allowance costs, once the facilities are placed in service.  I&M
also requested the IURC to authorize the deferral of the remaining construction
period carrying costs and any in-service cost of service for these facilities
until such costs can be recovered in the requested rate adjustment
mechanism.  Through September 30, 2009, I&M incurred $12 million
and $12 million in capitalized facilities cost related to the Rockport and
Tanners Creek Plants, respectively, which are included in
CWIP.  Subsequent to the filing of this petition, the Indiana base
rate order included recovery of emission allowance costs.  Therefore,
that portion of the emission allowances cost for the subject facilities will not
be recovered in this requested rate adjustment mechanism.
 
 In May
2009, a settlement agreement (settlement) was filed with the IURC recommending
approval of a CPCN and a rider to recover a weighted average cost of capital on
I&M’s investment in the SNCR system and the ACI system at December 31, 2008,
plus future depreciation and operation and maintenance costs.  The
settlement will allow I&M to file subsequent requests in six month intervals
to update the rider for additional investments in the SNCR systems and the ACI
systems and for true-ups of the rider revenues to actual costs.  In
June 2009, the IURC approved the settlement which will result in an annualized
increase in rates of $8 million effective August 1, 2009.
 
 Indiana
Fuel Clause Filing (Cook Plant Unit 1 Fire and Shutdown) – 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 the period of April through
September 2009.  The filing included an under-recovery for the period
ended November 2008, mainly as a result of deferred under-recovered fuel costs,
the shutdown of the Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused
by blade failure, which resulted in a fire and a projection for the future
period of fuel costs increases including Unit 1 shutdown replacement power
costs.  See “Cook Plant Unit 1 Fire and Shutdown” section of Note
4.  The filing also included an adjustment, beginning coincident with
the receipt of accidental outage insurance proceeds in mid-December 2008, to
eliminate the incremental fuel cost of replacement power post mid-December 2008
with a portion of the insurance proceeds from the accidental outage
policy.  I&M reached an agreement in February 2009 with
intervenors, which was approved by the IURC in March 2009, to collect the prior
period under-recovery deferral balance over twelve months instead of over six
months as proposed.  Under the agreement, the fuel factor was placed
into effect, subject to refund, and a subdocket was established to consider
issues relating to the Unit 1 shutdown, the use of the insurance proceeds and
I&M’s fuel procurement practices.  The order also provided for the
shutdown issues to be resolved subsequent to the date Unit 1 returns to service,
which if temporary repairs are successful, could occur as early as the fourth
quarter of 2009.
 
 Consistent
with the March 2009 IURC order, I&M made its semi-annual fuel filing in July
2009 requesting an increase of approximately $4 million for the period October
2009 through March 2010.  The projected fuel costs for the period
included the second half of the under-recovered deferral balance approved in the
March 2009 order plus recovery of an additional $12 million under-recovered
deferral balance from the reconciliation period of December 2008 through May
2009.
  In August
2009, an intervenor filed testimony proposing that I&M should refund
approximately $11 million through the fuel adjustment clause, which is the
intervenor’s estimate of the Indiana retail jurisdictional portion of the
additional fuel cost during the accidental outage insurance policy deductible
period, which is the period from the date of the incident in September 2008 to
when the insurance proceeds began in December 2008.  In August 2009,
I&M and intervenors filed a settlement agreement with the IURC that included
the recovery of the $12 million under-recovered deferral balance, subject to
refund, over twelve months instead of over six months as originally proposed and
an agreement to delay all Unit 1 outage issues in this filing until after the
unit is returned to service.
 
 Management
cannot predict the outcome of the pending proceedings, including the treatment
of the outage insurance proceeds, and whether any fuel clause revenues or
insurance proceeds will have to be refunded which could adversely affect future
net income and cash flows.
 
 Michigan Rate
Matters
  2008
Power Supply Cost Recovery (PSCR) Reconciliation (Cook Plant Unit 1 Fire and
Shutdown) – Affecting I&M
   In March
2009, I&M filed with the Michigan Public Service Commission (MPSC) its 2008
PSCR reconciliation.  The filing also included an adjustment to reduce
the incremental fuel cost of replacement power due to the Cook Plant Unit 1
outage with a portion of the accidental insurance proceeds from the Cook Plant
Unit 1 outage policy, which began in mid-December 2008.  See “Cook
Plant Unit 1 Fire and Shutdown” section of Note 4.  In May 2009, the
MPSC set a procedural schedule for testimony and hearings to be held in the
fourth quarter of 2009.  A final order is anticipated in the first
quarter of 2010.  Management is unable to predict the outcome of this
proceeding and whether it will have an adverse 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 two issues.  The first issue relates to the allocation of
off-system sales margins (OSS) among the AEP operating companies in accordance
with a FERC-approved allocation agreement.  In June 2008, the Oklahoma
Industrial Energy Consumers (OIEC) appealed the ALJ recommendations that
concluded the FERC and not the OCC had jurisdiction over this
matter.  In August 2008, the OCC filed a complaint with the FERC
concerning this allocation of OSS issue.  In December 2008, under an
adverse FERC ruling, PSO recorded a regulatory liability to return the
reallocated OSS to customers.  Effective with the March 2009 billing
cycle, PSO began refunding the additional reallocated OSS to its
customers.  See “Allocation of Off-system Sales Margins” section
within “FERC Rate Matters.”
 
 The
second issue concerns a 2002 under-recovery of $42 million of PSO 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 the June 2008 appeal by the OIEC of the ALJ
recommendations, the OIEC contended that PSO should not have collected the $42
million without specific OCC approval nor collected the $42 million before the
OSS allocation issue was resolved.  As such, the OIEC contends that
the OCC could and should require PSO to refund the $42 million it collected
through its fuel clause.  In August 2008, the OCC heard the OIEC
appeal and a decision is pending.  Although the OSS allocation issue
has been resolved at the FERC, if the OCC were to order PSO to make an
additional refund for all or a part of the $42 million, it would have an adverse
effect on future net income and cash flows.
 
 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.  In August 2009, a
joint stipulation and settlement agreement (settlement) was filed with the OCC
requesting the OCC to issue an order accepting the fuel adjustment clause for
2007 and find that PSO’s fuel procurement practices, policies and decisions were
prudent.  In September 2009, the OCC issued a final order approving
the settlement.
 
 2008
Oklahoma Base Rate Filing Appeal – 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.  At the
time of the filing, PSO was recovering $16 million a year for 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 terminates and PSO recovers 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 based on 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 provided for the deferral of $6
million of generation maintenance expenses to be recovered over a six-year
period.  The deferral was recorded in the first quarter of
2009.  PSO was given authority to record additional under/over
recovery deferrals for future 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.  During 2009, PSO
accrued a regulatory liability of approximately $1 million related to a delay in
installing gridSMART technologies as the OCC final order had included $2 million
of additional revenues for this purpose.
 
 PSO filed
an appeal with the Oklahoma Supreme Court challenging an adjustment contained
within the OCC final order to remove prepaid pension fund contributions from
rate base.  In February 2009, the Oklahoma Attorney General and
several intervenors also filed appeals with the Oklahoma Supreme Court raising
several rate case issues.  In July 2009, the Oklahoma Supreme Court
assigned the case to the Court of Civil Appeals.  If the Oklahoma
Attorney General or the intervenors’ appeals are successful, it could have an
adverse effect on future net income and cash flows.
 
 Oklahoma
Capital Reliability Rider Filing – Affecting PSO
 
 In August
2009, PSO filed an application with the OCC requesting a Capital Reliability
Rider (CRR) to recover depreciation, taxes and return on PSO’s net capital
investments for generation, transmission and distribution assets that have been
placed into service from September 1, 2008 to June 30, 2009.  If
approved, PSO would increase billings to customers during the first six months
of 2010 by $11 million related to the increase in revenue requirement and $9
million related to the lag between the investment cut-off of June 30, 2009 and
the date of the rider implementation of January 1, 2010.
 
 In
October 2009, all but two of the parties to the CRR filing agreed to a
stipulation that was filed with the OCC to collect no more than $30 million of
revenues under the CRR on an annual basis beginning January 2010 until PSO’s
next base rate order.  The CRR revenues are subject to refund with
interest pending the OCC’s audit.  The stipulation also provides for
an offsetting fuel revenue reduction via a modification to the fuel adjustment
factor of Oklahoma jurisdictional customers on an annual basis by $30 million
beginning January 2010 and refunds of certain over-recovered fuel balances
during the first quarter of 2010.  Finally, the stipulation requires
that PSO shall file a base rate case no later than July
2010.  Management is unable to predict the outcome of this
application.
 
 PSO
Purchase Power Agreement – Affecting PSO
 
 As a
result of the 2008 Request for Proposals following a December 2007 OCC order
that found PSO had a need for new base load generation by 2012, PSO and Exelon
Generation Company LLC, a subsidiary of Exelon Corporation, executed a long-term
purchase power agreement (PPA).  The PPA is for the annual purchase of
approximately 520 MW of electric generation from the 795 MW natural gas-fired
generating plant in Jenks, Oklahoma for a term of approximately ten years
beginning in June 2012.  In May 2009, an application seeking approval
was filed with the OCC.  In July 2009, OCC staff, the Independent
Evaluator and the Oklahoma Industrial Energy Consumers filed responsive
testimony in support of PSO’s proposed PPA with Exelon.  In August
2009, a settlement agreement was filed with the OCC.  In September
2009, the OCC approved the settlement agreement including the recovery of these
purchased power costs through a separate base load purchased power
rider.
 
 Louisiana Rate
Matters
 
 2008
Formula Rate Filing – Affecting SWEPCo
 
 In April
2008, SWEPCo filed its first formula rate filing under an approved three-year
formula rate plan (FRP).  SWEPCo requested an increase in its annual
Louisiana retail rates of $11 million to be effective in August 2008 in order to
earn the approved formula return on common equity of 10.565%.  In
August 2008, as provided by the FRP, SWEPCo implemented the FRP rates, subject
to refund.  During 2009, SWEPCo recorded a provision for refund of
approximately $1 million after reaching a settlement in principle with
intervenors.  SWEPCo is currently working with the settlement parties
to prepare a written agreement to be filed with the LPSC.
 
 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 effective in August 2009 pursuant to
the approved FRP.  SWEPCo implemented the FRP rate increase as filed
in August 2009, subject to refund.  In October 2009, consultants for
the LPSC objected to certain components of SWEPCo’s FRP
calculation.  The consultants also recommended refunding the SIA
through SWEPCo’s FRP.  See “Allocation of Off-system Sales Margins”
section within “FERC Rate Matters.”  SWEPCo will continue to work with
the LPSC regarding the issues raised in their objection.  SWEPCo
believes the rates as filed are in compliance with the FRP methodology
previously approved by the LPSC.  If the LPSC disagrees with SWEPCo,
it could result in material refunds.
 
 Stall
Unit – Affecting SWEPCo
 
 In May
2006, SWEPCo announced plans to build an intermediate load, 500 MW, natural
gas-fired, combustion turbine, combined cycle generating unit at its existing
Arsenal Hill Plant location in Shreveport, Louisiana to be named the Stall
Unit.  SWEPCo submitted the appropriate filings to the LPSC, the PUCT,
the APSC and the Louisiana Department of Environmental Quality to seek approvals
to construct the Stall Unit.  The Stall Unit is currently estimated to
cost $435 million, including $49 million of 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 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 including AFUDC and
excluding related transmission costs.  In October 2008, the LPSC
issued a final order effectively approving the ALJ recommendation.  In
March 2007, the PUCT approved SWEPCo’s request for a certificate of necessity
for the facility based on a prior cost estimate.  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.  In June 2009, the APSC approved the
construction of the unit with a series of conditions consistent with those
designated by the LPSC, including a requirement for an independent monitor and a
$445 million cost cap including AFUDC and excluding related transmission
costs.
 
 As of
September 30, 2009, SWEPCo has capitalized construction costs of $364 million,
including AFUDC, and has contractual construction commitments of an additional
$31million with
the total estimated cost to complete the unit at $435 million.  If the
final cost of the Stall Unit exceeds the $445 million cost cap, it could have an
adverse effect on net income and cash flows.  If for any other reason
SWEPCo cannot recover its capitalized costs, it would have an adverse effect on
future net income, cash flows and possibly financial condition.
 
 Temporary
Funding of Financing Costs during Construction – Affecting SWEPCo
 
 In
October 2009, SWEPCo made a filing with the LPSC requesting temporary recovery
of financing costs related to the Louisiana jurisdiction portion of the Turk
Plant.  In the filing, SWEPCo would recover over three years of
an estimated $105 million of construction financing costs related to SWEPCo’s
ongoing Turk generation construction program through its existing Fuel
Adjustment Rider.  If approved as requested, recovery would start in
January 2010 and continue through 2012 when the Turk Plant is scheduled to be
placed in service.  According to the filing, the amount of financing
costs collected during construction would be refunded to customers, including
interest at SWEPCo’s long-term debt rate, after the Turk Plant is in
service.  As filed, the refund would occur over a period not to exceed
five years.  Finally, SWEPCo requested that both the Turk Plant and
the Stall Unit be placed in rates via the formula rate plan without regulatory
lag.  Management cannot predict the outcome of this
filing.
 
 Louisiana
Fuel Adjustment Clause Audit – Affecting SWEPCo
 
 In July
2009, consultants for the LPSC issued their audit report of SWEPCo’s Louisiana
retail FAC.  Various recommendations were contained within the audit
report including two recommendations that might result in a financial impact
that could be material for SWEPCo.  The first recommendation is that
SWEPCo should provide the variable operation and maintenance and SO2 allowance
costs that were included in SWEPCo’s purchased power costs and that those costs
should be disallowed from 2003 until the effective date of the order in this
proceeding.  Management does not believe any variable operation and
maintenance and SO2 allowance
costs included in SWEPCo’s purchased power costs since 2003 would be
material.  The second recommendation is that the LPSC should
discontinue SWEPCo’s tiered sharing mechanism related to off-system sales
margins on a prospective basis.  In addition, the audit report
contained a recommendation that SWEPCo should reflect the SIA refunds as
reductions in the Louisiana FAC rates as soon as possible, including interest
through the date the refunds are reflected in the FAC.  See
“Allocation of Off-system Sales Margins” section within “FERC Rate
Matters.”  Management is unable to predict how the LPSC will rule on
the recommendations in the audit report and its financial statement impact on
net income and cash flows.
 
 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.  In 2007, the Oklahoma
Municipal Power Authority (OMPA) acquired an approximate 7% ownership interest
in the Turk Plant, paid SWEPCo $13.5 million for its share of the accrued
construction costs and began paying its proportional share of ongoing costs.
During the first quarter of 2009, the Arkansas Electric Cooperative Corporation
(AECC) and the East Texas Electric Cooperative (ETEC) acquired ownership
interests in the Turk Plant representing approximately 12% and 8%, respectively,
paid SWEPCo $104 million in the aggregate for their shares of accrued
construction costs and began paying their proportional shares of ongoing
construction costs.  The joint owners are billed monthly for their
share of the on-going construction costs exclusive of AFUDC.  Through
September 30, 2009, the joint owners paid SWEPCo $196 million for their share of
the Turk Plant construction expenditures.  SWEPCo owns 73% of the Turk
Plant and will operate the completed facility.  The Turk Plant is
currently estimated to cost $1.6 billion, excluding AFUDC, with SWEPCo’s share
estimated to cost $1.2 billion, excluding AFUDC.  In addition, SWEPCo
will own 100% of the related transmission facilities which are currently
estimated to cost $131 million, excluding AFUDC.
 
 In
November 2007, the APSC granted approval for SWEPCo to build the Turk Plant in
Arkansas by issuing a Certificate of Environmental Compatibility and Public Need
(CECPN).  Certain intervenors appealed the APSC’s decision to grant
the CECPN to the Arkansas Court of Appeals.  In January 2009, the APSC
granted additional CECPNs allowing SWEPCo to construct Turk-related transmission
facilities.  Intervenors also appealed these CECPN orders to the
Arkansas Court of Appeals.
 
 In June
2009, the Arkansas Court of Appeals issued a unanimous decision that, if upheld
by the Arkansas Supreme Court, would reverse the APSC’s grant of the CECPN
permitting construction of the Turk Plant to serve Arkansas retail
customers.  The decision was based upon the Arkansas Court of Appeals’
interpretation of the statute that governs the certification process and its
conclusion that the APSC did not fully comply with that process.  The
Arkansas Court of Appeals concluded that SWEPCo’s need for base load capacity,
the construction and financing of the Turk generating plant and the proposed
transmission facilities’ construction and location should all have been
considered by the APSC in a single docket instead of separate
dockets.  In October 2009, the Arkansas Supreme Court granted the
petitions filed by SWEPCo and the APSC to review the Arkansas Court of Appeals
decision.  While the appeal is pending, SWEPCo is continuing
construction of the Turk Plant.
 If the
decision of the Court of Appeals is not reversed by the Supreme Court of
Arkansas, SWEPCo and the other joint owners of the Turk Plant will evaluate
their options.  Depending on the time taken by the Arkansas Supreme
Court to consider the case and the reasoning of the Arkansas Supreme Court when
it acts on SWEPCo’s and the APSC’s petitions, the construction schedule and/or
the cost could be adversely affected.  Should the appeals by the APSC
and SWEPCo be unsuccessful, additional proceedings or alternative contractual
ownership and operational responsibilities could be required.
 
 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 and related transmission costs, (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 as
being unlawful.  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. If the cost cap restrictions are upheld and construction or CO2 emission
costs exceed the restrictions or if the intervenor appeal is successful, it
could have an adverse effect on net income, cash flows and possibly financial
condition.
 A request
to stop pre-construction activities at the site was filed in Federal District
Court by certain 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, which was granted in March 2009.
 
 In
November 2008, SWEPCo received the required air permit approval from the
Arkansas Department of Environmental Quality and commenced construction at the
site.  In December 2008, certain parties filed an appeal of the air
permit approval 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 the appeal of the Turk Plant’s air permit is
heard.  In June 2009, hearings on the air permit appeal were held at
the APCEC.  A decision is still pending and not expected until
2010.  These same parties have filed a petition with the Federal EPA
to review the air permit.  The petition will be acted on by December
2009 according to the terms of a recent settlement between the petitioners and
the Federal EPA.  The Turk Plant cannot be placed into service without
an air permit.  In August 2009, these same parties filed a petition
with the APCEC to halt construction of the Turk Plant.  In September
2009, the APCEC voted to allow construction of the Turk Plant to continue and
rejected the request for a stay.  If the air permit were to be
remanded or ultimately revoked, construction of the Turk Plant would be
suspended or cancelled.
 
 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 an inadvertent impact on approximately 2.5
acres of wetlands at the Turk Plant construction site prior to the receipt of
the permit.  The U.S. Army Corps of Engineers directed SWEPCo to cease
further work impacting the wetland areas.  Construction has continued
on other areas outside of the proposed Army Corps of Engineers permitted areas
of the Turk Plant pending the Army Corps of Engineers review.  SWEPCo
has entered into a Consent Agreement and Final Order with the Federal EPA to
resolve liability for the inadvertent impact and agreed to pay a civil penalty
of approximately $29 thousand.
 
 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.  To date, the
report’s effect is only advisory, but if legislation is passed as a result of
the findings in the Commission’s report, it could impact SWEPCo’s ability to
complete construction on schedule in 2012 and on budget.
 
 If the
Turk Plant cannot be completed and placed in service, SWEPCo would seek approval
to recover its prudently incurred capitalized construction costs including any
cancellation fees and a return on unrecovered balances through rates in all of
its jurisdictions.  As of September 30, 2009, and excluding costs
attributable to its joint owners, SWEPCo has capitalized approximately $646
million of expenditures (including AFUDC and capitalized interest, and related
transmission costs of $24 million).  As of September 30, 2009, the
joint owners and SWEPCo have contractual construction commitments of
approximately $515 million (including related transmission costs of $1 million)
and, if the plant had been cancelled, would have incurred cancellation fees of
$136million
(including related transmission cancellation fees of $1 million).
 
 Management
believes that SWEPCo’s planning, certification and construction of the Turk
Plant to date have been in material compliance with all applicable laws and
regulations, except for the inadvertent wetlands intrusion discussed
above.  Further, management expects that SWEPCo will ultimately be
able to complete construction of the Turk Plant and related transmission
facilities and place those facilities in service.  However, if for any
reason SWEPCo is unable to complete the Turk Plant construction and place the
Turk Plant in service, it would adversely impact net income, cash flows and
possibly financial condition unless the resultant losses can be fully recovered,
with a return on unrecovered balances, through rates in all of its
jurisdictions.
 
 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 Unit and Turk Plant.
 
 In
September 2009, SWEPCo, the APSC staff and the Arkansas Attorney General entered
into a settlement agreement in which the settling parties agreed to an $18
million increase based on a return on equity of 10.25%.  In addition,
the settlement agreement decreased depreciation expense by $10
million.  The settlement agreement would increase SWEPCo’s annual
pretax income by approximately $28 million.  The settlement agreement
also includes a separate rider of approximately $11 million annually that will
allow SWEPCo to recover carrying costs, depreciation and operation and
maintenance expenses on the Stall Unit once it is placed into
service.  Until then, SWEPCo will continue to accrue AFUDC on the
Stall Unit.  The other parties to the case do not oppose the
settlement agreement.  If the settlement agreement is approved by the
APSC, new base rates will become effective for all bills rendered on or after
November 25, 2009.
 
 In
January 2009, an ice storm struck in northern Arkansas affecting SWEPCo’s
customers.  SWEPCo incurred incremental operation and maintenance
expenses above the estimated amount of storm restoration costs included in
existing base rates.  In May 2009, SWEPCo filed an application with
the APSC seeking authority to defer $4 million (later adjusted to $3 million) of
expensed incremental operation and maintenance costs and to address the recovery
of these deferred expenses in the pending base rate case.  In July
2009, the APSC issued an order approving the deferral request subject to
investigation, analysis and audit of the costs.  In August 2009, the
APSC staff filed testimony that recommended recovery of approximately $1 million
per year through amortization of the deferred ice storm costs over three years
in base rates.  This amount was included in the $18 million base rate
increase agreed upon in the settlement agreement.  In September 2009,
based upon the APSC audit and recommendation, management established a
regulatory asset of $3 million for the recovery of the ice storm restoration
costs.
 
 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 refund of a portion or all of the 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 September 30, 2009, there were no in-process
settlements.  APCo’s, CSPCo’s, I&M’s and OPCo’s reserve balance at
September 30, 2009 was:
 
 September
      30, 2009Company
              
              (in
      millions)APCo
              
              $
              10.7CSPCo
              
              
              5.9I&M
              
              
              6.3OPCo
              
              
              8.2
 
 Management
cannot predict the ultimate outcome of future settlement discussions or future
FERC proceedings or court appeals, if any.  However, 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 cannot be settled and 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.
 
 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 even though other non-affiliated entities transmit
power over AEP’s lines.  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.  In August 2009, the United States Court of Appeals issued
an opinion affirming FERC’s refusal to implement a regional rate design in
PJM.
 
 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.  The AEP East companies sought and received retail rate
increases in Ohio, Virginia, West Virginia and Kentucky.  In January
and March 2009, the AEP East companies received retail rate increases in
Tennessee and Indiana, respectively, which recognized the higher retail
transmission costs resulting from the loss of wholesale transmission revenues
from T&O transactions.  As a result, the AEP East companies are
now recovering approximately 98% of the lost T&O transmission revenues from
their retail customers.  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 the AEP East companies’
transmission by others in PJM and MISO and as a result the use of zonal rates
would be unfair and discriminatory to AEP’s East zone retail
customers.  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 wholesale transmission T&O revenues
reduction of transmission cost to retail customers.  This case is
pending before the U.S. Court of Appeals which in August 2009 ruled against AEP
in a similar case.  See “The FERC PJM Regional Transmission Rate
Proceeding” section above.
 
 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.  Following authorized regulatory treatment, the AEP West
companies shared a portion of SIA margins with their customers during the period
June 2000 to March 2006.  In December 2008, the AEP West companies
recorded a provision for refund reflecting the sharing.  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.
 
 In July
2009, consultants for the LPSC issued an audit report of SWEPCo’s Louisiana
retail fuel adjustment clause.  Within this report, the consultants
for the LPSC recommended that SWEPCo refund the SIA, including interest, through
the fuel adjustment clause.  See “Louisiana Fuel Adjustment Clause
Audit” section within “Louisiana Rate Matters.”  In October 2009,
other consultants for the LPSC recommended refunding the SIA through SWEPCo’s
formula rate plan.  See “2009 Formula Rate Filing” section within
“Louisiana 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 related future state
regulatory proceedings is adequate.
 
 Modification
of the Transmission Agreement (TA) – Affecting APCo, CSPCo, I&M and
OPCo
 
 APCo,
CSPCo, I&M, KPCo and OPCo are parties to the TA entered into in 1984, as
amended, that provides for a sharing of the cost of transmission lines operated
at 138-kV and above and transmission stations operated at 345kV and
above.  In June 2009, AEPSC, on behalf of the parties to the TA, filed
with the FERC a request to modify the TA.  Under the proposed
amendments, WPCo and KGPCo will be added as parties to the TA.  In
addition, the amendments would provide for the allocation of PJM transmission
costs on the basis of the TA parties’ 12-month coincident peak and reimburse the
majority of PJM transmission revenues based on individual cost of service
instead of the MLR method used in the present TA.  AEPSC requested the
effective date to be the first day of the month following a final non-appealable
FERC order.  The delayed effective date was approved by the FERC in
August 2009 when the FERC accepted the new TA for filing.  Settlement
discussions are in process.  Management is unable to predict the
effect, if any, it will have on future net income and cash flows due to timing
of the implementation by various state regulators of the FERC’s new approved
TA.
 
 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 open access
transmission tariff (OATT) 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.  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.
 
 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 on an
annual basis through the transmission cost recovery rider (TCRR) mechanism by
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 May
2009, the first annual update of the formula rate was filed with the FERC which
reflected increased transmission service revenue requirements of approximately
$32 million on an annualized basis, effective for service as of July 1, 2009 to
be billed in August 2009.  Approximately $4 million of the increase
will be collected from nonaffiliated customers within PJM.  Retail
rates for CSPCo and OPCo would be increased through the TCRR mechanism by
approximately $5 million and $7 million, respectively.  Beginning in
December 2009, APCo's Virginia transmission rate adjustment clause is expected
to become effective and thus APCo will recover approximately $2 million of this
increase.  Retail rates for other AEP East jurisdictions are not
directly affected.
 
 Under the
formula, the second annual update will be filed effective July 1, 2010 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.
 
 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 an open access transmission tariff (OATT) 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.  Multiple intervenors protested or requested rehearing
of the August 2007 order.  In October 2007, PSO and SWEPCo filed the
required compliance filing, and began settlement discussions with the
intervenors and FERC staff.  Under the formula, rates were updated
effective July 1, 2009 and will be updated 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.  In February 2009, a settlement
agreement was reached and was filed with the FERC.  In 2009, a
provision for refund was recorded by PSO and SWEPCo based upon the pending
settlement.  In June 2009, the FERC approved the settlement agreement
and refunds were made to customers.
 
 Transmission
Agreement (TA) – Affecting APCo, CSPCo, I&M and OPCo
 
 Certain
transmission facilities placed in service in 1998 were inadvertently excluded
from the AEP East companies’ TA calculation prior to January
2009.  The excluded equipment was the Inez station which had been
determined as eligible equipment for inclusion in the TA in 1995 by the AEP TA
transmission committee.  The amount involved was $7 million
annually.  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, APCo,
CSPCo, I&M and OPCo could experience adverse effects 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.
 
 The
Registrant Subsidiaries and certain other companies in the AEP System have a
$627 million 3-year credit agreement.  As of September 30, 2009, $372
million of letters of credit were issued by Registrant Subsidiaries under the
$627 million 3-year credit agreement to support variable rate Pollution Control
Bonds.  The Registrant Subsidiaries and certain other companies in the
AEP System had a $350 million 364-day credit agreement that expired in April
2009.
 
 At
September 30, 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$627
      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), a consolidated variable interest entity.  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.  A
new study is in process to include new, expanded areas of the
mine.  As of September 30, 2009, SWEPCo has collected approximately
$42 million through a rider for final mine closure and reclamation costs, of
which $2 million is recorded in Other Current Liabilities, $17 million is
recorded in Asset Retirement Obligations and $23 million is recorded in Deferred
Credits and Other Noncurrent Liabilities 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 September 30, 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.  Historically, at the
end of the lease term the fair market value has been in excess of the
unamortized balance.  At September 30, 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
              
              $
              804CSPCo
              
              
              343I&M
              
              
              555OPCo
              
              
              750PSO
              
              
              1,024SWEPCo
              
              
              665
 
 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 $19 million for
I&M and $22 million for SWEPCo for the remaining railcars as of September
30, 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
a unit jointly owned by CSPCo, Dayton Power and Light Company and Duke Energy
Ohio, Inc. at the Beckjord Station was modified in violation of the NSR
requirements of the CAA.
 
 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.  Following a second liability trial, the jury again
found no liability at the jointly-owned Beckjord unit.  In 2009, the
defendants and the plaintiffs filed appeals.  Beckjord is operated by
Duke Energy Ohio, Inc.
 
 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
a 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.  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
GHG under the CAA.  The Second Circuit requested supplemental briefs
addressing the impact of the U.S. Supreme Court’s decision on this
case.
 
 In
September 2009, the Second Circuit Court issued a ruling vacating the dismissal
and remanding the case to the Federal District Court for the Southern District
of New York.  The Second Circuit held that the issues of climate
change and global warming do not raise political questions and that Congress’
refusal to regulate GHG emissions does not mean that plaintiffs must wait for an
initial policy determination by Congress or the President’s administration to
secure the relief sought in their complaints.  The court stated that
Congress could enact comprehensive legislation to regulate CO2 emissions
or that the Federal EPA could regulate CO2 emissions
under existing CAA authorities, and that either of these actions could override
any decision made by the district court under federal common law.  The
Second Circuit did not rule on whether the plaintiffs could proceed with their
state common law nuisance claims.  Management believes the actions are
without merit and intends to continue to defend against the claims including
seeking further review by the Second Circuit and, if necessary, the United
States Supreme Court.
 
 In
October 2009, the Fifth Circuit Court of Appeals reversed a decision by the
Federal District Court for the District of Mississippi dismissing state common
law nuisance claims in a putative class action by Mississippi residents
asserting that GHG emissions exacerbated the effects of Hurricane
Katrina.  The Fifth Circuit held that there was no exclusive
commitment of the common law issues raised in plaintiffs’ complaint to a
coordinate branch of government, and that no initial policy determination was
required to adjudicate these claims.  AEP companies, including the
Registrant Subsidiaries, were initially dismissed from this case without
prejudice, but are named as a defendant in a pending fourth amended
complaint.
 
 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
and 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.  In October 2009, the
judge dismissed plaintiffs’ federal common law claim for nuisance, finding the
claim barred by the political question doctrine and by plaintiffs’ lack of
standing to bring the claim.  The judge also dismissed plaintiffs’
state law claims without prejudice to refiling in state court.
  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 $7 million in
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 and 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, 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.  I&M is repairing
Unit 1 to resume operations as early as the fourth quarter of 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 September 30, 2009, I&M recorded $122 million
in Prepayments and Other Current Assets on its Condensed Consolidated Balance
Sheets representing recoverable amounts under the property insurance
policy.  Through September 30, 2009, I&M received partial payments
of $72 million 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 2009, I&M
recorded $145 million in revenues and applied $59 million of the accidental
outage insurance proceeds to reduce customer bills.
 
 NEIL is
reviewing claims made under the insurance policies to ensure that claims
associated with the outage are covered by the policies.  The treatment
of property damage costs, replacement power costs and insurance proceeds will be
the subject of future regulatory proceedings in Indiana and
Michigan.  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 or if any future regulatory
proceedings are adverse, it could have an adverse impact on net income, cash
flows and financial condition.
 
 Fort
Wayne Lease – Affecting I&M
 
 Since
1975 I&M has leased certain energy delivery assets from the City of Fort
Wayne, Indiana under a long-term lease that expires on February 28,
2010.  I&M has been negotiating with Fort Wayne to purchase the
assets at the end of the lease, but no agreement has been
reached.  Recent mediation with Fort Wayne was also
unsuccessful.  Fort Wayne issued a technical notice of default under
the lease to I&M in August 2009.  I&M responded to Fort Wayne
in October 2009 that it did not agree there was a default under the
lease.  In October 2009, I&M filed for declaratory and injunctive
relief in Indiana state court. I&M will seek
recovery in rates for any amount it may pay related to this
dispute.  At this time, management cannot predict the outcome of this
dispute or its potential impact on net income or cash flows.
 
 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.  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.  In August 2009, the U.S. District Court upheld
the arbitration board’s decision.  BNSF appealed the U.S. District
Court’s decision.
  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.  Trial is scheduled for December
2009.  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 recorded a provision
in 2008.  In September 2009, the parties reached a settlement and a
portion of the provision was reversed.
 
 5.
              ACQUISITION
 
 2009
 
 Oxbow
Mine Lignite – Affecting SWEPCo
 
 In April
2009, SWEPCo agreed to purchase 50% of the Oxbow Mine lignite reserves for $13
million and DHLC agreed to purchase 100% of all associated mining equipment and
assets for $16 million from the North American Coal Corporation and its
affiliates, Red River Mining Company and Oxbow Property Company,
LLC.  Cleco Power LLC (Cleco) will acquire the remaining 50% interest
in the lignite reserves for $13 million.  SWEPCo expects to complete
the transaction in the fourth quarter of 2009.  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.
 
 2008
 
 None
  6.
              BENEFIT
      PLANS
 
 The
Registrant Subsidiaries 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, the Registrant Subsidiaries 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 tables provide the components of AEP’s net periodic benefit cost for
the plans for the three and nine months ended September 30, 2009 and
2008:
 Other
      PostretirementPension
      Plans
              
              Benefit
      PlansThree
      Months Ended September 30,
              
              Three
      Months Ended September 30,2009
              
              2008
              
              2009
              
              2008(in
      millions)Service
      Cost
              
              $
              26
              
              
              $
              25
              
              
              $
              11
              
              
              $
              10Interest
      Cost
              
              
              64
              
              
              
              62
              
              
              
              27
              
              
              
              28Expected
      Return on Plan Assets
              
              
              (80
              )
              
              
              (84
              )
              
              
              (21
              )
              
              
              (27
              )Amortization
      of Transition Obligation
              
              
              -
              
              
              
              -
              
              
              
              7
              
              
              
              7Amortization
      of Net Actuarial Loss
              
              
              14
              
              
              
              10
              
              
              
              11
              
              
              
              3Net
      Periodic Benefit Cost
              
              $
              24
              
              
              $
              13
              
              
              $
              35
              
              
              $
              21
 
 Other
      PostretirementPension
      Plans
              
              Benefit
      PlansNine
      Months Ended September 30,
              
              Nine
      Months Ended September 30,2009
              
              2008
              
              2009
              
              2008(in
      millions)Service
      Cost
              
              $
              78
              
              
              $
              75
              
              
              $
              32
              
              
              $
              31Interest
      Cost
              
              
              191
              
              
              
              187
              
              
              
              82
              
              
              
              84Expected
      Return on Plan Assets
              
              
              (241
              )
              
              
              (252
              )
              
              
              (61
              )
              
              
              (83
              )Amortization
      of Transition Obligation
              
              
              -
              
              
              
              -
              
              
              
              20
              
              
              
              21Amortization
      of Net Actuarial Loss
              
              
              44
              
              
              
              29
              
              
              
              32
              
              
              
              8Net
      Periodic Benefit Cost
              
              $
              72
              
              
              $
              39
              
              
              $
              105
              
              
              $
              61
 
 The
following tables provide the Registrant Subsidiaries’ net periodic benefit cost
(credit) for the plans for the three and nine months ended September 30, 2009
and 2008:
 Other
      PostretirementPension
      Plans
              
              Benefit
      PlansThree
      Months Ended September 30,
              
              Three
      Months Ended September 30,2009
              
              2008
              
              2009
              
              2008Company
              (in
      thousands)APCo
              
              $
              2,614
              
              
              $
              834
              
              
              $
              6,058
              
              
              $
              3,797CSPCo
              
              
              687
              
              
              
              (351
              )
              
              
              2,638
              
              
              
              1,545I&M
              
              
              3,484
              
              
              
              1,821
              
              
              
              4,359
              
              
              
              2,496OPCo
              
              
              2,067
              
              
              
              318
              
              
              
              5,139
              
              
              
              2,908PSO
              
              
              770
              
              
              
              509
              
              
              
              2,283
              
              
              
              1,420SWEPCo
              
              
              1,208
              
              
              
              935
              
              
              
              2,363
              
              
              
              1,411
 
 Other
      PostretirementPension
      Plans
              
              Benefit
      PlansNine
      Months Ended September 30,
              
              Nine
      Months Ended September 30,2009
              
              2008
              
              2009
              
              2008Company
              (in
      thousands)APCo
              
              $
              7,844
              
              
              $
              2,503
              
              
              $
              18,173
              
              
              $
              11,196CSPCo
              
              
              2,063
              
              
              
              (1,049
              )
              
              
              7,915
              
              
              
              4,542I&M
              
              
              10,454
              
              
              
              5,462
              
              
              
              13,075
              
              
              
              7,342OPCo
              
              
              6,201
              
              
              
              957
              
              
              
              15,418
              
              
              
              8,541PSO
              
              
              2,310
              
              
              
              1,525
              
              
              
              6,850
              
              
              
              4,194SWEPCo
              
              
              3,623
              
              
              
              2,806
              
              
              
              7,090
              
              
              
              4,163
 
 7.
              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.
 
 8.
              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
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 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 the accounting guidance for “Derivatives and Hedging.”
Derivative risk management contracts elected normal under the normal purchases
and normal sales scope exception are not subject to the requirements of this
accounting guidance.
 
 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 September 30,
2009:
 Notional
      Volume of Derivative InstrumentsSeptember
      30, 2009(in
      thousands)Primary
      Risk
              
              Unit
      ofExposure
              
              Measure
              
              APCo
              
              CSPCo
              
              I&M
              
              OPCo
              
              PSO
              
              SWEPCoCommodity:Power
              
              MWHs
              
              172,458
              
              91,400
              
              88,122
              
              104,830
              
              177
              
              211Coal
              
              Tons
              
              12,029
              
              5,889
              
              7,299
              
              20,448
              
              5,659
              
              6,394Natural
      Gas
              
              MMBtus
              
              24,861
              
              13,176
              
              12,703
              
              15,112
              
              1,279
              
              1,521Heating Oil and Gasoline
              
              Gallons
              
              1,499
              
              612
              
              710
              
              1,079
              
              858
              
              806Interest
      Rate
              
              USD
              
              $
              20,802
              
              $
              10,993
              
              $
              10,703
              
              $
              13,455
              
              $
              1,124
              
              $
              1,431Interest
      Rate and Foreign Currency
              
              USD
              
              $
              -
              
              $
              -
              
              $
              -
              
              $
              -
              
              $
              -
              
              $
              3,847
 
 Fair
Value Hedging Strategies
 
 At
certain times, AEPSC, on behalf of the Registrant Subsidiaries, enters into
interest rate derivative transactions in order to manage 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 designates 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 to
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,
OPCo designated interest rate derivatives as cash flow hedges.  During
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, SWEPCo designated foreign currency derivatives
as cash flow hedges.  During 2008, APCo, OPCo and SWEPCo designated
foreign currency derivatives as cash flow hedges.
 
 Accounting for Derivative
Instruments and the Impact on the Financial Statements
 
 The
accounting guidance for “Derivatives and Hedging” 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 the accounting guidance for “Derivatives and Hedging,” 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 September 30,
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:
 
 September
      30, 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
              
              $
              9,679
              
              
              $
              32,791
              
              
              $
              2,189
              
              
              $
              5,621CSPCo
              
              
              5,129
              
              
              
              17,375
              
              
              
              1,229
              
              
              
              3,156I&M
              
              
              4,946
              
              
              
              16,763
              
              
              
              1,189
              
              
              
              3,054OPCo
              
              
              5,883
              
              
              
              20,013
              
              
              
              1,522
              
              
              
              3,909PSO
              
              
              1
              
              
              
              26
              
              
              
              -
              
              
              
              105SWEPCo
              
              
              2
              
              
              
              41
              
              
              
              -
              
              
              
              124
 
 The
following table represents the gross fair value impact of the Registrant
Subsidiaries’ derivative activity on the Condensed Balance Sheets as of
September 30, 2009:
 
 Fair
      Value of Derivative InstrumentsSeptember
      30, 2009RiskManagementAPCo
              Contracts
              
              Hedging
      ContractsInterest
      RateCommodity
              
              Commodity
              
              and
      Foreign(a)
              
              (a)
              
              Currency
      (a)
              
              Other
      (a) (b)
              
              TotalBalance
      Sheet Location
              (in
      thousands)Current
      Risk Management Assets
              
              $
              474,612
              
              
              $
              5,253
              
              
              $
              -
              
              
              $
              (396,430
              )
              
              $
              83,435Long-term
      Risk Management Assets
              
              
              200,051
              
              
              
              1,295
              
              
              
              -
              
              
              
              (143,594
              )
              
              
              57,752Total
      Assets
              
              
              674,663
              
              
              
              6,548
              
              
              
              -
              
              
              
              (540,024
              )
              
              
              141,187Current
      Risk Management Liabilities
              
              
              435,880
              
              
              
              4,833
              
              
              
              -
              
              
              
              (409,711
              )
              
              
              31,002Long-term
      Risk Management Liabilities
              
              
              181,925
              
              
              
              1,737
              
              
              
              -
              
              
              
              (160,008
              )
              
              
              23,654Total
      Liabilities
              
              
              617,805
              
              
              
              6,570
              
              
              
              -
              
              
              
              (569,719
              )
              
              
              54,656Total
      MTM Derivative Contract Net Assets (Liabilities)
              
              $
              56,858
              
              
              $
              (22
              )
              
              $
              -
              
              
              $
              29,695
              
              
              $
              86,531
  CSPCoRiskManagementContracts
              
              Hedging
      ContractsInterest
      RateCommodity
              
              Commodity
              
              and
      Foreign(a)
              
              (a)
              
              Currency
      (a)
              
              Other
      (a) (b)
              
              TotalBalance
      Sheet Location
              (in
      thousands)Current
      Risk Management Assets
              
              $
              249,520
              
              
              $
              2,763
              
              
              $
              -
              
              
              $
              (208,367
              )
              
              $
              43,916Long-term
      Risk Management Assets
              
              
              105,415
              
              
              
              682
              
              
              
              -
              
              
              
              (75,528
              )
              
              
              30,569Total
      Assets
              
              
              354,935
              
              
              
              3,445
              
              
              
              -
              
              
              
              (283,895
              )
              
              
              74,485Current
      Risk Management Liabilities
              
              
              229,126
              
              
              
              2,552
              
              
              
              -
              
              
              
              (215,403
              )
              
              
              16,275Long-term
      Risk Management Liabilities
              
              
              95,828
              
              
              
              921
              
              
              
              -
              
              
              
              (84,227
              )
              
              
              12,522Total
      Liabilities
              
              
              324,954
              
              
              
              3,473
              
              
              
              -
              
              
              
              (299,630
              )
              
              
              28,797Total
      MTM Derivative Contract Net Assets (Liabilities)
              
              $
              29,981
              
              
              $
              (28
              )
              
              $
              -
              
              
              $
              15,735
              
              
              $
              45,688
  I&MRiskManagementContracts
              
              Hedging
      ContractsInterest
      RateCommodity
              
              Commodity
              
              and
      Foreign(a)
              
              (a)
              
              Currency
      (a)
              
              Other
      (a) (b)
              
              TotalBalance
      Sheet Location
              (in
      thousands)Current
      Risk Management Assets
              
              $
              247,098
              
              
              $
              2,678
              
              
              $
              -
              
              
              $
              (206,656
              )
              
              $
              43,120Long-term
      Risk Management Assets
              
              
              103,663
              
              
              
              660
              
              
              
              -
              
              
              
              (74,731
              )
              
              
              29,592Total
      Assets
              
              
              350,761
              
              
              
              3,338
              
              
              
              -
              
              
              
              (281,387
              )
              
              
              72,712Current
      Risk Management Liabilities
              
              
              226,991
              
              
              
              2,465
              
              
              
              -
              
              
              
              (213,445
              )
              
              
              16,011Long-term
      Risk Management Liabilities
              
              
              94,356
              
              
              
              889
              
              
              
              -
              
              
              
              (83,124
              )
              
              
              12,121Total
      Liabilities
              
              
              321,347
              
              
              
              3,354
              
              
              
              -
              
              
              
              (296,569
              )
              
              
              28,132Total
      MTM Derivative Contract Net Assets (Liabilities)
              
              $
              29,414
              
              
              $
              (16
              )
              
              $
              -
              
              
              $
              15,182
              
              
              $
              44,580
 
 OPCoRiskManagementContracts
              
              Hedging
      ContractsInterest
      RateCommodity
              
              Commodity
              
              and
      Foreign(a)
              
              (a)
              
              Currency
      (a)
              
              Other
      (a) (b)
              
              TotalBalance
      Sheet Location
              (in
      thousands)Current
      Risk Management Assets
              
              $
              342,276
              
              
              $
              3,215
              
              
              $
              -
              
              
              $
              (286,497
              )
              
              $
              58,994Long-term
      Risk Management Assets
              
              
              137,788
              
              
              
              790
              
              
              
              -
              
              
              
              (102,253
              )
              
              
              36,325Total
      Assets
              
              
              480,064
              
              
              
              4,005
              
              
              
              -
              
              
              
              (388,750
              )
              
              
              95,319Current
      Risk Management Liabilities
              
              
              319,115
              
              
              
              2,944
              
              
              
              -
              
              
              
              (294,615
              )
              
              
              27,444Long-term
      Risk Management Liabilities
              
              
              127,345
              
              
              
              1,057
              
              
              
              -
              
              
              
              (112,268
              )
              
              
              16,134Total
      Liabilities
              
              
              446,460
              
              
              
              4,001
              
              
              
              -
              
              
              
              (406,883
              )
              
              
              43,578Total
      MTM Derivative Contract Net Assets (Liabilities)
              
              $
              33,604
              
              
              $
              4
              
              
              $
              -
              
              
              $
              18,133
              
              
              $
              51,741
  PSORiskManagementContracts
              
              Hedging
      ContractsInterest
      RateCommodity
              
              Commodity
              
              and
      Foreign(a)
              
              (a)
              
              Currency
      (a)
              
              Other
      (a) (b)
              
              TotalBalance
      Sheet Location
              (in
      thousands)Current
      Risk Management Assets
              
              $
              21,839
              
              
              $
              107
              
              
              $
              -
              
              
              $
              (18,041
              )
              
              $
              3,905Long-term
      Risk Management Assets
              
              
              5,178
              
              
              
              23
              
              
              
              -
              
              
              
              (4,889
              )
              
              
              312Total
      Assets
              
              
              27,017
              
              
              
              130
              
              
              
              -
              
              
              
              (22,930
              )
              
              
              4,217Current
      Risk Management Liabilities
              
              
              22,283
              
              
              
              536
              
              
              
              -
              
              
              
              (18,054
              )
              
              
              4,765Long-term
      Risk Management Liabilities
              
              
              5,327
              
              
              
              47
              
              
              
              -
              
              
              
              (4,901
              )
              
              
              473Total
      Liabilities
              
              
              27,610
              
              
              
              583
              
              
              
              -
              
              
              
              (22,955
              )
              
              
              5,238Total
      MTM Derivative Contract Net Assets (Liabilities)
              
              $
              (593
              )
              
              $
              (453
              )
              
              $
              -
              
              
              $
              25
              
              
              $
              (1,021
              )
  SWEPCoRiskManagementContracts
              
              Hedging
      ContractsInterest
      RateCommodity
              
              Commodity
              
              and
      Foreign(a)
              
              (a)
              
              Currency
      (a)
              
              Other
      (a) (b)
              
              TotalBalance
      Sheet Location
              (in
      thousands)Current
      Risk Management Assets
              
              $
              31,905
              
              
              $
              102
              
              
              $
              -
              
              
              $
              (26,680
              )
              
              $
              5,327Long-term
      Risk Management Assets
              
              
              8,004
              
              
              
              16
              
              
              
              6
              
              
              
              (7,546
              )
              
              
              480Total
      Assets
              
              
              39,909
              
              
              
              118
              
              
              
              6
              
              
              
              (34,226
              )
              
              
              5,807Current
      Risk Management Liabilities
              
              
              30,092
              
              
              
              33
              
              
              
              25
              
              
              
              (26,701
              )
              
              
              3,449Long-term
      Risk Management Liabilities
              
              
              7,774
              
              
              
              4
              
              
              
              -
              
              
              
              (7,564
              )
              
              
              214Total
      Liabilities
              
              
              37,866
              
              
              
              37
              
              
              
              25
              
              
              
              (34,265
              )
              
              
              3,663Total
      MTM Derivative Contract Net Assets (Liabilities)
              
              $
              2,043
              
              
              $
              81
              
              
              $
              (19
              )
              
              $
              39
              
              
              $
              2,144
 
 (a)
              Derivative
      instruments within these categories are reported gross.  These
      instruments are subject to master netting agreements and are presented on
      the Condensed Balance Sheets on a net basis in accordance with the
      accounting guidance for “Derivatives and Hedging.”(b)
              Amounts
      represent counterparty netting of risk management contracts, associated
      cash collateral in accordance with the accounting guidance for
      “Derivatives and Hedging” and dedesignated risk management
      contracts.
 
 The
tables below presents the Registrant Subsidiaries’ activity of derivative risk
management contracts for the three and nine months ended September 30,
2009:
 
 Amount
      of Gain (Loss) Recognizedon
      Risk Management ContractsFor
      the Three Months Ended September 30, 2009APCo
              
              CSPCo
              
              I&M
              
              OPCo
              
              PSO
              
              SWEPCo(in
      thousands)Location
      of Gain (Loss)Electric
      Generation, Transmission and Distribution Revenues
              
              $
              2,240
              
              
              $
              6,551
              
              
              $
              7,127
              
              
              $
              3,155
              
              
              $
              (850
              )
              
              $
              (1,067
              )Sales
      to AEP Affiliates
              
              
              (237
              )
              
              
              (238
              )
              
              
              (292
              )
              
              
              302
              
              
              
              1,135
              
              
              
              1,347Regulatory
      Assets
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (600
              )
              
              
              5Regulatory
      Liabilities
              
              
              24,750
              
              
              
              7,800
              
              
              
              6,917
              
              
              
              8,775
              
              
              
              (497
              )
              
              
              (16
              )Total
      Gain (Loss) on Risk Management Contracts
              
              $
              26,753
              
              
              $
              14,113
              
              
              $
              13,752
              
              
              $
              12,232
              
              
              $
              (812
              )
              
              $
              269
 
 Amount
      of Gain (Loss) Recognizedon
      Risk Management ContractsFor
      the Nine Months Ended September 30, 2009APCo
              
              CSPCo
              
              I&M
              
              OPCo
              
              PSO
              
              SWEPCo(in
      thousands)Location
      of Gain (Loss)Electric
      Generation, Transmission and Distribution Revenues
              
              $
              13,211
              
              
              $
              26,557
              
              
              $
              31,333
              
              
              $
              27,453
              
              
              $
              (2
              )
              
              $
              151Sales
      to AEP Affiliates
              
              
              (7,563
              )
              
              
              (4,707
              )
              
              
              (4,710
              )
              
              
              (1,191
              )
              
              
              510
              
              
              
              372Regulatory
      Assets
              
              
              (755
              )
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (600
              )
              
              
              (98
              )Regulatory
      Liabilities
              
              
              75,108
              
              
              
              18,876
              
              
              
              13,285
              
              
              
              21,811
              
              
              
              (1,379
              )
              
              
              233Total
      Gain (Loss) on Risk Management Contracts
              
              $
              80,001
              
              
              $
              40,726
              
              
              $
              39,908
              
              
              $
              48,073
              
              
              $
              (1,471
              )
              
              $
              658
 
 Certain
qualifying derivative instruments have been designated as normal purchase or
normal sale contracts, as provided in the accounting guidance for “Derivatives
and Hedging.”  Derivative contracts that have been designated as
normal purchases or normal sales under that accounting guidance are not subject
to MTM accounting treatment and are recognized on 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 on 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 some realized gains and losses in regulated jurisdictions (APCo,
I&M, PSO, the non-Texas portion of SWEPCo generation and beginning April
2009 the Texas portion of SWEPCo generation) for both trading and non-trading
derivative instruments are recorded as regulatory assets (for losses) or
regulatory liabilities (for gains) in accordance with the accounting guidance
for “Regulated Operations.”  SWEPCo returned to cost-based regulation
and re-applied the accounting guidance for “Regulated Operations” for the
generation portion of SWEPCo’s Texas retail jurisdiction effective April
2009.
 
 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 and nine months
ended September 30, 2009, the Registrant Subsidiaries did not employ any fair
value hedging strategies.  During the three and nine months ended
September 30, 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 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 on the Condensed Statements of Income, or Regulatory
Assets or Regulatory Liabilities on the Condensed Balance Sheets, 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 and nine months ended September 30,
2009 and 2008, APCo, CSPCo, I&M and OPCo recognized immaterial amounts
related to hedge ineffectiveness.
 
 Beginning
in 2009, AEPSC, on behalf of 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 and nine months ended September
30, 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 and nine months ended September 30, 2009,
OPCo recognized a $1 million loss and a $6 million gain, respectively, in
Interest Expense related to hedge ineffectiveness on interest rate derivatives
designated as cash flow hedges.  During the three and nine months
ended September 30, 2008, APCo and OPCo recognized immaterial amounts in
Interest Expense 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 on 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 and nine months ended September
30, 2009 and 2008, APCo, OPCo and SWEPCo recognized no hedge ineffectiveness
related to this hedge strategy.
 
 The
following tables 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 for the three and nine months ended September 30,
2009.  All amounts in the following tables are presented net of
related income taxes.
 
 Accumulated
      Other Comprehensive Income (Loss) Activity for Cash Flow
      HedgesFor
      the Three Months Ended September 30, 2009APCo
              
              
              CSPCo
              
              
              I&M
              
              
              OPCo
              
              
              PSO
              
              
              SWEPCo(in
      thousands)Commodity
      ContractsBeginning
      Balance in AOCI as of
                July
      1, 2009
              
              $
              2,296
              
              
              $
              1,189
              
              
              $
              1,170
              
              
              $
              1,526
              
              
              $
              127
              
              
              $
              141Changes
      in Fair Value Recognized in AOCI
              
              
              (451
              )
              
              
              (232
              )
              
              
              (227
              )
              
              
              (346
              )
              
              
              (377
              )
              
              
              (45
              )Amount
      of (Gain) or Loss Reclassified from AOCI to Income Statements/within
      Balance Sheets:Electric
      Generation, Transmission and Distribution Revenues
              
              
              (720
              )
              
              
              (1,815
              )
              
              
              (1,385
              )
              
              
              (2,126
              )
              
              
              -
              
              
              
              -Fuel
      and Other Consumables Used for Electric Generation
              
              
              (39
              )
              
              
              (17
              )
              
              
              (20
              )
              
              
              (27
              )
              
              
              (20
              )
              
              
              (22
              )Purchased
      Electricity for Resale
              
              
              444
              
              
              
              1,116
              
              
              
              852
              
              
              
              1,313
              
              
              
              -
              
              
              
              -Property,
      Plant and Equipment
              
              
              (23
              )
              
              
              (9
              )
              
              
              (12
              )
              
              
              (17
              )
              
              
              (12
              )
              
              
              (9
              )Regulatory
      Assets
              
              
              1,664
              
              
              
              -
              
              
              
              226
              
              
              
              -
              
              
              
              -
              
              
              
              -Regulatory
      Liabilities
              
              
              (2,709
              )
              
              
              -
              
              
              
              (369
              )
              
              
              -
              
              
              
              -
              
              
              
              -Ending
      Balance in AOCI as of
                September
      30, 2009
              
              $
              462
              
              
              $
              232
              
              
              $
              235
              
              
              $
              323
              
              
              $
              (282
              )
              
              $
              65
   APCo
              
              
              CSPCo
              
              
              I&M
              
              
              OPCo
              
              
              PSO
              
              
              SWEPCo(in
      thousands)Interest
      Rate and Foreign CurrencyContractsBeginning
      Balance in AOCI as of
                July
      1, 2009
              
              $
              (7,285
              )
              
              $
              -
              
              
              $
              (10,017
              )
              
              $
              16,662
              
              
              $
              (613
              )
              
              $
              (5,497
              )Changes
      in Fair Value Recognized in AOCI
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (4,038
              )
              
              
              -
              
              
              
              82Amount
      of (Gain) or Loss Reclassified from AOCI to Income Statements/within
      Balance Sheets:Depreciation
      and Amortization Expense
              
              
              -
              
              
              
              -
              
              
              
              (2
              )
              
              
              1
              
              
              
              -
              
              
              
              -Interest
      Expense
              
              
              418
              
              
              
              -
              
              
              
              253
              
              
              
              (113
              )
              
              
              46
              
              
              
              208Ending
      Balance in AOCI as of
                September
      30, 2009
              
              $
              (6,867
              )
              
              $
              -
              
              
              $
              (9,766
              )
              
              $
              12,512
              
              
              $
              (567
              )
              
              $
              (5,207
              )
 
 
 APCo
              
              
              CSPCo
              
              
              I&M
              
              
              OPCo
              
              
              PSO
              
              
              SWEPCo(in
      thousands)TOTAL
      ContractsBeginning
      Balance in AOCI as of
                July
      1, 2009
              
              $
              (4,989
              )
              
              $
              1,189
              
              
              $
              (8,847
              )
              
              $
              18,188
              
              
              $
              (486
              )
              
              $
              (5,356
              )Changes
      in Fair Value Recognized in AOCI
              
              
              (451
              )
              
              
              (232
              )
              
              
              (227
              )
              
              
              (4,384
              )
              
              
              (377
              )
              
              
              37Amount
      of (Gain) or Loss Reclassified from AOCI to Income Statements/within
      Balance Sheets:Electric
      Generation, Transmission and Distribution Revenues
              
              
              (720
              )
              
              
              (1,815
              )
              
              
              (1,385
              )
              
              
              (2,126
              )
              
              
              -
              
              
              
              -Fuel
      and Other Consumables Used for Electric Generation
              
              
              (39
              )
              
              
              (17
              )
              
              
              (20
              )
              
              
              (27
              )
              
              
              (20
              )
              
              
              (22
              )Purchased
      Electricity for Resale
              
              
              444
              
              
              
              1,116
              
              
              
              852
              
              
              
              1,313
              
              
              
              -
              
              
              
              -Depreciation
      and Amortization Expense
              
              
              -
              
              
              
              -
              
              
              
              (2
              )
              
              
              1
              
              
              
              -
              
              
              
              -Interest
      Expense
              
              
              418
              
              
              
              -
              
              
              
              253
              
              
              
              (113
              )
              
              
              46
              
              
              
              208Property,
      Plant and Equipment
              
              
              (23
              )
              
              
              (9
              )
              
              
              (12
              )
              
              
              (17
              )
              
              
              (12
              )
              
              
              (9
              )Regulatory
      Assets
              
              
              1,664
              
              
              
              -
              
              
              
              226
              
              
              
              -
              
              
              
              -
              
              
              
              -Regulatory
      Liabilities
              
              
              (2,709
              )
              
              
              -
              
              
              
              (369
              )
              
              
              -
              
              
              
              -
              
              
              
              -Ending
      Balance in AOCI as of
                September
      30, 2009
              
              $
              (6,405
              )
              
              $
              232
              
              
              $
              (9,531
              )
              
              $
              12,835
              
              
              $
              (849
              )
              
              $
              (5,142
              )
  
 Total
      Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow
      HedgesFor
      the Nine Months Ended September 30, 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
              
              
              (278
              )
              
              
              (257
              )
              
              
              (233
              )
              
              
              (325
              )
              
              
              (246
              )
              
              
              100Amount
      of (Gain) or Loss Reclassified from AOCI to Income Statements/within
      Balance Sheets:Electric
      Generation, Transmission and Distribution Revenues
              
              
              (1,429
              )
              
              
              (3,586
              )
              
              
              (2,774
              )
              
              
              (4,319
              )
              
              
              -
              
              
              
              -Fuel
      and Other Consumables Used for Electric Generation
              
              
              (45
              )
              
              
              (21
              )
              
              
              (24
              )
              
              
              (32
              )
              
              
              (23
              )
              
              
              (25
              )Purchased
      Electricity for Resale
              
              
              1,038
              
              
              
              2,576
              
              
              
              2,033
              
              
              
              3,120
              
              
              
              -
              
              
              
              -Property,
      Plant and Equipment
              
              
              (26
              )
              
              
              (11
              )
              
              
              (13
              )
              
              
              (19
              )
              
              
              (13
              )
              
              
              (10
              )Regulatory
      Assets
              
              
              3,800
              
              
              
              -
              
              
              
              457
              
              
              
              -
              
              
              
              -
              
              
              
              -Regulatory
      Liabilities
              
              
              (5,324
              )
              
              
              -
              
              
              
              (693
              )
              
              
              -
              
              
              
              -
              
              
              
              -Ending
      Balance in AOCI as of
                September
      30, 2009
              
              $
              462
              
              
              $
              232
              
              
              $
              235
              
              
              $
              323
              
              
              $
              (282
              )
              
              $
              65
 
 
 APCo
              
              
              CSPCo
              
              
              I&M
              
              
              OPCo
              
              
              PSO
              
              
              SWEPCo(in
      thousands)Interest
      Rate and Foreign CurrencyContractsBeginning
      Balance in AOCI as of January 1, 2009
              
              $
              (8,118
              )
              
              $
              -
              
              
              $
              (10,521
              )
              
              $
              1,752
              
              
              $
              (704
              )
              
              $
              (5,924
              )Changes
      in Fair Value Recognized in AOCI
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              10,915
              
              
              
              -
              
              
              
              95Amount
      of (Gain) or Loss Reclassified from AOCI to Income Statements/within
      Balance Sheets:Depreciation
      and Amortization Expense
              
              
              -
              
              
              
              -
              
              
              
              (4
              )
              
              
              3
              
              
              
              -
              
              
              
              -Interest
      Expense
              
              
              1,251
              
              
              
              -
              
              
              
              759
              
              
              
              (158
              )
              
              
              137
              
              
              
              622Ending
      Balance in AOCI as of
                September
      30, 2009
              
              $
              (6,867
              )
              
              $
              -
              
              
              $
              (9,766
              )
              
              $
              12,512
              
              
              $
              (567
              )
              
              $
              (5,207
              )
 
  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
              
              
              (278
              )
              
              
              (257
              )
              
              
              (233
              )
              
              
              10,590
              
              
              
              (246
              )
              
              
              195Amount
      of (Gain) or Loss Reclassified from AOCI to Income Statements/within
      Balance Sheets:Electric
      Generation, Transmission and Distribution Revenues
              
              
              (1,429
              )
              
              
              (3,586
              )
              
              
              (2,774
              )
              
              
              (4,319
              )
              
              
              -
              
              
              
              -Fuel
      and Other Consumables Used for Electric Generation
              
              
              (45
              )
              
              
              (21
              )
              
              
              (24
              )
              
              
              (32
              )
              
              
              (23
              )
              
              
              (25
              )Purchased
      Electricity for Resale
              
              
              1,038
              
              
              
              2,576
              
              
              
              2,033
              
              
              
              3,120
              
              
              
              -
              
              
              
              -Depreciation
      and Amortization Expense
              
              
              -
              
              
              
              -
              
              
              
              (4
              )
              
              
              3
              
              
              
              -
              
              
              
              -Interest
      Expense
              
              
              1,251
              
              
              
              -
              
              
              
              759
              
              
              
              (158
              )
              
              
              137
              
              
              
              622Property,
      Plant and Equipment
              
              
              (26
              )
              
              
              (11
              )
              
              
              (13
              )
              
              
              (19
              )
              
              
              (13
              )
              
              
              (10
              )Regulatory
      Assets
              
              
              3,800
              
              
              
              -
              
              
              
              457
              
              
              
              -
              
              
              
              -
              
              
              
              -Regulatory
      Liabilities
              
              
              (5,324
              )
              
              
              -
              
              
              
              (693
              )
              
              
              -
              
              
              
              -
              
              
              
              -Ending
      Balance in AOCI as of
                September
      30, 2009
              
              $
              (6,405
              )
              
              $
              232
              
              
              $
              (9,531
              )
              
              $
              12,835
              
              
              $
              (849
              )
              
              $
              (5,142
              )
 
  Cash flow
hedges included in Accumulated Other Comprehensive Income (Loss) on the
Condensed Balance Sheets at September 30, 2009 were:
 
 Impact
of Cash Flow Hedges on the Registrant Subsidiaries’
 Condensed
Balance Sheets
 September
30, 2009
 
 Hedging
      Assets (a)
              
              Hedging
      Liabilities (a)
              
              AOCI
      Gain (Loss) Net of TaxInterest
      Rate
              
              
              
              Interest
      Rate
              
              
              
              Interest
      Rateand
      Foreign
              
              
              
              and
      Foreign
              
              
              
              and
      ForeignCommodity
              
              Currency
              
              Commodity
              
              Currency
              
              Commodity
              
              CurrencyCompany
              (in
      thousands)APCo
              
              $
              3,371
              
              
              $
              -
              
              
              $
              (3,393
              )
              
              $
              -
              
              
              $
              462
              
              
              $
              (6,867
              )CSPCo
              
              
              1,770
              
              
              
              -
              
              
              
              (1,798
              )
              
              
              -
              
              
              
              232
              
              
              
              -I&M
              
              
              1,718
              
              
              
              -
              
              
              
              (1,734
              )
              
              
              -
              
              
              
              235
              
              
              
              (9,766
              )OPCo
              
              
              2,066
              
              
              
              -
              
              
              
              (2,062
              )
              
              
              -
              
              
              
              323
              
              
              
              12,512PSO
              
              
              85
              
              
              
              -
              
              
              
              (538
              )
              
              
              -
              
              
              
              (282
              )
              
              
              (567
              )SWEPCo
              
              
              81
              
              
              
              6
              
              
              
              -
              
              
              
              (25
              )
              
              
              65
              
              
              
              (5,207
              )
 
 
 Expected
      to be Reclassified toNet
      Income During the NextTwelve
      MonthsMaximum
      Term forInterest
      Rate
              
              Exposure
      toand
      Foreign
              
              Variability
      of FutureCommodity
              
              Currency
              
              Cash
      FlowsCompany
              (in
      thousands)
              
              (in
      months)APCo
              
              $
              751
              
              
              $
              (1,459
              )
              
              
              17CSPCo
              
              
              388
              
              
              
              -
              
              
              
              17I&M
              
              
              381
              
              
              
              (1,007
              )
              
              
              17OPCo
              
              
              497
              
              
              
              1,359
              
              
              
              17PSO
              
              
              (267
              )
              
              
              (142
              )
              
              
              15SWEPCo
              
              
              57
              
              
              
              (829
              )
              
              
              38
 
 (a)
              Hedging
      Assets and Hedging Liabilities are 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
 
 AEPSC, on
behalf of 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.  AEPSC, on behalf
of 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.
 
 AEPSC, on
behalf of 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 September 30, 2009.
 
 Amount
      of Collateral the
              
              AmountRegistrant
      Subsidiaries
              
              Attributable
      toAggregate
      Fair
              
              Would
      Have Been
              
              RTO
      and ISOValue
      Contracts
              
              Required
      to Post
              
              ActivitiesCompany
              
              (in
      thousands)APCo
              
              $
              9,340
              
              
              $
              9,340
              
              
              $
              8,699CSPCo
              
              
              4,950
              
              
              
              4,950
              
              
              
              4,610I&M
              
              
              4,772
              
              
              
              4,772
              
              
              
              4,445OPCo
              
              
              5,677
              
              
              
              5,677
              
              
              
              5,288PSO
              
              
              3,180
              
              
              
              3,180
              
              
              
              2,259SWEPCo
              
              
              3,782
              
              
              
              3,782
              
              
              
              2,687
 
 As of
September 30, 2009, the Registrant Subsidiaries were not required to post any
collateral.
 
 In
addition, a majority of the Registrant Subsidiaries’ non-exchange traded
commodity contracts contain cross-default provisions that, if triggered, would
permit the counterparty to declare a default and require settlement of the
outstanding payable.  These cross-default provisions could be
triggered if there was a non-performance event under borrowed debt in excess of
$50 million.  On an ongoing basis, AEPSC’s risk management
organization assesses the appropriateness of these cross-default provisions in
the contracts.  Management believes that a non-performance event under
these provisions is unlikely.  The following table represents the fair
value of these derivative liabilities subject to cross-default provisions prior
to consideration of contractual netting arrangements, the amount this exposure
has been reduced by cash collateral posted by the Registrant Subsidiaries and if
a cross-default provision would have been triggered, the settlement amount that
would be required after considering the Registrant Subsidiaries’ contractual
netting arrangements as of September 30, 2009:
 
 Liabilities
      of Contracts with Cross Default Provisions prior to Contractual
      Netting Arrangements
              
              
              Amount
      of Cash Collateral Posted
              
              Additional
      Settlement Liability if Cross Default Provision is
    TriggeredCompany
              
              (in
      thousands)APCo
              
              $
              239,073
              
              
              $
              3,315
              
              
              $
              43,244CSPCo
              
              
              126,514
              
              
              
              1,757
              
              
              
              22,841I&M
              
              
              122,614
              
              
              
              1,694
              
              
              
              22,281OPCo
              
              
              158,388
              
              
              
              2,015
              
              
              
              35,933PSO
              
              
              6,760
              
              
              
              -
              
              
              
              3,151SWEPCo
              
              
              5,664
              
              
              
              -
              
              
              
              1,027
 
 9.
              FAIR VALUE
      MEASUREMENTS
 
 With the
adoption of new accounting guidance, the Registrant Subsidiaries are required to
provide certain fair value disclosures which were previously only required in
the annual report.  The new accounting guidance did not change the
method to calculate the amounts reported on the balance sheets.
 
 Fair
Value Measurements of Long-term Debt
 
 The fair
values of Long-term Debt are based on quoted market prices, without credit
enhancements, for the same or similar issues and the current interest rates
offered for instruments with similar maturities.  These instruments
are not marked-to-market.  The estimates presented are not necessarily
indicative of the amounts that could be realized in a current market
exchange.
 
 The book
values and fair values of Long-term Debt for the Registrant Subsidiaries at
September 30, 2009 and December 31, 2008 are summarized in the following
table:
 
 September
      30, 2009
              
              
              December
      31, 2008Book
      Value
              
              
              Fair
      Value
              
              
              Book
      Value
              
              
              Fair
      ValueCompany
              
              (in
      thousands)APCo
              
              $
              3,372,360
              
              
              $
              3,605,111
              
              
              $
              3,174,512
              
              
              $
              2,858,278CSPCo
              
              
              1,536,291
              
              
              
              1,613,545
              
              
              
              1,443,594
              
              
              
              1,410,609I&M
              
              
              2,077,699
              
              
              
              2,187,235
              
              
              
              1,377,914
              
              
              
              1,308,712OPCo
              
              
              3,242,299
              
              
              
              3,366,787
              
              
              
              3,039,376
              
              
              
              2,953,131PSO
              
              
              868,738
              
              
              
              913,767
              
              
              
              884,859
              
              
              
              823,150SWEPCo
              
              
              1,475,152
              
              
              
              1,555,651
              
              
              
              1,478,149
              
              
              
              1,358,122
 
 Fair
Value Measurements of Trust Assets for Decommissioning and SNF
Disposal
 
 I&M
records securities held in trust funds for decommissioning nuclear facilities
and for the disposal of SNF at fair value.  I&M classifies
securities in the trust funds as available-for-sale due to their long-term
purpose.  The assessment of whether an investment in a debt security
has suffered an other-than-temporary impairment is based on whether the investor
has the intent to sell or more likely than not will be required to sell the debt
security before recovery of its amortized costs.  The assessment of
whether an investment in an equity security has suffered an other-than-temporary
impairment, among other things, is based on whether the  investor has
the ability and intent to hold the investment to recover its
value.  Other-than-temporary impairments for investments in both debt
and equity securities are considered realized losses as a result of securities
being managed by an external investment management firm.  The external
investment management firm makes specific investment decisions regarding the
equity and debt investments held in these trusts and generally intends to sell
debt securities in an unrealized loss position as part of a tax optimization
strategy.  I&M records unrealized gains and other-than-temporary
impairments from securities in these trust funds as adjustments to the
regulatory liability account for the nuclear decommissioning trust funds and to
regulatory assets or liabilities for the SNF disposal trust funds in accordance
with their treatment in rates.  The gains, losses or
other-than-temporary impairments shown below did not affect earnings or
AOCI.  The trust assets are recorded by jurisdiction and may not be
used for another jurisdictions’ liabilities.  Regulatory approval is
required to withdraw decommissioning funds.
 
 The
following is a summary of nuclear trust fund investments at September 30, 2009
and December 31, 2008:
 
 September
      30, 2009
              
              December
      31, 2008Estimated
              
              Gross
              
              Other-Than-
              
              Estimated
              
              Gross
              
              Other-Than-Fair
              
              Unrealized
              
              Temporary
              
              Fair
              
              Unrealized
              
              TemporaryValue
              
              Gains
              
              Impairments
              
              Value
              
              Gains
              
              Impairments(in
      millions)Cash
              
              $
              19
              
              
              $
              -
              
              
              $
              -
              
              
              $
              18
              
              
              $
              -
              
              
              $
              -Debt
      Securities
              
              
              780
              
              
              
              35
              
              
              
              (2
              )
              
              
              773
              
              
              
              52
              
              
              
              (3
              )Equity
      Securities
              
              
              565
              
              
              
              223
              
              
              
              (135
              )
              
              
              469
              
              
              
              89
              
              
              
              (82
              )Spent
      Nuclear Fuel and Decommissioning Trusts
              
              $
              1,364
              
              
              $
              258
              
              
              $
              (137
              )
              
              $
              1,260
              
              
              $
              141
              
              
              $
              (85
              )
 
 The
following table provides the securities activity within the decommissioning and
SNF trusts for the three and nine months ended September 30, 2009:
 Gross
      RealizedProceeds
      From
              
              Purchases
              
              Gross
      Realized Gains
              
              Losses
      onInvestment
      Sales
              
              of
      Investments
              
              on
      Investment Sales
              
              Investment
      Sales(in
      millions)Three
      Months Ended
              
              $
              113
              
              
              $
              129
              
              
              $
              1
              
              
              $
              -Nine
      Months Ended
              
              
              524
              
              
              
              571
              
              
              
              10
              
              
              
              (1
              )
 
 The
adjusted cost of debt securities was $745 million and $721 million as of
September 30, 2009 and December 31, 2008, respectively.
 
 The fair
value of debt securities held in the nuclear trust funds, summarized by
contractual maturities, at September 30, 2009 was as follows:
 Fair
      Valueof
      DebtSecurities(in
      millions)Within
      1 year
              
              $
              271
      year – 5 years
              
              
              2175
      years – 10 years
              
              
              241After
      10 years
              
              
              295Total
              
              $
              780
  Fair
Value Measurements of Financial Assets and Liabilities
 
 As
described in the 2008 Annual Report, the accounting guidance for “Fair Value
Measurements and Disclosures” 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.
 
 Exchange
traded derivatives, namely futures contracts, are generally fair valued based on
unadjusted quoted prices in active markets and are classified within Level
1.  Level 2 inputs primarily consist of OTC broker quotes in
moderately active or less active markets, as well as exchange traded contracts
where there is insufficient market liquidity to warrant inclusion in Level
1.  Where observable inputs are available for substantially the full
term of the asset or liability, the instrument is categorized in Level
2.  Certain OTC and bilaterally executed derivative instruments are
executed in less active markets with a lower availability of pricing
information.  In addition, long-dated and illiquid complex or
structured transactions and FTRs can introduce the need for internally developed
modeling inputs based upon extrapolations and assumptions of observable market
data to estimate fair value.  When such inputs have a significant
impact on the measurement of fair value, the instrument is categorized in Level
3.  Valuation models utilize various inputs that include quoted prices
for similar assets or liabilities in active markets, quoted prices for identical
or similar assets or liabilities in inactive markets, market corroborated inputs
(i.e. inputs derived principally from, or correlated to, observable market data)
and other observable inputs for the asset or liability.
 
 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 September 30, 2009 and December 31, 2008.  As
required by the accounting guidance for “Fair Value Measurements and
Disclosures,” 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.  There have not been any significant
changes in AEP’s valuation techniques.
 
 Assets
and Liabilities Measured at Fair Value on a Recurring Basis as of September 30,
2009
 APCoLevel
      1
              
              
              Level
      2
              
              
              Level
      3
              
              
              Other
              
              
              TotalAssets:
              
              (in
      thousands)Other
      Cash Deposits (d)
              
              $
              421
              
              
              $
              -
              
              
              $
              -
              
              
              $
              51
              
              
              $
              472Risk
      Management AssetsRisk
      Management Contracts (a)
              
              
              5,625
              
              
              
              637,506
              
              
              
              27,559
              
              
              
              (542,921
              )
              
              
              127,769Cash
      Flow and Fair Value Hedges (a)
              
              
              -
              
              
              
              6,518
              
              
              
              -
              
              
              
              (3,147
              )
              
              
              3,371Dedesignated
      Risk Management Contracts (b)
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              10,047
              
              
              
              10,047Total
      Risk Management Assets
              
              
              5,625
              
              
              
              644,024
              
              
              
              27,559
              
              
              
              (536,021
              )
              
              
              141,187Total
      Assets
              
              $
              6,046
              
              
              $
              644,024
              
              
              $
              27,559
              
              
              $
              (535,970
              )
              
              $
              141,659Liabilities:Risk
      Management LiabilitiesRisk
      Management Contracts (a)
              
              $
              6,116
              
              
              $
              603,805
              
              
              $
              3,911
              
              
              $
              (566,033
              )
              
              $
              47,799Cash
      Flow and Fair Value Hedges (a)
              
              
              -
              
              
              
              6,540
              
              
              
              -
              
              
              
              (3,147
              )
              
              
              3,393DETM
      Assignment (c)
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              3,464
              
              
              
              3,464Total
      Risk Management Liabilities
              
              $
              6,116
              
              
              $
              610,345
              
              
              $
              3,911
              
              
              $
              (565,716
              )
              
              $
              54,656
  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 September 30,
2009
 CSPCoLevel
      1
              
              
              Level
      2
              
              
              Level
      3
              
              
              Other
              
              
              TotalAssets:
              
              (in
      thousands)Other
      Cash Deposits (d)
              
              $
              20,056
              
              
              $
              -
              
              
              $
              -
              
              
              $
              21
              
              
              $
              20,077Risk
      Management AssetsRisk
      Management Contracts (a)
              
              
              2,981
              
              
              
              335,327
              
              
              
              14,603
              
              
              
              (285,521
              )
              
              
              67,390Cash
      Flow and Fair Value Hedges (a)
              
              
              -
              
              
              
              3,429
              
              
              
              -
              
              
              
              (1,659
              )
              
              
              1,770Dedesignated
      Risk Management Contracts (b)
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              5,325
              
              
              
              5,325Total
      Risk Management Assets
              
              
              2,981
              
              
              
              338,756
              
              
              
              14,603
              
              
              
              (281,855
              )
              
              
              74,485Total
      Assets
              
              $
              23,037
              
              
              $
              338,756
              
              
              $
              14,603
              
              
              $
              (281,834
              )
              
              $
              94,562Liabilities:Risk
      Management LiabilitiesRisk
      Management Contracts (a)
              
              $
              3,241
              
              
              $
              317,618
              
              
              $
              2,071
              
              
              $
              (297,767
              )
              
              $
              25,163Cash
      Flow and Fair Value Hedges (a)
              
              
              -
              
              
              
              3,457
              
              
              
              -
              
              
              
              (1,659
              )
              
              
              1,798DETM
      Assignment (c)
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              1,836
              
              
              
              1,836Total
      Risk Management Liabilities
              
              $
              3,241
              
              
              $
              321,075
              
              
              $
              2,071
              
              
              $
              (297,590
              )
              
              $
              28,797
 
 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 September 30,
2009
 I&MLevel
      1
              
              
              Level
      2
              
              
              Level
      3
              
              
              Other
              
              
              TotalAssets:
              
              (in
      thousands)Risk
      Management AssetsRisk
      Management Contracts (a)
              
              $
              2,874
              
              
              $
              331,776
              
              
              $
              14,087
              
              
              $
              (282,877
              )
              
              $
              65,860Cash
      Flow and Fair Value Hedges (a)
              
              
              -
              
              
              
              3,323
              
              
              
              -
              
              
              
              (1,605
              )
              
              
              1,718Dedesignated
      Risk Management Contracts (b)
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              5,134
              
              
              
              5,134Total
      Risk Management Assets
              
              
              2,874
              
              
              
              335,099
              
              
              
              14,087
              
              
              
              (279,348
              )
              
              
              72,712Spent
      Nuclear Fuel and Decommissioning TrustsCash
      and Cash Equivalents (e)
              
              
              -
              
              
              
              9,597
              
              
              
              -
              
              
              
              9,136
              
              
              
              18,733Debt
      Securities (f)
              
              
              -
              
              
              
              780,227
              
              
              
              -
              
              
              
              -
              
              
              
              780,227Equity
      Securities (g)
              
              
              565,482
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              565,482Total Spent Nuclear Fuel and
      Decommissioning Trusts
              
              
              565,482
              
              
              
              789,824
              
              
              
              -
              
              
              
              9,136
              
              
              
              1,364,442Total
      Assets
              
              $
              568,356
              
              
              $
              1,124,923
              
              
              $
              14,087
              
              
              $
              (270,212
              )
              
              $
              1,437,154Liabilities:Risk
      Management LiabilitiesRisk
      Management Contracts (a)
              
              $
              3,125
              
              
              $
              314,195
              
              
              $
              2,002
              
              
              $
              (294,694
              )
              
              $
              24,628Cash
      Flow and Fair Value Hedges (a)
              
              
              -
              
              
              
              3,339
              
              
              
              -
              
              
              
              (1,605
              )
              
              
              1,734DETM
      Assignment (c)
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              1,770
              
              
              
              1,770Total
      Risk Management Liabilities
              
              $
              3,125
              
              
              $
              317,534
              
              
              $
              2,002
              
              
              $
              (294,529
              )
              
              $
              28,132
 
 
 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 September 30,
2009
 OPCoLevel
      1
              
              
              Level
      2
              
              
              Level
      3
              
              
              Other
              
              
              TotalAssets:
              
              (in
      thousands)Other
      Cash Deposits (d)
              
              $
              1,075
              
              
              $
              -
              
              
              $
              -
              
              
              $
              24
              
              
              $
              1,099Risk
      Management AssetsRisk
      Management Contracts (a)
              
              
              3,419
              
              
              
              456,035
              
              
              
              16,801
              
              
              
              (389,110
              )
              
              
              87,145Cash
      Flow and Fair Value Hedges (a)
              
              
              -
              
              
              
              3,987
              
              
              
              -
              
              
              
              (1,921
              )
              
              
              2,066Dedesignated
      Risk Management Contracts (b)
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              6,108
              
              
              
              6,108Total
      Risk Management Assets
              
              
              3,419
              
              
              
              460,022
              
              
              
              16,801
              
              
              
              (384,923
              )
              
              
              95,319Total
      Assets
              
              $
              4,494
              
              
              $
              460,022
              
              
              $
              16,801
              
              
              $
              (384,899
              )
              
              $
              96,418Liabilities:Risk
      Management LiabilitiesRisk
      Management Contracts (a)
              
              $
              3,717
              
              
              $
              436,519
              
              
              $
              2,415
              
              
              $
              (403,240
              )
              
              $
              39,411Cash
      Flow and Fair Value Hedges (a)
              
              
              -
              
              
              
              3,983
              
              
              
              -
              
              
              
              (1,921
              )
              
              
              2,062DETM
      Assignment (c)
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              2,105
              
              
              
              2,105Total
      Risk Management Liabilities
              
              $
              3,717
              
              
              $
              440,502
              
              
              $
              2,415
              
              
              $
              (403,056
              )
              
              $
              43,578
 
 
 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 (d)
              
              $
              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 September 30,
2009
 PSOLevel
      1
              
              
              Level
      2
              
              
              Level
      3
              
              
              Other
              
              
              TotalAssets:
              
              (in
      thousands)Risk
      Management AssetsRisk
      Management Contracts (a)
              
              $
              818
              
              
              $
              25,801
              
              
              $
              16
              
              
              $
              (22,503
              )
              
              $
              4,132Cash
      Flow and Fair Value Hedges (a)
              
              
              -
              
              
              
              125
              
              
              
              -
              
              
              
              (40
              )
              
              
              85Total
      Risk Management Assets
              
              $
              818
              
              
              $
              25,926
              
              
              $
              16
              
              
              $
              (22,543
              )
              
              $
              4,217Liabilities:Risk
      Management LiabilitiesRisk
      Management Contracts (a)
              
              $
              771
              
              
              $
              26,446
              
              
              $
              11
              
              
              $
              (22,528
              )
              
              $
              4,700Cash
      Flow and Fair Value Hedges (a)
              
              
              -
              
              
              
              578
              
              
              
              -
              
              
              
              (40
              )
              
              
              538Total
      Risk Management Liabilities
              
              $
              771
              
              
              $
              27,024
              
              
              $
              11
              
              
              $
              (22,568
              )
              
              $
              5,238
  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 September 30,
2009
 SWEPCoLevel
      1
              
              
              Level
      2
              
              
              Level
      3
              
              
              Other
              
              
              TotalAssets:
              
              (in
      thousands)Risk
      Management AssetsRisk
      Management Contracts (a)
              
              $
              972
              
              
              $
              38,392
              
              
              $
              24
              
              
              $
              (33,668
              )
              
              $
              5,720Cash
      Flow and Fair Value Hedges (a)
              
              
              -
              
              
              
              237
              
              
              
              -
              
              
              
              (150
              )
              
              
              87Total
      Risk Management Assets
              
              $
              972
              
              
              $
              38,629
              
              
              $
              24
              
              
              $
              (33,818
              )
              
              $
              5,807Liabilities:Risk
      Management LiabilitiesRisk
      Management Contracts (a)
              
              $
              916
              
              
              $
              36,411
              
              
              $
              18
              
              
              $
              (33,707
              )
              
              $
              3,638Cash
      Flow and Fair Value Hedges (a)
              
              
              -
              
              
              
              175
              
              
              
              -
              
              
              
              (150
              )
              
              
              25Total
      Risk Management Liabilities
              
              $
              916
              
              
              $
              36,586
              
              
              $
              18
              
              
              $
              (33,857
              )
              
              $
              3,663
 
 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 the accounting
      guidance for “Derivatives and Hedging.”(b)
              “Dedesignated
      Risk Management Contracts” are contracts that were originally MTM but were
      subsequently elected as normal under the accounting guidance for
      “Derivatives and Hedging.”  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 September 30, 2009
              
              (in
      thousands)Balance
      as of July 1, 2009
              
              $
              13,900
              
              $
              7,372
              
              $
              7,135
              
              $
              9,410
              
              $
              12
              
              $
              15Realized
      (Gain) Loss Included in Net Income (or Changes in Net Assets)
      (a)
              
              
              (2,762)
              
              
              (1,465)
              
              
              (1,418)
              
              
              (2,087)
              
              
              (11)
              
              
              (13)Unrealized
      Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to
      Assets Still Held at the Reporting Date (a)
              
              
              -
              
              
              347
              
              
              -
              
              
              (185)
              
              
              -
              
              
              -Realized
      and Unrealized Gains (Losses) Included in Other Comprehensive
      Income
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Purchases,
      Issuances and Settlements
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Transfers
      in and/or out of Level 3 (b)
              
              
              2,322
              
              
              1,231
              
              
              1,192
              
              
              1,525
              
              
              -
              
              
              -Changes
      in Fair Value Allocated to Regulated Jurisdictions (c)
              
              
              10,188
              
              
              5,047
              
              
              5,176
              
              
              5,723
              
              
              4
              
              
              4Balance
      as of September 30, 2009
              
              $
              23,648
              
              $
              12,532
              
              $
              12,085
              
              $
              14,386
              
              $
              5
              
              $
              6
 
 APCo
              
              CSPCo
              
              I&M
              
              OPCo
              
              PSO
              
              SWEPCoNine
      Months Ended September 30, 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)
              
              
              (6,448)
              
              
              (3,621)
              
              
              (3,504)
              
              
              (4,473)
              
              
              3
              
              
              5Unrealized
      Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to
      Assets Still Held at the Reporting Date (a)
              
              
              -
              
              
              6,069
              
              
              -
              
              
              6,906
              
              
              -
              
              
              -Realized
      and Unrealized Gains (Losses) Included in Other Comprehensive
      Income
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Purchases,
      Issuances and Settlements
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Transfers
      in and/or out of Level 3 (b)
              
              
              (328)
              
              
              (184)
              
              
              (178)
              
              
              (228)
              
              
              -
              
              
              -Changes
      in Fair Value Allocated to Regulated Jurisdictions (c)
              
              
              22,415
              
              
              5,771
              
              
              11,415
              
              
              6,618
              
              
              4
              
              
              4Balance
      as of September 30, 2009
              
              $
              23,648
              
              $
              12,532
              
              $
              12,085
              
              $
              14,386
              
              $
              5
              
              $
              6
 
 Three
      Months Ended September 30, 2008
              
              APCo
              
              CSPCo
              
              I&M
              
              OPCo
              
              PSO
              
              SWEPCo(in
      thousands)Balance
      as of July 1, 2008
              
              $
              (18,560)
              
              $
              (11,122)
              
              $
              (10,675)
              
              $
              (13,245)
              
              $
              (23)
              
              $
              (45)Realized
      (Gain) Loss Included in Net Income   (or Changes in
                Net Assets) (a)
              
              
              4,466
              
              
              2,670
              
              
              2,561
              
              
              3,287
              
              
              4
              
              
              13Unrealized
      Gain (Loss) Included in Net Income (or Changes in Net Assets)
      Relating to Assets Still Held at the Reporting Date (a)
              
              
              -
              
              
              (1,317)
              
              
              -
              
              
              (1,574)
              
              
              -
              
              
              26Realized
      and Unrealized Gains (Losses)   Included in Other
                Comprehensive Income
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Purchases,
      Issuances and Settlements
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Transfers
      in and/or out of Level 3 (b)
              
              
              5,595
              
              
              3,360
              
              
              3,228
              
              
              3,914
              
              
              (1,249)
              
              
              (1,471)Changes
      in Fair Value Allocated to Regulated   Jurisdictions
      (c)
              
              
              3,858
              
              
              3,814
              
              
              2,373
              
              
              4,285
              
              
              61
              
              
              49Balance
      as of September 30, 2008
              
              $
              (4,641)
              
              $
              (2,595)
              
              $
              (2,513)
              
              $
              (3,333)
              
              $
              (1,207)
              
              $
              (1,428)
 
 Nine
      Months Ended September 30, 2008
              
              APCo
              
              CSPCo
              
              I&M
              
              OPCo
              
              PSO
              
              SWEPCo(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)
              
              
              332
              
              
              88
              
              
              105
              
              
              1,063
              
              
              170
              
              
              290Unrealized
      Gain (Loss) Included in Net Income (or Changes in Net Assets)
      Relating to Assets Still Held at the Reporting Date (a)
              
              
              -
              
              
              190
              
              
              -
              
              
              126
              
              
              -
              
              
              56Realized
      and Unrealized Gains (Losses)   Included in Other
                Comprehensive Income
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Purchases,
      Issuances and Settlements
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Transfers
      in and/or out of Level 3 (b)
              
              
              (731)
              
              
              (454)
              
              
              (430)
              
              
              (244)
              
              
              (1,249)
              
              
              (1,472)Changes
      in Fair Value Allocated to Regulated   Jurisdictions
      (c)
              
              
              (3,545)
              
              
              (2,156)
              
              
              (1,908)
              
              
              (2,671)
              
              
              115
              
              
              106Balance
      as of September 30, 2008
              
              $
              (4,641)
              
              $
              (2,595)
              
              $
              (2,513)
              
              $
              (3,333)
              
              $
              (1,207)
              
              $
              (1,428)
 
 (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.
 
 10.
              INCOME
      TAXES
 
 The
Registrant Subsidiaries join in the filing of a consolidated federal income tax
return with their affiliates in the AEP System.  The allocation of the
AEP System’s current consolidated federal income tax to the AEP System companies
allocates the benefit of current tax losses to the AEP System companies giving
rise to such losses in determining their current tax expense.  The tax
benefit of the Parent is allocated to its subsidiaries with taxable
income.  With the exception of the loss of the Parent, the method of
allocation reflects a separate return result for each company in the
consolidated group.
 
 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.  The years 2007 and 2008 are currently under
examination.  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.
  The
Registrant Subsidiaries file income tax returns in various state and local
jurisdictions.  These taxing authorities routinely examine their tax
returns and the Registrant Subsidiaries are currently under examination in
several state and local jurisdictions.  Management believes that
previously filed tax returns have positions that may be challenged by these tax
authorities.  However, management does not believe that the ultimate
resolution of these audits will materially impact net income.  With
few exceptions, the Registrant Subsidiaries are no longer subject to state or
local income tax examinations by tax authorities for years before
2000.
 
 The
Registrant Subsidiaries are changing the tax method of accounting for the
definition of a unit of property for generation assets.  This change
will provide a favorable cash flow benefit to the Registrant Subsidiaries in
2009 and 2010.
 
 Federal
Tax Legislation – Affecting APCo, CSPCo, I&M, OPCo, PSO and
SWEPCo
 
 The
American Recovery and Reinvestment Act of 2009 was signed into law by the
President in February 2009.  It provided for several new grant
programs and expanded tax credits and an extension of the 50% bonus depreciation
provision enacted in the Economic Stimulus Act of 2008.  The enacted
provisions are not expected to have a material impact on net income or financial
condition.  However, management forecasts the bonus depreciation
provision could provide a significant favorable cash flow benefit to the
Registrant Subsidiaries in 2009.
 
 11.       FINANCING
ACTIVITIES
 
 Long-term
Debt
 
 Long-term
debt and other securities issued, retired and principal payments made during the
first nine months of 2009 were:
 
 Principal
              
              Interest
              
              DueCompany
              
              Type
      of Debt
              
              Amount
              
              Rate
              
              Date(in
      thousands)
              
              (%)Issuances:APCo
              
              Senior
      Unsecured Notes
              
              $
              350,000
              
              7.95
              
              2020CSPCo
              
              Pollution
      Control Bonds
              
              
              60,000
              
              3.875
              
              2038CSPCo
              
              Pollution
      Control Bonds
              
              
              32,245
              
              5.80
              
              2038I&M
              
              Senior
      Unsecured Notes
              
              
              475,000
              
              7.00
              
              2019I&M
              
              Notes
      Payable
              
              
              102,300
              
              5.44
              
              2013I&M
              
              Pollution
      Control Bonds
              
              
              50,000
              
              6.25
              
              2025I&M
              
              Pollution
      Control Bonds
              
              
              50,000
              
              6.25
              
              2025OPCo
              
              Senior
      Unsecured Notes
              
              
              500,000
              
              5.375
              
              2021PSO
              
              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
              
              Senior
      Unsecured Notes
              
              $
              150,000
              
              6.60
              
              2009APCo
              
              Land
      Note
              
              
              12
              
              13.718
              
              2026OPCo
              
              Pollution
      Control Bonds
              
              
              218,000
              
              Variable
              
              2028-2029OPCo
              
              Notes
      Payable
              
              
              1,000
              
              6.27
              
              2009OPCo
              
              Notes
      Payable
              
              
              6,500
              
              7.21
              
              2009OPCo
              
              Notes
      Payable
              
              
              70,000
              
              7.49
              
              2009PSO
              
              Senior
      Unsecured Notes
              
              
              50,000
              
              4.70
              
              2009SWEPCo
              
              Notes
      Payable
              
              
              3,304
              
              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 September 30, 2009,
SWEPCo had $54 million of tax-exempt long-term debt sold at an auction rate of
0.862% that resets every 35 days.  The instruments under which the
bonds are issued allow for conversion to other short-term variable-rate
structures, term-put structures and fixed-rate structures.  In the
third quarter of 2009, OPCo reacquired $218 million of auction-rate debt related
to JMG with interest rates at the contractual maximum of 13%.  OPCo
was unable to refinance the debt without JMG's consent.  OPCo sought
approval from the PUCO to terminate the JMG relationship and received the
approval in June 2009.  In July 2009, OPCo purchased JMG's outstanding
equity ownership for $28 million which enabled OPCo to reacquire this
debt.
 
 On behalf
of the Registrant Subsidiaries, trustees held $321 million of reacquired
auction-rate tax-exempt long-term debt as shown in the following table,
including the $218 million related to JMG.  The Registrant
Subsidiaries plan to reissue the debt.
 September
      30, 2009Company
              (in
      thousands)APCo
              
              $
              17,500OPCo
              
              
              303,000
 
 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 September 30, 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 nine months ended September 30, 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
              
              September
      30, 2009
              
              LimitCompany
              (in
      thousands)APCo
              
              $
              420,925
              
              
              $
              -
              
              
              $
              203,296
              
              
              $
              -
              
              
              $
              (231,788
              )
              
              $
              600,000CSPCo
              
              
              203,306
              
              
              
              9,029
              
              
              
              124,804
              
              
              
              5,666
              
              
              
              (20,095
              )
              
              
              350,000I&M
              
              
              491,107
              
              
              
              161,072
              
              
              
              109,469
              
              
              
              46,765
              
              
              
              160,749
              
              
              
              500,000OPCo
              
              
              522,934
              
              
              
              367,743
              
              
              
              255,870
              
              
              
              94,655
              
              
              
              367,743
              
              
              
              600,000PSO
              
              
              77,976
              
              
              
              87,443
              
              
              
              56,378
              
              
              
              36,404
              
              
              
              8,450
              
              
              
              300,000SWEPCo
              
              
              62,871
              
              
              
              158,843
              
              
              
              18,530
              
              
              
              48,420
              
              
              
              106,662
              
              
              
              350,000
 
 
 The
maximum and minimum interest rates for funds either borrowed from or loaned to
the Utility Money Pool were as follows:
 Nine
      Months Ended September 30,2009
              
              2008Maximum
      Interest Rate
              
              2.28%
              
              5.37%Minimum
      Interest Rate
              
              0.27%
              
              2.91%
 
 The
average interest rates for funds borrowed from and loaned to the Utility Money
Pool for the nine months ended September 30, 2009 and 2008 are summarized for
all Registrant Subsidiaries in the following table:
 
 Average
      Interest Rate for Funds
              
              
              Average
      Interest Rate for FundsBorrowed
      from
              
              
              Loaned
      tothe
      Utility Money Pool for the
              
              
              the
      Utility Money Pool for theNine
      Months Ended September 30,
              
              
              Nine
      Months Ended September 30,2009
              
              
              2008
              
              
              2009
              
              
              2008CompanyAPCo
              
              
              1.14
              %
              
              
              3.62
              %
              
              
              -
              %
              
              
              3.25
              %CSPCo
              
              
              1.13
              %
              
              
              3.66
              %
              
              
              0.57
              %
              
              
              2.99
              %I&M
              
              
              1.46
              %
              
              
              3.19
              %
              
              
              0.49
              %
              
              
              -
              %OPCo
              
              
              1.21
              %
              
              
              3.24
              %
              
              
              0.38
              %
              
              
              3.62
              %PSO
              
              
              2.01
              %
              
              
              3.04
              %
              
              
              1.04
              %
              
              
              4.53
              %SWEPCo
              
              
              1.66
              %
              
              
              3.36
              %
              
              
              0.77
              %
              
              
              3.01
              %
 
 Short-term
Debt
 
 The
Registrant Subsidiaries’ outstanding short-term debt was as
follows:
 
 September
      30, 2009
              
              December
      31, 2008Outstanding
              
              Interest
              
              Outstanding
              
              InterestType
      of Debt
              
              Amount
              
              Rate
      (b)
              
              Amount
              
              Rate
      (b)Company
              
              
              
              (in
      thousands)
              
              
              
              (in
      thousands)SWEPCo
              
              Line
      of Credit – Sabine Mining Company (a)
              
              $
              5,273
              
              1.60%
              
              $
              7,172
              
              1.54%
 
 (a)
              Sabine
      Mining Company is a consolidated variable interest
  entity.(b)
              Weighted
      average rate.
 
 Credit
Facilities
 
 The
Registrant Subsidiaries and certain other companies in the AEP System have a
$627 million 3-year credit agreement.  Under the facility, letters of
credit may be issued.  As of September 30, 2009, $372 million of
letters of credit were issued by Registrant Subsidiaries under the $627 million
3-year credit agreement to support variable rate Pollution Control Bonds as
follows:
 
 AmountCompany
              
              (in
      thousands)APCo
              
              $
              126,716I&M
              
              
              77,886OPCo
              
              
              166,899
 
 The
Registrant Subsidiaries and certain other companies in the AEP System had a $350
million 364-day credit agreement that expired in April 2009.
 
 Sales
of Receivables
 
 AEP
Credit has a sale of receivables agreement with banks and commercial paper
conduits.  Under the sale of  receivables agreement, AEP
Credit sells an interest in the receivables it acquires from affiliated utility
subsidiaries to the commercial paper conduits and banks and receives
cash.
 
 In July
2009, AEP Credit renewed and increased its sale of receivables
agreement.  The sale of receivables agreement provides a commitment of
$750 million from bank conduits to purchase receivables.  This
agreement will expire in July 2010.  The previous sale of receivables
agreement provided a commitment of $700 million.
 
 
  
  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
Registrant Subsidiaries’ residential and commercial KWH sales appear to be
stable; nevertheless, some segments of their service territories are
experiencing slowdowns.  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.  For the first nine months of 2009 in comparison to
      the first nine months of 2008, off-system sales volumes decreased by 58%
      for the AEP System.
 
 ·
              Industrial KWH
      Sales – The AEP System’s industrial KWH sales for both the three
      and nine months ended September 30, 2009 were down
      17%.  Approximately half of the decrease for the first nine
      months of 2009 was due to cutbacks or closures by customers who produce
      primary metals served by APCo, CSPCo, I&M, OPCo, PSO and
      SWEPCo.  The Registrant Subsidiaries also experienced additional
      significant decreases in KWH sales to customers in the transportation,
      plastics, rubber and paper manufacturing
  industries.
 
 ·
              Risk of Loss of Major
      Industrial Customers – The Registrant Subsidiaries maintain close
      contact with each of their major industrial customers individually with
      respect to expected electric needs.  The Registrant Subsidiaries
      factor industrial customer analyses into their operational
      planning.  In September 2009, CSPCo’s and OPCo’s largest
      customer, Ormet, a major industrial customer currently operating at a
      reduced load of approximately 330 MW, (Ormet operated at an approximate
      500 MW load in 2008), announced that it will continue operations at this
      reduced level at least through the end of 2009.  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 were volatile at both a global and domestic level during the
last quarter of 2008 and first half of 2009.  The Registrant
Subsidiaries issued debt as follows during the first nine months of
2009:
 
 IssuanceCompany
              
              (in
      millions)APCo
              
              $
              350CSPCo
              
              
              92I&M
              
              
              677OPCo
              
              
              500PSO
              
              
              34
 
 Management
believes that the Registrant Subsidiaries have adequate liquidity, through the
Utility Money Pool and projected cash flows from their operations, to support
planned business operations and capital expenditures.  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 or repay debt maturities.  In September 2009, OPCo issued
$500 million of senior notes which may be used to pay at maturity some of its
outstanding debt due in 2010.
  Pension
Trust Fund
 
 Recent
recovery in the AEP System’s pension asset values and an IRS modification of
interest calculation rules reduced the estimated 2010 contribution for both
qualified and nonqualified pension plans to $62 million from a previously
disclosed estimated contribution of $453 million.  The present
estimated  contribution for both qualified and nonqualified pension
plans for 2011 is $389 million.  These estimates may vary
significantly based on market returns, changes in actuarial assumptions,
management discretion to contribute more than the minimum requirement and other
factors.  These amounts are allocated to companies in the AEP System,
including the Registrant Subsidiaries.
 
 Risk
Management Contracts
 
 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 excluding AFUDC for the Registrant Subsidiaries for
2010 are:
 
 BudgetedConstructionExpendituresCompany
              (in
      millions)APCo
              
              $
              356CSPCo
              
              
              256I&M
              
              
              258OPCo
              
              
              300PSO
              
              
              157SWEPCo
              
              
              444
 
 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.
 
 Fuel
Inventory
 
 Recent
coal consumption and projected consumption for the remainder of 2009 have
decreased significantly.  As a result of decreased coal consumption
and corresponding increases in fuel inventory, management is in continued
discussions with coal suppliers in an effort to better match deliveries with
current consumption forecast and to minimize the impact on fuel inventory costs,
carrying costs and cash.
 
 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 operate a money pool to
minimize the AEP System’s external short-term funding requirements and sell
accounts receivable to provide liquidity.  Under each credit facility,
$750 million may be issued 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.
  The
Registrant Subsidiaries and certain other companies in the AEP System entered
into a $627 million 3-year credit agreement.  The Registrant
Subsidiaries may issue LOCs under the credit facility.  Each
subsidiary has a borrowing/LOC limit under the credit facility.  As of
September 30, 2009, a total of $372 million of LOCs were issued under the 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$627
      million
              
              AgainstCredit
      Facility
              
              $627
      millionBorrowing/LOC
              
              Agreement
      atLimit
              
              September
      30, 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.
 
 Sales of Receivables Through
AEP Credit
 
 In July
2009, AEP Credit renewed and increased its sale of receivables
agreement.  The sale of receivables agreement provides a commitment of
$750 million from banks and commercial paper conduits to purchase receivables
from AEP Credit.  This agreement will expire in July
2010.  Management intends to extend or replace the sale of receivables
agreement.  The previous sale of receivables agreement provided a
commitment of $700 million.  At September 30, 2009, $530 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, which was amended by a rehearing entry in July
2009, that modified and approved CSPCo’s and OPCo’s ESPs that established
standard service offer rates.  The ESPs will be in effect through
2011.  The ESP order authorized revenue increases during the ESP
period and capped the overall revenue increases for CSPCo to 7% in 2009, 6% in
2010 and 6% in 2011 and for OPCo to 8% in 2009, 7% in 2010 and 8% in
2011.  CSPCo and OPCo implemented rates for the April 2009 billing
cycle.  In its July 2009 rehearing entry, the PUCO required CSPCo and
OPCo to reduce rates implemented in April 2009 by $22 million and $27 million,
respectively, on an annualized basis.  CSPCo and OPCo are collecting
the 2009 annualized revenue increase over the last nine months of
2009.
 
 The order
provides a FAC for the three-year period of the ESP.  The FAC increase
will be phased in to avoid having the resultant rate increases exceed 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 three-year ESP period will be recovered through a non-bypassable
surcharge over the period 2012 through 2018.  The FAC deferrals at
September 30, 2009 were $36 million and $238 million for CSPCo and OPCo,
respectively, inclusive of carrying charges at the weighted average cost of
capital.
 
 In August
2009, an intervenor filed for rehearing requesting, among other things, that the
PUCO order CSPCo and OPCo to cease and desist from charging ESP rates, to revert
to the rate stabilization plan rates and to compel a refund, including interest,
of the amounts collected by CSPCo and OPCo.  CSPCo and OPCo filed a
response stating the rates being charged by CSPCo and OPCo have been authorized
by the PUCO and there was no basis for precluding CSPCo and OPCo from continuing
to charge those rates.  In September 2009, certain intervenors filed
appeals of the March 2009 order and the July 2009 rehearing entry with the
Supreme Court of Ohio.  One of the intervenors, the Ohio Consumers’
Counsel, has asked the court to stay, pending the outcome of its appeal, a
portion of the authorized ESP rates which the Ohio Consumers’ Counsel
characterizes as being retroactive.  In
October 2009, the Supreme Court of Ohio denied the Ohio Consumers'
Counsel's request for a stay and granted motions to dismiss both
appeals.
 
 In
September 2009, CSPCo and OPCo filed their initial quarterly FAC filing with the
PUCO and adjusted their estimated phase-in deferrals to the amounts shown in the
filing, which was a decrease in the FAC deferral of $6 million for CSPCo and an
increase in the FAC deferral of $17 million for OPCo.  An order
approving the FAC 2009 filings will not be issued until a financial audit and
prudency review is performed by independent third parties and reviewed by the
PUCO.
 
 In
October 2009, the PUCO convened a workshop to begin to determine the methodology
for the Significantly Excessive Earnings Test (SEET).  The SEET
requires the PUCO to determine, following the end of each year of the ESP, if
rate adjustments included in the ESP resulted in significantly excessive
earnings.  This will be determined by measuring whether the utility’s
earned return on common equity is significantly in excess of the return on
common equity that was earned during the same period by publicly traded
companies, including utilities, which have comparable business and financial
risk.  In the March 2009 ESP order, the PUCO determined that
off-system sales margins and FAC deferral phase-in credits should be excluded
from the SEET methodology.  However, the July 2009 PUCO rehearing
entry deferred those issues to the SEET workshop.  If the rate
adjustments, in the aggregate, result in significantly excessive earnings, the
excess amount would 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 workshop is completed, the PUCO issues SEET guidelines, a
SEET filing is made by CSPCo and OPCo in 2010 and the PUCO issues an order
thereon. The SEET workshop will also determine whether CSPCo’s and OPCo’s
earnings will be measured on an individual company basis or on a combined
CSPCo/OPCo basis.
 
 In
October 2009, an intervenor filed a complaint for writ of prohibition with the
Supreme Court of Ohio requesting the Court to prohibit CSPCo and OPCo from
billing and collecting any ESP rate increases that the PUCO authorized as the
intervenor believes the PUCO's statutory jurisdiction over CSPCo's and OPCo's
ESP application ended on December 28, 2008, which was 150 days after the filing
of the ESP applications.  CSPCo and OPCo plan on filing a response in
opposition to the complaint for writ of prohibition.
 
 Management
is unable to predict the outcome of the various ongoing proceedings and
litigation discussed above including the SEET, the FAC filing review and the
various appeals to the Supreme Court of Ohio relating to the ESP
order.  If these proceedings result in adverse rulings, it could have
an adverse effect on future net income and cash flows.
 
 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
              
              $
              321
              (d)
              $
              199
              (d)
              Gas
              
              Combined-cycle
              
              580
              
              2013SWEPCo
              
              Stall
              
              Louisiana
              
              
              386
              
              
              364
              
              Gas
              
              Combined-cycle
              
              500
              
              2010SWEPCo
              
              Turk
              (e)
              Arkansas
              
              
              1,633
              (e)
              
              622
              (f)
              Coal
              
              Ultra-supercritical
              
              600
              (e)
              2012APCo
              
              Mountaineer
              (g)
              West
      Virginia
              
              
              
              (g)
              
              
              
              Coal
              
              IGCC
              
              629
              
              
              (g)CSPCo/OPCo
              
              Great
      Bend
              (g)
              Ohio
              
              
              
              (g)
              
              
              
              Coal
              
              IGCC
              
              629
              
              
              (g)
 
 (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)
              During
      2009, AEGCo suspended construction of the Dresden Plant.  As a
      result, AEGCo has stopped recording AFUDC and will resume recording AFUDC
      once construction is resumed.(e)
              SWEPCo
      owns approximately 73%, or 440 MW, totaling $1.2 billion in capital
      investment.  See “Turk Plant” section below.(f)
              Amount
      represents SWEPCo’s CWIP balance only.(g)
              Construction
      of IGCC plants is subject to regulatory
  approvals.
 
 Turk
Plant
 
 In
November 2007, the APSC granted approval for SWEPCo to build the Turk Plant in
Arkansas by issuing a Certificate of Environmental Compatibility and Public Need
(CECPN).  Certain intervenors appealed the APSC’s decision to grant
the CECPN to the Arkansas Court of Appeals.  In January 2009, the APSC
granted additional CECPNs allowing SWEPCo to construct Turk-related transmission
facilities.  Intervenors also appealed these CECPN orders to the
Arkansas Court of Appeals.
 
 In June
2009, the Arkansas Court of Appeals issued a unanimous decision that, if upheld
by the Arkansas Supreme Court, would reverse the APSC’s grant of the CECPN
permitting construction of the Turk Plant to serve Arkansas retail
customers.  The decision was based upon the Arkansas Court of Appeals’
interpretation of the statute that governs the certification process and its
conclusion that the APSC did not fully comply with that process.  The
Arkansas Court of Appeals concluded that SWEPCo’s need for base load capacity,
the construction and financing of the Turk generating plant and the proposed
transmission facilities’ construction and location should all have been
considered by the APSC in a single docket instead of separate
dockets.  In October 2009, the Arkansas Supreme Court granted the
petitions filed by SWEPCo and the APSC to review the Arkansas Court of Appeals
decision.  While the appeal is pending, SWEPCo is continuing
construction of the Turk Plant.
 
 If the
decision of the Court of Appeals is not reversed by the Supreme Court of
Arkansas, SWEPCo and the other joint owners of the Turk Plant will evaluate
their options.  Depending on the time taken by the Arkansas Supreme
Court to consider the case and the reasoning of the Arkansas Supreme Court when
it acts on SWEPCo’s and the APSC’s petitions, the construction schedule and/or
the cost could be adversely affected.  Should the appeals by the APSC
and SWEPCo be unsuccessful, additional proceedings or alternative contractual
ownership and operational responsibilities could be required.
 
 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 and related transmission costs, (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 as
being unlawful.  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. If the cost cap restrictions are upheld and construction or CO2 emission
costs exceed the restrictions or if the intervenor appeal is successful, it
could have an adverse effect on net income, cash flows and possibly financial
condition.
 A request
to stop pre-construction activities at the site was filed in Federal District
Court by certain 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, which was granted in March 2009.
 
 In
November 2008, SWEPCo received the required air permit approval from the
Arkansas Department of Environmental Quality and commenced construction at the
site.  In December 2008, certain parties filed an appeal of the air
permit approval 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 the appeal of the Turk Plant’s air permit is
heard.  In June 2009, hearings on the air permit appeal were held at
the APCEC.  A decision is still pending and not expected until
2010.  These same parties have filed a petition with the Federal EPA
to review the air permit.  The petition will be acted on by December
2009 according to the terms of a recent settlement between the petitioners and
the Federal EPA.  The Turk Plant cannot be placed into service without
an air permit.  In August 2009, these same parties filed a petition
with the APCEC to halt construction of the Turk Plant.  In September
2009, the APCEC voted to allow construction of the Turk Plant to continue and
rejected the request for a stay.  If the air permit were to be
remanded or ultimately revoked, construction of the Turk Plant would be
suspended or cancelled.
 
 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 an inadvertent impact on approximately 2.5
acres of wetlands at the Turk Plant construction site prior to the receipt of
the permit.  The U.S. Army Corps of Engineers directed SWEPCo to cease
further work impacting the wetland areas.  Construction has continued
on other areas outside of the proposed Army Corps of Engineers permitted areas
of the Turk Plant pending the Army Corps of Engineers review.  SWEPCo
has entered into a Consent Agreement and Final Order with the Federal EPA to
resolve liability for the inadvertent impact and agreed to pay a civil penalty
of approximately $29 thousand.
 
 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.  To date, the
report’s effect is only advisory, but if legislation is passed as a result of
the findings in the Commission’s report, it could impact SWEPCo’s ability to
complete construction on schedule in 2012 and on budget.
 
 If the
Turk Plant cannot be completed and placed in service, SWEPCo would seek approval
to recover its prudently incurred capitalized construction costs including any
cancellation fees and a return on unrecovered balances through rates in all of
its jurisdictions.  As of September 30, 2009, and excluding costs
attributable to its joint owners, SWEPCo has capitalized approximately $646
million of expenditures (including AFUDC and capitalized interest, and related
transmission costs of $24 million) and has contractual construction commitments
for an additional $515 million (including related transmission costs of $1
million).  As of September 30, 2009, if the plant had been cancelled,
SWEPCo would have incurred cancellation fees of $136 million (including
related transmission cancellation fees of $1 million).
 
 Management
believes that SWEPCo’s planning, certification and construction of the Turk
Plant to date have been in material compliance with all applicable laws and
regulations, except for the inadvertent wetlands intrusion discussed
above.  Further, management expects that SWEPCo will ultimately be
able to complete construction of the Turk Plant and related transmission
facilities and place those facilities in service.  However, if for any
reason SWEPCo is unable to complete the Turk Plant construction and place the
Turk Plant in service, it would adversely impact net income, cash flows and
possibly financial condition unless the resultant losses can be fully recovered,
with a return on unrecovered balances, through rates in all of its
jurisdictions.
 
 PSO
Purchase Power Agreement
 
 As a
result of the 2008 Request for Proposals following a December 2007 OCC order
that found PSO had a need for new base load generation by 2012, PSO and Exelon
Generation Company LLC, a subsidiary of Exelon Corporation, executed a long-term
purchase power agreement (PPA).  The PPA is for the annual purchase of
approximately 520 MW of electric generation from the 795 MW natural gas-fired
generating plant in Jenks, Oklahoma for a term of approximately ten years
beginning in June 2012.  In May 2009, an application seeking approval
was filed with the OCC.  In July 2009, OCC staff, the Independent
Evaluator and the Oklahoma Industrial Energy Consumers filed responsive
testimony in support of PSO’s proposed PPA with Exelon.  In August
2009, a settlement agreement was filed with the OCC.  In September
2009, the OCC approved the settlement agreement including the recovery of these
purchased power costs through a separate base load purchased power
rider.
  The American Recovery and
Reinvestment Act of 2009
 
 The
American Recovery and Reinvestment Act of 2009 was signed into law by the
President in February 2009.  It provided for several new grant
programs and expanded tax credits and an extension of the 50% bonus depreciation
provision enacted in the Economic Stimulus Act of 2008.  The enacted
provisions are not expected to have a material impact on net income or financial
condition.  However, management forecasts the bonus depreciation
provision could provide a significant favorable cash flow benefit to the
Registrant Subsidiaries in 2009 as follows:
 
 Company
              
              Amount(in
      millions)APCo
              
              $
              53CSPCo
              
              
              38I&M
              
              
              54OPCo
              
              
              38PSO
              
              
              27SWEPCo
              
              
              25
 
 In August
2009, the Registrant Subsidiaries applied with the U.S. Department of Energy
(DOE) for $411 million in federal stimulus money for gridSMART, clean coal
technology and hydro generation projects.  If granted, the funds will
provide capital and reduce the amount of money sought from
customers.  Management is unable to predict the likelihood of the DOE
granting the federal stimulus money to the Registrant Subsidiaries or the timing
of the DOE’s decision.  The requested federal stimulus money is
proposed for the following projects:
 
 Company
              Proposed
      Project
              Federal
      Stimulus Funds Requested(in
      millions)APCo
              Carbon
      Capture and Sequestration Demonstration Project at the Mountaineer
      Plant
              
              $
              334APCo
              Hydro
      Generation Modernization Project in London, W.V.
              
              
              2CSPCo
              gridSMART
              
              
              75
 
 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 and mercury from fossil fuel-fired power plants;
      and·
              Requirements
      under the Clean Water Act 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
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
 
 In June
2009, the U.S. House of Representatives passed the American Clean Energy and
Security Act (ACES).  ACES is a comprehensive energy and climate
change bill that includes a number of provisions that would directly affect the
Registrant Subsidiaries’ business.  ACES contains a combined energy
efficiency and renewable electricity standard beginning at 6% in 2012 and
increasing to 20% by 2020 of retail sales.  The proposed legislation
would also create a carbon capture and sequestration (CCS) program funded
through rates to accelerate the development of this technology as well as
significant funding through bonus allowances provided to CCS and establishes GHG
emission standards for new fossil fuel-fired electric generating
plants.  ACES creates an economy-wide cap and trade program for large
sources of GHG emissions that would reduce emissions by 17% in 2020 and just
over 80% by 2050 from 2005 levels.  A portion of the allowances under
the cap and trade program would be allocated to retail electric and gas
utilities, certain energy-intensive industries, small refiners and state
governments.  Some allowances would be
auctioned.   Bonus allowances would be available to encourage
energy efficiency, renewable energy and carbon sequestration
projects.  Consideration of climate legislation has now moved to the
Senate and the Senate released draft cap and trade legislation on September
30.  Until legislation is final, management is unable to predict its
impact on net income, cash flows and financial condition.
 
 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.  In September 2009, the Federal EPA issued
a final mandatory GHG reporting rule covering a broad range of facilities
emitting in excess of 25,000 tons of GHG emissions per year.  The
Federal EPA has also issued proposed light duty vehicle GHG emissions standards
for model years 2012-2016, and a proposed scheme to streamline and phase in
regulation of stationary source GHG emissions through the NSR’s prevention of
significant deterioration and CAA’s Title V permitting programs.  The
Federal EPA stated its intent to finalize the vehicle standards and permitting
rule in conjunction with or following a final endangerment finding, and is
reconsidering whether to include GHG emissions in a number of stationary source
standards, including standards that apply to electric utility
units.  Some of the policy approaches being discussed by the Federal
EPA 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 and that
reasonable and comprehensive legislative action is preferable.  Even
if reasonable CO2 and other
GHG emission standards are imposed, the standards could require significant
increases in capital expenditures and operating costs which would impact the
ultimate retirement of older, less-efficient, coal-fired
units.  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.
 
 Proposed Health Care
Legislation
 
 The U.S.
Congress, supported by President Obama, is debating health care reform that
could have a significant impact on the AEP System’s benefits and
costs.  The discussion centers around universal coverage, revenue
sources to keep it deficit neutral and changes to Medicare that could
significantly impact the AEP System’s employees and retirees and the benefits
and costs of the AEP System’s plans.  Until legislation is final, the
impact is impossible to predict.
 
 Adoption of New Accounting
Pronouncements
 
 The FASB
issued SFAS 141R “Business Combinations” improving financial reporting about
business combinations and their effects and FSP SFAS 141 (R)-1.  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, including
the FSP, effective January 1, 2009.  The Registrant Subsidiaries will
apply it to any future business combinations.  SFAS 141R is included
in the “Business Combinations” accounting guidance.
 
 The FASB
issued SFAS 160 “Noncontrolling Interests 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.  SFAS 160 is included in the “Consolidation” accounting
guidance.
 
 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.  The Registrant Subsidiaries adopted SFAS 161 effective
January 1, 2009.  SFAS 161 is included in the “Derivatives and
Hedging” accounting guidance.
 
 The FASB
issued SFAS 165 “Subsequent Events” (SFAS 165),incorporating guidance
on subsequent events into authoritative accounting literature and clarifying the
time following the balance sheet date which management reviewed for events and
transactions that may require disclosure in the financial
statements.  The Registrant Subsidiaries adopted this standard
effective second quarter of 2009.  The standard increased disclosure
by requiring disclosure of the date through which subsequent events have been
reviewed.  The standard did not change management’s procedures for
reviewing subsequent events.  SFAS 165 is included in the “Subsequent
Events” accounting guidance.
 
 The FASB
issued SFAS 168 “The FASB Accounting Standards CodificationTM and
the Hierarchy of Generally Accepted Accounting Principles” (SFAS 168)
establishing the FASB Accounting Standards CodificationTM as
the authoritative source of accounting principles for preparation of financial
statements and reporting in conformity with GAAP by nongovernmental
entities.  The Registrant Subsidiaries adopted SFAS 168 effective
third quarter of 2009.  It required an update of all references to
authoritative accounting literature.  SFAS 168 is included in the
“Generally Accepted Accounting Principles” accounting guidance.
 
 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.  With the
adoption of FSP SFAS 107-1 and APB 28-1, it is applied to the fair value of
long-term debt.  The application of this standard had an immaterial
effect on the fair value of debt outstanding.  EITF 08-5 is included
in the “Fair Value Measurements and Disclosures” accounting
guidance.
 
 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.  EITF 08-6 is included in the “Investments – Equity Method
and Joint Ventures” accounting guidance.
 
 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.  The Registrant Subsidiaries
adopted the standard effective second quarter of 2009.  This standard
increased the disclosure requirements related to financial
instruments.  FSP SFAS 107-1 and APB 28-1 is included in the
“Financial Instruments” accounting guidance.
 
 The FASB
issued FSP SFAS 115-2 and SFAS 124-2 “Recognition and Presentation of
Other-Than-Temporary Impairments”, 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.  The Registrant Subsidiaries adopted
the standard effective second quarter of 2009 with no impact on the financial
statements and increased disclosure requirements related to financial
instruments for I&M only.  FSP SFAS 115-2 and SFAS 124-2 is
included in the “Investments – Debt and Equity Securities” accounting
guidance.
 
 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.  SFAS 142-3 is included in the “Intangibles – Goodwill and
Other” accounting guidance.
 
 The FASB
issued SFAS 157-2 “Effective Date of FASB Statement No. 157” (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 2009.  SFAS 157-2 is included in the “Fair Value
Measurements and Disclosures” accounting guidance.
 
 The FASB
issued 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), 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.  The Registrant Subsidiaries adopted the standard effective
second quarter of 2009.  This standard had no impact on the financial
statements but increased disclosure requirements.  FSP SFAS 157-4 is
included in the “Fair Value Measurements and Disclosures” accounting guidance.
  Pronouncements
Effective in the Future
 
 The FASB
issued ASU 2009-05 “Measuring Liabilities at Fair Value” (ASU 2009-05) updating
the “Fair Value Measurement and Disclosures” accounting guidance.  The
guidance specifies the valuation techniques that should be used to fair value a
liability in the absence of a quoted price in an active market.  The
new accounting guidance is effective for interim and annual periods beginning
after the issuance date.  Although management has not completed an
analysis, management does not expect this update to have a material impact on
the financial statements.  The Registrant Subsidiaries will adopt ASU
2009-05 effective fourth quarter of 2009.
 
 The FASB
issued ASU 2009-12 “Investments in Certain Entities That Calculate Net Asset
Value per Share (or its Equivalent)” (ASU 2009-12) updating the “Fair Value
Measurement and Disclosures” accounting guidance for the fair value measurement
of investments in certain entities that calculate net asset value per share (or
its equivalent).  The guidance permits a reporting entity to measure
the fair value of an investment within its scope on the basis of the net asset
value per share of the investment (or its equivalent).  The new
accounting guidance is effective for interim and annual periods ending after
December 15, 2009.  Although management has not completed an analysis,
management does not expect this update to have a material impact on the
financial statements.  The Registrant Subsidiaries will adopt ASU
2009-12 effective fourth quarter of 2009.
 
 The FASB
issued ASU 2009-13 “Multiple-Deliverable Revenue Arrangements” (ASU 2009-13)
updating the “Revenue Recognition” accounting guidance by providing criteria for
separating consideration in multiple-deliverable arrangements.  It
establishes a selling price hierarchy for determining the price of a deliverable
and expands the disclosures related to a vendor’s multiple-deliverable revenue
arrangements.  The new accounting guidance is effective prospectively
for arrangements entered into or materially modified in years beginning after
June 15, 2010.  Although management has not completed an analysis,
management does not expect this update to have a material impact on the
financial statements.  The Registrant Subsidiaries will adopt ASU
2009-13 effective January 1, 2011.
 
 The FASB
issued SFAS 166 “Accounting for Transfers of Financial Assets” (SFAS 166)
clarifying when a transfer of a financial asset should be recorded as a
sale.  The standard defines participating interest to establish
specific conditions for a sale of a portion of a financial
asset.  This standard must be applied to all transfers after the
effective date.  SFAS 166 is effective for interim and annual
reporting in fiscal years beginning after November 15, 2009.  Early
adoption is prohibited.  Management continues to review the impact of
this standard.  The Registrant Subsidiaries will adopt SFAS 166
effective January 1, 2010.  SFAS 166 is included in the “Transfers and
Servicing” accounting guidance.
 
 The FASB
issued SFAS 167 “Amendments to FASB Interpretation No. 46(R)” (SFAS 167)
amending the analysis an entity must perform to determine if it has a
controlling interest in a variable interest entity (VIE).  This new
guidance provides that the primary beneficiary of a VIE must have
both:
 
 ·
              The
      power to direct the activities of the VIE that most significantly impact
      the VIE’s economic performance.·
              The
      obligation to absorb the losses of the entity that could potentially be
      significant to the VIE or the right to receive benefits from the entity
      that could potentially be significant to the
  VIE.
 
 The
standard also requires separate presentation on the face of the statement of
financial position for assets which can only be used to settle obligations of a
consolidated VIE and liabilities for which creditors do not have recourse to the
general credit of the primary beneficiary.  SFAS 167 is effective for
interim and annual reporting in fiscal years beginning after November 15,
2009.  Early adoption is prohibited.  Management continues
to review the impact of the changes in the consolidation guidance on the
financial statements.  This standard will increase the disclosure
requirements related to transactions with VIEs and may change the presentation
of consolidated VIE’s assets and liabilities on the balance
sheets.  The Registrant Subsidiaries will adopt SFAS 167 effective
January 1, 2010.  SFAS 167 is included in the “Consolidation”
accounting guidance.
 
 The FASB
issued FSP SFAS 132R-1 “Employers’ Disclosures about Postretirement Benefit Plan
Assets” (FSP SFAS 132R-1) providing additional disclosure guidance for pension
and OPEB plan assets.  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 132R-1 is included in the “Compensation – Retirement
Benefits” accounting guidance.
 
  
  CONTROLS
AND PROCEDURES
 
 During
the third 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
September 30, 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 third 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,” 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
 
 Turk Plant permits could be reversed
on appeal.  (Applies to AEP and
SWEPCo)
 
 In
November 2007, the APSC granted approval for SWEPCo to build the Turk Plant in
Arkansas by issuing a Certificate of Environmental Compatibility and Public Need
(CECPN).  Certain intervenors appealed the APSC’s decision to the
Arkansas Court of Appeals.  In June 2009, the Arkansas Court of
Appeals issued a unanimous decision that, if upheld by the Arkansas Supreme
Court, would reverse the APSC’s grant of the CECPN permitting construction of
the Turk Plant to serve Arkansas retail customers.  Both SWEPCo and
the APSC petitioned the Arkansas Supreme Court to review the Arkansas Court of
Appeals decision.
 
 In
November 2008, SWEPCo received the required air permit approval for the Turk
Plant from the Arkansas Department of Environmental Quality.  In
December 2008, certain parties filed an appeal of the air permit with the
Arkansas Pollution Control and Ecology Commission.  A decision on the
air permit is still pending and not expected until 2010.  These same
parties have filed a petition with the Federal EPA to review the air
permit.  The petition will be acted on by December 2009, according to
the terms of a recent settlement between the petitioners and the Federal
EPA.  The Turk Plant cannot be placed into service without an air
permit.  If SWEPCo is unable to complete the Turk Plant construction
and place the Turk Plant in service, it would adversely impact net income, cash
flow and possibly financial condition unless the resultant losses can be fully
recovered, with a return on unrecovered balances, through rates in all of its
jurisdictions.
  Rate recovery approved in Ohio may be
overturned on appeal or may not provide full recovery of fuel
costs.(Applies to AEP, OPCo and
CSPCo)
   In March
2009, the PUCO issued an order, which was amended by a rehearing entry in July
2009, that modified and approved CSPCo’s and OPCo’s ESPs.  The ESPs
will be in effect through 2011.  The ESP order authorized revenue
increases during the ESP period and capped the overall revenue increases through
a phase-in of the FAC.  The capped 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.  In its July 2009 rehearing entry, the PUCO required CSPCo and
OPCo to reduce rates implemented in April 2009 by $22 million and $27 million,
respectively, on an annualized basis.  The order provides a FAC for
the three-year period of the ESP.  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
three-year ESP period will be recovered through a non-bypassable surcharge over
the period 2012 through 2018.  In August 2009, an intervenor filed for
rehearing requesting, among other things, that the PUCO order CSPCo and OPCo to
cease and desist from charging ESP rates, to revert to the rate stabilization
plan rates and to compel a refund, including interest, of the amounts collected
by CSPCo and OPCo.  CSPCo and OPCo filed a response stating the rates
being charged by CSPCo and OPCo have been authorized by the PUCO and there was
no basis for precluding CSPCo and OPCo from continuing to charge those
rates. In
October 2009, an intervenor filed a complaint for writ of prohibition with the
Supreme Court of Ohio requesting the Court to prohibit CSPCo and OPCo from
billing and collecting any ESP rate increases that the PUCO authorized as the
intervenor believes the PUCO's statutory jurisdiction over CSPCo's and OPCo's
ESP application ended on December 28, 2008, which was 150 days after the filing
of the ESP applications.  CSPCo and OPCo plan on filing a response in
opposition to the complaint for writ of prohibition. If the
PUCO and/or the Supreme Court of Ohio reverses all or part of the rate recovery
or if deferred fuel costs are not fully recovered for other reasons, 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.  The order increased TCC’s
annual pretax income by approximately $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 appeals
are successful, it could have an adverse effect on future net income and cash
flows.
 
 Our request for rate recovery in
Texas may not be approved in its entirety.(Applies to AEP and
SWEPCo)
 
 In August
2009, SWEPCo filed a base rate case with the PUCT to increase non-fuel base
rates by approximately $75 million annually based on a requested return on
common equity of 11.5%.  If the PUCT denies all or part of the
requested rate recovery, it could have an adverse effect on future net income,
cash flows and financial condition.
 
 Our request for rate recovery in
Virginia may not be approved in its entirety.(Applies to AEP and
APCo)
 
 In July
2009, APCo filed a base rate case with the Virginia SCC requesting an increase
in the generation and distribution portions of its base rates of $169 million
(later adjusted to $154 million) annually and a 13.35% return on
equity.  If the Virginia SCC denies all or part of the requested 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 based on 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 rate case
issues.  In July 2009, the Oklahoma Supreme Court assigned the case to
the Court of Civil Appeals.  If the OCC, the Oklahoma Supreme Court
and/or the Court of Civil Appeals 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 additional recovery in Oklahoma may not be approved in its
entirety.
 In August
2009, PSO filed an application with the OCC requesting a Capital Reliability
Rider (CRR) to recover depreciation, taxes and return on PSO’s net capital
investments for generation, transmission and distribution assets that have been
placed into service from September 1, 2008 to June 30, 2009.  In
October 2009, all but two of the parties to the CRR filing agreed to a
stipulation that was filed with the OCC to collect no more than $30 million of
revenues under the CRR on an annual basis beginning January 2010 until PSO’s
next base rate order.  The stipulation also provides for an offsetting
fuel revenue reduction via a modification to the fuel adjustment factor of
Oklahoma jurisdictional customers on an annual basis by $30 million beginning
January 2010 and refunds of certain over-recovered fuel balances during the
first quarter of 2010.  If the OCC denies all or part of the requested
rider, 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 AEP and
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 Unit and Turk
Plant.  In September 2009, SWEPCo, the APSC staff and the Arkansas
Attorney General entered into a settlement agreement in which the settling
parties agreed to an $18 million increase based on a return on equity of
10.25%.  If the APSC denies all or part of the increase in the
settlement agreement, it could have an adverse effect on future net income, cash
flows and financial condition.
 
 Our future access to assets used to
serve a major customer is in question.(Applies to
I&M)
 Since
1975 I&M has leased certain energy delivery assets from the City of Fort
Wayne, Indiana under a long-term lease that expires on February 28,
2010.  I&M has been negotiating with Fort Wayne to purchase the
assets at the end of the lease, but no agreement has been
reached.  Recent mediation with Fort Wayne was also
unsuccessful.  Fort Wayne issued a technical notice of default under
the lease to I&M in August 2009.  I&M responded to Fort Wayne
in October 2009 that it did not agree there was a default under the
lease.  In October 2009, I&M filed for declaratory and injunctive
relief in Indiana state court.  I&M will seek recovery in rates
for any amount it may pay related to this dispute.  At this time,
management cannot predict the outcome of this dispute.  While
management believes any triggered costs should be recoverable from customers,
without such recovery those costs, if material, 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, S&P or Fitch 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
2009, Fitch changed its rating outlook for SWEPCo from stable to negative and
downgraded APCo’s senior unsecured rating to BBB with stable
outlook.  In 2009, Moody’s downgraded SWEPCo to Baa3 with stable
outlook and changed the rating outlook for APCo from negative to
stable.  Moody’s also placed AEP on negative outlook and downgraded
OPCo to Baa1 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
Related to Owning and Operating Generation Assets and Selling Power
  Increased regulation of GHG emissions
could materially increase our costs or cause some of our electric generating
units to be uneconomical to
 operate or maintain.(Applies to each
registrant)
 
  In April
2009, the Federal EPA issued a proposed endangerment finding under the CAA
regarding GHG emissions from motor vehicles.  This finding could lead
to regulation of CO2 and other gases under existing laws.  In
September 2009, the Federal EPA issued a final mandatory GHG reporting rule
covering a broad range of facilities emitting in excess of 25,000 tons of GHG
emissions per year.  The Federal EPA proposed regulation of stationary
source GHG emissions through the NSR’s prevention of significant deterioration
and CAA’s Title V permitting programs.  The Federal EPA is
reconsidering whether to include GHG emissions in a number of stationary source
standards, including standards that apply to electric utility
units.  Some of the policy approaches being discussed by the Federal
EPA would have significant and widespread negative consequences for the national
economy and major U.S. industrial enterprises, including us.  If CO2
and other GHG emission standards are imposed, the standards could require
significant increases in capital expenditures and operating costs which would
impact the ultimate retirement of older, less-efficient, coal-fired
units.  While 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, without
such recovery those costs could have an adverse effect on future net income,
cash flows and financial condition.
  Courts adjudicating nuisance and
other similar claims against us may order us to limit or reduce our GHG
emissions.  (Applies to each
registrant)
  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.  In September 2009, the Second
Circuit Court issued a ruling vacating the dismissal and remanding the case to
the trial court.  The Second Circuit held that the issues of climate
change and global warming do not raise political questions and that Congress’
refusal to regulate GHG emissions does not mean that plaintiffs must wait for an
initial policy determination by Congress or the President’s administration to
secure the relief sought in their complaints.  Similarly, in October
2009, the Fifth Circuit Court of Appeals reversed a decision by the trial court
dismissing state common law nuisance claims in a putative class action by
Mississippi residents asserting that GHG emissions exacerbated the effects of
Hurricane Katrina.  The Fifth Circuit held that there was no exclusive
commitment of the common law issues raised in plaintiffs’ complaint to a
coordinate branch of government, and that no initial policy determination was
required to adjudicate these claims.
 
 The trial
courts adjudicating these reinstated nuisance claims may order the defendants,
including us, to limit or reduce GHG emissions.  This or similar
remedies could require us to purchase power from third parties to fulfill our
commitments to supply power to our customers.  This could have a
material impact on our costs.  While management believes such costs
should be recoverable from customers as costs of doing business, without such
recovery those costs could have an adverse effect on future net income, cash
flows and financial condition.
 
 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 September 30, 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 Programs07/01/09
      – 07/31/09
              
              
              -
              
              $
              -
              
              
              
              -
              
              $
              -08/01/09
      – 08/31/09
              
              
              -
              
              
              -
              
              
              
              -
              
              
              -09/01/09
      – 09/30/09
              
              
              2
              (a)
              
              69.50
              
              
              
              -
              
              
              -
 
 (a)
              APCo
      purchased 2 shares of its 4.50% cumulative preferred stock in a
      privately-negotiated transaction outside of an announced
      program.
 
 Item
4.  Submission Matters to a Vote
of Security Holders
 
 NONE
 
 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:  October
30, 2009