**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 **June 30, 2007**


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. is a
                large
                accelerated filer, an accelerated filer, or a non-accelerated
                filer.  See definition of ‘accelerated filer and large
                accelerated filer’ in Rule 12b-2 of the Exchange Act. (Check
                One)**Large
                accelerated
                filer     X                                         Accelerated
                filer                                           Non-accelerated
                filer*





*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, or non-accelerated
                filers.  See definition of ‘accelerated filer and large
                accelerated filer’ in Rule 12b-2 of the Exchange Act. (Check
                One)**Large
                accelerated
                filer                                               Accelerated
                filer                                             Non-accelerated
                filer     X**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, Indiana Michigan Power Company and Public Service
      Company of Oklahoma meet the conditions set forth in General Instruction H(1)(a)
      and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced
      disclosure format specified in General Instruction H(2) to Form
      10-Q.*














**Number
                of shares of common stock outstanding of the registrants
                at**
              **July
                31, 2007**American
                Electric Power Company, Inc.
            
            
            399,203,993($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**


**June
      30, 2007**





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
                Statements**Appalachian
                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
                Subsidiaries**Columbus
                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
                Subsidiaries**Indiana
                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 Subsidiaries**Public 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 Subsidiaries**Southwestern Electric Power Company
                Consolidated:**Management’s
                Financial Discussion and AnalysisQuantitative
                and Qualitative Disclosures About Risk Management
                ActivitiesCondensed
                Consolidated Financial StatementsIndex
                to Condensed Notes to Condensed Financial Statements of
                Registrant Subsidiaries


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





This
                combined Form 10-Q is separately filed by American Electric Power
                Company,
                Inc., 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**





ADITC
            
            Accumulated
                Deferred Investment Tax Credits.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 domestic electric utility
                companies.AEP
                East companies
            
            APCo,
                CSPCo, I&M, KPCo and OPCo.AEP
                System or the System
            
            American
                Electric Power System, an integrated electric utility system, owned
                and
                operated by AEP’s electric utility subsidiaries.AEP
                System Power Pool or AEP
              Power Pool
            
            Members
                are APCo, CSPCo, I&M, KPCo and OPCo.  The Pool shares the
                generation, cost of generation and resultant wholesale off-system
                sales of
                the member companies.AEPEP
            
            AEP
                Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale
                marketing and trading, asset management and commercial and industrial
                sales in the deregulated Texas market.AEPSC
            
            American
                Electric Power Service Corporation, a service subsidiary providing
                management and professional services to AEP and its
                subsidiaries.AEP
                West companies
            
            PSO,
                SWEPCo, TCC and TNC.AFUDC
            
            Allowance
                for Funds Used During Construction.ALJ
            
            Administrative
                Law Judge.AOCI
            
            Accumulated
                Other Comprehensive Income (Loss).APCo
            
            Appalachian
                Power Company, an AEP electric utility subsidiary.ARO
            
            Asset
                Retirement Obligations.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.).CTC
            
            Competition
                Transition Charge.DETM
            
            Duke
                Energy Trading and Marketing L.L.C., a risk management
                counterparty.E&R
            
            Environmental
                compliance and transmission and distribution system
                reliability.ECAR
            
            East
                Central Area Reliability Council.EDFIT
            
            Excess
                Deferred Federal Income Taxes.EITF
            
            Financial
                Accounting Standards Board’s Emerging Issues Task
                Force.ERCOT
            
            Electric
                Reliability Council of Texas.FASB
            
            Financial
                Accounting Standards Board.Federal
                EPA
            
            United
                States Environmental Protection Agency.FERC
            
            Federal
                Energy Regulatory Commission.FIN
            
            FASB
                Interpretation No.FIN
                46
            
            FIN
                46, “Consolidation of Variable Interest Entities.”FIN
                48
            
            FIN
                48, “Accounting for Uncertainty in Income Taxes” and FASB Staff Position
                FIN 48-1 “Definition of *Settlement* in FASB Interpretation No.
                48.”GAAP
            
            Accounting
                Principles Generally Accepted in the United States of
                America.HPL
            
            Houston
                Pipeline Company, a former AEP
                subsidiary.


IGCC
            
            Integrated
                Gasification Combined Cycle, technology that turns coal into a
                cleaner-burning gas.IPP
            
            Independent
                Power Producer.IRS
            
            Internal
                Revenue Service.IURC
            
            Indiana
                Utility Regulatory Commission.I&M
            
            Indiana
                Michigan Power Company, an AEP electric utility
                subsidiary.JMG
            
            JMG
                Funding LP.KGPCo
            
            Kingsport
                Power Company, an AEP electric distribution subsidiary.KPCo
            
            Kentucky
                Power Company, an AEP electric utility subsidiary.KPSC
            
            Kentucky
                Public Service Commission.kV
            
            Kilovolt.KWH
            
            Kilowatthour.LPSC
            
            Louisiana
                Public Service Commission.MTM
            
            Mark-to-Market.MW
            
            Megawatt.MWH
            
            Megawatthour.NOx
            
            Nitrogen
                oxide.Nonutility
                Money Pool
            
            AEP
                System’s Nonutility Money Pool.NRC
            
            Nuclear
                Regulatory Commission.NSR
            
            New
                Source Review.NYMEX
            
            New
                York Mercantile Exchange.OATT
            
            Open
                Access Transmission Tariff.OCC
            
            Corporation
                Commission of the State of Oklahoma.OPCo
            
            Ohio
                Power Company, an AEP electric utility subsidiary.OTC
            
            Over
                the counter.OVEC
            
            Ohio
                Valley Electric Corporation, which is 43.47% owned by
                AEP.PJM
            
            Pennsylvania
                – New Jersey – Maryland regional transmission
                organization.PSO
            
            Public
                Service Company of Oklahoma, an AEP electric utility
                subsidiary.PUCO
            
            Public
                Utilities Commission of Ohio.PUCT
            
            Public
                Utility Commission of Texas.Registrant
                Subsidiaries
            
            AEP
                subsidiaries which are SEC registrants; APCo, CSPCo, I&M, OPCo, PSO,
                SWEPCo.REP
            
            Texas
                Retail Electric Provider.Risk
                Management Contracts
            
            Trading
                and nontrading derivatives, including those derivatives designated
                as cash
                flow and fair value hedges.Rockport
                Plant
            
            A
                generating plant, consisting of two 1,300 MW coal-fired generating
                units
                near Rockport, Indiana owned by AEGCo and I&M.RTO
            
            Regional
                Transmission Organization.S&P
            
            Standard
                and Poor’s.SEC
            
            United
                States Securities and Exchange Commission.SECA
            
            Seams
                Elimination Cost Allocation.SFAS
            
            Statement
                of Financial Accounting Standards issued by the Financial Accounting
                Standards Board.SFAS
                71
            
            Statement
                of Financial Accounting Standards No. 71, “Accounting for the Effects of
                Certain Types of Regulation.”SFAS
                133
            
            Statement
                of Financial Accounting Standards No. 133, “Accounting for Derivative
                Instruments and Hedging Activities.”SFAS
                157
            
            Statement
                of Financial Accounting Standards No. 157, “Fair Value
                Measurements.”


SFAS
                158
            
            Statement
                of Financial Accounting Standards No. 158, “Employers’ Accounting for
                Defined Benefit Pension and Other Postretirement
                Plans.”SFAS
                159
            
            Statement
                of Financial Accounting Standards No. 159, “The Fair Value Option for
                Financial Assets and Financial Liabilities.”SIA
            
            System
                Integration Agreement.SO2
            
            Sulfur
                Dioxide.SPP
            
            Southwest
                Power Pool.Sweeny
            
            Sweeny
                Cogeneration Limited Partnership, owner and operator of a four unit,
                480
                MW gas-fired generation facility, owned 50% by AEP.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.Utility
                Money Pool
            
            AEP
                System’s Utility Money Pool.VaR
            
            Value
                at Risk, a method to quantify risk exposure.Virginia
                SCC
            
            Virginia
                State Corporation Commission.WPCo
            
            Wheeling
                Power Company, an AEP electric distribution subsidiary.WVPSC
            
            Public
                Service Commission of West
                Virginia.





**FORWARD-LOOKING
      INFORMATION**





This
      report made by AEP and its Registrant Subsidiaries contains forward-looking
      statements within the meaning of Section 21E of the Securities Exchange Act
      of
      1934.  Although AEP and each of its Registrant Subsidiaries believe
      that their expectations are based on reasonable assumptions, any such statements
      may be influenced by factors that could cause actual outcomes and results to
      be
      materially different from those projected.  Among the factors that
      could cause actual results to differ materially from those in the
      forward-looking statements are:





·
            Electric
                load and customer growth.·
            Weather
                conditions, including storms.·
            Available
                sources and costs of, and transportation for, fuels and the
                creditworthiness of fuel suppliers and transporters.·
            Availability
                of generating capacity and the performance of our generating
                plants.·
            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 when needed at acceptable
                prices and terms and to recover those costs through applicable rate
                cases
                or competitive rates.·
            New
                legislation, litigation and government regulation including requirements
                for reduced emissions of sulfur, nitrogen, mercury, carbon, soot
                or
                particulate matter and other substances.·
            Timing
                and resolution of pending and future rate cases, negotiations and
                other
                regulatory decisions (including rate or other recovery for new
                investments, transmission service and environmental
                compliance).·
            Resolution
                of litigation (including pending Clean Air Act enforcement actions
                and
                disputes arising from the bankruptcy of Enron Corp. and related
                matters).·
            Our
                ability to constrain operation and maintenance costs.·
            The
                economic climate and growth in our service territory and changes
                in market
                demand and demographic patterns.·
            Inflationary
                and interest rate trends.·
            Our
                ability to develop and execute a strategy based on a view regarding
                prices
                of electricity, natural gas and other energy-related
                commodities.·
            Changes
                in the creditworthiness 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 and other
                energy-related commodities.·
            Changes
                in utility regulation, including the potential for new legislation
                in Ohio
                and membership in and integration into regional transmission
                organizations.·
            Accounting
                pronouncements periodically issued by accounting standard-setting
                bodies.·
            The
                performance of our pension and other postretirement benefit
                plans.·
            Prices
                for power that we generate and sell at wholesale.·
            Changes
                in technology, 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.








The
                registrants 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**





**Regulatory
      Activity**





The
      status of base rate filings ongoing or finalized this quarter with implemented
      rates are:





**Operating**
              **Company**
            
            **Jurisdiction**
            
            **Revised
                Annual  Rate Increase Request**
            
            **Implemented
                Annual Rate Increase**
            
            **Effective
                Date of Rate Increase****(in
                millions)**APCo
            
            Virginia
            
            $
            198
            (a)
            $
            24
            (a)
            October
                2006OPCo
            
            Ohio
            
            
            8
            
            
            8
            (b)
            May
                2007CSPCo
            
            Ohio
            
            
            24
            
            
            24
            (b)
            May
                2007TCC
            
            Texas
            
            
            81
            
            
            70
            (b)
            June
                2007TNC
            
            Texas
            
            
            25
            
            
            14
            
            June
                2007PSO
            
            Oklahoma
            
            
            50
            
            
            9
            (b)
            July
                2007





(a)
            The
                difference between the requested and implemented amounts of annual
                rate
                increase is partially offset by approximately $35 million of incremental
                E&R costs which APCo anticipates to file for recovery through the
                E&R surcharge mechanism in 2008.  APCo also requested a net
                $50 million reduction, beginning September 1, 2007, in credits to
                customers for off-system sales margins as part of its July 2007 fuel
                clause filing under the new re-regulation legislation.(b)
            Rate
                increase is presently subject to refund.  Proceeding is
                on-going.





In
      Virginia, APCo filed the following non-base rate requests in July 2007 with
      the
      Virginia SCC:





**Operating**
              **Company**
            
            **Jurisdiction**
            
            **Cost
                Type**
            
            **Request**
            
            **Projected
                Date of Rate Increase****(in
                millions)**APCo
            
            Virginia
            
            Incremental
                E&R
            
            $
            60
            
            December
                2007APCo
            
            Virginia
            
            Fuel,
                Off-system Sales
            
            
            33
            
            September
                2007





***West
      Virginia IGCC***





In
      June
      2007, APCo filed testimony with the WVPSC supporting construction of a 629
      MW
      IGCC plant adjacent to APCo’s existing Mountaineer Generating Station in Mason
      County, WV.   APCo requested pre-approval of a surcharge rate
      mechanism to provide for the timely recovery of both the ongoing finance costs
      of the project during the construction period as well as the capital and
      operating costs and a return on equity once the facility is placed into
      commercial operation.  In July 2007, APCo filed a request with the
      Virginia SCC to recover an estimated $45 million in financing costs on projected
      IGCC construction work in progress including pre-construction development design
      and planning costs from July 1, 2007 through December 31, 2009.  If
      APCo receives all necessary approvals, the plant could be completed as early
      as
      mid-2012 for an estimated cost of $2.2 billion**.**





***Indiana
      Depreciation Study***





In
      June
      2007, the IURC approved a settlement agreement allowing I&M to implement
      reduced book depreciation rates upon the filing by I&M of a general rate
      petition.  On June 19, 2007, I&M filed its rate petition to be
      effective on July 1, 2007.  The settlement agreement will result in a
      reduction of book depreciation expense of $37 million primarily related to
      the
      Cook Plant license extension for the period from June 19, 2007 to December
      31,
      2007, which was offset by a $5 million regulatory liability, recorded in June
      2007, to provide for an agreed-upon fuel credit.  I&M expects new
      base rates including the reduced depreciation to become effective in late 2008
      or early 2009.




***Indiana
      Rate Cap***





Effective
      July 1, 2007, I&M’s rate cap ended for both base and fuel
      rates.  I&M’s fuel factor increased effective with July 2007
      billings to recover the full projected cost of fuel.  I&M will
      resume deferring through revenues any under/over-recovered fuel costs for future
      recovery/refund.





***SWEPCo
      Fuel Reconciliation – Texas***





In
      June
      2007, an ALJ issued a Proposal for Decision recommending a $17 million
      disallowance in SWEPCo's Texas fuel reconciliation
      proceeding.  Results of operations for the second quarter were
      adversely affected by $25 million as a result of reflecting the ALJ’s
      decision.  In July 2007, the PUCT orally affirmed the ALJ
      report.  A final order is expected in the third quarter of
      2007.





**Virginia
      Restructuring**





In
      April
      2007, the Virginia legislature re-regulated electric utilities’
generation/supply rates on a cost basis effective July 1, 2007.  We
      recorded an extraordinary pretax reduction in APCo’s earnings of $118 million
      ($79 million, net of tax) from reapplication of SFAS 71 regulatory accounting
      in
      the second quarter of 2007 as a result of the new re-regulation
      legislation.





**Investment
      Activity**





In
      the
      second quarter of 2007, we completed the purchase of the 480 MW Darby Electric
      Generation Station for $102 million and the purchase of the 1,096 MW
      Lawrenceburg Generating Station for $325 million.





**RESULTS
      OF OPERATIONS**





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.





**MEMCO
      Operations**


·
            Barging
                operations that annually transport approximately 34 million tons
                of coal
                and dry bulk commodities primarily on the Ohio, Illinois and lower
                Mississippi rivers.  Approximately 35% of the barging operations
                relates to the transportation of coal, 30% relates to agricultural
                products, 18% relates to steel and 17% relates to other
                commodities.





**Generation
      and Marketing**


·
            IPPs,
                wind farms and marketing and risk management activities primarily
                in
                ERCOT.





The
      table
      below presents our consolidated Income Before Discontinued Operations and
      Extraordinary Loss for the three and six months ended June 30, 2007 and
      2006.  We reclassified prior year amounts to conform to the current
      year’s segment presentation.


**Three
                Months Ended June 30,**
            
            
            **Six
                Months Ended June 30,****2007**
            
            
            **2006**
            
            
            **2007**
            
            
            **2006****(in
                millions)**Utility
                Operations
            
            $
            238
            
            
            $
            159
            
            
            $
            491
            
            
            $
            524MEMCO
                Operations
            
            
            7
            
            
            
            14
            
            
            
            22
            
            
            
            35Generation
                and Marketing
            
            
            15
            
            
            
            2
            
            
            
            14
            
            
            
            6All
                Other (a)
            
            
            (3
            )
            
            
            (3
            )
            
            
            1
            
            
            
            (15
            )**Income
                Before Discontinued Operations**
              **and
                Extraordinary Loss**
            
            $
            257
            
            
            $
            172
            
            
            $
            528
            
            
            $
            550





(a)
            All
                Other includes:·
            Parent’s
                guarantee revenue received from affiliates, interest income and interest
                expense and other nonallocated costs.·
            Other
                energy supply related businesses, including the Plaquemine Cogeneration
                Facility, which was sold in the fourth quarter of
                2006.





Second
      Quarter of 2007 Compared to Second Quarter of 2006





Income
      Before Discontinued Operations and Extraordinary Loss in 2007 increased $85
      million compared to 2006 primarily due to an increase in Utility Operations
      segment earnings of $79 million.  The increase in Utility Operations
      segment earnings primarily relates to higher retail margins mostly due to rate
      increases and favorable weather and increased margins from off-system
      sales.





Average
      basic shares outstanding increased to 399 million in 2007 from 394 million
      in
      2006 primarily due to the issuance of shares under our incentive compensation
      plans.  Actual shares outstanding were 399 million as of June 30,
      2007.





Six
      Months Ended June 30, 2007 Compared to Six Months Ended June 30,
      2006





Income
      Before Discontinued Operations and Extraordinary Loss in 2007 decreased $22
      million compared to 2006 primarily due to a decrease in Utility Operations
      segment earnings of $33 million.  The decrease in Utility Operations
      segment earnings primarily relates to higher operation and maintenance expenses,
      higher regulatory amortization expense and lower earnings-sharing payments
      from
      Centrica received in March 2007 representing the last payment of the
      earnings-sharing agreement.  These decreases in earnings were
      partially offset by rate increases and favorable weather.





Average
      basic shares outstanding increased to 398 million in 2007 from 394 million
      in
      2006 primarily due to the issuance of shares under our incentive compensation
      plans.  Actual shares outstanding were 399 million as of June 30,
      2007.





**Utility
      Operations**





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





**Utility
      Operations Income Summary**


**For
      the Three and Six Months Ended June 30, 2007 and 2006**





**Three
                Months Ended**
              **June
                30,**
            
            
            **Six
                Months Ended**
              **June
                30,****2007**
            
            
            **2006**
            
            
            **2007**
            
            
            **2006****(in
                millions)**Revenues
            
            $
            2,954
            
            
            $
            2,796
            
            
            $
            5,987
            
            
            $
            5,762Fuel
                and Purchased Power
            
            
            1,109
            
            
            
            1,123
            
            
            
            2,228
            
            
            
            2,249**Gross
                Margin**
            
            
            1,845
            
            
            
            1,673
            
            
            
            3,759
            
            
            
            3,513Depreciation
                and Amortization
            
            
            365
            
            
            
            346
            
            
            
            748
            
            
            
            686Other
                Operating Expenses
            
            
            957
            
            
            
            983
            
            
            
            1,948
            
            
            
            1,819**Operating
                Income**
            
            
            523
            
            
            
            344
            
            
            
            1,063
            
            
            
            1,008Other
                Income, Net
            
            
            27
            
            
            
            44
            
            
            
            45
            
            
            
            85Interest
                Charges and Preferred Stock Dividend
                  Requirements
            
            
            207
            
            
            
            161
            
            
            
            386
            
            
            
            315Income
                Tax Expense
            
            
            105
            
            
            
            68
            
            
            
            231
            
            
            
            254**Income
                Before Discontinued Operations and**
              **Extraordinary
                Loss**
            
            $
            238
            
            
            $
            159
            
            
            $
            491
            
            
            $
            524







**Summary
      of Selected Sales and Weather Data**


**For
      Utility Operations**


**For
      the Three and Six Months Ended June 30, 2007 and 2006**





**Three
                Months Ended**
              **June
                30,**
            
            **Six
                Months Ended**
              **June
                30,****Energy/Delivery
                Summary**
            **2007**
            
            **2006**
            
            **2007**
            
            **2006****(in
                millions of KWH)****Energy**Retail:Residential
            
            10,127
            
            
            9,590
            
            
            24,267
            
            
            22,528Commercial
            
            10,227
            
            
            9,440
            
            
            19,586
            
            
            18,349Industrial
            
            14,848
            
            
            13,716
            
            
            28,413
            
            
            26,937Miscellaneous
            
            632
            
            
            655
            
            
            1,245
            
            
            1,274Total
                Retail
            
            35,834
            
            
            33,401
            
            
            73,511
            
            
            69,088Wholesale
            
            9,376
            
            
            10,822
            
            
            18,154
            
            
            21,667**Delivery**Texas
                Wires – Energy delivered to customers served
              by
                AEP’s Texas Wires Companies
            
            6,746
            
            
            6,915
            
            
            12,577
            
            
            12,461**Total
                KWHs**
            
            51,956
            
            
            51,138
            
            
            104,242
            
            
            103,216





Cooling
      degree days and heating degree days are metrics commonly used in the utility
      industry as a measure of the impact of weather on results of
      operations.  In general, degree day changes in our eastern region have
      a larger effect on results of operations than changes in our western region
      due
      to the relative size of the two regions and the associated number of customers
      within each.





**Summary
      of Heating and Cooling Degree Days for Utility Operations**


**For
      the Three and Six Months Ended June 30, 2007 and 2006**





**Three
                Months Ended**
              **June
                30,**
            
            **Six
                Months Ended**
              **June
                30,****2007**
            
            **2006**
            
            **2007**
            
            **2006****(in
                degree days)****Weather
                Summary**Eastern
                RegionActual
                – Heating (a)
            
            222
            
            
            107
            
            
            2,039
            
            
            1,563Normal
                – Heating (b)
            
            174
            
            
            175
            
            
            1,966
            
            
            1,992Actual
                – Cooling (c)
            
            367
            
            
            228
            
            
            382
            
            
            229Normal
                – Cooling (b)
            
            275
            
            
            279
            
            
            278
            
            
            282Western
                Region (d)Actual
                – Heating (a)
            
            92
            
            
            5
            
            
            994
            
            
            663Normal
                – Heating (b)
            
            33
            
            
            33
            
            
            991
            
            
            1,005Actual
                – Cooling (c)
            
            622
            
            
            815
            
            
            678
            
            
            858Normal
                – Cooling (b)
            
            656
            
            
            652
            
            
            674
            
            
            669





(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.




**Second
      Quarter of 2007 Compared to Second Quarter of 2006**





**Reconciliation
      of Second Quarter of 2006 to Second Quarter of 2007**


**Income
      from Utility Operations Before Discontinued Operations and Extraordinary
      Loss**


**(in
      millions)**





**Second
                Quarter of 2006**
            
            
            
            
            $
            159**Changes
                in Gross Margin:**Retail
                Margins
            
            
            72Off-system
                Sales
            
            
            52Transmission
                Revenues
            
            
            22Other
                Revenues
            
            
            26**Total
                Change in Gross Margin**
            
            
            
            
            
            
            172**Changes
                in Operating Expenses and Other:**Other
                Operation and Maintenance
            
            
            26Depreciation
                and Amortization
            
            
            (19
            )Carrying
                Costs Income
            
            
            (17
            )Interest
                and Other Charges
            
            
            (46
            )**Total
                Change in Operating Expenses and Other**
            
            
            
            
            
            
            (56
            )Income
                Tax Expense
            
            
            
            
            
            
            (37
            )**Second
                Quarter of 2007**
            
            
            
            
            
            $
            238





Income
      from Utility Operations Before Discontinued Operations and Extraordinary Loss
      increased $79 million to $238 million in 2007.  The key drivers of the
      increase were a $172 million increase in Gross Margin partially offset by a
      $56
      million increase in Operating Expenses and Other and a $37 million increase
      in
      Income Tax Expense.





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





·
            Retail
                Margins increased $72 million primarily due to the
                following:·
            A
                $36 million increase related to new rates implemented in our Ohio
                jurisdictions as approved by the PUCO in our RSP’s.·
            A
                $36 million increase related to increased residential and commercial
                usage
                and customer growth.·
            A
                $24 million increase related to Ormet, a new industrial customer
                in
                Ohio.  See “Ormet” section of Note 3.·
            A
                $19 million increase related to increased sales to municipal, cooperative
                and other customers primarily resulting from new power supply
                contracts.·
            A
                $26 million increase in usage related to weather.  As compared
                to the prior year, our eastern region experienced a 61% increase
                in
                cooling degree days partially offset by a 24% decrease in cooling
                degree
                days in our western region.These
                increases were partially offset by:·
            A
                $38 million net decrease related to the APCo Virginia base rate case
                which
                includes a second quarter 2007 provision for revenue refund as a
                result of
                the final order offset by the new rates implemented.  See
                “Virginia Base Rate Case” section of Note 3.·
            A
                $25 million decrease due to a second quarter 2007 provision related
                to a
                SWEPCo Texas fuel reconciliation proceeding.  See “SWEPCo Fuel
                Reconciliation – Texas” section of Note 3.·
            A
                $21 million decrease in financial transmission rights revenue, net
                of
                congestion, primarily due to fewer transmission constraints within
                the PJM
                market.·
            Margins
                from Off-system Sales increased $52 million primarily due to higher
                power
                prices in the east and stronger trading margins offset by higher
                internal
                load and lower generation availability.·
            Transmission
                Revenues increased $22 million primarily due to a provision recorded
                in
                the second quarter of 2006 related to potential SECA
                refunds.  See “Transmission Rate Proceedings at the FERC”
                section of Note 3.


·
            Other
                Revenues increased $26 million primarily due to higher securitization
                revenue at TCC resulting from the $1.7 billion securitization in
                October
                2006.  Securitization revenue represents amounts collected to
                recover securitization bond principal and interest payments related
                to
                TCC’s securitized transition assets and are fully offset by amortization
                and interest expenses.





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





·
            Other
                Operation and Maintenance expenses decreased $26 million primarily
                due to
                reduced expenses for storm restoration and lower administrative and
                general expenses.·
            Depreciation
                and Amortization expense increased $19 million primarily due to increased
                Ohio regulatory asset amortization related to recovery of IGCC
                pre-construction costs, increased Texas amortization of the securitized
                transition assets and higher depreciable property balances, offset
                by
                adjustments related to implementation of the final order in the APCo
                Virginia base rate case.·
            Carrying
                Costs Income decreased $17 million because TCC started recovering
                stranded
                costs in October 2006, thus eliminating future TCC carrying costs
                income.·
            Interest
                and Other Charges increased $46 million primarily due to additional
                debt
                issued in the fourth quarter of 2006 including TCC securitization
                bonds.·
            Income
                Tax Expense increased $37 million due to an increase in pretax
                income.





**Six
      Months Ended June 30, 2007 Compared to Six Months Ended June 30,
      2006**





**Reconciliation
      of Six Months Ended June 30, 2006 to Six Months Ended June 30,
      2007**


**Income
      from Utility Operations Before Discontinued Operations and Extraordinary
      Loss**


**(in
      millions)**


**Six
                Months Ended June 30, 2006**
            
            
            
            
            $
            524**Changes
                in Gross Margin:**Retail
                Margins
            
            
            210Off-system
                Sales
            
            
            11Transmission
                Revenues
            
            
            (8
            )Other
                Revenues
            
            
            33**Total
                Change in Gross Margin**
            
            
            
            
            
            
            246**Changes
                in Operating Expenses and Other:**Other
                Operation and Maintenance
            
            
            (85
            )Gain
                on Dispositions of Assets, Net
            
            
            (47
            )Depreciation
                and Amortization
            
            
            (62
            )Taxes
                Other Than Income Taxes
            
            
            3Carrying
                Costs Income
            
            
            (39
            )Other
                Income, Net
            
            
            (1
            )Interest
                and Other Charges
            
            
            (71
            )**Total
                Change in Operating Expenses and Other**
            
            
            
            
            
            
            (302
            )Income
                Tax Expense
            
            
            
            
            
            
            23**Six
                Months Ended June 30, 2007**
            
            
            
            
            
            $
            491





Income
      from Utility Operations Before Discontinued Operations and Extraordinary Loss
      decreased $33 million to $491 million in 2007.  The key driver of the
      decrease was a $302 million increase in Operating Expenses and Other, offset
      by
      a $246 million increase in Gross Margin and a $23 million decrease in Income
      Tax
      Expense.





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





·
            Retail
                Margins increased $210 million primarily due to the
                following:·
            A
                $71 million increase related to new rates implemented in our Ohio
                jurisdictions as approved by the PUCO in our RSPs and a $20 million
                increase related to new rates implemented in other east jurisdictions
                of
                Kentucky, West Virginia and Virginia.·
            A
                $70 million increase related to increased residential and commercial
                usage
                and customer growth.·
            A
                $66 million increase in usage related to weather.  As compared
                to the prior year, our eastern region and western region experienced
                30%
                and 50% increases, respectively, in heating degree days.  Also,
                our eastern region experienced a 67% increase in cooling degree days
                which
                was offset by a 21% decrease in cooling degree days in our western
                region.·
            A
                $37 million increase related to Ormet, a new industrial customer
                in
                Ohio.  See “Ormet” section of Note 3.These
                increases were partially offset by:·
            A
                $48 million decrease in financial transmission rights revenue, net
                of
                congestion, primarily due to fewer transmission constraints within
                the PJM
                market.·
            A
                $25 million decrease due to a second quarter 2007 provision related
                to a
                SWEPCo Texas fuel reconciliation proceeding.  See “SWEPCo Fuel
                Reconciliation – Texas” section of Note 3.·
            Margins
                from Off-system Sales increased $11 million primarily due to higher
                power
                prices in the east and stronger trading margins offset by higher
                internal
                load and lower generation availability.·
            Transmission
                Revenues decreased $8 million primarily due to the elimination of
                SECA
                revenues as of April 1, 2006 offset by a provision recorded in the
                second
                quarter of 2006 related to potential SECA
                refunds.  See  “Transmission Rate Proceedings at the
                FERC” section of Note 3.·
            Other
                Revenues increased $33 million primarily due to higher securitization
                revenue at TCC resulting from the $1.7 billion securitization in
                October
                2006.  Securitization revenue represents amounts collected to
                recover securitization bond principal and interest payments related
                to
                TCC’s securitized transition assets and are fully offset by amortization
                and interest expenses.





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





·
            Other
                Operation and Maintenance expenses increased $85 million primarily
                due to
                increases in generation expenses related to plant outages, base operations
                and removal costs and distribution expenses associated with service
                reliability and storm restoration primarily in
                Oklahoma.·
            Gain
                on Disposition of Assets, Net decreased $47 million primarily related
                to
                the earnings sharing agreement with Centrica from the sale of our
                REPs in
                2002.  In 2006, we received $70 million from Centrica for
                earnings sharing and in 2007 we received $20 million as the earnings
                sharing agreement ended.·
            Depreciation
                and Amortization expense increased $62 million primarily due to increased
                Ohio regulatory asset amortization related to recovery of IGCC
                pre-construction costs, increased Texas amortization of the securitized
                transition assets and higher depreciable property
                balances.·
            Carrying
                Costs Income decreased $39 million because TCC started recovering
                stranded
                costs in October 2006, thus eliminating future TCC carrying costs
                income.·
            Interest
                and Other Charges increased $71 million primarily due to additional
                debt
                issued in the fourth quarter of 2006 including TCC securitization
                bonds.·
            Income
                Tax Expense decreased $23 million due to a decrease in pretax
                income.





**MEMCO
      Operations**





**Second
      Quarter of 2007 Compared to Second Quarter of 2006**





Income
      Before Discontinued Operations and Extraordinary Loss from our MEMCO Operations
      segment decreased from $14 million in 2006 to $7 million in
      2007.  While MEMCO operated 15% more barges in the second quarter of
      2007 than the same period in 2006, freight revenues remained flat as spot market
      freight demand remained weaker than in 2006, primarily related to reduced steel
      and cement imports.  Operating expenses were up 11% over the same
      period in 2006 mainly due to the increased fleet size, increased fuel costs
      and
      wage increases for towboat crews.





**Six
      Months Ended June 30, 2007 Compared to Six Months Ended June 30,
      2006**





Income
      Before Discontinued Operations and Extraordinary Loss from our MEMCO Operations
      segment decreased from $35 million in 2006 to $22 million in
      2007.  MEMCO operated approximately 16% more barges in the first six
      months of 2007 than 2006, however, revenue remained flat as reduced imports,
      primarily steel and cement continued to depress freight rates and reduce
      northbound loadings.  Operating expenses were up for the first six
      months of 2007 compared to 2006 primarily due to the cost of the increased
      fleet
      size, fuel and wage increases.





**Generation
      and Marketing**





**Second
      Quarter of 2007 Compared to Second Quarter of 2006**





Income
      Before Discontinued Operations and Extraordinary Loss from our Generation and
      Marketing segment increased from $2 million in 2006 to $15 million in
      2007.  The increase primarily relates to favorable marketing contracts
      with municipalities and cooperatives in ERCOT.  Net revenues for our
      Generation and Marketing segment increased primarily due to certain existing
      ERCOT energy contracts which were transferred from our Utility Operations
      segment on January 1, 2007.





**Six
      Months Ended June 30, 2007 Compared to Six Months Ended June 30,
      2006**





Income
      Before Discontinued Operations and Extraordinary Loss from our Generation and
      Marketing segment increased from $6 million in 2006 to $14 million in
      2007.  The increase primarily relates to favorable marketing contracts
      with municipalities and cooperatives in ERCOT.  Net revenues for our
      Generation and Marketing segment increased primarily due to certain existing
      ERCOT energy contracts which were transferred from our Utility Operations
      segment on January 1, 2007.





**All
      Other**





**Second
      Quarter of 2007 Compared to Second Quarter of 2006**





Loss
      Before Discontinued Operations and Extraordinary Loss from All Other was
      essentially flat at $3 million.





**Six
      Months Ended June 30, 2007 Compared to Six Months Ended June 30,
      2006**





Income
      Before Discontinued Operations and Extraordinary Loss from All Other increased
      from a $15 million loss in 2006 to income of $1 million in 2007.  In
      2006, we had after-tax losses of $8 million from operation of the Plaquemine
      Cogeneration Facility which was sold in the fourth quarter of
      2006.  In 2007, we had an after-tax gain of $10 million on the sale of
      investment securities.





**AEP
      System Income Taxes**





Income
      Tax Expense increased $36 million in the second quarter of 2007 compared to
      the
      second quarter of 2006 primarily due to an increase in pretax book
      income.





Income
      Tax Expense decreased $23 million for the six-month period ended June 30, 2007
      compared to the six-month period ended June 30, 2006 primarily due to a decrease
      in pretax book income and changes in certain book/tax differences accounted
      for
      on a flow-through basis.





**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 Capitalization**


**June
                30, 2007**
            
            
            **December
                31, 2006****($
                in millions)**Long-term
                Debt, Including Amounts Due Within One Year
            
            $
            14,588
            
            
            
            59.0
            %
            
            $
            13,698
            
            
            
            59.1
            %Short-term
                Debt
            
            
            438
            
            
            
            1.8
            
            
            
            18
            
            
            
            0.0Total
                Debt
            
            
            15,026
            
            
            
            60.8
            
            
            
            13,716
            
            
            
            59.1Common
                Equity
            
            
            9,656
            
            
            
            39.0
            
            
            
            9,412
            
            
            
            40.6Preferred
                Stock
            
            
            61
            
            
            
            0.2
            
            
            
            61
            
            
            
            0.3**Total
                Debt and Equity Capitalization**
            
            $
            24,743
            
            
            
            100.0
            %
            
            $
            23,189
            
            
            
            100.0
            %





Our
      ratio
      of debt to total capital increased, as planned, from 59.1% to 60.8% in 2007
      due to our increased borrowings.




**Liquidity**





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




***Credit
      Facilities***





We
      manage
      our liquidity by maintaining adequate external financing
      commitments.  At June 30, 2007, our available liquidity was
      approximately $2.7 billion as illustrated in the table below:





**Amount**
            
            **Maturity****(in
                millions)**Commercial
                Paper Backup:Revolving
                Credit Facility
            
            
            $
            1,500
            
            March
                2011Revolving
                Credit Facility
            
            
            
            1,500
            
            April
                2012**Total**
            
            
            
            3,000Cash
                and Cash Equivalents
            
            
            
            172**Total
                Liquidity Sources**
            
            
            
            3,172Less:
                AEP Commercial Paper Outstanding
            
            
            
            416Letters
                of Credit Drawn
            
            
            
            27**Net
                Available Liquidity**
            
            
            $
            2,729





In
      2007,
      we amended the terms and extended the maturity of our two credit facilities
      by
      one year to March 2011 and April 2012, respectively.  The facilities
      are structured as two $1.5 billion credit facilities of which $300 million
      may
      be issued under each credit facility as letters of credit.





***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 in our revolving credit agreements. At June
      30,
      2007, this contractually-defined percentage was 56.1%.  Nonperformance
      of these covenants could result in an event of default under these credit
      agreements.  At June 30, 2007, we complied with all of the covenants
      contained in these credit agreements.  In addition, the acceleration
      of our payment obligations, or the obligations of certain of our major
      subsidiaries, prior to maturity under any other agreement or instrument relating
      to debt outstanding in excess of $50 million, would cause an event of default
      under these credit agreements and permit the lenders to declare the outstanding
      amounts payable.





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





Under
      a
      regulatory order, our utility subsidiaries, other than TCC, cannot incur
      additional indebtedness if the issuer’s common equity would constitute less than
      30% of its capital.  In addition, this order restricts those utility
      subsidiaries from issuing long-term debt unless that debt will be rated
      investment grade by at least one nationally recognized statistical rating
      organization.  At June 30, 2007, all applicable utility subsidiaries
      complied with this order.





Utility
      Money Pool borrowings and external borrowings may not exceed amounts authorized
      by regulatory orders.  At June 30, 2007, we had not exceeded those
      authorized limits.





***Credit
      Ratings***





AEP’s
      ratings have not been adjusted by any rating agency during 2007 and AEP is
      currently on a stable outlook by the rating agencies.  Our current
      credit ratings are as follows:





**Moody’s**
            
            
            **S&P**
            
            
            **Fitch**AEP
                Short Term Debt
            P-2
            
            
            A-2
            
            
            F-2AEP
                Senior Unsecured Debt
            Baa2
            
            
            BBB
            
            
            BBB





If
      we or
      any of our rated subsidiaries receive an upgrade from any of the rating agencies
      listed above, our borrowing costs could decrease.  If we receive a
      downgrade in our credit ratings by one of the rating agencies listed above,
      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.





**Six
                Months Ended****June
                30,****2007**
            
            
            **2006****(in
                millions)****Cash
                and Cash Equivalents at Beginning of Period**
            
            $
            301
            
            
            $
            401Net
                Cash Flows From Operating Activities
            
            
            969
            
            
            
            1,123Net
                Cash Flows Used For Investing Activities
            
            
            (2,127
            )
            
            
            (1,572
            )Net
                Cash Flows From Financing Activities
            
            
            1,029
            
            
            
            297**Net
                Decrease in Cash and Cash Equivalents**
            
            
            (129
            )
            
            
            (152
            )**Cash
                and Cash Equivalents at End of Period**
            
            $
            172
            
            
            $
            249





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.  We use our corporate borrowing program to meet
      the short-term borrowing needs of our subsidiaries.  The corporate
      borrowing program includes a Utility Money Pool, which funds the utility
      subsidiaries, and a Nonutility Money Pool, which funds the majority of the
      nonutility subsidiaries.  In addition, we also fund, as direct
      borrowers, the short-term debt requirements of other subsidiaries that are
      not
      participants in either money pool for regulatory or operational
      reasons.  As of June 30, 2007, we had credit facilities totaling $3
      billion to support our commercial paper program.  The maximum amount
      of commercial paper outstanding during 2007 was $833 million.  The
      weighted-average interest rate of our commercial paper for the six months
      ended June 30, 2007 was 5.40%.  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 common stock or long-term debt and sale-leaseback or leasing
      agreements.  Utility Money Pool borrowings and external borrowings may
      not exceed authorized limits under regulatory orders.  See the
      discussion below for further detail related to the components of our cash
      flows.





***Operating
      Activities***


**Six
                Months Ended****June
                30,****2007**
            
            
            **2006****(in
                millions)****Net
                Income**
            
            $
            451
            
            
            $
            556Less:  Discontinued
                Operations, Net of Tax
            
            
            (2
            )
            
            
            (6
            )**Income
                Before Discontinued Operations**
            
            
            449
            
            
            
            550Noncash
                Items Included in Earnings
            
            
            938
            
            
            
            617Changes
                in Assets and Liabilities
            
            
            (418
            )
            
            
            (44
            )**Net
                Cash Flows From Operating Activities**
            
            $
            969
            
            
            $
            1,123





Net
      Cash
      Flows From Operating Activities decreased in 2007 primarily due to lower fuel
      costs recovery.





Net
      Cash
      Flows From Operating Activities were $1 billion in 2007. We produced Income
      Before Discontinued Operations of $449 million adjusted for noncash expense
      items, primarily depreciation and amortization.  Other changes in
      assets and liabilities represent items that had a current period cash flow
      impact, such as changes in working capital, as well as items that represent
      future rights or obligations to receive or pay cash, such as regulatory assets
      and liabilities.  The current period activity in these asset and
      liability accounts relates to a number of items, the most significant of which
      relates primarily to the Texas CTC refund of fuel over-recovery.




Net
      Cash
      Flows From Operating Activities were $1.1 billion in 2006.  We
      produced Income Before Discontinued Operations of $550 million adjusted for
      noncash expense items, primarily depreciation and amortization.  In
      2005, we initiated fuel proceedings in Oklahoma, Texas, Virginia and Arkansas
      seeking recovery of our increased fuel costs.  Under-recovered fuel
      costs decreased due to recovery of higher cost of fuel, especially natural
      gas.  Other changes in assets and liabilities represent items that had
      a current period cash flow impact, such as changes in working capital, as well
      as items that represent future rights or obligations to receive or pay cash,
      such as regulatory assets and liabilities.  The current period
      activity in these asset and liability accounts relates to a number of items;
      the
      most significant are a $185 million cash increase from net Accounts
      Receivable/Accounts Payable due to a lower balance of Customer Accounts
      Receivable at June 30, 2006 and a $189 million decrease in cash related to
      customer deposits held for trading activities.





***Investing
      Activities***


**Six
                Months Ended****June
                30,****2007**
            
            
            **2006****(in
                millions)**Construction
                Expenditures
            
            $
            (1,823
            )
            
            $
            (1,611
            )Change
                in Other Temporary Investments, Net
            
            
            (129
            )
            
            
            3(Purchases)/Sales
                of Investment Securities, Net
            
            
            208
            
            
            
            (51
            )Acquisition
                of Darby and Lawrenceburg Plants
            
            
            (427
            )
            
            
            -Proceeds
                from Sales of Assets
            
            
            74
            
            
            
            118Other
            
            
            (30
            )
            
            
            (31
            )**Net
                Cash Flows Used For Investing Activities**
            
            $
            (2,127
            )
            
            $
            (1,572
            )





Net
      Cash
      Flows Used For Investing Activities were $2.1 billion in 2007 primarily due
      to
      Construction Expenditures for our environmental, distribution and new generation
      investment plan.  We paid $427 million to purchase gas-fired
      generating units.  In our normal course of business, we purchase
      investment securities including auction rate securities and variable rate demand
      notes with cash available for short-term investments.  Also included
      in Purchases/Sales of Investment Securities, Net are purchases and sales of
      securities within our nuclear trusts.





Net
      Cash
      Flows Used For Investing Activities were $1.6 billion in 2006 primarily due
      to
      Construction Expenditures.  Construction Expenditures increased due to
      our environmental investment plan.





We
      forecast approximately $1.7 billion of construction expenditures for the
      remainder of 2007.  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 results of operations and financing activities.





***Financing
      Activities***


**Six
                Months Ended****June
                30,****2007**
            
            
            **2006****(in
                millions)**Issuance
                of Common Stock
            
            $
            90
            
            
            $
            6Issuance/Retirement
                of Debt, Net
            
            
            1,294
            
            
            
            552Dividends
                Paid on Common Stock
            
            
            (311
            )
            
            
            (291
            )Other
            
            
            (44
            )
            
            
            30**Net
                Cash Flows From Financing Activities**
            
            $
            1,029
            
            
            $
            297





Net
      Cash
      Flows From Financing Activities in 2007 were $1 billion primarily due to issuing
      $1.1 billion of debt securities including $1 billion of new debt for plant
      acquisitions and construction and increasing short-term commercial paper
      borrowings.  We paid common stock dividends of $311
      million.  See Note 9 for a complete discussion of long-term debt
      issuances and retirements.




Net
      Cash
      Flows From Financing Activities in 2006 were $297 million.  During
      2006, we issued $115 million of obligations relating to pollution control bonds,
      issued $850 million of notes and retired $396 million of notes for a net
      increase in notes outstanding of $454 million and increased our short-term
      commercial paper outstanding by $144 million.  The Other amount of $30
      million in the above table includes $68 million received from a coal supplier,
      net of an $8 million repayment, related to a long-term coal purchase contract
      amended in March 2006.





Our
      capital investment plans for the remainder of 2007 will require additional
      funding of approximately $1.5 billion from the capital markets.





**Off-balance
      Sheet Arrangements**





Under
      a
      limited set of circumstances we enter into off-balance sheet arrangements to
      accelerate cash collections, reduce operational expenses and spread risk of
      loss
      to third parties.  Our current guidelines restrict the use of
      off-balance sheet financing entities or structures to only allow 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:


**June
                30,**
              **2007**
            
            
            **December
                31,**
              **2006****(in
                millions)**AEP
                Credit Accounts Receivable Purchase Commitments
            
            $
            549
            
            
            $
            536Rockport
                Plant Unit 2 Future Minimum Lease Payments
            
            
            2,290
            
            
            
            2,364Railcars
                Maximum Potential Loss From Lease Agreement
            
            
            30
            
            
            
            31





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 2006 Annual Report.





**Summary
      Obligation Information**





A
      summary
      of our contractual obligations is included in our 2006 Annual Report and has
      not
      changed significantly from year-end other than the debt issuances discussed
      in
“Cash Flow” and “Financing Activities” above.





**Other**





***Texas
      REPs***





As
      part
      of the purchase-and-sale agreement related to the sale of our Texas REPs in
      2002, we retained the right to share in earnings with Centrica from the two
      REPs
      above a threshold amount through 2006 if the Texas retail market developed
      increased earnings opportunities.  We received $20 million and $70
      million payments in 2007 and 2006, respectively, for our share in
      earnings.  The payment we received in 2007 was the final payment under
      the earnings sharing agreement.





**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 2006 Annual Report.  The 2006 Annual Report should
      be read in conjunction with this report in order to understand significant
      factors without material changes in status since the issuance of our 2006 Annual
      Report, but may have a material impact on our future results of operations,
      cash
      flows and financial condition.





**Ohio
      Restructuring**





CSPCo
      and
      OPCo are involved in discussions with various stakeholders in Ohio about
      potential legislation to address the period following the expiration of the
      RSPs
      on December 31, 2008.  At this time, management is unable to predict
      whether CSPCo and OPCo will transition to market pricing, as permitted by the
      current Ohio restructuring legislation, extend their RSP rates, with or without
      modification, or become subject to a legislative reinstatement of some form
      of
      cost-based regulation for their generation supply business on January 1, 2009
      when the RSP period ends.


**Texas
      Restructuring**





TCC
      recovered its net recoverable stranded generation costs through a securitization
      financing and is refunding its net other true-up items through a CTC rate rider
      credit under 2006 PUCT orders.  TCC appealed the PUCT stranded costs
      true-up 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, federal law and fail to fully compensate TCC
      for
      its net stranded cost and other true-up items.  The significant items
      appealed by TCC are:





·
            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 it 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 cost, and·
            The
                two federal matters regarding the allocation of off-system sales
                related
                to fuel recoveries and the potential tax normalization
                violation.





Municipal
      customers and other intervenors also appealed the PUCT true-up orders seeking
      to
      further reduce TCC’s true-up recoveries.  In March 2007, the Texas
      District Court judge hearing the various appeals affirmed the PUCT’s April 4,
      2006 final true-up order for TCC with two significant exceptions.  The
      judge determined that the PUCT erred by applying an invalidated rule to
      determine the carrying cost rate for the true-up of stranded
      costs.  However, the District Court did not rule that the carrying
      cost rate was inappropriate.  If the District Court’s ruling on the
      carrying cost rate is ultimately upheld on appeal and remanded to the PUCT
      for
      reconsideration, the PUCT could either confirm the existing weighted average
      carrying cost (WACC) rate or determine a new rate.  If the PUCT
      reduces the rate, it could result in a material adverse change to TCC’s
      recoverable carrying costs, results of operations, cash flows and financial
      condition.





The
      District Court judge also determined the PUCT improperly reduced TCC’s net
      stranded plant costs for commercial unreasonableness.  If upheld on
      appeal, this ruling could have a materially favorable effect on TCC’s results of
      operations and cash flows.





TCC,
      the
      PUCT and intervenors appealed the District Court rulings to the Court of
      Appeals.  Management cannot predict the outcome of these
      proceedings.  If TCC ultimately succeeds in its appeals, it could have
      a favorable effect on future results of operations, cash flows and financial
      condition.  If municipal customers and other intervenors succeed in
      their appeals, or if TCC has a tax normalization violation, it could have a
      substantial adverse effect on future results of operations, cash flows and
      financial condition.





**SECA
      Revenue Subject to Refund**





The
      AEP
      East companies ceased collecting T&O revenues in accordance with FERC
      orders, and collected SECA rates to mitigate the loss of T&O revenues from
      December 1, 2004 through March 31, 2006, when SECA rates
      expired.  Intervenors objected to the 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 or
      surcharge.  The AEP East companies paid SECA rates to other utilities
      at considerably lesser amounts than 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. Approximately $19 million of these recorded
      SECA revenues billed by PJM were not collected.  The AEP East
      companies filed a motion with the FERC to force payment of these uncollected
      SECA billings.





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 was not 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.




Since
        the
        implementation of SECA rates in December 2004, the AEP East companies recorded
        approximately $220 million of gross SECA revenues, subject to
        refund.  In 2006, the AEP East companies provided reserves of $37
        million in net refunds for current and future SECA settlements with all of
        AEP’s
        SECA customers.  The AEP East companies reached settlements with
        certain SECA customers related to approximately $69 million of such revenues
        for
        a net refund of $3 million.  The AEP East companies are in the process
        of completing two settlements-in-principle on an additional $36 million of
        SECA
        revenues and expect to make net refunds of $4 million when those settlements
        are
        approved.  Thus, completed and in-process settlements cover $105
        million of SECA revenues and will consume about $7 million of the reserves
        for
        refunds, leaving approximately $115 million of contested SECA revenues and
        $30
        million of refund reserves.  If the ALJ’s initial decision were upheld
        in its entirety, it would disallow approximately $90 million of the AEP East
        companies’ remaining $115 million of unsettled gross SECA
        revenues.  Based on recent settlement experience and the expectation
        that most of the $115 million of unsettled SECA revenues will be settled,
        management believes that the remaining reserve will be
        adequate.




In
      September 2006, AEP, together with Exelon Corporation and The Dayton Power
      and
      Light Company, filed an extensive post-hearing brief and reply brief noting
      exceptions to the ALJ’s initial decision and asking the FERC to reverse the
      decision in large part.  Management believes that the FERC should
      reject the 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.  As directed by the FERC, management is working to settle the
      remaining $115 million of unsettled revenues within the remaining reserve
      balance.  Although management believes it has meritorious arguments
      and can settle with the remaining customers within the amount provided,
      management cannot predict the ultimate outcome of ongoing settlement talks
      and,
      if necessary, any future FERC proceedings or court appeals.  If the
      FERC adopts the ALJ’s decision and/or AEP cannot settle a significant portion of
      the remaining unsettled claims within the amount provided, it will have an
      adverse effect on future results of operations and cash flows.





**Virginia
      Restructuring**





In
      April
      2004, Virginia enacted legislation that amended the Virginia Electric Utility
      Restructuring Act extending the transition period to market rates for the
      generation and supply of electricity, including the extension of capped rates,
      through December 31, 2010.  The legislation provided APCo with
      specified cost recovery opportunities during the extended capped rate period,
      including two optional bundled general base rate changes and an opportunity
      for
      timely recovery, through a separate rate mechanism, of certain unrecovered
      incremental environmental and reliability costs incurred on and after July
      1,
      2004.  Under the amended restructuring law, APCo continues to have an
      active fuel clause recovery mechanism in Virginia and continues to practice
      deferred fuel accounting.  Also, under the amended restructuring law,
      APCo has the right to defer incremental environmental compliance costs and
      incremental E&R costs for future recovery, to the extent such costs are not
      being recovered, and amortizes a portion of such deferrals commensurate with
      their recovery.





In
      April
      2007, the Virginia legislature adopted a comprehensive law providing for the
      re-regulation of electric utilities’ generation and supply
      rates.  These amendments shorten the transition period by two years
      (from 2010 to 2008) after which rates for retail generation and supply will
      return to a form of cost-based regulation in lieu of market-based
      rates.  The legislation provides for, among other things, biennial
      rate reviews beginning in 2009; rate adjustment clauses for the recovery of
      the
      costs of (a) transmission services and new transmission investments, (b) demand
      side management, load management, and energy efficiency programs, (c) renewable
      energy programs, and (d) environmental retrofit and new generation investments;
      significant return on equity enhancements for investments in new generation
      and,
      subject to Virginia SCC approval, certain environmental retrofits, and a floor
      on the allowed return on equity based on the average earned return on equities’
of regional vertically integrated electric utilities.  Effective July
      1, 2007, the amendments allow utilities to retain a minimum of 25% of the
      margins from off-system sales with the remaining margins from such sales
      credited against fuel factor expenses with a true-up to actual.  The
      legislation also allows APCo to continue to defer and recover incremental
      environmental and reliability costs incurred through December 31,
      2008.  The new re-regulation legislation should result in significant
      positive effects on APCo’s future earnings and cash flows from the mandated
      enhanced future returns on equity, the reduction of regulatory lag from the
      opportunities to adjust base rates on a biennial basis and the new opportunities
      to request timely recovery of certain new costs not included in base
      rates.





With
      the
      new re-regulation legislation, APCo’s generation business again meets the
      criteria for application of regulatory accounting principles under SFAS
      71.  The extraordinary pretax reduction in APCo’s earnings and
      shareholder’s equity from reapplication of SFAS 71 regulatory accounting of $118
      million ($79 million, net of tax) was recorded in the second quarter of
      2007.  This extraordinary net loss primarily relates to the
      reestablishment of $139 million in net generation-related customer-provided
      removal costs as a regulatory liability, offset by the restoration of $21
      million of deferred state income taxes as a regulatory asset.  In
      addition, APCo established a regulatory asset of $17 million for qualifying
      SFAS
      158 pension costs of the generation operations that, for ratemaking purposes,
      are deferred for future recovery under the new law.  AOCI and Deferred
      Income Taxes increased by $11 million and $6 million, respectively.





**New
      Generation**





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.  The application proposed three phases of
      cost recovery associated with the IGCC plant:  Phase 1, recovery of
      $24 million in pre-construction costs during 2006; Phase 2, concurrent recovery
      of construction-financing costs; and Phase 3, recovery or refund in distribution
      rates of any difference between the market-based standard service offer price
      for generation and the cost of operating and maintaining the plant, including
      a
      return on and return of the ultimate cost to construct the plant, originally
      projected to be $1.2 billion, along with fuel, consumables and replacement
      power
      costs.  The proposed recoveries in Phases 1 and 2 would be applied
      against the 4% limit on additional generation rate increases CSPCo and OPCo
      could request under their RSPs.





In
      April
      2006, the PUCO issued an order authorizing CSPCo and OPCo to implement Phase
      1
      of the cost recovery proposal.  In June 2006, the PUCO issued another
      order approving a tariff to recover Phase 1 pre-construction costs over a period
      of no more than twelve months effective July 1, 2006.  Through June
      30, 2007, CSPCo and OPCo each recorded pre-construction IGCC regulatory assets
      of $10 million and each collected the entire $12 million approved by the
      PUCO.  CSPCo and OPCo expect to incur additional pre-construction
      costs equal to or greater than the $12 million each recovered.  As of
      June 30, 2007, CSPCo and OPCo have recorded a liability of $2 million each
      for
      the over-recovered portion.  The PUCO indicated that if CSPCo and OPCo
      have not commenced a continuous course of construction of the IGCC plant within
      five years of the June 2006 PUCO order, all amounts collected for
      pre-construction costs, associated with items that may be utilized in IGCC
      projects to be built by AEP at other sites, must be refunded to Ohio ratepayers
      with interest.  The PUCO deferred ruling on cost recovery for Phases 2
      and 3 until further hearings are held.  A date for further rehearings
      has not been set.





In
      August
      2006, the Ohio Industrial Energy Users, Ohio Consumers’ Counsel, FirstEnergy
      Solutions and Ohio Energy Group filed four separate appeals of the PUCO’s order
      in the IGCC proceeding.  The Ohio Supreme Court has scheduled oral
      arguments for these appeals in October 2007.  Management believes that
      the PUCO’s authorization to begin collection of Phase 1 rates is
      lawful.  Management, however, cannot predict the outcome of these
      appeals.  If the PUCO’s order is found to be unlawful, CSPCo and OPCo
      could be required to refund Phase 1 cost-related recoveries.





Pending
      the outcome of the Supreme Court litigation, CSPCo and OPCo announced they
      may
      delay the start of construction of the IGCC plant.  Recent estimates
      of the cost to build an IGCC plant are $2.2 billion.  CSPCo and OPCo
      may need to request an extension to the 5 year start of construction requirement
      if the commencement of construction is delayed beyond 2011.  In July
      2007, CSPCo and OPCo filed a status report with the PUCO referencing APCo’s IGCC
      West Virginia filing.





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





In
      June
      2007, APCo filed testimony with the WVPSC supporting the requests for a CCN
      and
      for pre-approval of a surcharge rate mechanism to provide for the timely
      recovery of both the ongoing finance costs of the project during the
      construction period as well as the capital costs, operating costs and a return
      of equity once the facility is placed into commercial operation.  If
      APCo receives all necessary approvals, the plant could be completed by mid-2012
      at the earliest and currently is expected to cost an estimated $2.2
      billion**.**In July 2007, the WVPSC staff and
      intervenors filed to delay the procedural schedule by 90 days.  APCo
      supported the changes to the procedural schedule.  The statutory
      decision deadline was revised to March 2008.  In July 2007, the WVPSC
      approved the revised procedural schedule.  Through June 30, 2007, APCo
      deferred pre-construction IGCC costs totaling $11 million.  If the
      plant is not built and these costs are not recoverable, future results of
      operations and cash flows would be adversely affected.


In
      July
      2007, APCo filed a request with the Virginia SCC to recover, over the twelve
      months beginning January 1, 2009, a return on projected construction work in
      progress including development, design and planning costs from July 1, 2007
      through December 31, 2009 estimated to be $45 million associated with the IGCC
      plant to be constructed in West Virginia.  APCo is requesting
      authorization to defer a return on actual pre-construction costs incurred
      beginning July 1, 2007 until such costs are recovered, starting January 1,
      2009
      as required by the new re-regulation legislation.





In
      December 2005, SWEPCo sought proposals for new peaking, intermediate and base
      load generation to be online between 2008 and 2011.  In May 2006,
      SWEPCo announced plans to construct new generation to satisfy the demands of
      its
      customers.  Plans include the construction of up to 480 MW of
      simple-cycle natural gas combustion turbine peaking generation in Tontitown,
      Arkansas and a 480 MW combined-cycle natural gas fired intermediate plant at
      its
      existing Arsenal Hill Power Plant in Shreveport, Louisiana.  SWEPCo
      also plans to build the Turk plant, a new 600 MW base load coal plant, with
      a
      73% ownership share, in Hempstead County, Arkansas by 2011 to meet the long-term
      generation needs of its customers.  Preliminary cost estimates for
      SWEPCo’s share of these new facilities are approximately $1.4 billion (this
      total includes all three plants, but excludes the related transmission
      investment and AFUDC).  Expenditures related to construction of all of
      these facilities are expected to total $349 million in 2007.  These
      new facilities are subject to regulatory approvals from SWEPCo’s three state
      commissions.  Mattison plant, the peaking generation facility in
      Tontitown, Arkansas has been approved by all three state
      commissions.  Mattison plant Units 3 and 4 began commercial operation
      in July 2007, with the remaining two units scheduled for completion in December
      2007.  All four units of the Mattison plant are expected to be
      completed in advance of the originally planned 2008 commercial operation
      date.  Construction is expected to begin in the second half of 2007 on
      the base load facility and in 2008 on the intermediate facility, both upon
      approval from SWEPCo’s three state commissions.





In
      September 2005, PSO sought proposals for new peaking generation to be online
      in
      2008, and in December 2005 PSO sought proposals for base load generation to
      be
      online in 2011.  PSO received proposals and evaluated those proposals
      meeting the Request for Proposal criteria with oversight from a neutral third
      party.  In March 2006, PSO announced plans to add 170 MW of peaking
      generation to its Riverside Station plant in Jenks, Oklahoma where PSO will
      construct and operate two 85 MW simple-cycle natural gas combustion
      turbines.   Also in March 2006, PSO announced plans to add 170 MW
      of peaking generation to its Southwestern Station plant in Anadarko, Oklahoma
      where they will construct and operate two 85 MW simple-cycle natural gas
      combustion turbines.  Construction of all four peaking units began in
      the second quarter of 2007.  Combined preliminary cost estimates for
      these additions are approximately $120 million.  In April 2007, the
      OCC approved a settlement agreement in a matter involving a proposed
      cogeneration facility, which included a provision regarding these new peaking
      units.  The settlement agreement provides for recovery of a purchase
      fee of $35 million, which PSO paid to Lawton Cogeneration, LLC (Lawton) in
      the
      second quarter of 2007 to settle the proceeding and for all rights to Lawton’s
      permits, options and engineering studies for the cogeneration
      facility.  In April 2007, PSO recorded with OCC approval, the purchase
      fee as a regulatory asset and will recover it through a rider over a three-year
      period with a carrying charge of 8.25% beginning in September
      2007.  In addition, PSO will recover the traditional costs associated
      with plant in service of these new peaking units.  Such costs will be
      recovered through the rider until cost recovery occurs through base rates or
      formula rates in a subsequent proceeding.  PSO must file a rate case
      within eighteen months of the beginning of recovery through the rider unless
      the
      OCC approves a formula-based rate mechanism that provides for recovery of the
      peaking units.





In
      July
      2006, PSO announced plans to enter a joint ownership agreement with Oklahoma
      Gas
      and Electric Company (OG&E) and Oklahoma Municipal Power Authority (OMPA)
      where OG&E will construct and operate a new 950 MW coal-fueled electricity
      generating unit near Red Rock, Oklahoma.  PSO will own 50% of the new
      unit.  PSO, OG&E and OMPA signed an agreement in February 2007
      with Red Rock Power Partners to begin the first phase of the
      project.  Preliminary cost estimates for 100% of the new facility are
      approximately $1.8 billion, and the unit is expected to be online no later
      than
      the first half of 2012.  This new facility is subject to regulatory
      approval from the OCC, which is expected later in 2007.  Construction
      is expected to begin in the second half of 2007.  The Oklahoma Supreme
      Court is addressing whether the upfront approval process is
      constitutional.  PSO estimates construction expenditures for all of
      the new generation projects to be $167 million in 2007.




In
      November 2006, CSPCo agreed to purchase Darby Electric Generating Station
      (Darby) from DPL Energy, LLC, a subsidiary of The Dayton Power and Light
      Company, for $102 million and the assumption of liabilities of $2
      million.  CSPCo completed the purchase in April 2007.  The
      Darby plant is located near Mount Sterling, Ohio and is a natural gas, simple
      cycle power plant with a generating capacity of 480 MW.  The purchase
      of Darby is an economically efficient way to provide peaking generation to
      our
      customers at a cost below that of building a new, comparable plant.





In
      January 2007, AEGCo agreed to purchase Lawrenceburg Generating Station
      (Lawrenceburg) from Public Service Enterprise Group (PSEG) for $325 million
      and
      the assumption of liabilities of $3 million.  The transaction closed
      in May 2007.  The Lawrenceburg plant is located in Lawrenceburg,
      Indiana, adjacent to I&M’s Tanners Creek Plant, and is a natural gas,
      combined cycle power plant with a generating capacity of 1,096
      MW.  AEGCo sells the power to CSPCo under a FERC-approved purchase
      power contract.





**Electric
      Transmission Texas LLC Joint Venture**





In
      January 2007, we signed a participation agreement with MidAmerican Energy
      Holdings Company (MidAmerican) to form a joint venture company, Electric
      Transmission Texas LLC (ETT), to fund, own and operate electric transmission
      assets in ERCOT.  ETT filed with the PUCT in January 2007 requesting
      regulatory approval to operate as an electric transmission utility in Texas,
      to
      transfer from TCC to ETT approximately $76 million of transmission assets under
      construction and to establish a wholesale transmission tariff for
      ETT.  ETT also requested PUCT approval of initial rates based on an
      11.25% return on equity.  A hearing was held in July
      2007.  We expect a final order from the PUCT in October
      2007.





TCC
      also
      made a regulatory filing at the FERC in February 2007 regarding the transfer
      of
      certain transmission assets from TCC to ETT.  In April 2007, the FERC
      authorized the transfer.





Upon
      receipt of all required regulatory approvals, AEP Utilities, Inc., a subsidiary
      of AEP, and MEHC Texas Transco LLC, a subsidiary of MidAmerican, each will
      acquire a 50 percent equity ownership in ETT.  AEP and MidAmerican
      plan for ETT to invest in additional transmission projects in
      ERCOT.  The joint venture partners anticipate investments in excess of
      $1 billion of joint investment in Texas ERCOT Transmission projects that could
      be constructed by ETT during the next several years.  The joint
      venture is anticipated to be formed and begin operations in the fourth quarter
      of 2007, subject to certain closing conditions such as necessary regulatory
      approvals.





In
      February 2007, ETT filed a proposal with the PUCT that addresses the Competitive
      Renewable Energy Zone (CREZ) initiative of the Texas Legislature, which outlines
      opportunities for additional significant investment in transmission assets
      in
      Texas. A CREZ hearing was held in June 2007.  We expect an order in
      August 2007 on the designation of zones and amount of wind generation for each
      zone, subsequent studies by ERCOT on specific transmission recommendations
      in
      late 2007 or early 2008 and selection of transmission construction designees
      by
      the PUCT in early 2008.





We
      believe Texas can provide a high degree of regulatory certainty for transmission
      investment due to the predetermination of ERCOT’s need based on reliability
      requirements and significant Texas economic growth as well as public policy
      that
      supports “green generation” initiatives, which require substantial transmission
      improvements.  In addition, a streamlined annual interim transmission
      cost of service review process is available in ERCOT, which reduces regulatory
      lag.  The use of a joint venture structure will allow us to share the
      significant capital requirements for the investments, and also allow us to
      participate in more transmission projects than previously
      anticipated.





**AEP
      Interstate Project**





In
      January 2006, we filed a proposal with the FERC and PJM to build a new 765
      kV
      550-mile transmission line from West Virginia to New Jersey.  The 765
      kV line is designed to reduce PJM congestion costs by substantially improving
      west-east transfer capability by approximately 5,000 MW during peak loading
      conditions and reducing transmission line losses by up to 280 MW.  The
      project would also enhance reliability of the Eastern transmission
      grid.  The projected cost for the project, as originally proposed to
      PJM, is approximately $3 billion.  The project is subject to PJM and
      state approvals, and FERC approvals of incentive cost recovery
      mechanisms.





We
      were
      the first entity to file with the Department of Energy (DOE) seeking to have
      the
      route of a proposed transmission project designated as a National Interest
      Electric Transmission Corridor (NIETC).  The Energy Policy Act of 2005
      provides for NIETC designation for areas experiencing electric energy
      transmission capacity constraints or congestion that adversely affects
      consumers.  In August 2006, the DOE issued the “National Interest
      Electric Transmission Congestion Study.”  In this study, DOE indicated
      that the mid-Atlantic Coastal area, which the AEP Interstate Project is designed
      to reinforce, is one of the two most critical congestion areas in the
      nation.  In April 2007, the DOE included in its draft report the
      mid-Atlantic Coastal area NIETC which contains the entire proposed 765 kV
      transmission line.  The DOE expects to issue its final report by the
      end of 2007.





In
      July
      2006, pursuant to our request, the FERC clarified that the project qualifies
      for
      incentive rate treatment, provided that the new line is included in PJM’s 2007
      Regional Transmission Expansion Plan.  The conditionally- approved
      incentives include (a) a return on equity set at the high end of the “zone of
      reasonableness”; (b) the timely recovery of the cost of capital during the
      construction period; and (c) the ability to defer and recover costs incurred
      during the pre-construction and pre-operating period.  Since the FERC
      has clarified that the project qualifies for these rate incentives, we expect
      to
      propose rates that will capture the incentives in a future FERC rate
      filing.





In
      April
      2007, we signed a memorandum of understanding (MOU) with Allegheny Energy Inc.
      (AYE) to form a joint venture company to build and own certain electric
      transmission assets within PJM including the first half of the West Virginia
–
New Jersey line proposed by AEP in January 2006.  Under the terms of
      the MOU, the joint venture company will build and own approximately 300 miles
      of
      transmission lines from AEP’s Amos station to the Maryland
      border.  The MOU does not include any provisions for the remainder of
      the AEP Interstate Project proposal from AYE’s Kemptown station to New
      Jersey.





On
      June
      22, 2007, PJM’s Board authorized the construction of such a major new
      transmission line to address the reliability and efficiency needs of the PJM
      system.  PJM has identified a need for a new line as early as
      2012.  The line would be 765kV for most of its length and would run
      approximately 250 miles from AEP’s Amos substation in West Virginia to AYE’s
      Kemptown station in north central Maryland. AEP and AYE continue to work on
      finalizing the definitive agreements necessary to construct the line through
      a
      joint venture.  The new line has been named the “Potomac-Appalachian
      Transmission Highline” (PATH) by AEP and AYE and represents the “first leg” of
      the AEP Interstate Project.  The “second leg”, which would extend the
      line to New Jersey, is currently under evaluation by PJM.  We expect
      to execute definitive agreements for the joint venture with AYE in the third
      quarter of 2007 and anticipate the joint venture will begin activities in the
      second half of 2007.  The total PATH project is estimated to cost
      approximately $1.8 billion and AEP’s estimated share will be approximately $600
      million.





**Litigation**





In
      the
      ordinary course of business, we and our subsidiaries 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 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
      that have a probable likelihood of loss and the loss amount can be
      estimated.  For details on regulatory proceedings and our 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 2006 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 the results of
      operations, cash flows and financial condition of AEP and its
      subsidiaries.





See
      discussion of the “Environmental Litigation” within the “Environmental Matters”
section of “Significant Factors.”




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





In
      addition, we are engaged in litigation with respect to certain environmental
      matters, have been notified of potential responsibility for the clean-up of
      contaminated sites and incur costs for disposal of spent nuclear fuel and future
      decommissioning of our nuclear units.  We are also monitoring possible
      future requirements to reduce carbon dioxide (CO2) 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 2006 Annual
      Report.





***Environmental
      Litigation***





New
      Source Review (NSR) Litigation:  In 1999, the Federal EPA, a
      number of states and certain special interest groups filed complaints alleging
      that APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities including the
      Tennessee Valley Authority, Alabama Power Company, Cincinnati Gas & Electric
      Company, Ohio Edison Company, Southern Indiana Gas & Electric Company,
      Illinois Power Company, Tampa Electric Company, Virginia Electric Power Company
      and Duke Energy,  modified certain units at coal-fired generating
      plants in violation of the NSR requirements of the CAA.  Several
      similar complaints were filed in 1999 and thereafter against nonaffiliated
      utilities including Allegheny Energy, Eastern Kentucky Electric Cooperative,
      Public Service Enterprise Group, Santee Cooper, Wisconsin Electric Power
      Company, Mirant, NRG Energy and Niagara Mohawk.  Several of these
      cases were resolved through consent decrees.  The alleged
      modifications at our power plants occurred over a 20-year period.  A
      bench trial on the liability issues was held during 2005.  In 2006,
      the judge stayed the liability decision pending the issuance of a decision
      by
      the U.S. Supreme Court in the Duke Energy case.





Under
      the
      CAA, if a plant undertakes a major modification that directly results in an
      emissions increase, permitting requirements might be triggered and the plant
      may
      be required to install additional pollution control technology.  This
      requirement does not apply to activities such as routine maintenance,
      replacement of degraded equipment or failed components, or other repairs needed
      for the reliable, safe and efficient operation of the plant.





Courts
      that considered whether the activities at issue in these cases are routine
      maintenance, repair, or replacement, and therefore are excluded from NSR,
      reached different conclusions.  Similarly, courts that considered
      whether the activities at issue increased emissions from the power plants
      reached different results.  Appeals on these and other issues were
      filed in certain appellate courts, including a petition to appeal to the U.S.
      Supreme Court that was granted in the Duke Energy case.





In
      April
      2007, the U.S. Supreme Court reversed the Fourth Circuit Court of Appeals’
decision that had supported the statutory construction argument of Duke Energy
      in its NSR proceeding.  In a unanimous decision, the Court ruled that
      the Federal EPA was not obligated to define “major modification” in two
      different CAA provisions in the same way.  The Court also found that
      the Fourth Circuit’s interpretation of “major modification” as applying only to
      projects that increased hourly emission rates amounted to an invalidation of
      the
      relevant Federal EPA regulations, which under the CAA can only be challenged
      in
      the Court of Appeals within 60 days of the Federal EPA
      rulemaking.  The U.S. Supreme Court did acknowledge, however, that
      Duke Energy may argue on remand that the Federal EPA has been inconsistent
      in
      its interpretations of the CAA and the regulations and may not retroactively
      change 20 years of accepted practice.





In
      addition to providing guidance on the merits of arguments in our NSR
      proceedings, the U.S. Supreme Court’s issuance of a ruling in the Duke Energy
      cases has an impact on the timing of our NSR proceedings.  The court
      indicated an intent to issue a decision on liability issues in the third quarter
      of 2007.  A bench trial on remedy issues, if necessary, is likely to
      begin in the second half of 2007.




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





***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.





The
      rule
      was challenged in the courts by states, advocacy organizations and
      industry.  In January 2007, the Second Circuit Court of Appeals issued
      a decision remanding significant portions of the rule to the Federal
      EPA.  In July 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 cannot predict further action of the
      Federal EPA or what effect it may have on similar requirements adopted by the
      states.  We may seek further review or relief from the schedules
      included in our permits.





**Critical
      Accounting Estimates**





See
      the
“Critical Accounting Estimates” section of “Management’s Financial Discussion
      and Analysis of Results of Operations” in the 2006 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**





FIN
      48
      clarifies the accounting for uncertainty in income taxes recognized in an
      enterprise’s financial statements by prescribing a recognition threshold
      (whether a tax position is more likely than not to be sustained) without which,
      the benefit of that position is not recognized in the financial
      statements.  It requires a measurement determination for recognized
      tax positions based on the largest amount of benefit that is greater than 50
      percent likely of being realized upon ultimate settlement.  FIN 48
      also provides guidance on derecognition, classification, interest and penalties,
      accounting in interim periods, disclosure and transition.  FIN 48
      requires that the cumulative effect of applying this interpretation be reported
      and disclosed as an adjustment to the opening balance of retained earnings
      for
      that fiscal year and presented separately.  We adopted FIN 48
      effective January 1, 2007.  The effect of this interpretation on our
      financial statements was an unfavorable adjustment to retained earnings of
      $17
      million.  See “FIN  48 “Accounting for Uncertainty in Income
      Taxes” and FASB Staff Position FIN 48-1 “Definition of *Settlement* in
      FASB Interpretation No. 48”” section of Note 2 and Note 8 – Income
      Taxes.










**QUANTITATIVE
      AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT
      ACTIVITIES**





**Market
      Risks**





As
      a
      major power producer and marketer of wholesale electricity, coal and emission
      allowances, our Utility Operations segment is exposed to certain market
      risks.  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.





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 primarily financial derivatives, along with physical contracts,
      which will gradually liquidate and completely expire in 2011.  Our
      risk objective is to keep these positions generally risk neutral through
      maturity.





Our
      Generation and Marketing segment holds power sale contracts to commercial and
      industrial customers and wholesale power trading and marketing contracts within
      ERCOT.





We
      employ
      risk management contracts including physical forward purchase and sale
      contracts, exchange futures and options, over-the-counter options, swaps and
      other derivative contracts to offset price risk where appropriate.  We
      engage in risk management of electricity, natural gas, coal, and emissions
      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 management staff independently
      monitors our risk policies, procedures and risk levels and provides members
      of
      the Commercial Operations Risk Committee (CORC) various daily, weekly and/or
      monthly reports regarding compliance with policies, limits and
      procedures.  The CORC consists of our President – AEP Utilities, Chief
      Financial Officer, Senior Vice President of Commercial Operations and
      Treasurer.  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.





We
      actively participate in the Committee of Chief Risk Officers (CCRO) to develop
      standard disclosures for risk management activities around risk management
      contracts.  The CCRO adopted disclosure standards for risk management
      contracts to improve clarity, understanding and consistency of information
      reported.  We support the work of the CCRO and embrace the disclosure
      standards applicable to our business activities.  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 condensed consolidated balance sheet as of June 30, 2007 and
      the
      reasons for changes in our total MTM value included on our condensed
      consolidated balance sheet as compared to December 31, 2006.





**Reconciliation
      of MTM Risk Management Contracts to**


**Condensed
      Consolidated Balance Sheet**


**June
      30, 2007**


**(in
      millions)**


**Utility
                Operations**
            
            
            **Generation
                and**
              **Marketing**
            
            
            **All
                Other**
            
            
            **Sub-Total
                MTM Risk Management Contracts**
            
            
            **PLUS:
                MTM of Cash Flow and Fair Value Hedges**
            
            
            **Total**Current
                Assets
            
            $
            305
            
            
            $
            40
            
            
            $
            83
            
            
            $
            428
            
            
            $
            39
            
            
            $
            467Noncurrent
                Assets
            
            
            197
            
            
            
            46
            
            
            
            98
            
            
            
            341
            
            
            
            15
            
            
            
            356**Total
                Assets**
            
            
            502
            
            
            
            86
            
            
            
            181
            
            
            
            769
            
            
            
            54
            
            
            
            823Current
                Liabilities
            
            
            (215
            )
            
            
            (50
            )
            
            
            (83
            )
            
            
            (348
            )
            
            
            (3
            )
            
            
            (351
            )Noncurrent
                Liabilities
            
            
            (91
            )
            
            
            (11
            )
            
            
            (105
            )
            
            
            (207
            )
            
            
            (1
            )
            
            
            (208
            )**Total
                Liabilities**
            
            
            (306
            )
            
            
            (61
            )
            
            
            (188
            )
            
            
            (555
            )
            
            
            (4
            )
            
            
            (559
            )**Total
                MTM****Derivative****Contract
                Net**
              **Assets****(Liabilities)**
            
            $
            196
            
            
            $
            25
            
            
            $
            (7
            )
            
            $
            214
            
            
            $
            50
            
            
            $
            264





**MTM
      Risk Management Contract Net Assets (Liabilities)**


**Six
      Months Ended June 30, 2007**


**(in
      millions)**


**Utility
                Operations**
            
            
            **Generation**
              **and**
              **Marketing**
            
            
            **All
                Other**
            
            
            **Total****Total
                MTM Risk Management Contract Net Assets**
              **(Liabilities)
                 at December 31, 2006**
            
            $
            236
            
            
            $
            2
            
            
            $
            (5
            )
            
            $
            233(Gain)
                Loss from Contracts Realized/Settled
                During
              the Period and Entered in a Prior Period
            
            
            (37
            )
            
            
            (1
            )
            
            
            (1
            )
            
            
            (39
            )Fair
                Value of New Contracts at Inception When Entered
              During the Period (a)
            
            
            1
            
            
            
            31
            
            
            
            -
            
            
            
            32Net
                Option Premiums Paid/(Received) for Unexercised or
              Unexpired Option
                Contracts Entered During The Period
            
            
            1
            
            
            
            -
            
            
            
            -
            
            
            
            1Changes
                in Fair Value Due to Valuation Methodology
              Changes on Forward Contracts
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Changes
                in Fair Value Due to Market Fluctuations During
              the Period (b)
            
            
            8
            
            
            
            (7
            )
            
            
            (1
            )
            
            
            -Changes
                in Fair Value Allocated to Regulated Jurisdictions
                (c)
            
            
            (13
            )
            
            
            -
            
            
            
            -
            
            
            
            (13
            )**Total
                MTM Risk Management Contract Net Assets**
              **(Liabilities) at June 30, 2007**
            
            $
            196
            
            
            $
            25
            
            
            $
            (7
            )
            
            
            214Net
                Cash Flow and Fair Value
                Hedge****Contracts
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            50**Total
                MTM Risk Management Contract Net Assets at**
              **June 30, 2007**
            
            
            
            
            
            
            
            
            
            
            
            
            
            $
            264





(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.  Inception value is only recorded if observable market
                data can be obtained for valuation inputs for the entire contract
                term.  The contract prices are valued against market curves
                associated with the delivery location and delivery
                term.(b)
            Market
                fluctuations are attributable to various factors such as supply/demand,
                weather, storage, 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 assets/liabilities for those subsidiaries
                that
                operate in regulated jurisdictions.






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





The
      following table presents:





·
            The
                method of measuring fair value used in determining the carrying amount
                of
                our total MTM asset or liability (external sources or modeled
                internally).·
            The
                maturity, by year, of our net assets/liabilities, to give an indication
                of
                when these MTM amounts will settle and generate
                cash.





**Maturity
      and Source of Fair Value of MTM**


**Risk
      Management Contract Net Assets (Liabilities)**


**Fair
      Value of Contracts as of June 30, 2007**


**(in
      millions)**


**Remainder**
              **2007**
            
            
            **2008**
            
            
            **2009**
            
            
            **2010**
            
            
            **2011**
            
            
            **After**
              **2011
                (c)**
            
            
            **Total****Utility
                Operations:**Prices
                Actively Quoted – Exchange Traded Contracts
            
            $
            (6
            )
            
            $
            (8
            )
            
            $
            -
            
            
            $
            -
            
            
            $
            -
            
            
            $
            -
            
            
            $
            (14
            )Prices
                Provided by Other External
              Sources
                – OTC Broker Quotes (a)
            
            
            73
            
            
            
            56
            
            
            
            37
            
            
            
            17
            
            
            
            -
            
            
            
            -
            
            
            
            183Prices
                Based on Models and Other
              Valuation
                Methods (b)
            
            
            (4
            )
            
            
            (3
            )
            
            
            8
            
            
            
            17
            
            
            
            4
            
            
            
            5
            
            
            
            27**Total**
            
            
            63
            
            
            
            45
            
            
            
            45
            
            
            
            34
            
            
            
            4
            
            
            
            5
            
            
            
            196**Generation
                and Marketing:**Prices
                Actively Quoted – Exchange Traded Contracts
            
            
            (8
            )
            
            
            (2
            )
            
            
            2
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            (8
            )Prices
                Provided by Other External
              Sources
                – OTC Broker Quotes (a)
            
            
            (5
            )
            
            
            8
            
            
            
            3
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            6Prices
                Based on Models and Other
              Valuation
                Methods (b)
            
            
            1
            
            
            
            2
            
            
            
            (3
            )
            
            
            6
            
            
            
            5
            
            
            
            16
            
            
            
            27**Total**
            
            
            (12
            )
            
            
            8
            
            
            
            2
            
            
            
            6
            
            
            
            5
            
            
            
            16
            
            
            
            25**All
                Other:**Prices
                Actively Quoted – Exchange Traded Contracts
            
            
            2
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            2Prices
                Provided by Other External
              Sources
                – OTC Broker Quotes (a)
            
            
            (1
            )
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            (1
            )Prices
                Based on Models and Other
              Valuation
                Methods (b)
            
            
            (1
            )
            
            
            (1
            )
            
            
            (4
            )
            
            
            (4
            )
            
            
            2
            
            
            
            -
            
            
            
            (8
            )**Total**
            
            
            -
            
            
            
            (1
            )
            
            
            (4
            )
            
            
            (4
            )
            
            
            2
            
            
            
            -
            
            
            
            (7
            )**Total:**Prices
                Actively Quoted – Exchange
              Traded
                Contracts
            
            
            (12
            )
            
            
            (10
            )
            
            
            2
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            (20
            )Prices
                Provided by Other External
              Sources
                – OTC Broker Quotes (a)
            
            
            67
            
            
            
            64
            
            
            
            40
            
            
            
            17
            
            
            
            -
            
            
            
            -
            
            
            
            188Prices
                Based on Models and Other
              Valuation
                Methods (b)
            
            
            (4
            )
            
            
            (2
            )
            
            
            1
            
            
            
            19
            
            
            
            11
            
            
            
            21
            
            
            
            46**Total**
            
            $
            51
            
            
            $
            52
            
            
            $
            43
            
            
            $
            36
            
            
            $
            11
            
            
            $
            21
            
            
            $
            214





(a)
            Prices
                Provided by Other External Sources – OTC Broker Quotes reflects
                information obtained from over-the-counter brokers (OTC), industry
                services, or multiple-party online platforms.(b)
            Prices
                Based on Models and Other Valuation Methods is used in the absence
                of
                independent information from external sources.  Modeled
                information is derived using valuation models developed by the reporting
                entity, reflecting when appropriate, option pricing theory, discounted
                cash flow concepts, valuation adjustments, etc. and may require projection
                of prices for underlying commodities beyond the period that prices
                are
                available from third-party sources.  In addition, where external
                pricing information or market liquidity is limited, such valuations
                are
                classified as modeled.  Contract values that are measured using
                models or valuation methods other than active quotes or OTC broker
                quotes
                (because of the lack of such data for all delivery quantities, locations
                and periods) incorporate in the model or other valuation methods,
                to the
                extent possible, OTC broker quotes and active quotes for deliveries
                in
                years and at locations for which such quotes are available including
                values determinable by other third party transactions.(c)
            There
                is mark-to-market value of $21 million in individual periods beyond
                2011.  $10 million of this mark-to-market value is in 2012, $5
                million is in 2013, and $5 million is in 2014, and $1 million for
                years
                2015 through 2017.




The
      determination of the point at which a market is no longer supported by
      independent quotes and therefore considered in the modeled category in the
      preceding table varies by market.  The following table generally
      reports an estimate of the maximum tenors (contract maturities) of the liquid
      portion of each energy market.





**Maximum
      Tenor of the Liquid Portion of Risk Management Contracts**


**As
      of June 30, 2007**





**Commodity**
            
            **Transaction
                Class**
            
            **Market/Region**
            
            **Tenor****(in
                Months)**Natural
                Gas
            
            Futures
            
            NYMEX
                / Henry Hub
            
            60Physical
                Forwards
            
            Gulf
                Coast, Texas
            
            16Swaps
            
            Northeast,
                Mid-Continent, Gulf Coast, Texas
            
            16Exchange
                Option Volatility
            
            NYMEX
                / Henry Hub
            
            12Power
            
            Futures
            
            AEP
                East - PJM
            
            30Physical
                Forwards
            
            AEP
                East
            
            42Physical
                Forwards
            
            AEP
                West
            
            18Physical
                Forwards
            
            West
                Coast
            
            30Peak
                Power Volatility (Options)
            AEP
                East - Cinergy, PJM
            
            12Emissions
            
            Credits
            
            SO2,
                NOx
            
            30Coal
            
            Physical
                Forwards
            
            PRB,
                NYMEX, CSX
            
            30








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





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





We
      use
      interest rate derivative transactions to manage interest rate risk related
      to
      existing variable rate debt and to manage interest rate exposure on anticipated
      borrowings of fixed-rate debt.  We do not hedge all interest rate
      exposure.





We
      use
      forward contracts and collars as cash flow hedges to lock in prices on certain
      transactions denominated in foreign currencies where deemed
      necessary.  We do not hedge all foreign currency
      exposure.




The
      following table provides the detail on designated, effective cash flow hedges
      included in AOCI on our Condensed Consolidated Balance Sheets and the reasons
      for changes in cash flow hedges from December 31, 2006 to June 30,
      2007.  The following table also indicates what portion of designated,
      effective hedges are expected to be reclassified into net income in the next
      12
      months.  Only contracts designated as cash flow hedges are recorded in
      AOCI.  Therefore, economic hedge contracts which are not designated as
      effective cash flow hedges are marked-to-market and are included in the previous
      risk management tables.





**Total
      Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow
      Hedges**


**Six
      Months Ended June 30, 2007**


**(in
      millions)**


**Power**
            
            
            **Interest
                Rate and**
              **Foreign**
              **Currency**
            
            
            **Total****Beginning
                Balance in AOCI, December 31, 2006**
            
            $
            17
            
            
            $
            (23
            )
            
            $
            (6
            )Changes
                in Fair Value
            
            
            22
            
            
            
            5
            
            
            
            27Reclassifications
                from AOCI to Net Income for
              Cash
                Flow Hedges Settled
            
            
            (13
            )
            
            
            1
            
            
            
            (12
            )**Ending
                Balance in AOCI, June 30, 2007**
            
            $
            26
            
            
            $
            (17
            )
            
            $
            9**After
                Tax Portion Expected to be Reclassified**
              **to
                Earnings During Next 12 Months**
            
            $
            20
            
            
            $
            -
            
            
            $
            20





**Credit
      Risk**





We
      limit
      credit risk in our wholesale marketing and trading activities by assessing
      creditworthiness of potential counterparties before entering into transactions
      with them and continuing to evaluate their creditworthiness after transactions
      have been initiated.  Only after an entity meets our internal credit
      rating criteria will we extend unsecured credit.  We use Moody’s
      Investors Service, Standard & Poor’s and qualitative and quantitative data
      to assess the financial health of counterparties on an ongoing
      basis.  We use our analysis, in conjunction with the rating agencies’
information, to determine appropriate risk parameters.  We also
      require cash deposits, letters of credit and parent/affiliate guarantees as
      security from counterparties depending upon credit quality in our normal course
      of business.





We
      have
      risk management contracts with numerous counterparties.  Since open
      risk management contracts are valued based on changes in market prices of the
      related commodities, our exposures change daily.  As of June 30, 2007,
      our credit exposure net of credit collateral to sub investment grade
      counterparties was approximately 4.9%, 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 June 30, 2007, the following table approximates our
      counterparty credit quality and exposure based on netting across commodities,
      instruments and legal entities where applicable (in millions, except number
      of
      counterparties):





**Counterparty
                Credit Quality**
            
            **Exposure
                Before Credit Collateral**
            
            
            **Credit
                Collateral**
            
            
            **Net
                Exposure**
            
            
            **Number
                of Counterparties>10% of**
              **Net
                Exposure**
            
            
            **Net
                Exposure of Counterparties>10%**Investment
                Grade
            
            $
            723
            
            
            $
            81
            
            
            $
            642
            
            
            
            1
            
            
            $
            67Split
                Rating
            
            
            20
            
            
            
            2
            
            
            
            18
            
            
            
            3
            
            
            
            17Noninvestment
                Grade
            
            
            30
            
            
            
            7
            
            
            
            23
            
            
            
            1
            
            
            
            19No
                External Ratings:Internal
                Investment Grade
            
            
            71
            
            
            
            -
            
            
            
            71
            
            
            
            1
            
            
            
            30Internal
                Noninvestment Grade
            
            
            17
            
            
            
            2
            
            
            
            15
            
            
            
            1
            
            
            
            11**Total
                as of June 30, 2007**
            
            $
            861
            
            
            $
            92
            
            
            $
            769
            
            
            
            7
            
            
            $
            144**Total
                as of December 31, 2006**
            
            $
            998
            
            
            $
            161
            
            
            $
            837
            
            
            
            9
            
            
            $
            169




**Generation
      Plant Hedging Information**





This
      table provides information on operating measures regarding the proportion of
      output of our generation facilities (based on economic availability projections)
      economically hedged, including both contracts designated as cash flow hedges
      under SFAS 133 and contracts not designated as cash flow hedges.  This
      information is forward-looking and provided on a prospective basis through
      December 31, 2009.  This table is a point-in-time estimate, subject to
      changes in market conditions and our decisions on how to manage operations
      and
      risk.  “Estimated Plant Output Hedged” represents the portion of MWHs
      of future generation/production, taking into consideration scheduled plant
      outages, for which we have sales commitments or estimated requirement
      obligations to customers.





**Generation
      Plant Hedging Information**


**Estimated
      Next Three Years**


**As
      of June 30, 2007**





**Remainder****2007**
            
            **2008**
            
            **2009**Estimated
                Plant Output Hedged
            94%
            
            90%
            
            91%





**VaR
      Associated with Risk Management Contracts**





***Commodity
      Price Risk***





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 June 30, 2007, a near term
      typical change in commodity prices is not expected to have a material effect
      on
      our results of operations, cash flows or financial condition.





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





**VaR
      Model**





**Six
                Months Ended**
              **June
                30, 2007**
            
            
            
            
            **Twelve
                Months Ended**
              **December
                31, 2006****(in
                millions)**
            
            
            
            
            **(in
                millions)****End**
            
            **High**
            
            **Average**
            
            **Low**
            
            
            
            
            **End**
            
            **High**
            
            **Average**
            
            **Low**$1
            
            $6
            
            $2
            
            $1
            
            
            
            
            $3
            
            $10
            
            $3
            
            $1





The
      High
      VaR for 2006 occurred in mid-August during a period of high gas and power
      volatility.  The following day, positions were flattened and the VaR
      was significantly reduced.





***Interest
      Rate Risk***





We
      utilize a VaR model to measure interest rate market risk exposure. The interest
      rate VaR model is based on a Monte Carlo simulation with a 95% confidence level
      and a one-year holding period.  The volatilities and correlations were
      based on three years of daily prices. The risk of potential loss in fair value
      attributable to our exposure to interest rates, primarily related to long-term
      debt with fixed interest rates, was $912 million at June 30, 2007 and $870
      million at December 31, 2006.  We would not expect to liquidate our
      entire debt portfolio in a one-year holding period.  Therefore, a near
      term change in interest rates should not materially affect our results of
      operations, cash flows or financial position.








**AMERICAN
      ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY
      COMPANIES**


**CONDENSED
      CONSOLIDATED STATEMENTS OF INCOME**


**For
      the Three and Six Months Ended June 30, 2007 and 2006**


**(in
      millions, except per-share amounts and shares outstanding)**


**(Unaudited)**


**Three
                Months Ended**
            
            
            **Six
                Months Ended****2007**
            
            
            **2006**
            
            
            **2007**
            
            
            **2006****REVENUES**Utility
                Operations
            
            $
            2,818
            
            
            $
            2,799
            
            
            $
            5,704
            
            
            $
            5,781Other
            
            
            328
            
            
            
            137
            
            
            
            611
            
            
            
            263**TOTAL**
            
            
            3,146
            
            
            
            2,936
            
            
            
            6,315
            
            
            
            6,044**EXPENSES**Fuel
                and Other Consumables Used for Electric Generation
            
            
            868
            
            
            
            888
            
            
            
            1,754
            
            
            
            1,849Purchased
                Energy for Resale
            
            
            291
            
            
            
            237
            
            
            
            537
            
            
            
            403Other
                Operation and Maintenance
            
            
            881
            
            
            
            896
            
            
            
            1,819
            
            
            
            1,717Gain
                on Disposition of Assets, Net
            
            
            (3
            )
            
            
            -
            
            
            
            (26
            )
            
            
            (68
            )Depreciation
                and Amortization
            
            
            372
            
            
            
            354
            
            
            
            763
            
            
            
            702Taxes
                Other Than Income Taxes
            
            
            188
            
            
            
            190
            
            
            
            374
            
            
            
            381**TOTAL**
            
            
            2,597
            
            
            
            2,565
            
            
            
            5,221
            
            
            
            4,984**OPERATING
                INCOME**
            
            
            549
            
            
            
            371
            
            
            
            1,094
            
            
            
            1,060Interest
                and Investment Income
            
            
            8
            
            
            
            11
            
            
            
            31
            
            
            
            19Carrying
                Costs Income
            
            
            16
            
            
            
            33
            
            
            
            24
            
            
            
            63Allowance
                For Equity Funds Used During Construction
            
            
            6
            
            
            
            7
            
            
            
            14
            
            
            
            13Gain
                on Disposition of Equity Investments, Net
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            3**INTEREST
                AND OTHER CHARGES**Interest
                Expense
            
            
            213
            
            
            
            176
            
            
            
            399
            
            
            
            344Preferred
                Stock Dividend Requirements of Subsidiaries
            
            
            -
            
            
            
            -
            
            
            
            1
            
            
            
            1**TOTAL**
            
            
            213
            
            
            
            176
            
            
            
            400
            
            
            
            345**INCOME
                BEFORE INCOME TAX EXPENSE, MINORITY**
              **INTEREST
                EXPENSE AND EQUITY EARNINGS (LOSS)**
            
            
            366
            
            
            
            246
            
            
            
            763
            
            
            
            813Income
                Tax Expense
            
            
            108
            
            
            
            72
            
            
            
            238
            
            
            
            261Minority
                Interest Expense
            
            
            1
            
            
            
            1
            
            
            
            2
            
            
            
            1Equity
                Earnings (Loss) of Unconsolidated Subsidiaries
            
            
            -
            
            
            
            (1
            )
            
            
            5
            
            
            
            (1
            )**INCOME
                BEFORE DISCONTINUED OPERATIONS AND**
              **EXTRAORDINARY
                LOSS**
            
            
            257
            
            
            
            172
            
            
            
            528
            
            
            
            550**DISCONTINUED
                OPERATIONS, NET OF TAX**
            
            
            2
            
            
            
            3
            
            
            
            2
            
            
            
            6**INCOME
                BEFORE EXTRAORDINARY LOSS**
            
            
            259
            
            
            
            175
            
            
            
            530
            
            
            
            556**EXTRAORDINARY
                LOSS, NET OF TAX**
            
            
            (79
            )
            
            
            -
            
            
            
            (79
            )
            
            
            -**NET
                INCOME**
            
            $
            180
            
            
            $
            175
            
            
            $
            451
            
            
            $
            556**WEIGHTED
                AVERAGE NUMBER OF BASIC SHARES OUTSTANDING**
            
            
            398,679,242
            
            
            
            393,722,353
            
            
            
            398,000,712
            
            
            
            393,687,949**BASIC
                EARNINGS PER SHARE**Income
                Before Discontinued Operations and Extraordinary Loss
            
            $
            0.64
            
            
            $
            0.44
            
            
            $
            1.33
            
            
            $
            1.40Discontinued
                Operations, Net of Tax
            
            
            0.01
            
            
            
            -
            
            
            
            -
            
            
            
            0.01Income
                Before Extraordinary Loss
            
            
            0.65
            
            
            
            0.44
            
            
            
            1.33
            
            
            
            1.41Extraordinary
                Loss, Net of Tax
            
            
            (0.20
            )
            
            
            -
            
            
            
            (0.20
            )
            
            
            -**TOTAL
                BASIC EARNINGS PER SHARE**
            
            $
            0.45
            
            
            $
            0.44
            
            
            $
            1.13
            
            
            $
            1.41**WEIGHTED
                AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING**
            
            
            399,868,900
            
            
            
            395,500,506
            
            
            
            399,214,277
            
            
            
            395,540,498**DILUTED
                EARNINGS PER SHARE**Income
                Before Discontinued Operations and Extraordinary Loss
            
            $
            0.64
            
            
            $
            0.43
            
            
            $
            1.32
            
            
            $
            1.39Discontinued
                Operations, Net of Tax
            
            
            0.01
            
            
            
            0.01
            
            
            
            0.01
            
            
            
            0.02Income
                Before Extraordinary Loss
            
            
            0.65
            
            
            
            0.44
            
            
            
            1.33
            
            
            
            1.41Extraordinary
                Loss, Net of Tax
            
            
            (0.20
            )
            
            
            -
            
            
            
            (0.20
            )
            
            
            -**TOTAL
                DILUTED EARNINGS PER SHARE**
            
            $
            0.45
            
            
            $
            0.44
            
            
            $
            1.13
            
            
            $
            1.41**CASH
                DIVIDENDS PAID PER SHARE**
            
            $
            0.39
            
            
            $
            0.37
            
            
            $
            0.78
            
            
            $
            0.74


*See
      Condensed Notes to Condensed Consolidated Financial
      Statements.*





**AMERICAN
      ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES**


**CONDENSED
      CONSOLIDATED BALANCE SHEETS**


**ASSETS**


**June
      30, 2007 and December 31, 2006**


**(in
      millions)**


**(Unaudited)**





**2007**
            
            
            **2006****CURRENT
                ASSETS**Cash
                and Cash Equivalents
            
            $
            172
            
            
            $
            301Other
                Temporary Investments
            
            
            337
            
            
            
            425Accounts
                Receivable:Customers
            
            
            676
            
            
            
            676Accrued
                Unbilled Revenues
            
            
            378
            
            
            
            350Miscellaneous
            
            
            58
            
            
            
            44Allowance for Uncollectible Accounts
            
            
            (40
            )
            
            
            (30
            )Total Accounts Receivable
            
            
            1,072
            
            
            
            1,040Fuel,
                Materials and Supplies
            
            
            1,038
            
            
            
            913Risk
                Management Assets
            
            
            467
            
            
            
            680Regulatory
                Asset for Under-Recovered Fuel Costs
            
            
            28
            
            
            
            38Margin
                Deposits
            
            
            75
            
            
            
            120Prepayments
                and Other
            
            
            74
            
            
            
            71**TOTAL**
            
            
            3,263
            
            
            
            3,588**PROPERTY,
                PLANT AND EQUIPMENT**Electric:Production
            
            
            19,618
            
            
            
            16,787Transmission
            
            
            7,275
            
            
            
            7,018Distribution
            
            
            11,718
            
            
            
            11,338Other
                (including coal mining and nuclear fuel)
            
            
            3,320
            
            
            
            3,405Construction
                Work in Progress
            
            
            2,469
            
            
            
            3,473**Total**
            
            
            44,400
            
            
            
            42,021Accumulated
                Depreciation and Amortization
            
            
            (15,933
            )
            
            
            (15,240
            )**TOTAL
                - NET**
            
            
            28,467
            
            
            
            26,781**OTHER
                NONCURRENT ASSETS**Regulatory
                Assets
            
            
            2,405
            
            
            
            2,477Securitized
                Transition Assets
            
            
            2,116
            
            
            
            2,158Spent
                Nuclear Fuel and Decommissioning Trusts
            
            
            1,311
            
            
            
            1,248Goodwill
            
            
            76
            
            
            
            76Long-term
                Risk Management Assets
            
            
            356
            
            
            
            378Employee
                Benefits and Pension Assets
            
            
            303
            
            
            
            327Deferred
                Charges and Other
            
            
            896
            
            
            
            910**TOTAL**
            
            
            7,463
            
            
            
            7,574**Assets
                Held for Sale**
            
            
            -
            
            
            
            44**TOTAL
                ASSETS**
            
            $
            39,193
            
            
            $
            37,987





*See
      Condensed Notes to Condensed Consolidated Financial
      Statements.*





**AMERICAN
      ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES**


**CONDENSED
      CONSOLIDATED BALANCE SHEETS**


**LIABILITIES
      AND SHAREHOLDERS’ EQUITY**


**June
      30, 2007 and December 31, 2006**


**(Unaudited)**








**2007**
            
            **2006****CURRENT
                LIABILITIES**
            
            
            
            
            **(in
                millions)**Accounts
                Payable
            
            
            
            
            $
            1,189
            
            $
            1,360Short-term
                Debt
            
            
            
            
            
            438
            
            
            18Long-term
                Debt Due Within One Year
            
            
            
            
            
            1,521
            
            
            1,269Risk
                Management Liabilities
            
            
            
            
            
            351
            
            
            541Customer
                Deposits
            
            
            
            
            
            353
            
            
            339Accrued
                Taxes
            
            
            
            
            
            783
            
            
            781Accrued
                Interest
            
            
            
            
            
            291
            
            
            186Other
            
            
            
            
            
            878
            
            
            962**TOTAL**
            
            
            
            
            
            5,804
            
            
            5,456**NONCURRENT
                LIABILITIES**Long-term
                Debt
            
            
            
            
            
            13,067
            
            
            12,429Long-term
                Risk Management Liabilities
            
            
            
            
            
            208
            
            
            260Deferred
                Income Taxes
            
            
            
            
            
            4,536
            
            
            4,690Regulatory
                Liabilities and Deferred Investment Tax Credits
            
            
            
            
            
            2,936
            
            
            2,910Asset
                Retirement Obligations
            
            
            
            
            
            1,047
            
            
            1,023Employee
                Benefits and Pension Obligations
            
            
            
            
            
            838
            
            
            823Deferred
                Gain on Sale and Leaseback – Rockport Plant Unit 2
            
            
            
            
            
            143
            
            
            148Deferred
                Credits and Other
            
            
            
            
            
            897
            
            
            775**TOTAL**
            
            
            
            
            
            23,672
            
            
            23,058**TOTAL
                LIABILITIES**
            
            
            
            
            
            29,476
            
            
            28,514Cumulative
                Preferred Stock Not Subject to Mandatory Redemption
            
            
            
            
            
            61
            
            
            61Commitments
                and Contingencies (Note 4)**COMMON
                SHAREHOLDERS’ EQUITY**Common
                Stock Par Value $6.50:2007
            
            2006Shares
                Authorized
            600,000,000
            
            600,000,000Shares
                Issued
            420,689,766
            
            418,174,728(21,499,992
                shares were held in treasury at June 30, 2007 and December 31,
                2006)
            
            
            
            
            
            2,734
            
            
            2,718Paid-in
                Capital
            
            
            
            
            
            4,305
            
            
            4,221Retained
                Earnings
            
            
            
            
            
            2,819
            
            
            2,696Accumulated
                Other Comprehensive Income (Loss)
            
            
            
            
            
            (202
            )
            
            (223
            )**TOTAL**
            
            
            
            
            
            9,656
            
            
            9,412**TOTAL
                LIABILITIES AND SHAREHOLDERS’ EQUITY**
            
            
            
            
            $
            39,193
            
            $
            37,987





*See
      Condensed Notes to Condensed Consolidated Financial
      Statements.*





**AMERICAN
      ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES**


**CONDENSED
      CONSOLIDATED STATEMENTS OF CASH FLOWS**


**For
      the Six Months Ended June 30, 2007 and 2006**


**(in
      millions)**


**(Unaudited)**


**2007**
            
            
            **2006****OPERATING
                ACTIVITIES****Net
                Income**
            
            $
            451
            
            
            $
            556Less:  Discontinued
                Operations, Net of Tax
            
            
            (2
            )
            
            
            (6
            )**Income
                Before Discontinued Operations**
            
            
            449
            
            
            
            550**Adjustments
                for Noncash Items:**Depreciation
                and Amortization
            
            
            763
            
            
            
            702Deferred
                Income Taxes
            
            
            (24
            )
            
            
            10Deferred
                Investment Tax Credits
            
            
            (13
            )
            
            
            (14
            )Extraordinary
                Loss
            
            
            79
            
            
            
            -Regulatory
                Provision
            
            
            105
            
            
            
            -Carrying
                Costs Income
            
            
            (24
            )
            
            
            (63
            )Mark-to-Market
                of Risk Management Contracts
            
            
            19
            
            
            
            (43
            )Amortization
                of Nuclear Fuel
            
            
            33
            
            
            
            25Deferred
                Property Taxes
            
            
            24
            
            
            
            12Fuel
                Over/Under-Recovery, Net
            
            
            (101
            )
            
            
            128Gain
                on Sales of Assets and Equity Investments, Net
            
            
            (26
            )
            
            
            (71
            )Change
                in Other Noncurrent Assets
            
            
            (53
            )
            
            
            82Change
                in Other Noncurrent Liabilities
            
            
            23
            
            
            
            (12
            )**Changes
                in Certain Components of Working Capital:**Accounts
                Receivable, Net
            
            
            (81
            )
            
            
            202Fuel,
                Materials and Supplies
            
            
            (90
            )
            
            
            (140
            )Margin
                Deposits
            
            
            45
            
            
            
            67Accounts
                Payable
            
            
            (58
            )
            
            
            (17
            )Customer
                Deposits
            
            
            14
            
            
            
            (189
            )Accrued
                Taxes, Net
            
            
            49
            
            
            
            90Accrued
                Interest
            
            
            67
            
            
            
            1Other
                Current Assets
            
            
            (21
            )
            
            
            19Other
                Current Liabilities
            
            
            (210
            )
            
            
            (216
            )**Net
                Cash Flows From Operating Activities**
            
            
            969
            
            
            
            1,123**INVESTING
                ACTIVITIES**Construction
                Expenditures
            
            
            (1,823
            )
            
            
            (1,611
            )Change
                in Other Temporary Investments, Net
            
            
            (129
            )
            
            
            3Purchases
                of Investment Securities
            
            
            (6,827
            )
            
            
            (5,647
            )Sales
                of Investment Securities
            
            
            7,035
            
            
            
            5,596Acquisition
                of Darby and Lawrenceburg Plants
            
            
            (427
            )
            
            
            -Proceeds
                from Sales of Assets
            
            
            74
            
            
            
            118Other
            
            
            (30
            )
            
            
            (31
            )**Net
                Cash Flows Used For Investing Activities**
            
            
            (2,127
            )
            
            
            (1,572
            )**FINANCING
                ACTIVITIES**Issuance
                of Common Stock
            
            
            90
            
            
            
            6Change
                in Short-term Debt, Net
            
            
            420
            
            
            
            147Issuance
                of Long-term Debt
            
            
            1,064
            
            
            
            1,081Retirement
                of Long-term Debt
            
            
            (190
            )
            
            
            (676
            )Dividends
                Paid on Common Stock
            
            
            (311
            )
            
            
            (291
            )Other
            
            
            (44
            )
            
            
            30**Net
                Cash Flows From Financing Activities**
            
            
            1,029
            
            
            
            297**Net
                Decrease in Cash and Cash Equivalents**
            
            
            (129
            )
            
            
            (152
            )**Cash
                and Cash Equivalents at Beginning of Period**
            
            
            301
            
            
            
            401**Cash
                and Cash Equivalents at End of Period**
            
            $
            172
            
            
            $
            249**SUPPLEMENTARY
                INFORMATION**Cash
                Paid for Interest, Net of Capitalized Amounts
            
            $
            304
            
            
            $
            316Net
                Cash Paid for Income Taxes
            
            
            128
            
            
            
            123Noncash
                Acquisitions Under Capital Leases
            
            
            23
            
            
            
            37Construction
                Expenditures Included in Accounts Payable at June 30,
            
            
            295
            
            
            
            273Acquisition
                of Nuclear Fuel in Accounts Payable at June 30,
            
            
            31
            
            
            
            26Noncash
                Assumption of Liabilities Related to Acquisitions
            
            
            5
            
            
            
            -*See
                Condensed Notes to Condensed Consolidated Financial
                Statements.*





**AMERICAN
      ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES**


**CONDENSED
      CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDERS’ EQUITY
      AND**


**COMPREHENSIVE
      INCOME (LOSS)**


**For
      the Six Months Ended June 30, 2007 and 2006**


**(in
      millions)**


**(Unaudited)**





**Common
                Stock****Shares**
            
            
            **Amount**
            
            
            **Paid-in
                Capital**
            
            
            **Retained
                Earnings**
            
            
            **Accumulated
                Other Comprehensive Income (Loss)**
            
            
            **Total****DECEMBER
                31, 2005**
            
            
            415
            
            
            $
            2,699
            
            
            $
            4,131
            
            
            $
            2,285
            
            
            $
            (27
            )
            
            $
            9,088Issuance
                of Common Stock
            
            
            
            
            
            
            1
            
            
            
            5
            
            
            
            
            
            
            
            
            
            
            
            6Common
                Stock Dividends
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            (291
            )
            
            
            
            
            
            
            (291
            )Other
            
            
            
            
            
            
            
            
            
            
            2
            
            
            
            
            
            
            
            
            
            
            
            2**TOTAL**
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            8,805**COMPREHENSIVE
                INCOME****Other
                Comprehensive Income, Net of Tax:**Cash
                Flow Hedges, Net of Tax of $29
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            54
            
            
            
            54Securities
                Available for Sale, Net of Tax of $6
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            11
            
            
            
            11**NET
                INCOME**
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            556
            
            
            
            
            
            
            
            556**TOTAL
                COMPREHENSIVE INCOME**
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            621**JUNE
                30, 2006**
            
            
            415
            
            
            $
            2,700
            
            
            $
            4,138
            
            
            $
            2,550
            
            
            $
            38
            
            
            $
            9,426**DECEMBER
                31, 2006**
            
            
            418
            
            
            $
            2,718
            
            
            $
            4,221
            
            
            $
            2,696
            
            
            $
            (223
            )
            
            $
            9,412FIN
                48 Adoption, Net of Tax
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            (17
            )
            
            
            
            
            
            
            (17
            )Issuance
                of Common Stock
            
            
            3
            
            
            
            16
            
            
            
            74
            
            
            
            
            
            
            
            
            
            
            
            90Common
                Stock Dividends
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            (311
            )
            
            
            
            
            
            
            (311
            )Other
            
            
            
            
            
            
            
            
            
            
            10
            
            
            
            
            
            
            
            
            
            
            
            10**TOTAL**
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            9,184**COMPREHENSIVE
                INCOME****Other
                Comprehensive Income (Loss), Net of Tax:**Cash
                Flow Hedges, Net of Tax of $8
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            15
            
            
            
            15Securities
                Available for Sale, Net of Tax of $3
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            (5
            )
            
            
            (5
            )SFAS
                158 Costs Established as a Regulatory Asset  for the Reapplication of
                SFAS 71, Net of Tax of $6
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            11
            
            
            
            11**NET
                INCOME**
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            451
            
            
            
            
            
            
            
            451**TOTAL
                COMPREHENSIVE INCOME**
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            472**JUNE
                30, 2007**
            
            
            421
            
            
            $
            2,734
            
            
            $
            4,305
            
            
            $
            2,819
            
            
            $
            (202
            )
            
            $
            9,656




*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,
                Dispositions, Discontinued Operations and Assets Held for
                Sale6.
            Benefit
                Plans7.
            Business
                Segments8.
            Income
                Taxes9.
            Financing
                Activities





**AMERICAN
      ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES**


**CONDENSED
        NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS**




**1.**
            **SIGNIFICANT
                ACCOUNTING MATTERS**





***General***





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





In
      the
      opinion of management, the unaudited interim financial statements reflect all
      normal and recurring accruals and adjustments necessary for a fair presentation
      of our results of operations, financial position and cash flows for the interim
      periods.  The results of operations for the three or six months ended
      June 30, 2007 are not necessarily indicative of results that may be expected
      for
      the year ending December 31, 2007.  The accompanying condensed
      consolidated financial statements are unaudited and should be read in
      conjunction with the audited 2006 consolidated financial statements and notes
      thereto, which are included in our Annual Report on Form 10-K for the year
      ended
      December 31, 2006 as filed with the SEC on February 28, 2007.





***Property,
      Plant and Equipment and Equity Investments***





Electric
      utility property, plant and equipment are stated at original purchase cost.
      Property, plant and equipment of nonregulated operations and other investments
      are stated at fair market value at acquisition (or as adjusted for any
      applicable impairments) plus the original cost of property acquired or
      constructed since the acquisition, less disposals.  Additions, major
      replacements and betterments are added to the plant accounts.  For the
      Utility Operations segment, normal and routine retirements from the plant
      accounts, net of salvage, are charged to accumulated depreciation for both
      cost-based rate-regulated and nonregulated operations under the group composite
      method of depreciation.  The group composite method of depreciation
      assumes that on average, asset components are retired at the end of their useful
      lives and thus there is no gain or loss.  The equipment in each
      primary electric plant account is identified as a separate
      group.  Under the group composite method of depreciation, continuous
      interim routine replacements of items such as boiler tubes, pumps, motors,
      etc.
      result in the original cost, less salvage, being charged to accumulated
      depreciation.  For the nonregulated generation assets, a gain or loss
      would be recorded if the retirement is not considered an interim routine
      replacement.  The depreciation rates that are established for the
      generating plants take into account the past history of interim capital
      replacements and the amount of salvage received.  These rates and the
      related lives are subject to periodic review.  Gains and losses are
      recorded for any retirements in the MEMCO Operations and Generation and
      Marketing segments.  Removal costs are charged to regulatory
      liabilities for cost-based rate-regulated operations and charged to expense
      for
      nonregulated operations.  The costs of labor, materials and overhead
      incurred to operate and maintain our plants are included in operating
      expenses.





Long-lived
      assets are required to be tested for impairment when it is determined that
      the
      carrying value of the assets may no longer be recoverable or when the assets
      meet the held for sale criteria under SFAS 144, “Accounting for the Impairment
      or Disposal of Long-Lived Assets.”  Equity investments are required to
      be tested for impairment when it is determined there may be an other than
      temporary loss in value.





The
      fair
      value of an asset or investment is the amount at which that asset or investment
      could be bought or sold in a current transaction between willing parties, as
      opposed to a forced or liquidation sale.  Quoted market prices in
      active markets are the best evidence of fair value and are used as the basis
      for
      the measurement, if available.  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.




***Revenue
      Recognition***





*Traditional
      Electricity Supply and Delivery Activities*





Revenues
      are recognized from retail and wholesale electricity supply 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.  In accordance with the applicable state commission
      regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled
      revenue.





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, and we purchase power
      back
      from the same RTO to supply power to our load.  These power sales and
      purchases are reported on a net basis as revenues 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 an exchange.





Physical
      energy purchases, including those from all RTOs, that are identified as
      non-trading, but excluding PJM purchases described in the preceding paragraph,
      are accounted for on a gross basis in Purchased Energy for Resale on our
      Condensed Consolidated Statements of Income.





In
      general, we record expenses when purchased electricity is received and when
      expenses are incurred, with the exception of certain power purchase-and-sale
      contracts that are derivatives and accounted for using MTM accounting where
      generation/supply rates are not cost-based regulated, such as in Ohio and the
      ERCOT portion of Texas.  In jurisdictions where the generation/supply
      business is subject to cost-based regulation, the unrealized MTM amounts are
      deferred as regulatory assets (for losses) and regulatory liabilities (for
      gains).





For
      power
      purchased under derivative contracts in our west zone where we are short
      capacity, we recognize as revenues the unrealized gains and losses (other than
      those subject to regulatory deferral) that result from measuring these contracts
      at fair value during the period before settlement.  If the contract
      results in the physical delivery of power from a RTO or any other counterparty,
      we reverse the previously recorded unrealized gains and losses from MTM
      valuations and record the settled amounts gross as Purchased Energy for
      Resale.  If the contract does not result in physical delivery, we
      reverse the previously recorded unrealized gains and losses from MTM valuations
      and record the settled amounts as revenues on our Condensed Consolidated
      Statements of Income on a net basis.





*Energy
      Marketing and Risk Management Activities*





We
      engage
      in wholesale electricity, natural gas, coal and emission allowances marketing
      and risk management activities focused on wholesale markets where we own
      assets.  Our activities include the purchase and sale of energy under
      forward contracts at fixed and variable prices and the buying and selling of
      financial energy contracts, which include exchange traded futures and options
      and over-the-counter options and swaps.  We engage in certain energy
      marketing and risk management transactions with RTOs.





We
      recognize revenues and expenses from wholesale marketing and risk management
      transactions that are not derivatives upon delivery of the
      commodity.  We use MTM accounting for wholesale marketing and risk
      management transactions that are derivatives unless the derivative is designated
      in a qualifying cash flow or fair value hedge relationship, or as a normal
      purchase or sale.  We include the unrealized and realized gains and
      losses on wholesale marketing and risk management transactions that are
      accounted for using MTM in revenues on our Condensed Consolidated Statements
      of
      Income on a net basis.  In jurisdictions subject to cost-based
      regulation, we defer the unrealized MTM amounts as regulatory assets (for
      losses) and regulatory liabilities (for gains).  We include unrealized
      MTM gains and losses resulting from derivative contracts on our Condensed
      Consolidated Balance Sheets as Risk Management Assets or Liabilities as
      appropriate.





Certain
      wholesale marketing and risk management transactions are designated as hedges
      of
      future cash flows as a result of forecasted transactions (cash flow hedge)
      or as
      hedges of a recognized asset, liability or firm commitment (fair value
      hedge).  We recognize the gains or losses on derivatives designated as
      fair value hedges in revenues on our Condensed Consolidated Statements of Income
      in the period of change together with the offsetting losses or gains on the
      hedged item attributable to the risks being hedged.  For derivatives
      designated as cash flow hedges, we initially record the effective portion of
      the
      derivative’s gain or loss as a component of Accumulated Other Comprehensive
      Income (Loss) and, depending upon the specific nature of the risk being hedged,
      subsequently reclassify into revenues or expenses on our Condensed Consolidated
      Statements of Income when the forecasted transaction is realized and affects
      earnings.  We recognize the ineffective portion of the gain or loss in
      revenues on our Condensed Consolidated Statements of Income immediately, except
      in those jurisdictions subject to cost-based regulation.  In those
      regulated jurisdictions we defer the ineffective portion as regulatory assets
      (for losses) and regulatory liabilities (for gains).





***Components
      of Accumulated Other Comprehensive Income (Loss)
      (AOCI)***





AOCI
      is
      included on the Condensed Consolidated Balance Sheets in the common
      shareholders’ equity section.  The following table provides the
      components that constitute the balance sheet amount in AOCI:





**June
                30,**
            
            
            **December
                31,****2007**
            
            
            **2006****Components**
            
            **(in
                millions)**Securities
                Available for Sale, Net of Tax
            
            $
            13
            
            
            $
            18Cash
                Flow Hedges, Net of Tax
            
            
            9
            
            
            
            (6
            )SFAS
                158 Costs, Net of Tax
            
            
            (224
            )
            
            
            (235
            )**Total**
            
            $
            (202
            )
            
            $
            (223
            )





At
      June
      30, 2007, during the next twelve months, we expect to reclassify approximately
      $20 million of net gains from cash flow hedges in AOCI to Net Income during
      the
      next twelve months at the time the hedged transactions affect Net
      Income.  The actual amounts that are reclassified from AOCI to Net
      Income can differ as a result of market fluctuations.





At
      June
      30, 2007, thirty-six months is the maximum length of time that our exposure
      to
      variability in future cash flows is hedged with contracts designated as cash
      flow hedges.





***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 June 30,****2007**
            
            
            **2006****(in
                millions, except per share data)****$/share**
            
            
            
            
            
            **$/share****Earnings
                Applicable to Common Stock**
            
            $
            180
            
            
            
            
            
            $
            175Average
                Number of Basic Shares Outstanding
            
            
            398.7
            
            
            $
            0.45
            
            
            
            393.7
            
            
            $
            0.44Average
                Dilutive Effect of:Performance
                Share Units
            
            
            0.6
            
            
            
            -
            
            
            
            1.4
            
            
            
            -Stock
                Options
            
            
            0.4
            
            
            
            -
            
            
            
            0.2
            
            
            
            -Restricted
                Stock Units
            
            
            0.1
            
            
            
            -
            
            
            
            0.1
            
            
            
            -Restricted
                Shares
            
            
            0.1
            
            
            
            -
            
            
            
            0.1
            
            
            
            -**Average
                Number of Diluted Shares Outstanding**
            
            
            399.9
            
            
            $
            0.45
            
            
            
            395.5
            
            
            $
            0.44








**Six
                Months Ended June 30,****2007**
            
            
            **2006****(in
                millions, except per share data)****$/share**
            
            
            
            
            
            **$/share****Earnings
                Applicable to Common Stock**
            
            $
            451
            
            
            
            
            
            $
            556Average
                Number of Basic Shares Outstanding
            
            
            398.0
            
            
            $
            1.13
            
            
            
            393.7
            
            
            $
            1.41Average
                Dilutive Effect of:Performance
                Share Units
            
            
            0.6
            
            
            
            -
            
            
            
            1.4
            
            
            
            -Stock
                Options
            
            
            0.4
            
            
            
            -
            
            
            
            0.2
            
            
            
            -Restricted
                Stock Units
            
            
            0.1
            
            
            
            -
            
            
            
            0.1
            
            
            
            -Restricted
                Shares
            
            
            0.1
            
            
            
            -
            
            
            
            0.1
            
            
            
            -**Average
                Number of Diluted Shares Outstanding**
            
            
            399.2
            
            
            $
            1.13
            
            
            
            395.5
            
            
            $
            1.41





The
      assumed conversion of our share-based compensation does not affect net earnings
      for purposes of calculating diluted earnings per share as of June 30,
      2007.





Options
      to purchase 0.1 million and 4.3 million shares of common stock were outstanding
      at June 30, 2007 and 2006, respectively, but were not included in the
      computation of diluted earnings per share because the options’ exercise prices
      were greater than the average market price of the common shares for the period
      and, therefore, the effect would not be dilutive.





***Supplementary
      Information***


**Three
                Months Ended**
              **June
                30,**
            
            
            **Six
                Months Ended**
              **June
                30,****2007**
            
            
            **2006**
            
            
            **2007**
            
            
            **2006****Related
                Party Transactions**
            
            **(in
                millions)**
            
            
            **(in
                millions)**AEP
                Consolidated Purchased Energy:Ohio
                Valley Electric Corporation (43.47% Owned)
            
            $
            56
            
            
            $
            58
            
            
            $
            105
            
            
            $
            113Sweeny
                Cogeneration Limited Partnership (50% Owned)
            
            
            29
            
            
            
            28
            
            
            
            59
            
            
            
            62AEP
                Consolidated Other Revenues – Barging and OtherTransportation
              Services – Ohio Valley Electric Corporation   (43.47%
                Owned)
            
            
            8
            
            
            
            8
            
            
            
            17
            
            
            
            15AEP
                Consolidated Revenues – Utility Operations:Power
                Pool Purchases – Ohio Valley Electric Corporation
              (43.47%
                Owned)
            
            
            (4
            )
            
            
            -
            
            
            
            (4
            )
            
            
            -





***Reclassifications***





Certain
      prior period financial statement items have been reclassified to conform to
      current period presentation.





On
      our
      2006 Condensed Consolidated Statement of Income, we reclassified regulatory
      credits related to regulatory asset cost deferral on ARO from Depreciation
      and
      Amortization to Other Operation and Maintenance to offset the ARO accretion
      expense.  These reclassifications totaled $6 million and $13 million
      for the three and six months ended June 30, 2006, respectively.





In
      our
      segment information, we reclassified two subsidiary companies, AEP Texas
      Commercial & Industrial Retail GP, LLC and AEP Texas Commercial &
Industrial Retail LP, from the Utility Operations segment to the Generation
      and
      Marketing segment.  Combined revenues for these companies totaled $11
      million and $16 million for the three and six months ended June 30, 2006,
      respectively.  As a result, on our 2006 Condensed Consolidated
      Statement of Income, we reclassified these revenues from Utility Operations
      to
      Other.





These
      revisions had no impact on our previously reported results of operations, cash
      flows or changes in shareholders’ equity.






**2.**
            **NEW
                ACCOUNTING PRONOUNCEMENTS AND EXTRAORDINARY
                ITEM**





**NEW
      ACCOUNTING PRONOUNCEMENTS**





Upon
      issuance of exposure drafts or final pronouncements, we thoroughly review the
      new accounting literature to determine the relevance, if any, to our
      business.  The following represents a summary of new
      pronouncements  issued or implemented in 2007 and standards issued but
      not implemented that we have determined relate to our operations.





***SFAS
      157 “Fair Value Measurements” (SFAS 157)***





In
      September 2006, the FASB issued SFAS 157, enhancing existing guidance for fair
      value measurement of assets and liabilities and instruments measured at fair
      value that are classified in shareholders’ equity.  The statement
      defines fair value, establishes a fair value measurement framework and expands
      fair value disclosures.  It emphasizes that fair value is market-based
      with the highest measurement hierarchy being market prices in active
      markets.  The standard requires fair value measurements be disclosed
      by hierarchy level and an entity include its own credit standing in the
      measurement of its liabilities and modifies the transaction price
      presumption.





SFAS
      157
      is effective for interim and annual periods in fiscal years beginning after
      November 15, 2007.  We expect that the adoption of this standard will
      impact MTM valuations of certain contracts, but we are unable to quantify the
      effect.  Although the statement is applied prospectively upon
      adoption, the effect of certain transactions is applied retrospectively as
      of
      the beginning of the fiscal year of application, with a cumulative effect
      adjustment to the appropriate balance sheet items.  We will adopt SFAS
      157 effective January 1, 2008.





***SFAS
      159 “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS
      159)***





In
      February 2007, the FASB issued SFAS 159, permitting entities to choose to
      measure many financial instruments and certain other items at fair
      value.  The standard also establishes presentation and disclosure
      requirements designed to facilitate comparison between entities that choose
      different measurement attributes for similar types of assets and
      liabilities.





SFAS
      159
      is effective for annual periods in fiscal years beginning after November 15,
      2007.  If the fair value option is elected, the effect of the first
      remeasurement to fair value is reported as a cumulative effect adjustment to
      the
      opening balance of retained earnings.  If we elect the fair value
      option promulgated by this standard, the valuations of certain assets and
      liabilities may be impacted.  The statement is applied prospectively
      upon adoption.  We will adopt SFAS 159 effective January 1,
      2008.  We expect the adoption of this standard to have an immaterial
      impact on our financial statements.





***EITF
      Issue No. 06-11 “Accounting for Income Tax Benefits of Dividends on Share-Based
      Payment Awards”   (EITF 06-11)***





In
      June
      2007, the FASB ratified the EITF consensus on the treatment of income tax
      benefits of dividends on employee share-based compensation.  The issue
      is how a company should recognize the income tax benefit received on dividends
      that are paid to employees holding equity-classified nonvested shares,
      equity-classified nonvested share units, or equity-classified outstanding share
      options and charged to retained earnings under SFAS 123R, “Share-Based
      Payments.”  Under EITF 06-11, a realized income tax benefit from
      dividends or dividend equivalents that are charged to retained earnings and
      are
      paid to employees for equity-classified nonvested equity shares, nonvested
      equity share units, and outstanding equity share options should be recognized
      as
      an increase to additional paid-in capital.





EITF
      06-11 will be applied prospectively to the income tax benefits of dividends
      on
      equity-classified employee share-based payment awards that are declared in
      fiscal years beginning after September 15, 2007.  We expect that the
      adoption of this standard will have an immaterial effect on our financial
      statements.  We will adopt EITF 06-11 effective January 1,
      2008.




***FIN
      48 “Accounting for Uncertainty in Income Taxes” and FASB Staff Position FIN 48-1
“Definition of Settlement in FASB Interpretation No. 48” (FIN
      48)***




In
      July
      2006, the FASB issued FASB Interpretation No. 48 “Accounting for Uncertainty in
      Income Taxes” and in May 2007, the FASB issued FASB Staff Position FIN 48-1
“Definition of *Settlement* in FASB Interpretation No.
      48.”  FIN 48 clarifies the accounting for uncertainty in income taxes
      recognized in an enterprise’s financial statements by prescribing a recognition
      threshold (whether a tax position is more likely than not to be sustained)
      without which, the benefit of that position is not recognized in the financial
      statements.  It requires a measurement determination for recognized
      tax positions based on the largest amount of benefit that is greater than 50
      percent likely of being realized upon ultimate settlement.  FIN 48
      also provides guidance on derecognition, classification, interest and penalties,
      accounting in interim periods, disclosure and transition.





FIN
      48
      requires that the cumulative effect of applying this interpretation be reported
      and disclosed as an adjustment to the opening balance of retained earnings
      for
      that fiscal year and presented separately.  We adopted FIN 48
      effective January 1, 2007, with an unfavorable adjustment to retained earnings
      of $17 million.





***FIN
      39-1 “Amendment of FASB Interpretation No. 39”***





In
      April
      2007, the FASB issued FIN 39-1.  It amends FASB Interpretation No. 39,
“Offsetting of Amounts Related to Certain Contracts” by replacing the
      interpretation’s definition of contracts with the definition of derivative
      instruments per SFAS 133.  It also requires entities that offset fair
      values of derivatives with the same party under a netting agreement to also
      net
      the fair values (or approximate fair values) of related cash
      collateral.  The entities must disclose whether or not they offset
      fair values of derivatives and related cash collateral and amounts recognized
      for cash collateral payables and receivables at the end of each reporting
      period.





FIN
      39-1
      is effective for fiscal years beginning after November 15, 2007.  We
      expect this standard to change our method of netting certain balance sheet
      amounts but are unable to quantify the effect.  It requires
      retrospective application as a change in accounting principle for all periods
      presented.  We will adopt FIN 39-1 effective January 1,
      2008.





***Future
      Accounting Changes***





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





**EXTRAORDINARY
      ITEM**





In
      April
      2007, Virginia passed legislation to reestablish regulation for retail
      generation and supply of electricity.  As a result, we recorded an
      extraordinary loss of $118 million ($79 million, net of tax) during the second
      quarter of 2007 for the reestablishment of regulatory assets and liabilities
      related to our Virginia retail generation and supply operations.  In
      2000, we discontinued SFAS 71 regulatory accounting in our Virginia jurisdiction
      for retail generation and supply operations due to the passage of legislation
      for customer choice and deregulation.  See “Virginia Restructuring”
section of Note 3.





**3.**
            **RATE
                MATTERS**





As
      discussed in our 2006 Annual Report, our subsidiaries are involved in rate
      and
      regulatory proceedings at the FERC and their state commissions.  The
      Rate Matters note within our 2006 Annual Report should be read in conjunction
      with this report to gain a complete understanding of material rate matters
      still
      pending that could impact results of operations, cash flows and possibly
      financial condition.  The following discusses ratemaking developments
      in 2007 and updates the 2006 Annual Report.





**Ohio
      Rate Matters**





***Ohio
      Restructuring and Rate Stabilization Plans***





In
      January 2007, CSPCo and OPCo filed with the PUCO under the 4% provision of
      their
      RSPs to increase their annual generation rates for 2007 by $24 million and
      $8
      million, respectively, to recover governmentally-mandated
      costs.  Pursuant to the RSPs, CSPCo and OPCo implemented these
      proposed increases effective with the first billing cycle in May
      2007.  These increases are subject to refund until the PUCO issues a
      final order in the matter.  The PUCO staff and intervenors have
      proposed disallowances.  The revenues collected, subject to refund,
      are immaterial through June 30, 2007.  Management is unable to
      determine the impact, if any, of potential refunds or rider reductions on future
      results of operations and cash flows.   The hearing is completed
      and initial post-hearing and reply briefs have been filed.  A final
      order is expected in late third quarter or early fourth quarter of
      2007.





In
      March
      2007, CSPCo filed an application under the 4% provision of the RSP to adjust
      the
      Power Acquisition Rider (PAR) which was authorized in 2005 by the PUCO in
      connection with CSPCo's acquisition of Monongahela Power Company's certified
      territory in Ohio and a new purchase power contract to serve the
      load.  The PUCO approved the requested increase in the PAR, which is
      expected to increase CSPCo's revenues by $22 million and $38 million for 2007
      and 2008, respectively.





In
      March
      2007, CSPCo and OPCo filed a settlement agreement at the PUCO resolving the
      Ohio
      Supreme Court's remand of the PUCO’s RSP order.  The Supreme Court
      indicated concern with the absence of a competitive bid process as an
      alternative to the generation rates set by the RSP.  In response, the
      settling parties agreed to have CSPCo and OPCo take bids for Renewable Energy
      Certificates (RECs).  CSPCo and OPCo will give customers the option to
      pay a generation rate premium that would encourage the development of renewable
      energy sources by reimbursing CSPCo and OPCo for the cost of the RECs and the
      administrative costs of the program.  The Office of Consumers’
Counsel, the Ohio Partners for Affordable Energy, the Ohio Energy Group and
      the
      PUCO staff supported this settlement agreement.  In May 2007, the PUCO
      adopted the settlement agreement in its entirety.  The settlement, as
      approved, fully compensates CSPCo and OPCo regarding the cost of the
      program.





CSPCo
      and
      OPCo are involved in discussions with various stakeholders in Ohio regarding
      potential legislation to address the period following the expiration of the
      RSPs
      on December 31, 2008.  At this time, management is unable to predict
      whether CSPCo and OPCo will transition to market pricing, as permitted by the
      current Ohio restructuring legislation, extend their RSP rates, with or without
      modification, or become subject to a legislative reinstatement of some form
      of
      cost-based regulation for their generation supply business on January 1, 2009
      when the RSP period ends.





***Customer
      Choice Deferrals***





As
      provided in the restructuring settlement agreement approved by the PUCO in
      2000,
      CSPCo and OPCo established regulatory assets for customer choice implementation
      costs and related carrying costs in excess of $20 million each for recovery
      in
      the next general base rate filing which changes distribution rates after
      December 31, 2007 for OPCo and December 31, 2008 for
      CSPCo.   Pursuant to the RSPs, recovery of these amounts for OPCo
      was further deferred until the next base rate filing to change distribution
      rates after the end of the RSP period of December 31, 2008.  Through
      June 30, 2007, CSPCo and OPCo incurred $51 million and $52 million,
      respectively, of such costs and established regulatory assets of $25 million
      and
      $26 million, respectively, for such costs.  CSPCo and OPCo each have
      not recognized $6 million of equity carrying costs, which are recognizable
      when
      collected.  In 2007, CSPCo and OPCo incurred $2 million each of such
      costs and established regulatory assets of $1 million each for such
      costs.  Management believes that the deferred customer choice
      implementation costs were prudently incurred to implement customer choice in
      Ohio and are probable of recovery in future distribution
      rates.  However, failure to recover such costs will have an adverse
      effect on results of operations 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.  The application proposed three phases of
      cost recovery associated with the IGCC plant:  Phase 1, recovery of
      $24 million in pre-construction costs during 2006; Phase 2, concurrent recovery
      of construction-financing costs; and Phase 3, recovery or refund in distribution
      rates of any difference between the market-based standard service offer price
      for generation and the cost of operating and maintaining the plant, including
      a
      return on and return of the ultimate cost to construct the plant, originally
      projected to be $1.2 billion, along with fuel, consumables and replacement
      power
      costs.  The proposed recoveries in Phases 1 and 2 would be applied
      against the 4% limit on additional generation rate increases CSPCo and OPCo
      could request under their RSPs.





In
      April
      2006, the PUCO issued an order authorizing CSPCo and OPCo to implement Phase
      1
      of the cost recovery proposal.  In June 2006, the PUCO issued another
      order approving a tariff to recover Phase 1 pre-construction costs over a period
      of no more than twelve months effective July 1, 2006.  Through June
      30, 2007, CSPCo and OPCo each recorded pre-construction IGCC regulatory assets
      of $10 million and each collected the entire $12 million approved by the
      PUCO.  CSPCo and OPCo expect to incur additional pre-construction
      costs equal to or greater than the $12 million each recovered.  As of
      June 30, 2007, CSPCo and OPCo have recorded a liability of $2 million each
      for
      the over-recovered portion.  The PUCO indicated that if CSPCo and OPCo
      have not commenced a continuous course of construction of the IGCC plant within
      five years of the June 2006 PUCO order, all amounts collected for
      pre-construction costs, associated with items that may be utilized in IGCC
      projects to be built by AEP at other sites, must be refunded to Ohio ratepayers
      with interest.  The PUCO deferred ruling on cost recovery for Phases 2
      and 3 until further hearings are held.  A date for further rehearings
      has not been set.





In
      August
      2006, the Ohio Industrial Energy Users, Ohio Consumers’ Counsel, FirstEnergy
      Solutions and Ohio Energy Group filed four separate appeals of the PUCO’s order
      in the IGCC proceeding.  The Ohio Supreme Court has scheduled oral
      arguments for these appeals in October 2007.  Management believes that
      the PUCO’s authorization to begin collection of Phase 1 rates is
      lawful.  Management, however, cannot predict the outcome of these
      appeals.  If the PUCO’s order is found to be unlawful, CSPCo and OPCo
      could be required to refund Phase 1 cost-related recoveries.





Pending
      the outcome of the Supreme Court litigation, CSPCo and OPCo announced they
      may
      delay the start of construction of the IGCC plant. Recent estimates of the
      cost
      to build an IGCC plant are $2.2 billion.  CSPCo and OPCo may need to
      request an extension to the 5 year start of construction requirement if the
      commencement of construction is delayed beyond 2011.  In July 2007,
      CSPCo and OPCo filed a status report with the PUCO referencing APCo’s IGCC West
      Virginia filing.  See the “West Virginia IGCC Plant” section within
      West Virginia Rate Matters of this note.





***Distribution
      Reliability Plan***





In
      January 2006, CSPCo and OPCo initiated a proceeding at the PUCO seeking a new
      distribution rate rider to fund enhanced distribution reliability
      programs.  In the fourth quarter of 2006, as directed by the PUCO,
      CSPCo and OPCo filed a proposed enhanced reliability plan.  The plan
      contemplated CSPCo and OPCo recovering approximately $28 million and $43
      million, respectively, in additional distribution revenue during an eighteen
      month period beginning July 2007.  In January 2007, the Ohio
      Consumers’ Counsel filed testimony, which argued that CSPCo and OPCo should be
      required to improve distribution service reliability with funds from their
      existing rates.





In
      April
      2007, CSPCo and OPCo filed a joint motion with the PUCO staff, the Ohio
      Consumers’ Counsel, the Appalachian People’s Action Coalition, the Ohio Partners
      for Affordable Energy and the Ohio Manufacturers Association to withdraw the
      proposed enhanced reliability plan.  The motion was granted in May
      2007.  CSPCo and OPCo do not intend to implement the enhanced
      reliability plan without recovery of any incremental costs.





***Ormet***





Effective
      January 1, 2007, CSPCo and OPCo began to serve Ormet, a major industrial
      customer with a 520 MW load, under a PUCO-encouraged settlement
      agreement.  The settlement agreement between CSPCo and OPCo, Ormet,
      its employees’ union and certain other interested parties was approved by the
      PUCO in November 2006.   The settlement agreement provides for
      the recovery in 2007 and 2008 by CSPCo and OPCo of the difference between $43
      per MWH to be paid by Ormet for power and a PUCO-approved market price, if
      higher.  The recovery will be accomplished by the amortization of a
      $57 million ($15 million for CSPCo and $42 million for OPCo) Ohio franchise
      tax
      phase-out regulatory liability recorded in 2005 and, if that is insufficient,
      an
      increase in RSP generation rates under the additional 4% provision of the
      RSPs.  The $43 per MWH price to be paid by Ormet for generation
      services is above the industrial RSP generation tariff but below current market
      prices.  In December 2006, CSPCo and OPCo submitted a market price of
      $47.69 per MWH for 2007, which was approved by the PUCO in June
      2007.  CSPCo and OPCo have each amortized $3 million of their Ohio
      Franchise Tax phase-out tax regulatory liability to income through June 30,
      2007.  If the PUCO approves a lower-than-market price in 2008, it
      could have an adverse effect on future results of operations and cash
      flows.  If CSPCo and OPCo serve the Ormet load after 2008 without any
      special provisions, they could experience incremental costs to acquire
      additional capacity to meet their reserve requirements and/or forgo off-system
      sales margins, which could have an adverse effect on future results of
      operations and cash flows.





**Texas
      Rate Matters**





**TCC
      TEXAS RESTRUCTURING**





***Texas
      District Court Appeal Proceedings***





TCC
      recovered its net recoverable stranded generation costs through a securitization
      financing and is refunding its net other true-up items through a CTC rate rider
      credit under 2006 PUCT orders.  TCC appealed the PUCT stranded costs
      true-up 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 are:





·
            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 it 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 cost, and·
            The
                two federal matters regarding the allocation of off-system sales
                related
                to fuel recoveries and the potential tax normalization
                violation.  See “TCC Deferred Investment Tax Credits and Excess
                Deferred Federal Income Taxes” and “TCC and TNC Deferred Fuel ” sections
                below.





Municipal
      customers and other intervenors also appealed the PUCT true-up orders seeking
      to
      further reduce TCC’s true-up recoveries.  In March 2007, the Texas
      District Court judge hearing the various appeals affirmed the PUCT’s April 4,
      2006 final true-up order for TCC with two significant exceptions.  The
      judge determined that the PUCT erred by applying an invalidated rule to
      determine the carrying cost rate for the true-up of stranded
      costs.  However, the District Court did not rule that the carrying
      cost rate was inappropriate.  If the District Court’s ruling on the
      carrying cost rate is ultimately upheld on appeal and remanded to the PUCT
      for
      reconsideration, the PUCT could either confirm the existing weighted average
      carrying cost (WACC) rate or determine a new rate.  If the PUCT
      reduces the rate, it could result in a material adverse change to TCC’s
      recoverable carrying costs, results of operations, cash flows and financial
      condition.





The
      District Court judge also determined the PUCT improperly reduced TCC’s net
      stranded plant costs for commercial unreasonableness.  If upheld on
      appeal, this ruling could have a materially favorable effect on TCC’s results of
      operations and cash flows.





TCC,
      the
      PUCT and intervenors appealed the District Court rulings to the Court of
      Appeals.  Management cannot predict the outcome of these
      proceedings.  If TCC ultimately succeeds in its appeals, it could have
      a favorable effect on future results of operations, cash flows and financial
      condition.  If municipal customers and other intervenors succeed in
      their appeals, or if TCC has a tax normalization violation, it could have a
      substantial adverse effect on future results of operations, cash flows and
      financial condition.




**OTHER
      TEXAS RESTRUCTURING MATTERS**





***TCC
      Deferred Investment Tax Credits and Excess Deferred Federal Income
      Taxes***





In
      TCC’s
      2006 true-up and securitization orders, the PUCT reduced net regulatory assets
      and the amount to be securitized by $51 million related to the present value
      of
      ADITC and by $10 million related to EDFIT associated with TCC’s generation
      assets for a total reduction of $61 million.





TCC
      filed
      a request for a private letter ruling with the IRS in June 2005 regarding the
      permissibility under the IRS rules and regulations of the ADITC and EDFIT
      reduction proposed by the PUCT.  The IRS issued its private letter
      ruling in May 2006, which stated that the PUCT’s flow-through to customers of
      the present value of the ADITC and EDFIT benefits would result in a
      normalization violation.  To address the matter and avoid a possible
      normalization violation, the PUCT agreed to allow TCC to defer an amount of
      the
      CTC refund totaling $103 million ($61 million in present value of ADITC and
      EDFIT associated with TCC’s generation assets plus $42 million of related
      carrying costs) pending resolution of the normalization issue. **If
      it is ultimately determined that a refund to customers through the true-up
      process of the ADITC and EDFIT is not a normalization violation, then TCC will
      be required to refund the $103 million, plus additional carrying costs adversely
      affecting future results of operations and cash flows.  However, if
      such refund of ADITC and EDFIT is ultimately determined to cause a normalization
      violation, TCC anticipates it will be permitted to retain the $61 million
      present value of ADITC and EDFIT plus carrying costs, favorably impacting future
      results of operations and cash flows.





If
      a
      normalization violation occurs, it could result in TCC’s repayment to the IRS of
      ADITC on all property, including transmission and distribution property, which
      approximates $104 million as of June 30, 2007, and a loss of TCC’s right to
      claim accelerated tax depreciation in future tax returns.  Tax counsel
      advised management that a normalization violation should not occur until all
      remedies under law have been exhausted and the tax benefits are returned to
      ratepayers under a nonappealable order.  Management intends to
      continue its efforts to work with the PUCT to avoid a normalization violation
      that would adversely affect future results of operations and cash
      flows.





***TCC
      and TNC Deferred Fuel***





TCC’s
      deferred fuel over-recovery regulatory liability is a component of the other
      true-up items net regulatory liability refunded through the CTC rate rider
      credit.  In 2002, TCC and TNC filed with the PUCT seeking to reconcile
      fuel costs and establish their final deferred fuel balances.  In its
      final fuel reconciliation orders, the PUCT ordered substantial reductions in
      TCC’s and TNC’s recoverable fuel costs for, among other things, the reallocation
      of additional AEP System off-system sales margins to TCC and TNC under a
      FERC-approved tariff.  Both TCC and TNC appealed the PUCT’s rulings
      regarding a number of issues in the fuel orders in state court and challenged
      the jurisdiction of the PUCT over the allocation of off-system sales margins
      in
      the federal court.  Intervenors also appealed the PUCT’s final fuel
      rulings in state court seeking to increase the various allowances.





In
      2006,
      the Federal District Court issued orders precluding the PUCT from enforcing
      the
      off-system sales reallocation portion of its ruling in the final TNC and TCC
      fuel reconciliation proceedings.  The Federal court ruled, in both
      cases, that the FERC, not the PUCT, has jurisdiction over the
      allocation.  The PUCT appealed both Federal District Court decisions
      to the United States Court of Appeals.  In TNC’s case, the Court of
      Appeals affirmed the District Court’s decision.   In April 2007,
      the PUCT petitioned the United States Supreme Court for a review of the Court
      of
      Appeals’ order.  If the PUCT’s appeals are ultimately unsuccessful,
      TCC and TNC could record income of $16 million and $8 million, respectively,
      related to the reversal of the previously-recorded fuel over-recovery regulatory
      liabilities related to the reallocation of off-system sales margins to TCC
      and
      TNC.





If
      the
      PUCT is unsuccessful in the federal court system, it or another interested
      party
      may file a complaint at the FERC to address the allocation issue.  If
      a complaint at the FERC results in the PUCT’s decisions being adopted by the
      FERC, there could be an adverse effect on results of operations and cash
      flows.  An unfavorable FERC ruling may result in a retroactive
      reallocation of off-system sales margins from AEP East companies to AEP West
      companies under the then-existing SIA allocation method.  If the
      adjustments were applied retroactively, the AEP East companies may be unable
      to
      recover the amounts reallocated to the West companies from their customers
      due
      to past frozen rates, past inactive fuel clauses and fuel clauses that do not
      include off-system sales credits.  Although management cannot predict
      the ultimate outcome of this federal litigation, management believes that the
      allocations were in accordance with the then-existing FERC-approved SIA and
      that
      it should not be expected to reallocate additional off-system sales margins
      to
      the West companies including TCC and TNC.





In
      January 2007, TCC began refunding as part of the CTC rate rider credit, $149
      million of its $165 million over-recovered deferred fuel regulatory
      liability.  The remaining $16 million refund related to the favorable
      Federal District Court order has been deferred pending the outcome of the
      federal court appeal and would be subject to refund only upon a successful
      appeal by the PUCT.





***TCC
      Excess Earnings***





In
      2005,
      the Texas Court of Appeals issued a decision finding that the PUCT’s prior order
      from the unbundled cost of service case requiring TCC to refund excess earnings
      prior to and outside of the true-up process was unlawful under the Texas
      Restructuring Legislation.  TCC refunded $55 million of excess
      earnings, including interest, of which $30 million went to the affiliated
      REP.  In November 2005, the PUCT filed a petition for review with the
      Supreme Court of Texas seeking reversal of the Texas Court of Appeals’
decision.  In June 2007, the Supreme Court of Texas declined the
      petition for review.  Certain intervenors have contended in the
      stranded cost proceeding that a reduction to stranded cost is required, but
      a
      surcharge of unlawfully-refunded amounts is unnecessary. TCC believes it has
      properly reflected the effects of the Court of Appeals’ ruling and the PUCT’s
      rules on stranded costs. However, a ruling in favor of the intervenor’s position
      could have a material adverse effect on future results of operations and cash
      flow.





***TCC
      Oklaunion Refund***





In
      2005,
      TCC filed a special request with the PUCT allowing TCC to file its true-up
      proceeding before it had completed the sale of its share of the Oklaunion power
      plant.  TCC agreed to provide customers the net economic benefit
      related to its continued ownership of the Oklaunion power plant until the sale
      closed.  TCC also agreed to reduce stranded costs in the event the
      Oklaunion power plant sales price increased.  In June
      2007,  TCC filed with the PUCT reporting no change in the sales price
      and to include the net economic benefit from the operation of the Oklaunion
      power plant in the CTC credit rider.  As of June 30, 2007, TCC has
      recorded a $3 million regulatory liability for the net economic benefit related
      to the operation of the Oklaunion power plant.  Management is unable
      to predict the ultimate outcome of this filing.  If the PUCT orders a
      refund greater than the $3 million recorded liability, it would have an adverse
      effect on future results of operations and cash flow.





**OTHER
      TEXAS RATE MATTERS**





***TCC
      and TNC Energy Delivery Base Rate Filings***





TCC
      and
      TNC each filed a base rate case seeking to increase transmission and
      distribution energy delivery services (wires) base rates in
      Texas.  TCC and TNC requested increases in annual base rates of $81
      million and $25 million, respectively.  Both requests include a return
      on common equity of 11.25% and a favorable impact of an expiration of the CSW
      merger savings rate credits (merger credits).  In March 2007, various
      intervenors and the PUCT staff filed their recommendations.  Though
      the recommendations varied, the range of recommended increase was $8 million
      to
      $30 million for TCC.  The recommended return on common equity ranged
      from 9.00% to 9.75%.  In April 2007, TCC filed rebuttal testimony
      reducing its requested increase to $70 million including a reduced requested
      return on common equity of 10.75%.  In May 2007, TNC reached a
      settlement agreement for a revenue increase of $14 million including an $8
      million increase in base rates and a $6 million increase related to the impact
      of the expiration of the merger credits.  TNC received a final order
      in May 2007 and began billing in June 2007.  TCC was unable to settle
      its proceeding.





Beginning
      in June 2007, TCC implemented an interim base rate increase of $50 million,
      subject to refund, in accordance with Texas law.  In addition, TCC’s
      merger credits were terminated in June 2007, which effectively increased base
      rates by $20 million on an annual basis.  In June 2007, an ALJ issued
      an interim order affirming the termination of the merger credits.  The
      PUCT affirmed the ALJ ruling.  Management has evaluated its exposure
      to a future refund of revenues being collected, subject to refund, and believes
      it is recognizing a reasonable amount of such revenues.  A decision
      from the PUCT is expected in the third quarter of 2007.  Management is
      unable to predict the ultimate effect of this filing and any true-up of
      recognized revenues collected, subject to refund, on future results of
      operations, cash flows and financial condition.





***SWEPCo
      Fuel Reconciliation – Texas***





In
      June
      2006, SWEPCo filed a fuel reconciliation proceeding with the PUCT for its Texas
      retail operations for the three-year reconciliation period ended December 31,
      2005.  SWEPCo sought, in the proceedings, to include under-recoveries
      related to the reconciliation period of $50 million.  In January 2007,
      intervenors filed testimony recommending that SWEPCo’s reconcilable fuel costs
      be reduced.  The PUCT staff and intervenor disallowances ranged from
      $10 million to $28 million.  In June 2007, an ALJ issued a Proposal
      for Decision recommending a $17 million disallowance.  Results of
      operations for the second quarter of 2007 were adversely affected by $25 million
      as a result of reflecting the ALJ’s decision.  In July 2007, the PUCT
      orally affirmed the ALJ report.  A final order is expected in the
      third quarter of 2007.  Management is unable to predict the ultimate
      outcome of this proceeding or its additional effect on future results of
      operations and cash flows**.**





***ERCOT
      Price-to-Beat (PTB) Fuel Factor Appeal***





Several
      parties including the Office of Public Utility Counsel and the cities served
      by
      both TCC and TNC appealed the PUCT’s December 2001 orders establishing initial
      PTB fuel factors for Mutual Energy CPL and Mutual Energy WTU (TCC’s and TNC’s
      respective former affiliated REPs).  In 2003, the District Court ruled
      the PUCT record lacked substantial evidence regarding the amount of
      unaccounted-for energy (UFE) included in TNC PTB fuel factor.  The
      Court of Appeals upheld the District Court regarding the UFE
      issue.  AEP’s third quarter 2005 pretax earnings were adversely
      affected by $3 million at an assumed 1% UFE factor, as a result of reflecting
      this decision on its books.  The Supreme Court of Texas has remanded
      this issue to the PUCT.  If the PUCT adopts a higher UFE factor on
      remand, future results of operations and cash flows would be adversely
      affected.  Management is unable to predict the outcome of this remand
      on future results of operations and cash flows.





**Virginia
      Rate Matters**





***Virginia
      Restructuring***





In
      April
      2004, Virginia enacted legislation that amended the Virginia Electric Utility
      Restructuring Act extending the transition period to market rates for the
      generation and supply of electricity, including the extension of capped rates,
      through December 31, 2010.  The legislation provided APCo with
      specified cost recovery opportunities during the extended capped rate period,
      including two optional bundled general base rate changes and an opportunity
      for
      timely recovery, through a separate rate mechanism, of certain unrecovered
      incremental environmental and reliability costs incurred on and after July
      1,
      2004.  Under the amended restructuring law, APCo continues to have an
      active fuel clause recovery mechanism in Virginia and continues to practice
      deferred fuel accounting.  Also, under the amended restructuring law,
      APCo has the right to defer incremental environmental compliance costs and
      incremental E&R costs for future recovery, to the extent such costs are not
      being recovered, and amortizes a portion of such deferrals commensurate with
      their recovery.





In
      April
      2007, the Virginia legislature adopted a comprehensive law providing for the
      re-regulation of electric utilities’ generation and supply
      rates.  These amendments shorten the transition period by two years
      (from 2010 to 2008) after which rates for retail generation and supply will
      return to a form of cost-based regulation in lieu of market-based
      rates.  The legislation provides for, among other things, biennial
      rate reviews beginning in 2009; rate adjustment clauses for the recovery of
      the
      costs of (a) transmission services and new transmission investments, (b) demand
      side management, load management, and energy efficiency programs, (c) renewable
      energy programs, and (d) environmental retrofit and new generation investments;
      significant return on equity enhancements for investments in new generation
      and,
      subject to Virginia SCC approval, certain environmental retrofits, and a floor
      on the allowed return on equity based on the average earned return on equities’
of regional vertically integrated electric utilities.  Effective July
      1, 2007, the amendments allow utilities to retain a minimum of 25% of the
      margins from off-system sales with the remaining margins from such sales
      credited against fuel factor expenses with a true-up to actual.  The
      legislation also allows APCo to continue to defer and recover incremental
      environmental and reliability costs incurred through December 31,
      2008.  The new re-regulation legislation should result in significant
      positive effects on APCo’s future earnings and cash flows from the mandated
      enhanced future returns on equity, the reduction of regulatory lag from the
      opportunities to adjust base rates on a biennial basis and the new opportunities
      to request timely recovery of certain new costs not included in base
      rates.




With
      the
      return of cost-based regulation, APCo’s generation business again meets the
      criteria for application of regulatory accounting principles under SFAS
      71.  The extraordinary pretax reduction in APCo’s earnings and
      shareholder’s equity from reapplication of SFAS 71 regulatory accounting of $118
      million ($79 million, net of tax) was recorded in the second quarter of
      2007.  This extraordinary net loss primarily relates to the
      reestablishment of $139 million in net generation-related customer-provided
      removal costs as a regulatory liability, offset by the restoration of $21
      million of deferred state income taxes as a regulatory asset.  In
      addition, APCo established a regulatory asset of $17 million for qualifying
      SFAS
      158 pension costs of the generation operations that, for ratemaking purposes,
      are deferred for future recovery under the new re-regulation
      legislation.  AOCI and Deferred Income Taxes increased by $11 million
      and $6 million, respectively.





***Virginia
      Base Rate Case***





In
      May
      2006, APCo filed a request with the Virginia SCC seeking an increase in base
      rates of $225 million to recover increasing costs including the cost of its
      investment in environmental equipment and a return on equity of
      11.5%.  In addition, APCo requested to move off-system sales margins,
      currently credited to customers through base rates, to the fuel factor where
      they can be trued-up to actual.  APCo also proposed to share the
      off-system sales margins with customers with 40% going to reduce rates and
      60%
      being retained by APCo.  This proposed off-system sales fuel rate
      credit, which was estimated to be $27 million, partially offsets the $225
      million requested increase in base rates for a net increase in base rate
      revenues of $198 million.  The major components of the $225 million
      base rate request included $73 million for the impact of removing off-system
      sales margins from the rate year ending September 30, 2007, $60 million mainly
      due to projected net environmental plant additions through September 30, 2007
      and $48 million for return on equity.





In
      May
      2006, the Virginia SCC issued an order, consistent with Virginia law, placing
      the net requested base rate increase of $198 million into effect on October
      2,
      2006, subject to refund.  The $198 million base rate increase that was
      collected, subject to refund, includes recovery of incremental E&R costs
      projected to be incurred during the rate year beginning October
      2006.  These incremental E&R costs can be deferred and recovered
      through the E&R surcharge mechanism if not recovered through base
      rates.  In October 2006, the Virginia SCC staff filed its direct
      testimony recommending a base rate increase of $13 million with a return on
      equity of 9.9% and no off-system sales margin sharing.  Other
      intervenors recommended base rate increases ranging from $42 million to $112
      million.   APCo filed rebuttal testimony in November
      2006.  Hearings were held in December 2006.





In
      March
      2007, the Hearing Examiner issued a report recommending a $76 million increase
      in APCo’s base rates and a $45 million credit to the fuel factor for off-system
      sales margins resulting in a net $31 million recommended rate
      increase.   In May 2007, the Virginia SCC issued a final order
      approving an overall annual base rate increase of $24 million effective as
      of
      October 2006.  The final order approved a return on equity of 10.0%
      and limited forward-looking ratemaking adjustments to June 30, 2006 as opposed
      to September 30, 2007 as proposed.  In addition, the final order
      excluded a portion of APCo's requested E&R costs in base
      rates.  However, APCo was able to defer unrecovered incremental
      E&R costs incurred after October 1, 2006 and will recover those costs
      through the E&R surcharge mechanism.  The order also provided for
      a retroactive annual reduction in depreciation to January 1, 2006 of
      approximately $11 million per year and a deferral and recovery of ARO costs
      over
      10 years.  The final order further provides that off-system sales
      margins of $101 million be credited to customers through a separate base rate
      margin rider which is not trued-up to actual margins.  The final order
      did not implement the minimum 25% sharing percentage for off-system sales
      margins embodied in the new re-regulation legislation, which is effective with
      the first fuel clause filing after July 1, 2007.  This sharing
      requirement in the new re-regulation legislation also includes a
      true-up to actual off-system sales margins.





As
      a
      result of the final order, APCo’s second quarter pretax earnings decreased by
      approximately $3 million due to a decrease in revenues of $42 million net of
      a
      recorded provision for refund and related interest offset by (a) a $15 million
      net effect from the deferral of unrecovered incremental E&R costs incurred
      from October 1, 2006 through June 30, 2007 to be collected in a future E&R
      filing, (b) a $9 million net deferral of ARO costs to be recovered over 10
      years
      and (c) a $15 million retroactive decrease in depreciation
      expense.  In addition to the favorable effect of the base rate
      increase in the second half of 2007, APCo expects to defer for future recovery
      unrecovered incremental E&R costs incurred of $20 million to $25 million and
      reduce depreciation and amortization expense by a net $5
      million.  APCo will complete the refund by August
      2007.  APCo’s Other Current Liabilities includes accrued refunds of
      $127 million and $22 million as of June 30, 2007 and December 31, 2006,
      respectively.  Management expects pretax earnings for 2007 to be
      favorably affected by the ordered May 2007 rate increase.





***Virginia
      E&R Costs Recovery Filing***





In
      July
      2007, APCo filed a request with the Virginia SCC seeking recovery over the
      twelve months beginning December 1, 2007 of approximately $60 million of
      unrecovered incremental E&R costs inclusive of carrying costs thereon
      incurred from October 1, 2005 through September 30, 2006.  APCo will
      file for recovery in 2008 of E&R cost deferrals incurred and recorded after
      September 30, 2006.





***Virginia
      Fuel Clause Filing***





In
      July
      2007, APCo filed an application with the Virginia SCC to seek an increase,
      effective September 1, 2007, to the current fuel factor of $33 million in
      annualized revenue requirements for fuel costs and a sharing of the benefits
      of
      off-system sales between APCo and its customers.  This filing was made
      in compliance with the minimum 25% retention of off-system sales margins
      provision of the new re-regulation legislation which is effective with the
      first fuel clause filing after July 1, 2007.  This sharing requirement
      in the new law also includes a true-up to actual off-system sales
      margins.  In addition, APCo requested authorization to defer for
      future recovery the difference between off-system sales margins credited to
      customers at 100% of the ordered amount through the current margin rider and
      75%
      of actual off-system sales margins as provided in the new law from July 1,
      2007
      until the new fuel rate becomes effective.





***West
      Virginia IGCC Plant***





In
      July
      2007, APCo filed a request with the Virginia SCC to recover, over the twelve
      months beginning January 1, 2009, a return on projected construction work in
      progress including development, design and planning costs from July 1, 2007
      through December 31, 2009 estimated to be $45 million associated with a proposed
      629 MW IGCC plant to be constructed in West Virginia for an estimated cost
      of
      $2.2 billion.  APCo is requesting authorization to defer a return on
      actual pre-construction costs incurred beginning July 1, 2007 until such costs
      are recovered, starting January 1, 2009 in accordance with the
      new re-regulation legislation.  See “West Virginia IGCC Plant”
section within West Virginia Rate Matters below.





**West
      Virginia Rate Matters**





***APCo
      and WPCo ENEC Filing***





In
      April
      2007, the WVPSC issued an order establishing an investigation and hearing
      concerning APCo’s and WPCo’s 2007 Expanded Net Energy Cost (ENEC) compliance
      filing.  The ENEC is an expanded form of fuel clause mechanism, which
      includes all energy-related costs including fuel, purchased power expenses,
      off-system sales credits and other energy/transmission
      items.   In the March 2007 ENEC joint filing, APCo and WPCo filed
      for an increase of approximately $101 million including a $72 million increase
      in ENEC and a $29 million increase in construction cost surcharges to become
      effective July 1, 2007.  In June 2007, the WVPSC issued an order
      approving, without modification, a joint stipulation and agreement for
      settlement reached among the parties.  The settlement agreement
      provided for an increase in annual non-base revenues of approximately $86
      million effective July 1, 2007.  This annual revenue increase
      primarily includes $55 million of ENEC and $29 million of construction cost
      surcharges.  The ENEC portion of the increase is subject to a true-up,
      which should avoid an under-recovery of ENEC costs if they exceed the $55
      million.





***West
      Virginia IGCC Plant***





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





In
      June
      2007, APCo filed testimony with the WVPSC supporting the requests for a CCN
      and
      for pre-approval of a surcharge rate mechanism to provide for the timely
      recovery of both 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.  If
      APCo receives all necessary approvals, the plant could be completed as early
      as
      mid-2012 and currently is expected to cost an estimated $2.2
      billion**.**In July 2007, the WVPSC staff and
      intervenors filed to delay the procedural schedule by 90 days.  APCo
      supported the changes to the procedural schedule.  The statutory
      decision deadline was revised to March 2008.  In July 2007, the WVPSC
      approved the revised procedural schedule.  Through June 30, 2007, APCo
      deferred pre-construction IGCC costs totaling $11 million.  If the
      plant is not built and these costs are not recoverable, future results of
      operations and cash flows would be adversely affected.





**Indiana
      Rate Matters**





***Indiana
      Depreciation Study Filing***





In
      February 2007, I&M filed a request with the IURC for approval of revised
      book depreciation rates effective January 1, 2007.  The filing
      included a settlement agreement entered into with the Indiana Office of the
      Utility Consumer Counsel (OUCC) that would provide direct benefits to I&M's
      customers if new lower depreciation rates were approved by the
      IURC.  The direct benefits would include a $5 million credit to fuel
      costs and an approximate $8 million smart metering pilot program.  In
      addition, if the agreement were to be approved, I&M would initiate a general
      rate proceeding on or before July 1, 2007 and initiate two studies, one to
      investigate a general smart metering program and the other to study the market
      viability of demand side management programs.  Based on the
      depreciation study included in the filing, I&M recommended and the
      settlement agreed to a decrease in pretax annual depreciation expense on an
      Indiana jurisdictional basis of approximately $69 million reflecting an
      NRC-approved 20-year extension of the Cook Plant licenses for Units 1 and 2
      and
      an extension of the service life of the Tanners Creek coal-fired generating
      units.  This petition was not a request for a change in customers’
electric service rates.  As proposed, the book depreciation reduction
      would increase earnings, but would not impact cash flows until rates are
      revised. Base and fuel rates were frozen in Indiana through June 30,
      2007.  The IURC held a public hearing in April 2007.  In
      June 2007, the IURC approved the settlement agreement, but modified the
      effective date of the new depreciation rates upon the filing by I&M of a
      general rate petition.  See “Indiana Rate Filing” section
      below.  On June 19, 2007, I&M and the OUCC notified the IURC the
      parties would accept the modification to the settlement agreement and I&M
      filed its rate petition.





The
      settlement agreement modification reduced book depreciation rates, which will
      result in an increase of $37 million in pretax earnings for the period June
      19,
      2007 to December 31, 2007.  The $37 million increase is partially
      offset by a $5 million regulatory liability, recorded in June 2007, to provide
      for the agreed-upon fuel credit.  I&M’s approved depreciation
      rates are subject to further review in the general rate
      case.  I&M’s earnings will continue to benefit until the base
      rates are revised to include lower depreciation rates, at which time cash flows
      will be adversely affected.  Management expects new base rates will
      become effective in late 2008 or early 2009.





***Indiana
      Rate Filing***





In
      June
      2007, I&M filed a rate notification petition with the IURC regarding its
      intent to file for a base rate increase with a proposed test year ended
      September 30, 2007.  The petition indicated, among other things, the
      filing would include a request to implement rate tracker mechanisms for certain
      variable components of the cost of service including AEP Power Pool capacity
      settlements, PJM RTO costs, reliability enhancement costs, DSM/energy efficiency
      program costs, off-system sales margins, and net environmental compliance
      costs.  The petition requests the IURC to approve the test year period
      and the inclusion of the above trackers in the rate
      filing.  Management expects to file the case in late 2007 or early
      2008 with a decision expected in late 2008 or early 2009.





***Indiana
      Rate Cap***





Effective
      July 1, 2007, I&M’s rate cap ended for both base and fuel
      rates.  I&M’s fuel factor increased with the July 2007 billing
      month to recover the projected cost of fuel.  I&M will resume
      deferring through revenues any under/over-recovered fuel costs for future
      recovery/refund.  Under the capped rates, I&M was unable to
      recover $44 million of fuel costs since 2004 of which $7 million adversely
      impacted 2007 pretax earnings through June 30, 2007.  Future results
      of operations should no longer be impacted by fuel costs.




**Kentucky
      Rate Matters**





***Environmental
      Surcharge Filing***





In
      July
      2006, KPCo filed for approval of an amended environmental compliance plan and
      revised tariff to implement an adjusted environmental surcharge.  KPCo
      estimates the amended environmental compliance plan and revised tariff would
      increase revenues over 2006 levels by approximately $2 million in 2007 and
      $6
      million in 2008 for a total of $8 million of additional revenue at current
      cost
      projections.  In January 2007, the KPSC issued an order approving
      KPCo’s proposed plan and surcharge.  Future recovery is based upon
      actual environmental costs and is subject to periodic review and approval by
      the
      KPSC.





In
      November 2006, the Kentucky Attorney General and the Kentucky Industrial Utility
      Consumers (KIUC) filed an appeal with the Kentucky Court of Appeals of the
      Franklin Circuit Court’s 2006 order upholding the KPSC’s 2005 Environmental
      Surcharge order.  In KPCo’s order, the KPSC approved recovery of its
      environmental costs at its Big Sandy Plant and its share of environmental costs
      incurred as a result of the AEP Power Pool capacity settlement.  The
      KPSC has allowed KPCo to recover these FERC-approved allocated costs, via the
      environmental surcharge, since the KPSC’s first environmental surcharge order in
      1997.  KPCo presently recovers $7 million a year in environmental
      surcharge revenues.





In
      March
      2007, the KPSC issued an order, at the request of the Kentucky Attorney General,
      stating the environmental surcharge collections authorized in the January 2007
      order that are associated with out-of-state generating facilities should be
      collected over the six months beginning March 2007, subject to refund, pending
      the outcome of the Court of Appeals process.  At this time, management
      is unable to predict the outcome of this proceeding and its effect on KPCo’s
      current environmental surcharge revenues or on the January 2007 KPSC order
      increasing KPCo’s environmental rates.  If the appeal is successful,
      future results of operations and cash flows could be adversely
      affected.





**Oklahoma
      Rate Matters**





***PSO
      Fuel and Purchased Power and its Possible Impact on AEP East companies and
      AEP
      West companies***





In
      2002,
      PSO under-recovered $44 million of purchased power costs through its fuel clause
      resulting from a reallocation among AEP West companies of purchased power costs
      for periods prior to January 1, 2002.  In July 2003, PSO proposed
      collection of those reallocated costs over eighteen months.  In August
      2003, the OCC staff filed testimony recommending PSO recover $42 million of
      the
      reallocated purchased power costs over three years and PSO reduced its
      regulatory asset deferral by $2 million.  The OCC subsequently
      expanded the case to include a full prudence review of PSO’s 2001 fuel and
      purchased power practices.  In January 2006, the OCC staff and
      intervenors issued supplemental testimony alleging that AEP deviated from the
      FERC-approved method of allocating off-system sales margins between AEP East
      companies and AEP West companies and among AEP West companies.  The
      OCC staff proposed that the OCC offset the $42 million of under-recovered fuel
      with the proposed reallocation of off-system sales margins of $27 million to
      $37
      million and with $9 million of purchased power reallocation attributed to
      wholesale customers, which they claimed had not been refunded.  In
      February 2006, the OCC staff filed a report concluding that the $9 million
      of
      reallocated purchased power costs assigned to wholesale customers had been
      refunded, thus removing that issue from its recommendation.





In
      2004,
      an Oklahoma ALJ found that the OCC lacks authority to examine whether PSO
      deviated from the FERC-approved allocation methodology and held that any such
      complaints should be addressed at the FERC.  The OCC has not ruled on
      appeals by intervenors of the ALJ’s finding.  The United States
      District Court for the Western District of Texas issued orders in September
      2005
      regarding a TNC fuel proceeding and in August 2006 regarding a TCC fuel
      proceeding, preempting the PUCT from reallocating off-system sales margins
      between the AEP East companies and AEP West companies.  The federal
      court agreed that the FERC has sole jurisdiction over that
      allocation.  The PUCT appealed the ruling. The United States Court of
      Appeals for the Fifth Circuit, issued a decision in December 2006 regarding
      the
      TNC fuel proceeding that affirmed the United States District Court
      ruling.  In April 2007, the PUCT petitioned the United States Supreme
      Court for a review of the Court of Appeal’s order.




PSO
      does
      not agree with the intervenors’ and the OCC staff’s recommendations and
      proposals other than the staff’s original recommendation that PSO be allowed to
      recover the $42 million over three years and will defend its right to recover
      its under-recovered fuel balance.  Management believes that if the
      position taken by the federal courts in the Texas proceeding is applied to
      PSO’s
      case, then the OCC should be preempted from disallowing fuel recoveries for
      alleged improper allocations of off-system sales margins between AEP East
      companies and AEP West companies.  The OCC or another party could file
      a complaint at the FERC alleging the allocation of off-system sales margins
      to
      PSO is improper, which could result in an adverse effect on future results
      of
      operations and cash flows for AEP and the AEP East
      companies.  However, to date, there has been no claim asserted at the
      FERC that AEP deviated from the FERC approved allocation methodologies, but
      even
      if one were asserted, management believes that the OCC or another party would
      not prevail.





In
      June
      2005, the OCC issued an order directing its staff to conduct a prudence review
      of PSO’s fuel and purchased power practices for the year 2003.  The
      OCC staff filed testimony finding no disallowances in the test year
      data.  The Attorney General of Oklahoma filed testimony stating that
      they could not determine if PSO’s gas procurement activities were prudent, but
      did not include a recommended disallowance.  However, an intervenor
      filed testimony in June 2006 proposing the disallowance of $22 million in fuel
      costs based on a historical review of potential hedging opportunities that
      he
      alleges existed during the year.  A hearing was held in August 2006
      and management expects a recommendation from the ALJ in the second half of
      2007.





In
      February 2006, a law was enacted requiring the OCC to conduct prudence reviews
      on all generation and fuel procurement processes, practices and costs on either
      a two or three-year cycle depending on the number of customers
      served.  PSO is subject to the required biennial
      reviews.  PSO filed its testimony in June 2007 covering the year
      2005.





In
      May
      2007, PSO filed an application to adjust its fuel/purchase power
      rates.  In the filing, PSO netted the $42 million of under-recovered
      pre-2002 reallocated purchased power costs against their current $48 million
      over-recovered fuel balance.  In oral discussions, the OCC staff did
      not oppose the netting of the balances.  The $6 million net
      over-recovered fuel/purchased power cost deferral balance will be refunded
      over
      the twelve month period beginning June 2007.  To date, no party has
      objected to the offset.





Management
      cannot predict the outcome of the pending fuel and purchased power costs and
      prudence reviews, planned future reviews or the current fuel adjustment clause
      filing, but believes that PSO’s fuel and purchased power procurement practices
      and costs are prudent and properly incurred.  If the OCC disagrees and
      disallows fuel or purchased power costs including the pre-2002 reallocation
      of
      purchased power costs incurred by PSO, it would have an adverse effect on future
      results of operations and cash flows.





***Oklahoma
      Rate Filing***





In
      November 2006, PSO filed a request to increase base rates by $50 million for
      Oklahoma jurisdictional customers with a proposed effective date in the second
      quarter of 2007.  PSO sought a return on equity of
      11.75%.  PSO also proposed a formula rate plan that, if approved as
      filed, will permit PSO to defer any unrecovered costs as a result of a revenue
      deficiency that exceeds 50 basis points of the allowed return on equity for
      recovery within twelve months beginning six months after the test
      year.  The proposed formula rate plan would enable PSO to recover on a
      timely basis the cost of its new generation, transmission and distribution
      construction (including carrying costs during construction), provide the
      opportunity to achieve the approved return on equity and prevent the
      capitalization of a significant amount of AFUDC that would have been recorded
      during the construction time period to be recovered in the future through
      depreciation expense.





In
      March
      2007, the OCC staff and various intervenors filed testimony.  The
      recommendations were base rate reductions that ranged from $18 million to $52
      million.  The recommended returns on equity ranged from 9.25% to
      10.09%.  These recommendations included reductions in depreciation
      expense of approximately $25 million, which has no earnings
      impact.  The OCC staff filed testimony supporting a formula rate plan,
      generally similar to the one proposed by PSO.  In April 2007, PSO
      filed rebuttal testimony regarding various issues raised by the OCC staff and
      the intervenors.  In connection with the filing of rebuttal testimony,
      PSO reduced its base rate request by $2 million.  The ALJ issued a
      report in May 2007 recommending a 10.5% return on equity but did not compute
      an
      overall revenue requirement.  The ALJ’s report did not recommend
      adopting a formula rate plan, but did recommend recovery through a rider of
      certain generation and transmission projects’ financing costs during
      construction.  However, the report also contained an alternative
      recommendation that the OCC could delay a decision on the rider and take up
      this
      issue in PSO’s application seeking regulatory approval of the coal-fueled
      generating unit.  The OCC’s discussions during deliberations have
      centered around a return on equity of 9.75%.  PSO implemented interim
      rates, subject to refund, for residential customers beginning July
      2007.  The interim rate implements a key provision of the rate case on
      which there seems to be agreement at the OCC, and is estimated to increase
      revenues by approximately $4 million in 2007 and $9 million on an annual
      basis.  Other components of the rate case will be implemented once the
      OCC issues a final order, which is expected in early August 2007.





Management
      is unable to predict the final outcome of these proceedings. However, if rates
      are not increased in an amount sufficient to recover expected unavoidable cost
      increases, future results of operations, cash flows and possibly financial
      condition could be adversely affected.





***Lawton
      and Peaking Generation Settlement Agreement***





On
      November 26, 2003, pursuant to an application by Lawton Cogeneration, L.L.C.
      (Lawton) seeking approval of a Power Supply Agreement (the Agreement) with
      PSO
      and associated avoided cost payments, the OCC issued an order approving the
      Agreement and setting the avoided costs.





In
      December 2003, PSO filed an appeal of the OCC’s order with the Oklahoma Supreme
      Court (the Court).  In the appeal, PSO maintained that the OCC
      exceeded its authority under state and federal laws to require PSO to enter
      into
      the Agreement.  The Court issued a decision on June 21, 2005,
      affirming portions of the OCC’s order and remanding certain
      provisions.  The Court affirmed the OCC’s finding that Lawton
      established a legally-enforceable obligation and ruled that it was within the
      OCC’s discretion to award a 20-year contract and to base the capacity payment on
      a peaking unit.  The Court directed the OCC to revisit its
      determination of PSO’s avoided energy cost. Hearings were held on the remanded
      issues in April and May 2006.





In
      April
      2007, all parties in the case filed a settlement agreement with the OCC
      resolving all issues. The OCC approved the settlement agreement in April
      2007.  The OCC staff, the Attorney General, the Oklahoma Industrial
      Energy Consumers and Lawton Cogeneration, L.L.C supported this settlement
      agreement.  The settlement agreement provides for a purchase fee of
      $35 million to be paid by PSO to Lawton and for Lawton to provide, at PSO’s
      direction, all rights to the Lawton Cogeneration Facility including permits,
      options and engineering studies.  PSO paid the $35 million purchase
      fee in June 2007 and recorded the purchase fee as a regulatory asset and will
      recover it through a rider over a three-year period with a carrying charge
      of
      8.25% beginning in September 2007.  In addition, PSO will recover
      through a rider, subject to a $135 million cost cap, all of the traditional
      costs associated with plant in service of its new peaking units to be located
      at
      the Southwestern Station and Riverside Station at the time these units are
      placed in service.  PSO expects these units will have a substantially
      lower plant-in-service cost than the proposed Lawton Cogeneration
      Facility.  PSO may request approval from the OCC for recovery of costs
      exceeding the cost cap if special circumstances occur necessitating a higher
      level of costs.  Such costs will continue to be recovered through the
      rider until cost recovery occurs through base rates or formula rates in a
      subsequent proceeding.  Under the settlement, PSO must file a rate
      case within eighteen months of the beginning of recovery through the rider
      unless the OCC approves a formula-based rate mechanism that provides for
      recovery of the peaking units.  Once the cost recovery for the new
      peaking units begins in mid-2008, PSO expects annual revenues of an estimated
      $36 million related to cost recovery of the peaking units and the purchase
      fee.





**Louisiana
      Rate Matters**





***Louisiana
      Compliance Filing***





In
      October 2002, SWEPCo filed detailed financial information typically utilized
      in
      a revenue requirement filing, including a jurisdictional cost of service, with
      the LPSC.  This filing was required by the LPSC as a result of its
      order approving the merger between AEP and CSW.  Due to multiple
      delays, in April 2006, the LPSC and SWEPCo agreed to update the financial
      information based on a 2005 test year.  SWEPCo filed updated financial
      review schedules in May 2006 showing a return on equity of 9.44% compared to
      the
      previously-authorized return on equity of 11.1%.




In
      July
      2006, the LPSC staff’s consultants filed direct testimony recommending a base
      rate reduction in the range of $12 million to $20 million for SWEPCo’s Louisiana
      jurisdiction customers, based on a proposed 10% return on equity.  The
      recommended reduction range is subject to SWEPCo validating certain ongoing
      operations and maintenance expense levels.  SWEPCo filed rebuttal
      testimony in October 2006 strongly refuting the consultants’
recommendations.  In December 2006, the LPSC staff’s consultants filed
      reply testimony asserting that SWEPCo’s Louisiana base rates are excessive by
      $17 million which includes a proposed return on equity of
      9.8%.  SWEPCo filed rebuttal testimony in January
      2007.  Constructive settlement negotiations are making meaningful
      progress.  At this time, management is unable to predict the outcome
      of this proceeding.  If a rate reduction is ultimately ordered, it
      would adversely affect future results of operations, cash flows and possibly
      financial condition.





**FERC
      Rate Matters**





***Transmission
      Rate Proceedings at the FERC***





*The
      FERC PJM Regional Transmission Rate Proceeding*





At
      AEP’s
      urging, the FERC instituted an investigation of PJM’s zonal rate regime,
      indicating that the present rate regime may need to be replaced through
      establishment of regional rates that would compensate AEP and other transmission
      owners for the regional transmission facilities they provide to PJM, which
      provides service for the benefit of customers throughout PJM.  In
      September 2005, AEP and a nonaffiliated utility (Allegheny Power or AP) jointly
      filed a regional transmission rate design proposal with the
      FERC.  This filing proposed and supported a new PJM rate regime
      generally referred to as a Highway/Byway rate design.





Parties
      to the regional rate proceeding proposed the following rate
      regimes:





·
            AEP/AP
                proposed a Highway/Byway rate design in which:·
            The
                cost of all transmission facilities in the PJM region operated at
                345 kV
                or higher would be included in a “Highway” rate that all load serving
                entities (LSEs) would pay based on peak demand.  The AEP/AP
                proposal would produce about $125 million in net revenues per year
                for AEP
                from users in other zones of PJM.·
            The
                cost of transmission facilities operating at lower voltages would
                be
                collected in the zones where those costs are presently charged under
                PJM’s
                existing rate design.·
            Two
                other utilities, Baltimore Gas & Electric Company (BG&E) and Old
                Dominion Electric Cooperative (ODEC), proposed a Highway/Byway rate
                that
                includes transmission facilities above 200 kV in the Highway rate,
                which
                would have produced lower net revenues for AEP than the AEP/AP
                proposal.·
            In
                another competing Highway/Byway proposal, a group of LSEs proposed
                rates
                that would include existing 500 kV and higher voltage facilities
                and new
                facilities above 200 kV in the Highway rate, which would also have
                produced lower net revenues for AEP than the AEP/AP
                proposal.·
            In
                January 2006, the FERC staff issued testimony and exhibits supporting
                phase-in of a PJM-wide flat rate or “Postage Stamp” type of rate design
                that would socialize the cost of all transmission facilities. The
                proposed
                rate design would have initially produced much lower net transmission
                revenues for AEP than the AEP/AP proposal, but could produce slightly
                higher net revenues when fully phased
                in.





All
      of
      these proposals were challenged by a majority of other transmission owners
      in
      the PJM region, who favored continuation of the existing PJM rate design which
      provides AEP with no compensation for through and out traffic on its east zone
      transmission system.  Hearings were held in April 2006 and the ALJ
      issued an initial decision in July 2006.  The ALJ found the existing
      PJM zonal rate design to be unjust and determined that it should be
      replaced.  The ALJ found that the Highway/Byway rates proposed by
      AEP/AP and BG&E/ODEC to be just and reasonable alternatives.  The
      ALJ also found FERC staff’s proposed Postage Stamp rate to be just and
      reasonable and recommended that it be adopted.  The ALJ also found
      that the effective date of the rate change should be April 1, 2006 to coincide
      with SECA rate elimination.  Because the Postage Stamp rate was found
      to produce greater cost shifts than other proposals, the judge also recommended
      that the new regional design be phased-in.  Without a phase-in, the
      Postage Stamp method would produce more revenue for AEP than the AEP/AP
      proposal. However, the proposed phase-in of Postage Stamp rates would delay
      the
      full favorable impact of those new regional rates until about 2012.




AEP
      filed
      briefs noting exceptions to the initial decision and replies to the exceptions
      of other parties.  AEP argued that a phase-in should not be
      required.  Nevertheless, AEP argued that if the FERC adopts the
      Postage Stamp rate and a phase-in plan, the revenue collections curtailed by
      the
      phase-in should be deferred and paid later with interest.





Since
      the
      FERC’s decision in 2005 to cease through-and-out rates and replace them
      temporarily with SECA rates which ceased on April 1, 2006, the AEP East
      companies increased their retail rates in all states except Indiana and Michigan
      to recover lost through-and-out transmission service (T&O) and SECA
      revenues.





In
      April
      2007, the FERC issued an order reversing the ALJ’s decision.  The FERC
      ruled that the current PJM rate design is just and reasonable for existing
      transmission facilities.  However, the FERC ruled that the cost of new
      facilities of 500 kV and above would be shared among all PJM
      participants.  As a result of this order, the AEP East companies’
retail customers will bear the full cost of the existing AEP east transmission
      zone facilities although others use them.  Presently AEP is collecting
      the full cost of those facilities from its retail customers with the exception
      of Indiana and Michigan customers.  As a result of this order, the AEP
      East companies’ customers will also be charged a share of the cost of future new
      500 kV and higher voltage transmission facilities built in PJM, most of which
      are expected to be upgrades of the facilities in other zones of
      PJM.  The AEP East companies will need to obtain regulatory approvals
      for recovery of any costs of new facilities that are assigned to them as a
      result of this order, if upheld.  AEP has requested rehearing of this
      order.  Management cannot estimate at this time what effect, if any,
      this order will have on their future construction of new east transmission
      facilities, results of operations, cash flows and financial
      condition.





The
      AEP
      East companies presently recover from retail customers approximately 85% of
      the
      lost T&O/SECA transmission revenues of $128 million a
      year.  Future results of operations, cash flows and financial
      condition will continue to be adversely affected in Indiana and Michigan until
      these lost T&O/SECA transmission revenues are recovered in retail
      rates.





*SECA
      Revenue Subject to Refund*





The
      AEP
      East companies ceased collecting T&O revenues in accordance with FERC
      orders, and collected SECA rates to mitigate the loss of T&O revenues from
      December 1, 2004 through March 31, 2006, when SECA rates
      expired.  Intervenors objected to the 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 or
      surcharge.  The AEP East companies paid SECA rates to other utilities
      at considerably lesser amounts than 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. Approximately $19 million of these recorded
      SECA revenues billed by PJM were not collected.  The AEP East
      companies filed a motion with the FERC to force payment of these uncollected
      SECA billings.





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 was not 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.




Since
        the
        implementation of SECA rates in December 2004, the AEP East companies recorded
        approximately $220 million of gross SECA revenues, subject to
        refund.  In 2006, the AEP East companies provided reserves of $37
        million in net refunds for current and future SECA settlements with all of
        AEP’s
        SECA customers.  The AEP East companies reached settlements with
        certain SECA customers related to approximately $69 million of such revenues
        for
        a net refund of $3 million.  The AEP East companies are in the process
        of completing two settlements-in-principle on an additional $36 million of
        SECA
        revenues and expect to make net refunds of $4 million when those settlements
        are
        approved.  Thus, completed and in-process settlements cover $105
        million of SECA revenues and will consume about $7 million of the reserves
        for
        refunds, leaving approximately $115 million of contested SECA revenues and
        $30
        million of refund reserves.  If the ALJ’s initial decision were upheld
        in its entirety, it would disallow approximately $90 million of the AEP East
        companies’ remaining $115 million of unsettled gross SECA
        revenues.  Based on recent settlement experience and the expectation
        that most of the $115 million of unsettled SECA revenues will be settled,
        management believes that the remaining reserve will be
        adequate.


In
      September 2006, AEP, together with Exelon Corporation and The Dayton Power
      and
      Light Company, filed an extensive post-hearing brief and reply brief noting
      exceptions to the ALJ’s initial decision and asking the FERC to reverse the
      decision in large part.  Management believes that the FERC should
      reject the 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.  As directed by the FERC, management is working to settle the
      remaining $115 million of unsettled revenues within the remaining reserve
      balance.  Although management believes it has meritorious arguments
      and can settle with the remaining customers within the amount provided,
      management cannot predict the ultimate outcome of ongoing settlement talks
      and,
      if necessary, any future FERC proceedings or court appeals.  If the
      FERC adopts the ALJ’s decision and/or AEP cannot settle a significant portion of
      the remaining unsettled claims within the amount provided, it will have an
      adverse effect on future results of operations and cash flows.





***PSO
      and SWEPCo SPP Transmission Formula Rate Filing***





In
      June
      2007, AEPSC filed revised tariff sheets on behalf of PSO and SWEPCo for the
      AEP
      pricing zone of the SPP OATT.  The revised tariff sheets seek to
      establish an up-to-date revenue requirement for SPP transmission services over
      the facilities of PSO and SWEPCo and implement a transmission cost of service
      formula rate.





PSO
      and
      SWEPCo requested an effective date of September 1, 2007 for the revised
      tariff.  FERC could suspend the effective date until February 1,
      2008.  The primary impact of the filed revised tariff will be an
      increase in network transmission service revenues from nonaffiliated municipal
      and rural cooperative utilities in the AEP Zone.  If the proposed
      formula rate and requested return on equity are approved, the 2008 network
      transmission service revenues from nonaffiliates will increase by approximately
      $10 million compared to the revenues that would result from the presently
      approved network transmission rate.  PSO and SWEPCo take service under
      the same rate, and will also incur the increased OATT rates resulting from
      the
      filing, but will receive corresponding revenue to offset the
      increase.  This filing will not directly impact retail
      rates.





**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 2006 Annual Report should be read in conjunction
      with this report.





**GUARANTEES**





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





***Letters
      of Credit***





We
      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, debt service reserves and
      credit enhancements for issued bonds.  As the parent company, we
      issued all of these LOCs in our ordinary course of business on behalf of our
      subsidiaries.  At June 30, 2007, the maximum future payments for all
      the LOCs were approximately $27 million with maturities ranging from July 2007
      to July 2008.





***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 $85 million.  Since SWEPCo uses self-bonding, the
      guarantee provides for SWEPCo to commit to use its resources to complete the
      reclamation in the event the work is not completed by Sabine Mining Company
      (Sabine), an entity consolidated under FIN 46.  This guarantee ends
      upon depletion of reserves and completion of final reclamation.  Based
      on the latest study, we estimate the reserves will be depleted in 2029 with
      final reclamation completed by 2036, at an estimated cost of approximately $39
      million.  As of June 30, 2007, SWEPCo has collected approximately $31
      million through a rider for final mine closure costs, of which approximately
      $14
      million is recorded in Deferred Credits and Other and approximately $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 through its fuel clause.





***Indemnifications
      and Other Guarantees***





*Contracts*





We
      enter
      into several types of contracts which require
      indemnifications.  Typically these contracts include, but are not
      limited to, sale agreements, lease agreements, purchase agreements and financing
      agreements.  Generally, these agreements may include, but are not
      limited to, indemnifications around certain tax, contractual and environmental
      matters.  With respect to sale agreements, our exposure generally does
      not exceed the sale price.  The status of certain sales agreements is
      discussed in the 2006 Annual Report, “Dispositions” section of Note
      8.  These sale agreements include indemnifications with a maximum
      exposure related to the collective purchase price, which is approximately $1.9
      billion (approximately $1 billion relates to the Bank of America (BOA)
      litigation, see “Enron Bankruptcy” section of this note).  There are
      no material liabilities recorded for any indemnifications.





*Master
      Operating Lease*





We
      lease
      certain equipment under a master operating lease.  Under the lease
      agreement, the lessor is guaranteed 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.  At June 30, 2007, the maximum
      potential loss for these lease agreements was approximately $59 million ($38
      million, net of tax) assuming the fair market value of the equipment is zero
      at
      the end of the lease term.





*Railcar
      Lease*





In
      June
      2003, we entered into an agreement with BTM Capital Corporation, as lessor,
      to
      lease 875 coal-transporting aluminum railcars.  The lease has an
      initial term of five years.  At the end of each lease term, we may (a)
      renew for another five-year term, not to exceed a total of twenty years; (b)
      purchase the railcars for the purchase price amount specified in the lease,
      projected at the lease inception to be the then fair market value; or (c) return
      the railcars and arrange a third party sale (return-and-sale
      option).  The lease is accounted for as an operating
      lease.  We intend to renew the lease for the full twenty
      years.  This operating lease agreement allows us to avoid a large
      initial capital expenditure and to spread our railcar costs evenly over the
      expected twenty-year usage.





Under
      the
      lease agreement, the lessor is guaranteed that the sale proceeds under the
      return-and-sale option discussed above will equal at least a lessee obligation
      amount specified in the lease, which declines over the current lease term from
      approximately 86% to 77% of the projected fair market value of the
      equipment.  At June 30, 2007, the maximum potential loss was
      approximately $30 million ($20 million, net of tax) assuming the fair market
      value of the equipment is zero at the end of the current lease
      term.  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 allege
      that
      APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities including the
      Tennessee Valley Authority, Alabama Power Company, Cincinnati Gas & Electric
      Company, Ohio Edison Company, Southern Indiana Gas & Electric Company,
      Illinois Power Company, Tampa Electric Company, Virginia Electric Power Company
      and Duke Energy, modified certain units at coal-fired generating plants in
      violation of the NSR requirements of the CAA.  The Federal EPA filed
      its complaints against our subsidiaries in U.S. District Court for the Southern
      District of Ohio.  The alleged modifications occurred at our
      generating units over a 20-year period.  A bench trial on the
      liability issues was held during July 2005.  In June 2006, the judge
      stayed the liability decision pending the issuance of a decision by the U.S.
      Supreme Court in the Duke Energy case.





Under
      the
      CAA, if a plant undertakes a major modification that results in an emissions
      increase, permitting requirements might be triggered and the plant may be
      required to install additional pollution control technology.  This
      requirement does not apply to routine maintenance, replacement of degraded
      equipment or failed component or other repairs needed for the reliable, safe
      and
      efficient operation of the plant.  The CAA authorizes civil penalties
      of up to $27,500 ($32,500 after March 15, 2004) per day per violation at each
      generating unit.  In 2001, the District Court ruled claims for civil
      penalties based on activities that occurred more than five years before the
      filing date of the complaints cannot be imposed.  There is no time
      limit on claims for injunctive relief.





Cases
      are
      pending that could affect CSPCo’s share of jointly-owned units at Beckjord,
      Zimmer, and Stuart Stations.  Similar cases have been filed against
      other nonaffiliated utilities, including Allegheny Energy, Eastern Kentucky
      Electric Cooperative, Public Service Enterprise Group, Santee Cooper, Wisconsin
      Electric Power Company, Mirant, NRG Energy and Niagara
      Mohawk.  Several of these cases were resolved through consent
      decrees.





Courts
      have reached different conclusions regarding whether the activities at issue
      in
      these cases are routine maintenance, repair or replacement, and therefore are
      excluded from NSR.  Similarly, courts have reached different results
      regarding whether the activities at issue increased emissions from the power
      plants.  Appeals on these and other issues were filed in certain
      appellate courts, including a petition to appeal to the U.S. Supreme Court
      that
      was granted in the Duke Energy case.  The Federal EPA issued a final
      rule that would exclude activities similar to those challenged in these cases
      from NSR as “routine replacements.”  In March 2006, the Court of
      Appeals for the District of Columbia Circuit issued a decision vacating the
      rule.  The Court denied the Federal EPA’s request for rehearing, and
      the Federal EPA and other parties filed a petition for review by the U.S.
      Supreme Court.  In April 2007, the Supreme Court denied the petition
      for review.  The Federal EPA also proposed a rule that would define
“emissions increases” in a way that most of the challenged activities would be
      excluded from NSR.





On
      April
      2, 2007, the U.S. Supreme Court reversed the Fourth Circuit Court of Appeals’
decision that had supported the statutory construction argument of Duke Energy
      in its NSR proceeding.  In a unanimous decision, the Court ruled that
      the Federal EPA was not obligated to define “major modification” in two
      different CAA provisions in the same way.  The Court also found that
      the Fourth Circuit’s interpretation of “major modification” as applying only to
      projects that increased hourly emission rates amounted to an invalidation of
      the
      relevant Federal EPA regulations, which under the CAA can only be challenged
      in
      the Court of Appeals within 60 days of the Federal EPA
      rulemaking.  The U.S. Supreme Court did acknowledge, however, that
      Duke Energy may argue on remand that the Federal EPA has been inconsistent
      in
      its interpretations of the CAA and the regulations and may not retroactively
      change 20 years of accepted practice.





In
      addition to providing guidance on certain of the merits of the NSR proceedings
      brought against APCo, CSPCo, I&M and OPCo in U.S. District Court for the
      Southern District of Ohio, the U.S. Supreme Court’s issuance of a ruling in the
      Duke Energy cases has an impact on the timing of our NSR
      proceedings.  The court that heard our trial on liability issues will
      likely issue its decision during the third quarter of 2007.  A bench
      trial on remedy issues, if necessary, is likely to begin in 2007.





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




***SWEPCo
      Notice of Enforcement and Notice of Citizen Suit***





In
      March
      2005, two special interest groups, Sierra Club and Public Citizen, filed a
      complaint in Federal District Court for the Eastern District of Texas alleging
      violations of the CAA at SWEPCo’s Welsh Plant.  SWEPCo filed a
      response to the complaint in May 2005.  A trial in this matter is
      scheduled for the third quarter of 2007.





In
      2004,
      the Texas Commission on Environmental Quality (TCEQ) issued a Notice of
      Enforcement to SWEPCo relating to the Welsh Plant containing a summary of
      findings resulting from a compliance investigation at the plant.  In
      April 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition
      recommending the entry of an enforcement order to undertake certain corrective
      actions and assessing an administrative penalty of approximately $228 thousand
      against SWEPCo based on alleged violations of certain representations regarding
      heat input in SWEPCo’s permit application and the violations of certain
      recordkeeping and reporting requirements.  SWEPCo responded to the
      preliminary report and petition in May 2005.  The enforcement order
      contains a recommendation limiting the heat input on each Welsh unit to the
      referenced heat input contained within the permit application within 10 days
      of
      the issuance of a final TCEQ order and until a permit amendment is
      issued.  SWEPCo had previously requested a permit alteration to remove
      the reference to a specific heat input value for each Welsh unit and to clarify
      the sulfur content requirement for fuels consumed at the plant.  A
      permit alteration was issued in March 2007 removing the heat input references
      from the Welsh permit and clarifying the sulfur content of fuels burned at
      the
      plant is limited to 0.5% on an as-received basis.  The Sierra Club and
      Public Citizen filed a motion to overturn the permit alteration.  In
      June 2007, TCEQ denied that motion.





We
      are
      unable to predict the timing of any future action by TCEQ or the special
      interest groups or the effect of such actions on our results of operations,
      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 defendants’ motion to dismiss the lawsuits was
      granted in September 2005.  The dismissal was appealed to the Second
      Circuit Court of Appeals.  Briefing and oral argument have
      concluded.  On April 2, 2007, the U.S. Supreme Court issued a decision
      holding that the Federal EPA has authority to regulate emissions of CO2 and other
      greenhouse gases under the CAA, which may impact the Second Circuit’s analysis
      of these issues.  The Second Circuit requested supplemental briefs
      addressing the impact of the Supreme Court’s decision on this
      case.  We believe the actions are without merit and intend to defend
      against the claims.





***TEM
      Litigation***





OPCo
      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 dated November 15, 2000
      (PPA).  Beginning May 1, 2003, OPCo 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.  We alleged that
      TEM breached the PPA, and we sought a determination of our rights under the
      PPA.  TEM alleged that the PPA never became enforceable, or
      alternatively, that the PPA was terminated as the result of AEP’s
      breaches.  The corporate parent of TEM (SUEZ-TRACTEBEL S.A.) provided
      a limited guaranty.





In
      2005,
      a federal judge ruled that TEM had breached the contract and awarded us damages
      of $123 million plus prejudgment interest.  Any eventual proceeds will
      be recorded as a gain when received.





In
      May
      2007, the United States Court of Appeals for the Second Circuit ruled that
      the
      lower court was correct in finding that TEM breached the PPA and we did not
      breach the PPA.  It also ruled that the lower court applied an
      incorrect standard in denying us any damages for TEM’s breach of the 20-year
      term of the PPA holding that we are entitled to the benefit of our bargain
      and
      that the trial court must determine our damages.  The Court of Appeals
      vacated our $123 million judgment for damages against TEM related to replacement
      products and remanded the issue for further proceedings.





***Enron
      Bankruptcy***





In
      connection with the 2001 acquisition of HPL, we entered into an agreement with
      BAM Lease Company, which granted HPL the exclusive right to use approximately
      65
      billion cubic feet (BCF) of cushion gas required for the normal operation of
      the
      Bammel gas storage facility.  At the time of our acquisition of HPL,
      Bank of America (BOA) and certain other banks (the BOA Syndicate) and Enron
      entered into an agreement granting HPL the exclusive use of 65 BCF of cushion
      gas.  Also at the time of our acquisition, Enron and the BOA Syndicate
      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.  In 2002, the BOA
      Syndicate filed a lawsuit against HPL in Texas state court seeking a declaratory
      judgment that the BOA Syndicate has a valid and enforceable security interest
      in
      gas purportedly in the Bammel storage facility.  In 2003, the Texas
      state court granted partial summary judgment in favor of the BOA
      Syndicate.  In August 2006, the Court of Appeals for the First
      District of Texas vacated the trial court’s judgment and dismissed the BOA
      Syndicate’s case.  The BOA Syndicate did not seek review of this
      decision.  In June 2004, BOA filed an amended petition in a separate
      lawsuit in Texas state court seeking to obtain possession of up to 55 BCF of
      storage gas in the Bammel storage facility or its fair
      value.  Following an adverse decision on its motion to obtain
      possession of this gas, BOA voluntarily dismissed this action.  In
      October 2004, BOA refiled this action.  HPL’s motion to have the case
      assigned to the judge who heard the case originally was granted.  HPL
      intends to defend against any renewed claims by BOA.





In
      2003,
      AEP filed a lawsuit against BOA in the United States District Court for the
      Southern District of Texas.  BOA led a lending syndicate involving the
      1997 gas monetization that Enron and its subsidiaries undertook and the leasing
      of the Bammel underground gas storage facility to HPL.  The lawsuit
      asserts that BOA made misrepresentations and engaged in fraud to induce and
      promote the stock sale of HPL, that BOA directly benefited from the sale of
      HPL
      and that AEP undertook the stock purchase and entered into the Bammel storage
      facility lease arrangement with Enron and the cushion gas arrangement with
      Enron
      and BOA based on misrepresentations that BOA made about Enron’s financial
      condition that BOA knew or should have known were false including that the
      1997
      gas monetization did not contravene or constitute a default of any federal,
      state, or local statute, rule, regulation, code or any law.  In
      February 2004, BOA filed a motion to dismiss this Texas federal
      lawsuit.  In September 2004, the Magistrate Judge issued a Recommended
      Decision and Order recommending that BOA’s Motion to Dismiss be denied, that the
      five counts in the lawsuit seeking declaratory judgments involving the Bammel
      facility and the right to use and cushion gas consent agreements be transferred
      to the Southern District of New York and that the four counts alleging breach
      of
      contract, fraud and negligent misrepresentation proceed in the Southern District
      of Texas.  BOA objected to the Magistrate Judge’s
      decision.  In April 2005, the Judge entered an order overruling BOA’s
      objections, denying BOA’s Motion to Dismiss and severing and transferring the
      declaratory judgment claims to the Southern District of New York.  HPL
      and BOA filed motions for summary judgment in the case pending in the Southern
      District of New York.  The case in federal court in Texas was set for
      trial beginning April 2007 but the Court continued the trial pending a decision
      on the motions for summary judgment in the New York case.





In
      February 2007, the Judge in the New York action, after hearing oral argument
      on
      the motions for summary judgment, made a series of oral “informal findings” and
      submitted a written memorandum to the parties’ counsel.  In the
      memorandum to counsel, the Judge stated that he was denying several of AEP’s
      motions for partial summary judgment and granting several of BOA motions for
      summary judgment.  The substantive matters left open for further
      proceedings include the issue of the nature of the gas subject to BOA security
      interest and the value of that interest.  The Judge stated that the
      memorandum to counsel is not an opinion or an order, and that no opinion or
      order will be issued until all motions pending before the Court have been
      decided.  The Judge heard additional arguments on the summary judgment
      motions in March 2007.  At this time we are unable to predict how the
      Judge will rule on the pending motions due to the complexity of those issues
      and
      the parties’ disagreement over each issue. If the Judge issues a judgment
      directing AEP to pay an amount in excess of the gain on the sale of HPL
      described below and if AEP is unsuccessful in having the judgment reversed
      or
      modified, the judgment could have a material adverse effect on the results
      of
      operations, cash flows, and possibly financial condition.





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





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.  The determination and recognition of the gain on the sale are
      dependent on the ultimate resolution of the BOA dispute and the costs, if any,
      associated with the resolution of this matter.  The deferred gain,
      estimated to be $382 million and $380 million at June 30, 2007 and December
      31,
      2006, respectively, is included in Deferred Credits and Other on our Condensed
      Consolidated Balance Sheets.





Although
      management is unable to predict the outcome of the remaining lawsuits, it is
      possible that their resolution could have a material adverse impact on our
      results of operations, cash flows and financial condition.





***Shareholder
      Lawsuits***





In
      2002
      and 2003, three putative class action lawsuits were filed against AEP, certain
      executives and AEP’s Employee Retirement Income Security Act (ERISA) Plan
      Administrator alleging violations of ERISA in the selection of AEP stock as
      an
      investment alternative and in the allocation of assets to AEP
      stock.  The ERISA actions were pending in Federal District Court,
      Columbus, Ohio.  In these actions, the plaintiffs sought recovery of
      an unstated amount of compensatory damages, attorney fees and
      costs.  In July 2006, the Court entered judgment denying plaintiff’s
      motion for class certification and dismissing all claims without
      prejudice.  In August 2006, the plaintiffs filed a notice of appeal to
      the United States Court of Appeals for the Sixth Circuit.  Briefing of
      this appeal was completed in December 2006.  The Court of Appeals
      heard oral argument in July 2007.  We intend to continue to defend
      against these claims.





***Natural
      Gas Markets Lawsuits***





In
      2002,
      the Lieutenant Governor of California filed a lawsuit in Los Angeles County
      California Superior Court against forty energy companies, including AEP, and
      two
      publishing companies alleging violations of California law through alleged
      fraudulent reporting of false natural gas price and volume information with
      an
      intent to affect the market price of natural gas and electricity.  AEP
      was dismissed from the case.  A number of similar cases were filed in
      California.  In addition, a number of other cases were filed in state
      and federal courts in several states making essentially the same allegations
      under federal or state laws against the same companies.  In some of
      these cases, AEP (or a subsidiary) is among the companies named as
      defendants.  These cases are at various pre-trial
      stages.  Several of these cases were transferred to the United States
      District Court for the District of Nevada but subsequently were remanded to
      California state court.  In 2005 and subsequently, the judge in Nevada
      dismissed a number of the remaining cases on the basis of the filed rate
      doctrine.  Plaintiffs in these cases appealed the
      decisions.  In July 2007, the judge in the California cases stayed
      those proceedings pending a decision by the Ninth Circuit in the federal
      cases.  We will continue to defend each case where an AEP company is a
      defendant.





***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.  An ALJ recommended rejection
      of the complaint, holding that the markets for future delivery were not
      dysfunctional, and that the Nevada utilities failed to demonstrate that the
      public interest required that changes be made to the contracts.  In
      June 2003, the FERC issued an order affirming the ALJ’s decision.  In
      December 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.  In
      May 2007, we, along with other sellers involved in the case, sought review
      of
      the Ninth Circuit’s decision by the U.S. Supreme Court.  The Solicitor
      General of the United States has asked the Supreme Court for an extension of
      time, until August 6, 2007, to respond to the petitions for
      review.  Management is unable to predict the outcome of these
      proceedings or their impact on future results of operations and cash
      flows.  We have asserted claims against certain companies that sold
      power to us, which we resold to the Nevada utilities, seeking to recover a
      portion of any amounts we may owe to the Nevada utilities.





**5.**
            **ACQUISITIONS,
                DISPOSITIONS, DISCONTINUED OPERATIONS AND ASSETS HELD FOR
                SALE**





**ACQUISITIONS**





**2007**





***Darby
      Electric Generating Station (Utility Operations
      segment)***





In
      November 2006, CSPCo agreed to purchase Darby Electric Generating Station
      (Darby) from DPL Energy, LLC, a subsidiary of The Dayton Power and Light
      Company, for $102 million and the assumption of liabilities of $2
      million.  CSPCo completed the purchase in April 2007.  The
      Darby plant is located near Mount Sterling, Ohio and is a natural gas, simple
      cycle power plant with a generating capacity of 480 MW.





***Lawrenceburg
      Generating Station (Utility Operations segment)***





In
      January 2007, AEGCo agreed to purchase Lawrenceburg Generating Station
      (Lawrenceburg) from an affiliate of Public Service Enterprise Group (PSEG)
      for
      $325 million and the assumption of liabilities of $3 million.  AEGCo
      completed the purchase in May 2007.  The Lawrenceburg plant is located
      in Lawrenceburg, Indiana, adjacent to I&M’s Tanners Creek Plant, and is a
      natural gas, combined cycle power plant with a generating capacity of 1,096
      MW.  AEGCo will sell the power to CSPCo through a FERC-approved
      purchase power contract.





**2006**





None





**DISPOSITIONS**





**2007**





***Texas
      Plants – Oklaunion Power Station (Utility Operations
      segment)***





In
      February 2007, TCC sold its 7.81% share of Oklaunion Power Station to the Public
      Utilities Board of the City of Brownsville for $42.8 million plus capital
      adjustments.  The sale did not have an impact on our results of
      operations nor do we expect the remaining litigation to have a significant
      effect on our results of operations.





***Intercontinental
      Exchange, Inc. (ICE) (All Other)***





During
      March 2007, we sold 130,000 shares of ICE and recognized a $16 million pretax
      gain ($10 million, net of tax).  We recorded the gains in Interest and
      Investment Income on our 2007 Condensed Consolidated Statement of
      Income.  We recorded our remaining investment of approximately 138,000
      shares in Other Temporary Investments on our Condensed Consolidated Balance
      Sheets.





***Texas
      REPs (Utility Operations Segment)***





As
      part
      of the purchase-and-sale agreement related to the sale of our Texas REPs in
      2002, we retained the right to share in earnings with Centrica from the two
      REPs
      above a threshold amount through 2006 if the Texas retail market developed
      increased earnings opportunities.  We received $20 million and $70
      million payments in 2007 and 2006, respectively, for our share in
      earnings.  These payments are reflected in Gain/Loss on Disposition of
      Assets, Net on our Condensed Consolidated Statements of Income.  The
      payment we received in 2007 was the final payment under the earnings sharing
      agreement.





**2006**





***Compresion
      Bajio S de R.L. de C.V. (All Other)***





In
      January 2002, we acquired a 50% interest in Compresion Bajio S de R.L. de C.V.
      (Bajio), a 600 MW power plant in Mexico.  In February 2006, we
      completed the sale of the 50% interest in Bajio for $29 million with no effect
      on our 2006 results of operations.




**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 in 2007 and 2006 related to discontinued operations:





**U.K.**
              **Generation****(a)****Three
                Months Ended June 30,**
            
            **(in
                millions)**2007
                Revenue
            
            $
            -2007
                Pretax Income
            
            
            32007
                Earnings, Net of Tax
            
            
            22006
                Revenue
            
            $
            -2006
                Pretax Income
            
            
            42006
                Earnings, Net of Tax
            
            
            3





**U.K.**
              **Generation****(a)****Six
                Months Ended June 30,**
            
            **(in
                millions)**2007
                Revenue
            
            $
            -2007
                Pretax Income
            
            
            32007
                Earnings, Net of Tax
            
            
            22006
                Revenue
            
            $
            -2006
                Pretax Income
            
            
            92006
                Earnings, Net of Tax
            
            
            6





(a)
            The
                2007 amounts relate to tax adjustments from the sale.  Amounts
                in 2006 relate to a release of accrued liabilities for the settlement
                of
                the London office lease and tax adjustments related to the
                sale.





There
      were no cash flows used for or provided by operating, investing or financing
      activities related to our discontinued operations for the six months ended
      June
      30, 2007 and 2006.





**ASSETS
      HELD FOR SALE**





***Texas
      Plants – Oklaunion Power Station (Utility Operations
      segment)***





In
      February 2007, TCC sold its 7.81% share of Oklaunion Power Station to the Public
      Utilities Board of the City of Brownsville.  We classified TCC’s
      assets related to the Oklaunion Power Station in Assets Held for Sale on our
      Condensed Consolidated Balance Sheet at December 31, 2006.  The plant
      did not meet the “component-of-an-entity” criteria because the plant did not
      have cash flows that can be clearly distinguished operationally.  The
      plant also did not meet the “component-of-an-entity” criteria for financial
      reporting purposes because the plant did not operate individually, but rather
      as
      a part of the AEP System.





**Assets
      Held for Sale were as follows:**





**June
                30,**
            
            
            **December
                31,****2007**
            
            
            **2006****Texas
                Plants**
            
            **(in
                millions)**Other
                Current Assets
            
            $
            -
            
            
            $
            1Property,
                Plant and Equipment, Net
            
            
            -
            
            
            
            43**Total
                Assets Held for Sale**
            
            $
            -
            
            
            $
            44





**6.       BENEFIT
      PLANS**





We
      adopted SFAS 158 as of December 31, 2006.  We recorded a SFAS 71
      regulatory asset for qualifying SFAS 158 costs of our regulated operations
      that
      for ratemaking purposes are deferred for future recovery.





***Components
      of Net Periodic Benefit Cost***





The
      following table provides the components of our net periodic benefit cost for
      the
      plans for the three and six months ended June 30, 2007 and 2006:


**Other****Postretirement****Pension
                Plans**
            
            
            **Benefit
                Plans****2007**
            
            
            **2006**
            
            
            **2007**
            
            
            **2006****Three
                Months Ended June 30, 2007 and 2006**
            
            **(in
                millions)**Service
                Cost
            
            $
            23
            
            
            $
            24
            
            
            $
            11
            
            
            $
            10Interest
                Cost
            
            
            57
            
            
            
            57
            
            
            
            26
            
            
            
            25Expected
                Return on Plan Assets
            
            
            (82
            )
            
            
            (83
            )
            
            
            (26
            )
            
            
            (23
            )Amortization
                of Transition Obligation
            
            
            -
            
            
            
            -
            
            
            
            7
            
            
            
            7Amortization
                of Net Actuarial Loss
            
            
            14
            
            
            
            19
            
            
            
            3
            
            
            
            5**Net
                Periodic Benefit Cost**
            
            $
            12
            
            
            $
            17
            
            
            $
            21
            
            
            $
            24





**Other****Postretirement****Pension
                Plans**
            
            
            **Benefit
                Plans****2007**
            
            
            **2006**
            
            
            **2007**
            
            
            **2006****Six
                Months Ended June 30, 2007 and 2006**
            
            **(in
                millions)**Service
                Cost
            
            $
            47
            
            
            $
            48
            
            
            $
            21
            
            
            $
            20Interest
                Cost
            
            
            116
            
            
            
            114
            
            
            
            52
            
            
            
            50Expected
                Return on Plan Assets
            
            
            (167
            )
            
            
            (166
            )
            
            
            (52
            )
            
            
            (46
            )Amortization
                of Transition Obligation
            
            
            -
            
            
            
            -
            
            
            
            14
            
            
            
            14Amortization
                of Net Actuarial Loss
            
            
            29
            
            
            
            39
            
            
            
            6
            
            
            
            10**Net
                Periodic Benefit Cost**
            
            $
            25
            
            
            $
            35
            
            
            $
            41
            
            
            $
            48





**7.**
            **BUSINESS
                SEGMENTS**





As
      outlined in our 2006 Annual Report, our primary business strategy and the core
      of our business focus on our electric utility operations.  Within our
      Utility Operations segment, we centrally dispatch all generation assets and
      manage our overall utility operations on an integrated basis because of the
      substantial impact of cost-based rates and regulatory
      oversight.  Generation/supply in Ohio continues to have
      commission-determined transition rates.





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.





**MEMCO
      Operations**


·
            Barging
                operations that annually transport approximately 34 million tons
                of coal
                and dry bulk commodities primarily on the Ohio, Illinois and lower
                Mississippi rivers.  Approximately 35% of the barging operations
                relates to the transportation of coal, 30% relates to agricultural
                products, 18% relates to steel and 17% relates to other
                commodities.





**Generation
      and Marketing**


·
            IPPs,
                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, interest income and interest
                expense and other nonallocated costs.·
            Other
                energy supply related businesses, including the Plaquemine Cogeneration
                Facility, which was sold in the fourth quarter of
                2006.





The
      tables below present our reportable segment information for the three and six
      months ended June 30, 2007 and 2006 and balance sheet information as of June
      30,
      2007 and December 31, 2006.  These amounts include certain estimates
      and allocations where necessary. We reclassified prior year amounts to conform
      to the current year’s segment presentation.


**Nonutility
                Operations****Utility
                Operations**
            
            
            **MEMCO**
              **Operations**
            
            
            **Generation**
              **and**
              **Marketing**
            
            
            **All
                Other (a)**
            
            
            **Reconciling
                Adjustments**
            
            
            **Consolidated****(in
                millions)****Three
                Months Ended June 30, 2007**Revenues
                from:External
                Customers
            
            $
            2,818
            
            
            $
            116
            
            
            $
            218
            
            
            $
            (6
            )
            
            $
            -
            
            
            $
            3,146Other
                Operating Segments
            
            
            136
            
            
            
            3
            
            
            
            (113
            )
            
            
            12
            
            
            
            (38
            )
            
            
            -**Total
                Revenues**
            
            $
            2,954
            
            
            $
            119
            
            
            $
            105
            
            
            $
            6
            
            
            $
            (38
            )
            
            $
            3,146Income
                (Loss) Before Discontinued
              Operations
                and Extraordinary Loss
            
            $
            238
            
            
            $
            7
            
            
            $
            15
            
            
            $
            (3
            )
            
            $
            -
            
            
            $
            257Discontinued
                Operations, Net of Tax
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            2
            
            
            
            -
            
            
            
            2Extraordinary
                Loss, Net of Tax
            
            
            (79
            )
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            (79
            )**Net
                Income (Loss)**
            
            $
            159
            
            
            $
            7
            
            
            $
            15
            
            
            $
            (1
            )
            
            $
            -
            
            
            $
            180





**Nonutility
                Operations****Utility
                Operations**
            
            
            **MEMCO**
              **Operations**
            
            
            **Generation**
              **and**
              **Marketing**
            
            
            **All
                Other (a)**
            
            
            **Reconciling
                Adjustments**
            
            
            **Consolidated****(in
                millions)****Three
                Months Ended June 30, 2006**Revenues
                from:External
                Customers
            
            $
            2,799
            
            
            $
            117
            
            
            $
            20
            
            
            $
            -
            
            
            $
            -
            
            
            $
            2,936Other
                Operating Segments
            
            
            (3
            )
            
            
            2
            
            
            
            -
            
            
            
            15
            
            
            
            (14
            )
            
            
            -**Total
                Revenues**
            
            $
            2,796
            
            
            $
            119
            
            
            $
            20
            
            
            $
            15
            
            
            $
            (14
            )
            
            $
            2,936Income
                (Loss) Before Discontinued
              Operations
            
            $
            159
            
            
            $
            14
            
            
            $
            2
            
            
            $
            (3
            )
            
            $
            -
            
            
            $
            172Discontinued
                Operations, Net of Tax
            
            ****
            **-**
            
            
            
            -
            
            
            
            -
            
            
            
            3
            
            
            
            -
            
            
            
            3**Net
                Income**
            
            $
            159
            
            
            $
            14
            
            
            $
            2
            
            
            $
            -
            
            
            $
            -
            
            
            $
            175





**Nonutility
                Operations****Utility
                Operations**
            
            
            **MEMCO**
              **Operations**
            
            
            **Generation**
              **and**
              **Marketing**
            
            
            **All
                Other (a)**
            
            
            **Reconciling
                Adjustments**
            
            
            **Consolidated****(in
                millions)****Six
                Months Ended June 30, 2007**Revenues
                from:External
                Customers
            
            $
            5,704
            
            
            $
            233
            
            
            $
            333
            
            
            $
            45
            
            
            $
            -
            
            
            $
            6,315Other
                Operating Segments
            
            
            283
            
            
            
            6
            
            
            
            (186
            )
            
            
            (33
            )
            
            
            (70
            )
            
            
            -**Total
                Revenues**
            
            $
            5,987
            
            
            $
            239
            
            
            $
            147
            
            
            $
            12
            
            
            $
            (70
            )
            
            $
            6,315Income
                Before Discontinued
              Operations
                and Extraordinary Loss
            
            $
            491
            
            
            $
            22
            
            
            $
            14
            
            
            $
            1
            
            
            $
            -
            
            
            $
            528Discontinued
                Operations, Net of Tax
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            2
            
            
            
            -
            
            
            
            2Extraordinary
                Loss, Net of Tax
            
            
            (79
            )
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            (79
            )**Net
                Income**
            
            $
            412
            
            
            $
            22
            
            
            $
            14
            
            
            $
            3
            
            
            $
            -
            
            
            $
            451





**Nonutility
                Operations****Utility
                Operations**
            
            
            **MEMCO**
              **Operations**
            
            
            **Generation**
              **and**
              **Marketing**
            
            
            **All
                Other (a)**
            
            
            **Reconciling
                Adjustments**
            
            
            **Consolidated****(in
                millions)****Six
                Months Ended June 30, 2006**Revenues
                from:External
                Customers
            
            $
            5,781
            
            
            $
            233
            
            
            $
            33
            
            
            $
            (3
            )
            
            $
            -
            
            
            $
            6,044Other
                Operating Segments
            
            
            (19
            )
            
            
            5
            
            
            
            -
            
            
            
            37
            
            
            
            (23
            )
            
            
            -**Total
                Revenues**
            
            $
            5,762
            
            
            $
            238
            
            
            $
            33
            
            
            $
            34
            
            
            $
            (23
            )
            
            $
            6,044Income
                (Loss) Before Discontinued
              Operations
            
            $
            524
            
            
            $
            35
            
            
            $
            6
            
            
            $
            (15
            )
            
            $
            -
            
            
            $
            550Discontinued
                Operations, Net of Tax
            
            ****
            **-**
            
            
            
            -
            
            
            
            -
            
            
            
            6
            
            
            
            -
            
            
            
            6**Net
                Income (Loss)**
            
            $
            524
            
            
            $
            35
            
            
            $
            6
            
            
            $
            (9
            )
            
            $
            -
            
            
            $
            556





**Nonutility
                Operations****Utility
                Operations**
            
            
            **MEMCO**
              **Operations**
            
            
            **Generation**
              **and**
              **Marketing**
            
            
            **All
                Other (a)**
            
            
            **Reconciling
                Adjustments**
            
            
            **Consolidated****June
                30, 2007**
            
            **(in
                millions)**Total
                Property, Plant and Equipment
            
            $
            43,794
            
            
            $
            241
            
            
            $
            566
            
            
            $
            36
            
            
            $
            (237
            )(b)
            
            $
            44,400Accumulated
                Depreciation and
              Amortization
            
            
            15,781
            
            
            
            55
            
            
            
            97
            
            
            
            6
            
            
            
            (6
            )(b)
            
            
            15,933**Total
                Property, Plant and Equipment –**
              **Net**
            
            $
            28,013
            
            
            $
            186
            
            
            $
            469
            
            
            $
            30
            
            
            $
            (231
            )(b)
            
            $
            28,467Total
                Assets
            
            $
            38,109
            
            
            $
            307
            
            
            $
            752
            
            
            $
            11,901
            
            
            $
            (11,875
            )(c)
            
            $
            39,193





**Nonutility
                Operations****Utility
                Operations**
            
            
            **MEMCO**
              **Operations**
            
            
            **Generation**
              **and**
              **Marketing**
            
            
            **All
                Other (a)**
            
            
            **Reconciling
                Adjustments**
            
            
            **Consolidated****December
                31, 2006**
            
            **(in
                millions)**Total
                Property, Plant and Equipment
            
            $
            41,420
            
            
            $
            239
            
            
            $
            327
            
            
            $
            35
            
            
            $
            -
            
            
            $
            42,021Accumulated
                Depreciation and
              Amortization
            
            
            15,101
            
            
            
            51
            
            
            
            83
            
            
            
            5
            
            
            
            -
            
            
            
            15,240**Total
                Property, Plant and Equipment –   Net**
            
            $
            26,319
            
            
            $
            188
            
            
            $
            244
            
            
            $
            30
            
            
            $
            -
            
            
            $
            26,781Total
                Assets
            
            $
            36,632
            
            
            $
            315
            
            
            $
            342
            
            
            $
            11,460
            
            
            $
            (10,762
            )(c)
            
            $
            37,987Assets
                Held for Sale
            
            
            44
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            44





(a)
            All
                Other includes:·
            Parent’s
                guarantee revenue received from affiliates, interest income and interest
                expense and other nonallocated costs.·
            Other
                energy supply related businesses, including the Plaquemine Cogeneration
                Facility, which was sold in the fourth quarter of 2006.(b)
            Reconciling
                Adjustments for Total Property, Plant and Equipment and Accumulated
                Depreciation and Amortization as of June 30, 2007 represent the
                elimination of an intercompany capital lease that began during the
                first
                quarter of 2007.(c)
            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.





**8.     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 expense.  The tax benefit of the parent is allocated to
      our subsidiaries with taxable income.  With the exception of the loss
      of the parent company, the method of allocation approximates a separate return
      result for each company in the consolidated group.




***Audit
      Status***





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





We
      have
      settled with the IRS on all issues from the audits of our consolidated federal
      income tax returns for years prior to 1997.  We have effectively
      settled all outstanding proposed IRS adjustments for years 1997 through 1999
      and
      through June 2000 for the CSW pre-merger tax period and anticipate payment
      for
      the agreed adjustments to occur during 2007.  Returns for the years
      2000 through 2005 are presently being audited by the IRS and we anticipate
      that
      the audit of the 2000 through 2003 years will be completed by the end of
      2007.





The
      IRS
      has proposed certain adjustments to our foreign tax credit and interest
      allocation positions.  Management has evaluated the proposed
      adjustments and has agreed to pay the related taxes.  Management does
      not anticipate that the adjustments will result in a material change to our
      financial position.





***FIN
      48 Adoption***





We
      adopted the provisions of FIN 48 on January 1, 2007.  As a result of
      the implementation of FIN 48, we recognized a $17 million increase in the
      liabilities for unrecognized tax benefits, as well as related interest expense
      and penalties, which was accounted for as a reduction to the January 1, 2007
      balance of retained earnings.





At
      January 1, 2007, the total amount of unrecognized tax benefits under FIN 48
      was
      $175 million.  We believe it is reasonably possible that there will be
      a $46 million net decrease in unrecognized tax benefits due to the settlement
      of
      audits and the expiration of statute of limitations within 12 months of the
      reporting date.  The total amount of unrecognized tax benefits that,
      if recognized, would affect the effective tax rate is $73
      million.  There are $66 million of tax positions for which the
      ultimate deductibility is highly certain but the timing of such deductibility
      is
      uncertain.  Because of the impact of deferred tax accounting, other
      than interest and penalties, the disallowance of the shorter deductibility
      period would not affect the annual effective tax rate but would accelerate
      the
      payment of cash to the taxing authority to an earlier period.





Prior
      to
      the adoption of FIN 48, we recorded interest and penalty accruals related to
      income tax positions in tax accrual accounts.  With the adoption of
      FIN 48, we began recognizing interest accruals related to income tax positions
      in interest income or expense as applicable, and penalties in Other Operation
      and Maintenance.  As of January 1, 2007, we accrued $25 million for
      the payment of uncertain interest and penalties.





***Michigan
      Tax Restructuring***





On
      July
      12, 2007, the Governor of Michigan signed Michigan Senate Bill 0094 (MBT Act)
      and related companion bills into law providing a comprehensive restructuring
      of
      Michigan’s principal business tax.  The new law is effective January
      1, 2008 and replaces the Michigan Single Business Tax that is scheduled to
      expire at the end of 2007.  The MBT Act is composed of a new tax which
      will be calculated based upon two components:  a business income tax
      imposed at a rate of 4.95% and a modified gross receipts tax imposed at a rate
      of 0.80%, which will collectively be referred to as the BIT/GRT tax
      calculation.  The new law also includes significant credits for
      engaging in Michigan-based activity.





We
      are in
      the process of evaluating the impact of the MBT Act.  It is expected
      that the application of the MBT Act will not have a material effect on our
      results of operation, cash flows or financial condition.




**9.**
            **FINANCING
                ACTIVITIES**





***Long-term
      Debt***


**June
                30,**
            
            
            **December
                31,****2007**
            
            
            **2006****Type
                of Debt**
            
            **(in
                millions)**Senior
                Unsecured Notes
            
            $
            9,399
            
            
            $
            8,653Pollution
                Control Bonds
            
            
            2,153
            
            
            
            1,950First
                Mortgage Bonds
            
            
            90
            
            
            
            90Defeased
                First Mortgage Bonds (a)
            
            
            19
            
            
            
            27Notes
                Payable
            
            
            312
            
            
            
            337Securitization
                Bonds
            
            
            2,303
            
            
            
            2,335Notes
                Payable To Trust
            
            
            113
            
            
            
            113Spent
                Nuclear Fuel Obligation (b)
            
            
            253
            
            
            
            247Other
                Long-term Debt
            
            
            3
            
            
            
            2Unamortized
                Discount (net)
            
            
            (57
            )
            
            
            (56
            )**Total
                Long-term Debt Outstanding**
            
            
            14,588
            
            
            
            13,698**Less
                Portion Due Within One Year**
            
            
            1,521
            
            
            
            1,269**Long-term
                Portion**
            
            $
            13,067
            
            
            $
            12,429





(a)
            In
                May 2004, cash and treasury securities were deposited with a trustee
                to
                defease all of TCC’s outstanding First Mortgage Bonds.  The
                defeased TCC First Mortgage Bonds had a balance of $19 million at
                both
                June 30, 2007 and December 31, 2006.  Trust Fund Assets related
                to this obligation of $23 million and $2 million at June 30, 2007
                and
                December 31, 2006, respectively, are included in Other Temporary
                Investments and $21 million at December 31, 2006, is included in
                Other
                Noncurrent Assets on our Condensed Consolidated Balance
                Sheets.  In December 2005, cash and treasury securities were
                deposited with a trustee to defease the remaining TNC outstanding
                First
                Mortgage Bond.  The defeased TNC First Mortgage Bond was retired
                in June 2007.  The defeased TNC First Mortgage Bond had a
                balance of $8 million at  December 31, 2006.  Trust
                fund assets related to this obligation of $9 million at December
                31, 2006,
                are included in Other Temporary Investments on our Condensed Consolidated
                Balance Sheet.  Trust fund assets are restricted for exclusive
                use in funding the interest and principal due on the First Mortgage
                Bonds.(b)
            Pursuant
                to the Nuclear Waste Policy Act of 1982, I&M (a nuclear licensee) has
                an obligation with the United States Department of Energy for spent
                nuclear fuel disposal.  The obligation includes a one-time fee
                for nuclear fuel consumed prior to April 7, 1983.  Trust Fund
                assets related to this obligation of $277 million and $274 million
                at June
                30, 2007 and December 31, 2006, 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 six months of 2007 are shown in the tables below.




**Company**
            
            **Type
                of Debt**
            
            **Principal
                Amount**
            
            **Interest
                Rate**
            
            **Due
                Date****(in
                millions)**
            
            **(%)****Issuances:**APCo
            
            Pollution
                Control Bonds
            
            $
            75
            
            Variable
            
            2037OPCo
            
            Pollution
                Control Bonds
            
            
            65
            
            4.90
            
            2037OPCo
            
            Senior
                Unsecured Notes
            
            
            400
            
            Variable
            
            2010PSO
            
            Pollution
                Control Bonds
            
            
            13
            
            4.45
            
            2020SWEPCo
            
            Senior
                Unsecured Notes
            
            
            250
            
            5.55
            
            2017*Non-Registrant:*AEGCo
            
            Senior
                Unsecured Notes
            
            
            220
            
            6.33
            
            2037TCC
            
            Pollution
                Control Bonds
            
            
            6
            
            4.45
            
            2020TNC
            
            Pollution
                Control Bonds
            
            
            44
            
            4.45
            
            2020**Total
                Issuances**
            
            
            
            $
            1,073
            (a)





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





(a)
            Amount
                indicated on statement of cash flows of $1,064 million is net of
                issuance
                costs and unamortized premium or
                discount.





In
      May
      2007, I&M remarketed its outstanding $50 million pollution control bonds,
      resulting in a new interest rate of 4.625%.  No proceeds were received
      related to this remarketing.  The principal amount of the pollution
      control bonds is reflected in Long-term Debt on our Condensed Consolidated
      Balance Sheet as of June 30, 2007.





**Company**
            
            **Type
                of Debt**
            
            **Principal**
              **Amount
                Paid**
            
            **Interest
                Rate**
            
            **Due
                Date****(in
                millions)**
            
            **(%)****Retirements
                and  Principal****Payments:**APCo
            
            Senior
                Unsecured Notes
            
            $
            125
            
            Variable
            
            2007OPCo
            
            Notes
                Payable
            
            
            3
            
            6.81
            
            2008OPCo
            
            Notes
                Payable
            
            
            6
            
            6.27
            
            2009SWEPCo
            
            Notes
                Payable
            
            
            3
            
            4.47
            
            2011SWEPCo
            
            Notes
                Payable
            
            
            4
            
            6.36
            
            2007SWEPCo
            
            Notes
                Payable
            
            
            2
            
            Variable
            
            2008*Non-Registrant:*AEP
                Subsidiaries
            
            Notes
                Payable
            
            
            3
            
            Variable
            
            2017CSW
                Energy, Inc.
            
            Notes
                Payable
            
            
            4
            
            5.88
            
            2011TCC
            
            Securitization
                Bonds
            
            
            32
            
            5.01
            
            2008TNC
            
            Defeased
                First Mortgage Bonds
            
            
            8
            
            7.75
            
            2007**Total
                Retirements and**
              **Principal
                Payments**
            
            
            $
            190





In
      July
      2007, KPCo retired $125 million of 5.50% Senior Unsecured Notes due in
      2007.





In
      July
      2007, PSO redeemed $13 million of 6.00% Pollution Control Bonds due in
      2020.





In
      July
      2007, TCC redeemed $6 million of 6.00% Pollution Control Bonds due in
      2020.





In
      July
      2007, TNC redeemed $44 million of 6.00% Pollution Control Bonds due in
      2020.





***Short-term
      Debt***





Short-term
      debt is used to fund our corporate borrowing program and fund other short-term
      cash needs.  Our outstanding short-term debt was as
      follows:


**June
                30, 2007**
            
            
            
            **December
                31, 2006****Outstanding**
              **Amount**
            
            
            **Interest**
              **Rate**
            
            
            
            **Outstanding**
              **Amount**
            
            
            **Interest**
              **Rate****Type
                of Debt**
            
            **(in
                millions)**
            
            
            
            
            
            
            **(in
                millions)**Commercial
                Paper – AEP
            
            $
            416
            
            
            
            5.40
            %
            (a)
            
            $
            -
            
            
            
            -Commercial
                Paper – JMG (b)
            
            
            -
            
            
            
            -
            
            
            
            
            1
            
            
            
            5.56
            %Line
                of Credit – Sabine (c)
            
            
            22
            
            
            
            6.20
            %
            
            
            
            17
            
            
            
            6.38
            %**Total**
            
            $
            438
            
            
            
            
            
            
            
            $
            18





(a)
            Weighted
                average rate.(b)
            This
                commercial paper is specifically associated with the Gavin Scrubber
                and is
                backed by a separate credit facility.  This commercial paper
                does not reduce available liquidity under AEP’s credit
                facilities.(c)
            Sabine
                is consolidated under FIN 46.  This line of credit does not
                reduce available liquidity under AEP’s credit
                facilities.




***Credit
      Facilities***





In
      March
      2007, we amended the terms of our credit facilities.  The amended
      facilities are structured as two $1.5 billion credit facilities, with an option
      in each to issue up to $300 million as letters of credit, expiring separately
      in
      March 2011 and April 2012.





***Dividend
      Restrictions***





Under
      the
      Federal Power Act, AEP’s public utility subsidiaries are restricted from paying
      dividends out of stated capital.





***Sale
      of Receivables – AEP Credit***





In
      July
      2007, we extended AEP Credit’s sale of receivables agreement.  The
      sale of receivables agreement provides commitments of $600 million from a bank
      conduit to purchase receivables from AEP Credit.  This agreement will
      expire in November 2007.  We intend to renew or replace this
      agreement.









**APPALACHIAN
        POWER COMPANY**
 **AND
        SUBSIDIARIES**
                
 
 **APPALACHIAN
        POWER COMPANY AND SUBSIDIARIES**
 **MANAGEMENT’S
        FINANCIAL DISCUSSION AND ANALYSIS**
 
 **Results
        of Operations**
 
 Second
        Quarter of 2007 Compared to Second Quarter of 2006
 
 **Reconciliation
        of Second Quarter of 2006 to Second Quarter of 2007**
 **Net
        Income Before Extraordinary Loss**
 **(in
        millions)**
 
 **Second
                  Quarter of 2006**
              
              
              
              
              $
              10**Changes
                  in Gross Margin:**Retail
                  Margins
              
              
              (39
              )Off-system
                  Sales
              
              
              18Transmission
                  Revenues
              
              
              7Other
              
              
              3**Total
                  Change in Gross Margin**
              
              
              
              
              
              
              (11
              )**Changes
                  in Operating Expenses and Other:**Other
                  Operation and Maintenance
              
              
              (3
              )Depreciation
                  and Amortization
              
              
              17Carrying
                  Costs Income
              
              
              3Other
                  Income, Net
              
              
              (5
              )Interest
                  Expense
              
              
              (13
              )**Total
                  Change in Operating Expenses and Other**
              
              
              
              
              
              
              (1
              )Income
                  Tax Expense
              
              
              
              
              
              
              5**Second Quarter of 2007**
              
              
              
              
              
              $
              3
 
 Net
        Income Before Extraordinary Loss decreased $7 million to $3
        million.  The key drivers of the decrease were an $11 million decrease
        in Gross Margin, partially offset by a $5 million decrease in Income Tax
        Expense.
 
 The
        major
        components of the change 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 $39 million in comparison to 2006 primarily due
                  to:·
              A
                  $38 million decrease in retail revenues primarily related to APCo’s
                  Virginia base rate case which includes a second quarter 2007 provision
                  for
                  revenue refund as a result of the final order offset by the new
                  rates
                  implemented.  See “Virginia Base Rate Case” section of Note
                  3.·
              A
                  $24 million increase in capacity settlement expenses under the
                  Interconnection Agreement reflecting APCo’s new peak demand in February
                  2007.·
              A
                  $12 million decrease in revenues related to financial transmission
                  rights,
                  net of congestion, primarily due to fewer transmission constraints
                  in the
                  PJM market.These
                  decreases were partially offset by:·
              A
                  $16 million increase in revenues related to the Expanded Net Energy
                  Cost
                  (ENEC) mechanism with West Virginia retail
                  customers.  The mechanism was reinstated in West Virginia
                  effective July 1, 2006 in conjunction with the West Virginia rate
                  case.·
              An
                  $18 million increase in retail sales primarily due to increased
                  demand in
                  the residential class associated with favorable weather
                  conditions.  Cooling degree days increased approximately
                  54%.·
              Margins
                  from Off-system Sales increased $18 million primarily due to higher
                  power
                  prices in the east, higher trading margins, and an increase in
                  APCo’s
                  allocated share of off-system sales revenues due to its new peak.·
              Transmission
                  Revenues increased $7 million primarily due to a provision recorded
                  in the
                  second quarter of 2006 related to potential SECA refunds.  See
                  “Transmission Rate Proceedings at the FERC” section of Note
                  3.
 
 Operating
        Expenses and Other changed between years as follows:
 
 ·
              Other
                  Operation and Maintenance expenses increased $3 million primarily
                  due to
                  the following:·
              A
                  $4 million increase in steam maintenance expenses resulting from
                  2007
                  planned outages at the Amos and Glen Lyn plants.·
              A
                  $3 million increase in customer accounts and services expense primarily
                  related to an increase in uncollectible accounts under a contract
                  dispute.These
                  increases were offset by:·
              A
                  $5 million decrease in expenses related to the AEP Transmission
                  Equalization Agreement due to the addition of the Wyoming-Jacksons
                  Ferry
                  765 kV line which was energized and placed into service in June
                  2006.·
              Depreciation
                  and Amortization expenses decreased $17 million primarily due to
                  lower
                  Virginia depreciation rates implemented retroactively to January
                  2006 for
                  $15 million and lower amortization resulting from a net deferral
                  of $9
                  million in ARO costs as ordered in APCo’s Virginia base rate
                  case.  These decreases were partially offset by the amortization
                  of carrying charges and depreciation expense of $3 million that
                  are being
                  collected through the E&R surcharge mechanism. In addition, an
                  increase in depreciation expense was also related to the Wyoming-Jacksons
                  Ferry 765 kV line, which was energized and placed in service in
                  June 2006,
                  and the Mountaineer scrubber, which was placed in service in February
                  2007.·
              Carrying
                  Costs Income increased $3 million related to carrying costs associated
                  with the E&R case.·
              Other
                  Income, Net decreased $5 million primarily due to a $2 million
                  decrease in
                  interest income from the Utility Money Pool and a $2 million decrease
                  in
                  AFUDC resulting from a lower construction work in progress (CWIP)
                  balance
                  after the Wyoming-Jacksons Ferry 765 kv line and the Mountaineer
                  scrubber
                  were placed into service.·
              Interest
                  Expense increased $13 million primarily due to a $6 million decrease
                  in
                  allowance for borrowed funds used for construction, a $3 million
                  increase
                  in interest expense from the Utility Money Pool, and a $3 million
                  increase
                  in the interest on the Virginia provision for
                  refund.
 
 *Income
        Taxes*
 
 Income
        Tax Expense decreased $5 million primarily due to a decrease in pretax book
        income.
 
 Six
        Months Ended June 30, 2007 Compared to Six Months Ended June 30,
        2006
 
 **Reconciliation
        of Six Months Ended June 30, 2006 to Six Months Ended June 30,
        2007**
 **Net
        Income Before Extraordinary Loss**
 **(in
        millions)**
 **Six
                  Months Ended June 30, 2006**
              
              
              
              
              $
              83**Changes
                  in Gross Margin:**Retail
                  Margins
              
              
              (10
              )Off-system
                  Sales
              
              
              12Transmission
                  Revenues
              
              
              (4
              )Other
              
              
              4**Total
                  Change in Gross Margin**
              
              
              
              
              
              
              2**Changes
                  in Operating Expenses and Other:**Other
                  Operation and Maintenance
              
              
              (8
              )Depreciation
                  and Amortization
              
              
              7Taxes
                  Other Than Income Taxes
              
              
              2Other
                  Income, Net
              
              
              (5
              )Interest
                  Expense
              
              
              (15
              )**Total
                  Change in Operating Expenses and Other**
              
              
              
              
              
              
              (19
              )Income
                  Tax Expense
              
              
              
              
              
              
              8**Six Months Ended June 30, 2007**
              
              
              
              
              
              $
              74
 
 Net
        Income Before Extraordinary Loss decreased $9 million to $74 million in
        2007.  The key drivers of the decrease were a $19 million increase in
        Operating Expenses and Other, partially offset by an $8 million decrease
        in
        Income Tax Expense.
 
 The
        major
        components of the change 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 $10 million in comparison to 2006 primarily due
                  to:·
              A
                  $26 million decrease in revenues related to financial transmission
                  rights,
                  net of congestion, primarily due to fewer transmission constraints
                  in the
                  PJM market.·
              A
                  $26 million increase in capacity settlement expenses under the
                  Interconnection Agreement reflecting APCo’s new peak demand in February
                  2007.These
                  decreases were partially offset by:·
              A
                  $7 million increase in revenues related to the ENEC mechanism with
                  West
                  Virginia retail customers.  The mechanism was reinstated in
                  West Virginia effective July 1, 2006 in conjunction with the West
                  Virginia
                  rate case.·
              A
                  $27 million increase in retail sales primarily due to increased
                  demand in
                  the residential class associated with favorable weather
                  conditions.  Heating degree days increased approximately 27% and
                  Cooling degree days increased approximately 62%.·
              A
                  $9 million increase in municipal and cooperative revenues primarily
                  due to
                  the addition of the Blue Ridge Power Agency customers.·
              Margins
                  from Off-system Sales increased $12 million primarily due to higher
                  power
                  prices in the east, higher trading margins, an increase in APCo’s
                  allocated share of off-system sales revenues due to its new peak,
                  and a
                  change in the allocation of off-system sales margins under the
                  SIA
                  effective April 1, 2006.·
              Transmission
                  Revenues decreased $4 million primarily due to the elimination
                  of SECA
                  revenues of $13 million as of April 1, 2006.  See “Transmission
                  Rate Proceedings at the FERC” section of Note 3.  This decrease
                  was partially offset by a provision recorded in the second quarter
                  of 2006
                  related to potential SECA refunds and additional transmission revenues
                  relating to dedicated energy sales of $2 million.·
              Other
                  revenue increased $4 primarily due to the reversal of previously
                  deferred
                  gains on sales of allowances associated with the E&R
                  case.
 
 Operating
        Expenses and Other changed between years as follows:
 
 ·
              Other
                  Operation and Maintenance expenses increased $8 million primarily
                  due to
                  the following:·
              A
                  $4 million increase in steam maintenance expenses resulting from
                  2007
                  planned outages at the Amos and Glen Lyn plants.·
              A
                  $6 million increase in expenses for distribution line right-of-way
                  clearing.·
              A
                  $4 million increase in uncollectible and factored accounts receivable
                  expense.·
              An
                  $8 million increase in employee related and various other operational
                  expenses.These
                  increases were partially offset by:·
              A
                  $14 million decrease in expenses related to the AEP Transmission
                  Equalization Agreement due to the addition of the Wyoming-Jacksons
                  Ferry
                  765 kV line, which was energized and placed into service in June
                  2006.·
              Depreciation
                  and Amortization expenses decreased $7 million primarily due to
                  lower
                  Virginia depreciation rates implemented retroactively to January
                  2006 for
                  $15 million and lower amortization resulting from a net deferral
                  of $9
                  million in ARO costs as ordered in APCo’s Virginia base rate
                  case.  These decreases were partially offset by the amortization
                  of carrying charges and depreciation expense of $13 million that
                  are being
                  collected through the E&R surcharges.  In addition, an
                  increase in depreciation expense was also related to the Wyoming-Jacksons
                  Ferry 765 kV line, which was energized and placed in service in
                  June 2006,
                  and the Mountaineer scrubber, which was placed in service in February
                  2007.·
              Other
                  Income, Net decreased $5 million primarily due to lower interest
                  income
                  from the Utility Money Pool of $2 million and a $2 million decrease
                  in
                  AFUDC resulting from a lower CWIP balance after the Wyoming-Jacksons
                  Ferry
                  765 kV line and the Mountaineer scrubber were placed into
                  service.·
              Interest
                  Expense increased $15 million primarily due to an $8 million increase
                  related to the issuance of $500 million of debt in April 2006 and
                  a $4
                  million decrease in allowance for borrowed funds used during
                  construction.
 
 *Income
        Taxes*
 
 Income
        Tax Expense decreased $8 million primarily due to a decrease in pretax book
        income.
 
 **Financial
        Condition**
 
 **Credit
        Ratings**
 
 The
        rating agencies currently have APCo on stable outlook.  Current
        ratings are as follows:
 
 **Moody’s**
              
              **S&P**
              
              **Fitch**Senior
                  Unsecured Debt
              Baa2
              
              BBB
              
              BBB+
 
 **Cash
        Flow**
 
 Cash
        flows for the six months ended June 30, 2007 and 2006 were as
        follows:
 
 **2007**
              
              
              **2006****(in
                  thousands)****Cash
                  and Cash Equivalents at Beginning of Period**
              
              $
              2,318
              
              
              $
              1,741Cash
                  Flows From (Used For):Operating
                  Activities
              
              
              265,414
              
              
              
              316,970Investing
                  Activities
              
              
              (378,985
              )
              
              
              (618,920
              )Financing
                  Activities
              
              
              112,605
              
              
              
              301,555Net
                  Decrease in Cash and Cash Equivalents
              
              
              (966
              )
              
              
              (395
              )**Cash
                  and Cash Equivalents at End of Period**
              
              $
              1,352
              
              
              $
              1,346
 
 *Operating
        Activities*
 
 Net
        Cash
        Flows From Operating Activities were $265 million in 2007.  APCo
        incurred a Net Loss of $5 million during the period and had noncash expense
        items of $90 million for Depreciation and Amortization and $79 million for
        Extraordinary Loss for the Reapplication of Regulatory Accounting for Generation
        and $105 million for Regulatory Provision related to the Virginia base rate
        case.  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 included no significant items.
 
 Net
        Cash
        Flows From Operating Activities were $317 million in 2006.  APCo
        produced Net Income of $83 million during the period and a noncash expense
        item
        of $97 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
        included two significant items.  Accounts Receivable, Net decreased
        $60 million primarily due to the collection of receivables related to power
        sales to affiliates, settled litigation and sales on emission
        allowances.  Accrued Taxes, Net increased $42 million related to the
        lack of federal income tax payments made in 2006.
 
 *Investing
        Activities*
 
 Net
        Cash
        Flows Used For Investing Activities during 2007 and 2006 primarily reflect
        construction expenditures of $383 million and $404 million,
        respectively.  Construction expenditures are primarily for projects to
        improve service reliability for transmission and distribution, as well as
        environmental upgrades at power plants for both periods.  In 2006,
        capital projects for transmission expenditures were primarily related to
        the
        Wyoming-Jacksons Ferry 765 KV line placed into service in June
        2006.  Environmental upgrades include the installation of selective
        catalytic reduction equipment on certain plants and the flue gas desulfurization
        project at the Amos and Mountaineer plants.  In February 2007,
        environmental upgrades were completed for the Mountaineer plant.  For
        the remainder of 2007, APCo expects construction expenditures to be
        approximately $281 million.  In addition, APCo’s investments in the
        Utility Money Pool increased by $219 million in 2006.
 
 *Financing
        Activities*
 
 Net
        Cash
        Flows From Financing Activities in 2007 were $113 million primarily due to
        an
        increase of $213 million in borrowings from the Utility Money Pool and the
        issuance of $75 million of Pollution Control Bonds.  These increases
        were partially offset by the retirement of $125 million of Senior Notes and
        payment of $25 million in dividends on common stock.
 
 Net
        Cash
        Flows From Financing Activities were $302 million in 2006.  In 2006,
        APCo issued $500 million in Senior Notes and issued $50 million in Pollution
        Control Bonds.  APCo also retired First Mortgage Bonds of $100 million
        and repaid short-term borrowings from the Utility Money Pool of $194
        million.  In addition, APCo received funds of $68 million related to a
        long-term coal purchase contract amended in March 2006.
 
 **Financing
        Activity**
 
 Long-term
        debt issuances and retirements during the first six months of 2007
        were:
 
 Issuances
 **Principal**
                **Amount**
              
              **Interest**
              
              **Due****Type
                  of Debt**
              
              
              **Rate**
              
              **Date****(in
                  thousands)**
              
              **(%)**Pollution
                  Control Bonds
              
              $
              75,000
              
              Variable
              
              2037
 
 Retirements
 **Principal**
                **Amount**
              
              **Interest**
              
              **Due****Type
                  of Debt**
              
              
              **Rate**
              
              **Date****(in
                  thousands)**
              
              **(%)**Senior
                  Unsecured Notes
              
              $
              125,000
              
              Variable
              
              2007
 
 **Liquidity**
 
 APCo
        has
        solid investment grade ratings, which provide ready access to capital markets
        in
        order to issue new debt or refinance long-term debt maturities.  In
        addition, APCo participates in the Utility Money Pool, which provides access
        to
        AEP’s liquidity.
 
 **Summary
        Obligation Information**
 
 A
        summary
        of contractual obligations is included in the 2006 Annual Report and has
        not
        changed significantly from year-end other than the debt issuance and retirement
        discussed in “Cash Flow” and “Financing Activity” above.
 
 **Significant
        Factors**
 
 ***New
        Generation***
 
 In
        January 2006, APCo filed a petition with the WVPSC requesting its approval
        of a
        Certificate of Public Convenience and Necessity (CCN) to construct a 629
        MW IGCC
        plant adjacent to APCo’s existing Mountaineer Generating Station in Mason
        County, WV.
 
 In
        June
        2007, APCo filed testimony with the WVPSC supporting the requests for a CCN
        and
        for pre-approval of a surcharge rate mechanism to provide for the timely
        recovery of both the ongoing finance costs of the project during the
        construction period as well as the capital costs, operating costs and a return
        of equity once the facility is placed into commercial operation.  If
        APCo receives all necessary approvals, the plant could be completed by mid-2012
        at the earliest and currently is expected to cost an estimated $2.2
        billion**.**In July 2007, the WVPSC staff and
        intervenors filed to delay the procedural schedule by 90 days.  APCo
        supported the changes to the procedural schedule.  The statutory
        decision deadline was revised to March 2008.  In July 2007, the WVPSC
        approved the revised procedural schedule.  Through June 30, 2007, APCo
        deferred pre-construction IGCC costs totaling $11 million.  If the
        plant is not built and these costs are not recoverable, future results of
        operations and cash flows would be adversely affected.
 
 In
        July
        2007, APCo filed a request with the Virginia SCC to recover over the twelve
        months beginning January 1, 2009 a return on projected construction work
        in
        progress including development, design and planning costs from July 1, 2007
        through December 31, 2009 estimated to be $45 million associated with the
        IGCC
        plant to be constructed in West Virginia.  APCo is requesting
        authorization to defer a return on actual pre-construction costs incurred
        beginning July 1, 2007 until such costs are recovered, starting January 1,
        2009
        as required by the new Virginia Re-regulation legislation.
 
 ***Virginia
        Restructuring***
 
 In
        April
        2004, Virginia enacted legislation that amended the Virginia Electric Utility
        Restructuring Act extending the transition period to market rates for the
        generation and supply of electricity, including the extension of capped rates,
        through December 31, 2010.  The legislation provided APCo with
        specified cost recovery opportunities during the extended capped rate period,
        including two optional bundled general base rate changes and an opportunity
        for
        timely recovery, through a separate rate mechanism, of certain unrecovered
        incremental environmental and reliability costs incurred on and after July
        1,
        2004.  Under the amended restructuring law, APCo continues to have an
        active fuel clause recovery mechanism in Virginia and continues to practice
        deferred fuel accounting.  Also, under the amended restructuring law,
        APCo has the right to defer incremental environmental compliance costs and
        incremental  E&R costs for future recovery, to the extent such costs
        are not being recovered, and amortizes a portion of such deferrals commensurate
        with their recovery.
 
 In
        April
        2007, the Virginia legislature adopted a comprehensive law providing for
        the
        re-regulation of electric utilities’ generation and supply
        rates.  These amendments shorten the transition period by two years
        (from 2010 to 2008) after which rates for retail generation and supply will
        return to a form of cost-based regulation in lieu of market-based
        rates.  The legislation provides for, among other things, biennial
        rate reviews beginning in 2009; rate adjustment clauses for the recovery
        of the
        costs of (a) transmission services and new transmission investments, (b)
        demand
        side management, load management, and energy efficiency programs, (c) renewable
        energy programs, and (d) environmental retrofit and new generation investments;
        significant return on equity enhancements for investments in new generation
        and,
        subject to Virginia SCC approval, certain environmental retrofits, and a
        floor
        on the allowed return on equity based on the average earned return on equities’
of regional vertically integrated electric utilities.  Effective July
        1, 2007, the amendments allow utilities to retain a minimum of 25% of the
        margins from off-system sales with the remaining margins from such sales
        credited against fuel factor expenses with a true-up to actual.  The
        legislation also allows APCo to continue to defer and recover incremental
        environmental and reliability costs incurred through December 31,
        2008.  The new re-regulation legislation should result in significant
        positive effects on APCo’s future earnings and cash flows from the mandated
        enhanced future returns on equity, the reduction of regulatory lag from the
        opportunities to adjust base rates on a biennial basis and the new opportunities
        to request timely recovery of certain new costs not included in base
        rates.
 
 With
        the
        new re-regulation legislation, APCo’s generation business again meets the
        criteria for application of regulatory accounting principles under SFAS
        71.  The extraordinary pretax reduction in APCo’s earnings and
        shareholder’s equity from reapplication of SFAS 71 regulatory accounting of $118
        million ($79 million, net of tax) was recorded in the second quarter of
        2007.  This extraordinary net loss primarily relates to the
        reestablishment of $139 million in net generation-related customer-provided
        removal costs as a regulatory liability offset by the restoration of $21
        million
        of deferred state income taxes as a regulatory asset.  In addition,
        APCo established a regulatory asset of $17 million for qualifying SFAS 158
        pension costs of the generation operations that for ratemaking purposes are
        deferred for future recovery under the new re-regulation
        legislation.  AOCI and Deferred Income Taxes increased by $11 million
        and $6 million, respectively.
 
 ***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 pending litigation and regulatory
        proceedings, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and
        Contingencies in the 2006 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 results of operations, 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 2006 Annual Report for a discussion
        of the estimates and judgments required for regulatory accounting, revenue
        recognition, the valuation of long-lived assets, pension and other
        postretirement benefits and the impact of new accounting
        pronouncements.
 
 **Adoption
        of New Accounting Pronouncements**
 
 See
        the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for a discussion of adoption of new accounting
        pronouncements.
   
 **QUANTITATIVE
        AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT
        ACTIVITIES**
 
 **Market
        Risks**
 
 Risk
        management assets and liabilities are managed by AEPSC as agent.  The
        related risk management policies and procedures are instituted and administered
        by AEPSC.  See complete discussion within AEP’s “Quantitative and
        Qualitative Disclosures About Risk Management Activities”
section.  The following tables provide information about AEP’s risk
        management activities’ effect on APCo.
 
 **MTM
        Risk Management Contract Net Assets**
 
 The
        following two tables summarize the various mark-to-market (MTM) positions
        included on the condensed consolidated balance sheet as of June 30, 2007
        and the
        reasons for changes in total MTM value as compared to December 31,
        2006.
  **Reconciliation
        of MTM Risk Management Contracts to**
 **Condensed
        Consolidated Balance Sheet**
 **As
        of June 30, 2007**
 **(in
        thousands)**
 
 **MTM
                  Risk Management Contracts**
              
              
              **Cash
                  Flow &**
                **Fair
                  Value Hedges**
              
              
              **DETM
                  Assignment (a)**
              
              
              **Total**Current
                  Assets
              
              $
              73,123
              
              
              $
              11,439
              
              
              $
              -
              
              
              $
              84,562Noncurrent
                  Assets
              
              
              84,029
              
              
              
              2,919
              
              
              
              -
              
              
              
              86,948**Total
                  MTM Derivative Contract Assets**
              
              
              157,152
              
              
              
              14,358
              
              
              
              -
              
              
              
              171,510Current
                  Liabilities
              
              
              (55,013
              )
              
              
              (1,137
              )
              
              
              (3,570
              )
              
              
              (59,720
              )Noncurrent
                  Liabilities
              
              
              (51,130
              )
              
              
              (87
              )
              
              
              (7,551
              )
              
              
              (58,768
              )**Total
                  MTM Derivative Contract Liabilities**
              
              
              (106,143
              )
              
              
              (1,224
              )
              
              
              (11,121
              )
              
              
              (118,488
              )**Total
                  MTM Derivative Contract Net Assets
                  (Liabilities)**
              
              $
              51,009
              
              
              $
              13,134
              
              
              $
              (11,121
              )
              
              $
              53,022
 
 (a)
              See
                  “Natural Gas Contracts with DETM” section of Note 16 of the 2006 Annual
                  Report.
 
 **MTM
        Risk Management Contract Net Assets**
 **Six
        Months Ended June 30, 2007**
 **(in
        thousands)**
 
 **Total
                  MTM Risk Management Contract Net Assets at December 31,
                  2006**
              
              $
              52,489(Gain)
                  Loss from Contracts Realized/Settled During the Period and Entered
                  in a
                  Prior Period
              
              
              (8,051
              )Fair
                  Value of New Contracts at Inception When Entered During the Period
                  (a)
              
              
              255Net
                  Option Premiums Paid/(Received) for Unexercised or Unexpired Option
                  Contracts Entered During the Period
              
              
              511Change
                  in Fair Value Due to Valuation Methodology Changes on Forward
                  Contracts
              
              
              -Changes
                  in Fair Value Due to Market Fluctuations During the Period
                  (b)
              
              
              4,757Changes
                  in Fair Value Allocated to Regulated Jurisdictions (c)
              
              
              1,048**Total
                  MTM Risk Management Contract Net Assets**
              
              
              51,009Net
                  Cash Flow & Fair Value Hedge Contracts
              
              
              13,134DETM
                  Assignment (d)
              
              
              (11,121
              )**Total
                  MTM Risk Management Contract Net Assets at June 30,
                  2007**
              
              $
              53,022
 
 (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.  Inception value is only recorded if observable market
                  data can be obtained for valuation inputs for the entire contract
                  term.  The contract prices are valued against market curves
                  associated with the delivery location and delivery
                  term.(b)
              Market
                  fluctuations are attributable to various factors such as supply/demand,
                  weather, storage, etc.(c)
              “Changes
                  in Fair Value Allocated to Regulated Jurisdictions” relates to the net
                  gains (losses) of those contracts that are not reflected in the
                  Condensed
                  Consolidated Statements of Income.  These net gains (losses) are
                  recorded as regulatory liabilities/assets for those subsidiaries
                  that
                  operate in regulated jurisdictions.(d)
              See
                  “Natural Gas Contracts with DETM” section of Note 16 of the 2006 Annual
                  Report.
 
 **Maturity
        and Source of Fair Value of MTM Risk Management Contract Net
        Assets**
 
 The
        following table presents:
 
 ·
              The
                  method of measuring fair value used in determining the carrying
                  amount of
                  total MTM asset or liability (external sources or modeled
                  internally).·
              The
                  maturity, by year, of net assets/liabilities to give an indication
                  of when
                  these MTM amounts will settle and generate
                  cash.
 
 **Maturity
        and Source of Fair Value of MTM**
 **Risk
        Management Contract Net Assets**
 **Fair
        Value of Contracts as of June 30, 2007**
 **(in
        thousands)**
 
 **Remainder
                  2007**
              
              **2008**
              
              **2009**
              
              **2010**
              
              **2011**
              
              **After**
                **2011**
              
              **Total**Prices
                  Actively Quoted – ExchangeTraded
                  Contracts
              
              $
              4,823
              
              $
              (3,624
              )
              $
              163
              
              $
              -
              
              $
              -
              
              $
              -
              
              $
              1,362Prices
                  Provided by Other ExternalSources
                  –
                OTC BrokerQuotes
                  (a)
              
              
              6,824
              
              
              16,070
              
              
              12,886
              
              
              5,714
              
              
              -
              
              
              -
              
              
              41,494Prices
                  Based on Models and OtherValuation
                  Methods (b)
              
              
              (401
              )
              
              (1,510
              )
              
              1,682
              
              
              5,485
              
              
              1,248
              
              
              1,649
              
              
              8,153**Total**
              
              $
              11,246
              
              $
              10,936
              
              $
              14,731
              
              $
              11,199
              
              $
              1,248
              
              $
              1,649
              
              $
              51,009
 
 (a)
              “Prices
                  Provided by Other External Sources – OTC Broker Quotes” reflects
                  information obtained from over-the-counter brokers, industry services,
                  or
                  multiple-party on-line platforms.(b)
              “Prices
                  Based on Models and Other Valuation Methods” is used in absence of
                  independent information from external sources.  Modeled
                  information is derived using valuation models developed by the
                  reporting
                  entity, reflecting when appropriate, option pricing theory, discounted
                  cash flow concepts, valuation adjustments, etc. and may require
                  projection
                  of prices for underlying commodities beyond the period that prices
                  are
                  available from third-party sources.  In addition, where external
                  pricing information or market liquidity are limited, such valuations
                  are
                  classified as modeled.  The determination of the point at which
                  a market is no longer liquid for placing it in the modeled category
                  varies
                  by market.  Contract values that are measured using models or
                  valuation methods other than active quotes or OTC broker quotes
                  (because
                  of the lack of such data for all delivery quantities, locations
                  and
                  periods) incorporate in the model or other valuation methods, to
                  the
                  extent possible, OTC broker quotes and active quotes for deliveries
                  in
                  years and at locations for which such quotes are available including
                  values determinable by other third party
                  transactions.
 
 **Cash
        Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI)
        on
        the Condensed Consolidated Balance Sheet**
 
 APCo
        is
        exposed to market fluctuations in energy commodity prices impacting its power
        operations.  Management monitors these risks on future operations and
        may use various commodity instruments designated in qualifying cash flow
        hedge
        strategies to mitigate the impact of these fluctuations on future cash
        flows.  Management does not hedge all commodity price
        risk.
 
 Management
        uses interest rate derivative transactions to manage interest rate risk related
        to anticipated borrowings of fixed-rate debt.  Management does not
        hedge all interest rate risk.
 
 Management
        uses forward contracts and collars as cash flow hedges to lock in prices
        on
        certain transactions denominated in foreign currencies where deemed
        necessary.  Management does not hedge all foreign currency
        exposure.
 
 The
        following table provides the detail on designated, effective cash flow hedges
        included in AOCI on the Condensed Consolidated Balance Sheets and the reasons
        for the changes from December 31, 2006 to June 30, 2007.  Only
        contracts designated as cash flow hedges are recorded in
        AOCI.  Therefore, economic hedge contracts that are not designated as
        effective cash flow hedges are marked-to-market and included in the previous
        risk management tables.  All amounts are presented net of related
        income taxes.
 
 **Total
        Accumulated Other Comprehensive Income (Loss) Activity**
 **Six
        Months Ended June 30, 2007**
 **(in
        thousands)**
 
 **Power**
              
              
              **Foreign**
                **Currency**
              
              
              **Interest**
                **Rate**
              
              
              **Total****Beginning
                  Balance in AOCI December 31, 2006**
              
              $
              5,332
              
              
              $
              (164
              )
              
              $
              (7,715
              )
              
              $
              (2,547
              )Changes
                  in Fair Value
              
              
              7,980
              
              
              
              -
              
              
              
              -
              
              
              
              7,980Reclassifications
                  from AOCI to Net Income for Cash Flow Hedges Settled
              
              
              (4,067
              )
              
              
              3
              
              
              
              694
              
              
              
              (3,370
              )**Ending
                  Balance in AOCI June 30, 2007**
              
              $
              9,245
              
              
              $
              (161
              )
              
              $
              (7,021
              )
              
              $
              2,063
 
 The
        portion of cash flow hedges in AOCI expected to be reclassified to earnings
        during the next twelve months is a $6,737 thousand gain.
 
 **Credit
        Risk**
 
 Counterparty
        credit quality and exposure is generally consistent with that of
        AEP.
 
 **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 June 30, 2007, a near term
        typical change in commodity prices is not expected to have a material effect
        on
        results of operations, cash flows or financial condition.
 
 The
        following table shows the end, high, average, and low market risk as measured by
        VaR for the periods indicated:
 
 **Six
                  Months Ended**
                **June
                  30, 2007**
              
              
              
              
              **Twelve
                  Months Ended**
                **December
                  31, 2006****(in
                  thousands)**
              
              
              
              
              **(in
                  thousands)****End**
              
              **High**
              
              **Average**
              
              **Low**
              
              
              
              
              **End**
              
              **High**
              
              **Average**
              
              **Low**$475
              
              $2,328
              
              $779
              
              $227
              
              
              
              
              $756
              
              $1,915
              
              $658
              
              $358
 
 The
        High
        VaR for the twelve months ended December 31, 2006 occurred in the third quarter
        due to volatility in the ECAR/PJM region.
 
 **VaR
        Associated with Debt Outstanding**
 
 Management
        utilizes a VaR model to measure interest rate market risk exposure. The interest
        rate VaR model is based on a Monte Carlo simulation with a 95% confidence
        level
        and a one-year holding period.  The risk of potential loss in fair
        value attributable to exposure to interest rates primarily related to long-term
        debt with fixed interest rates was $178 million and $153 million at June
        30,
        2007 and December 31, 2006, respectively. Management would not expect to
        liquidate the entire debt portfolio in a one-year holding period; therefore,
        a
        near term change in interest rates should not negatively affect results of
        operations or consolidated financial position.
   
 **APPALACHIAN
        POWER COMPANY AND SUBSIDIARIES**
 **CONDENSED
        CONSOLIDATED STATEMENTS OF OPERATIONS**
 **For
        the Three and Six Months Ended June 30, 2007 and 2006**
 **(in
        thousands)**
 **(Unaudited)**
 
 **Three
                  Months Ended**
              
              
              **Six
                  Months Ended****2007**
              
              
              **2006**
              
              
              **2007**
              
              
              **2006****REVENUES**Electric
                  Generation, Transmission and Distribution
              
              $
              499,189
              
              
              $
              464,058
              
              
              $
              1,100,735
              
              
              $
              1,024,051Sales
                  to AEP Affiliates
              
              
              55,371
              
              
              
              48,608
              
              
              
              116,916
              
              
              
              120,380Other
              
              
              2,850
              
              
              
              1,922
              
              
              
              5,487
              
              
              
              4,598**TOTAL**
              
              
              557,410
              
              
              
              514,588
              
              
              
              1,223,138
              
              
              
              1,149,029**EXPENSES**Fuel
                  and Other Consumables Used for Electric Generation
              
              
              164,018
              
              
              
              155,240
              
              
              
              335,204
              
              
              
              322,093Purchased
                  Electricity for Resale
              
              
              34,328
              
              
              
              29,979
              
              
              
              70,278
              
              
              
              57,595Purchased
                  Electricity from AEP Affiliates
              
              
              144,630
              
              
              
              103,457
              
              
              
              272,231
              
              
              
              225,856Other
                  Operation
              
              
              75,125
              
              
              
              77,156
              
              
              
              142,754
              
              
              
              147,057Maintenance
              
              
              51,414
              
              
              
              46,668
              
              
              
              97,167
              
              
              
              84,507Depreciation
                  and Amortization
              
              
              31,076
              
              
              
              48,688
              
              
              
              90,236
              
              
              
              96,956Taxes
                  Other Than Income Taxes
              
              
              22,975
              
              
              
              22,799
              
              
              
              44,250
              
              
              
              45,891**TOTAL**
              
              
              523,566
              
              
              
              483,987
              
              
              
              1,052,120
              
              
              
              979,955**OPERATING
                  INCOME**
              
              
              33,844
              
              
              
              30,601
              
              
              
              171,018
              
              
              
              169,074**Other
                  Income (Expense):**Interest
                  Income
              
              
              390
              
              
              
              2,814
              
              
              
              1,029
              
              
              
              3,765Carrying
                  Costs Income
              
              
              10,950
              
              
              
              7,773
              
              
              
              14,116
              
              
              
              13,784Allowance
                  for Equity Funds Used During Construction
              
              
              1,581
              
              
              
              4,083
              
              
              
              4,358
              
              
              
              6,559Interest
                  Expense
              
              
              (44,955
              )
              
              
              (31,653
              )
              
              
              (76,778
              )
              
              
              (61,921
              )**INCOME
                  BEFORE INCOME TAXES**
              
              
              1,810
              
              
              
              13,618
              
              
              
              113,743
              
              
              
              131,261Income
                  Tax Expense (Credit)
              
              
              (1,471
              )
              
              
              3,971
              
              
              
              40,235
              
              
              
              48,020**INCOME
                  BEFORE EXTRAORDINARY LOSS**
              
              
              3,281
              
              
              
              9,647
              
              
              
              73,508
              
              
              
              83,241Extraordinary
                  Loss – Reapplication of Regulatory Accountingfor
                  Generation, Net of Tax
              
              
              (78,763
              )
              
              
              -
              
              
              
              (78,763
              )
              
              
              -**NET
                  INCOME (LOSS)**
              
              
              (75,482
              )
              
              
              9,647
              
              
              
              (5,255
              )
              
              
              83,241Preferred
                  Stock Dividend Requirements IncludingCapital
                  Stock****Expense
              
              
              238
              
              
              
              238
              
              
              
              476
              
              
              
              476**EARNINGS
                  (LOSS) APPLICABLE TO COMMON STOCK**
              
              $
              (75,720
              )
              
              $
              9,409
              
              
              $
              (5,731
              )
              
              $
              82,765
  *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 Six Months Ended June 30, 2007 and 2006**
 **(in
        thousands)**
 **(Unaudited)**
 
 **Common
                  Stock**
              
              
              **Paid-in
                  Capital**
              
              
              **Retained
                  Earnings**
              
              
              **Accumulated
                  Other Comprehensive Income (Loss)**
              
              
              **Total****DECEMBER
                  31, 2005**
              
              $
              260,458
              
              
              $
              924,837
              
              
              $
              635,016
              
              
              $
              (16,610
              )
              
              $
              1,803,701Common
                  Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (5,000
              )
              
              
              
              
              
              
              (5,000
              )Preferred
                  Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (400
              )
              
              
              
              
              
              
              (400
              )Capital
                  Stock Expense and Other
              
              
              
              
              
              
              80
              
              
              
              (76
              )
              
              
              
              
              
              
              4**TOTAL**
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              1,798,305**COMPREHENSIVE
                  INCOME****Other
                  Comprehensive Income, Net of Taxes:**Cash
                  Flow Hedges, Net of Tax****of $9,692
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              17,998
              
              
              
              17,998**NET
                  INCOME**
              
              
              
              
              
              
              
              
              
              
              83,241
              
              
              
              
              
              
              
              83,241**TOTAL
                  COMPREHENSIVE INCOME**
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              101,239**JUNE
                  30, 2006**
              
              $
              260,458
              
              
              $
              924,917
              
              
              $
              712,781
              
              
              $
              1,388
              
              
              $
              1,899,544**DECEMBER
                  31, 2006**
              
              $
              260,458
              
              
              $
              1,024,994
              
              
              $
              805,513
              
              
              $
              (54,791
              )
              
              $
              2,036,174FIN
                  48 Adoption, Net of Tax
              
              
              
              
              
              
              
              
              
              
              (2,685
              )
              
              
              
              
              
              
              (2,685
              )Common
                  Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (25,000
              )
              
              
              
              
              
              
              (25,000
              )Preferred
                  Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (400
              )
              
              
              
              
              
              
              (400
              )Capital
                  Stock Expense and Other
              
              
              
              
              
              
              76
              
              
              
              (76
              )
              
              
              
              
              
              
              -**TOTAL**
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              2,008,089**COMPREHENSIVE
                  INCOME****Other
                  Comprehensive Income, Net of Taxes:**Cash
                  Flow Hedges, Net of Tax of $2,482
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              4,610
              
              
              
              4,610SFAS
                  158 Costs Established as a Regulatory
                Asset
                  Related to the Reapplication of
                SFAS
                  71, Net of Tax of $6,055
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              11,245
              
              
              
              11,245**NET
                  LOSS**
              
              
              
              
              
              
              
              
              
              
              (5,255
              )
              
              
              
              
              
              
              (5,255
              )**TOTAL
                  COMPREHENSIVE INCOME**
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              10,600**JUNE
                  30, 2007**
              
              $
              260,458
              
              
              $
              1,025,070
              
              
              $
              772,097
              
              
              $
              (38,936
              )
              
              $
              2,018,689
 
 *See
        Condensed Notes to Condensed Financial Statements of Registrant
        Subsidiaries.*
   
 **APPALACHIAN
        POWER COMPANY AND SUBSIDIARIES**
 **CONDENSED
        CONSOLIDATED BALANCE SHEETS**
 **ASSETS**
 **June
        30, 2007 and December 31, 2006**
 **(in
        thousands)**
 **(Unaudited)**
 
 **2007**
              
              
              **2006****CURRENT
                  ASSETS**Cash
                  and Cash Equivalents
              
              $
              1,352
              
              
              $
              2,318Accounts
                  Receivable:Customers
              
              
              176,758
              
              
              
              180,190Affiliated
                  Companies
              
              
              76,139
              
              
              
              98,237Accrued
                  Unbilled Revenues
              
              
              28,373
              
              
              
              46,281Miscellaneous
              
              
              3,343
              
              
              
              3,400Allowance
                  for Uncollectible Accounts
              
              
              (8,779
              )
              
              
              (4,334
              )Total
                  Accounts Receivable
              
              
              275,834
              
              
              
              323,774Fuel
              
              
              89,129
              
              
              
              77,077Materials
                  and Supplies
              
              
              71,994
              
              
              
              56,235Risk
                  Management Assets
              
              
              84,562
              
              
              
              105,376Accrued
                  Tax Benefits
              
              
              10,095
              
              
              
              3,748Regulatory
                  Asset for Under-Recovered Fuel Costs
              
              
              6,591
              
              
              
              29,526Prepayments
                  and Other
              
              
              17,266
              
              
              
              20,126**TOTAL**
              
              
              556,823
              
              
              
              618,180**PROPERTY,
                  PLANT AND EQUIPMENT**Electric:Production
              
              
              3,487,306
              
              
              
              2,844,803Transmission
              
              
              1,658,340
              
              
              
              1,620,512Distribution
              
              
              2,309,637
              
              
              
              2,237,887Other
              
              
              344,201
              
              
              
              339,450Construction
                  Work in Progress
              
              
              592,554
              
              
              
              957,626**Total**
              
              
              8,392,038
              
              
              
              8,000,278Accumulated
                  Depreciation and Amortization
              
              
              2,554,296
              
              
              
              2,476,290**TOTAL
                  - NET**
              
              
              5,837,742
              
              
              
              5,523,988**OTHER
                  NONCURRENT ASSETS**Regulatory
                  Assets
              
              
              675,027
              
              
              
              622,153Long-term
                  Risk Management Assets
              
              
              86,948
              
              
              
              88,906Deferred
                  Charges and Other
              
              
              163,892
              
              
              
              163,089**TOTAL**
              
              
              925,867
              
              
              
              874,148**TOTAL
                  ASSETS**
              
              $
              7,320,432
              
              
              $
              7,016,316
 
 *See
        Condensed Notes to Condensed Financial Statements of Registrant
        Subsidiaries.*
   
 **APPALACHIAN
        POWER COMPANY AND SUBSIDIARIES**
 **CONDENSED
        CONSOLIDATED BALANCE SHEETS**
 **LIABILITIES
        AND SHAREHOLDERS’ EQUITY**
 **June
        30, 2007 and December 31, 2006**
 **(Unaudited)**
 
 **2007**
              
              
              **2006****CURRENT
                  LIABILITIES**
              
              **(in
                  thousands)**Advances
                  from Affiliates
              
              $
              247,616
              
              
              $
              34,975Accounts
                  Payable:General
              
              
              232,509
              
              
              
              296,437Affiliated
                  Companies
              
              
              92,697
              
              
              
              105,525Long-term
                  Debt Due Within One Year – Nonaffiliated
              
              
              399,144
              
              
              
              324,191Risk
                  Management Liabilities
              
              
              59,720
              
              
              
              81,114Customer
                  Deposits
              
              
              64,285
              
              
              
              56,364Accrued
                  Taxes
              
              
              102,445
              
              
              
              60,056Other
              
              
              260,549
              
              
              
              172,943**TOTAL**
              
              
              1,458,965
              
              
              
              1,131,605**NONCURRENT
                  LIABILITIES**Long-term
                  Debt – Nonaffiliated
              
              
              2,050,742
              
              
              
              2,174,473Long-term
                  Debt – Affiliated
              
              
              100,000
              
              
              
              100,000Long-term
                  Risk Management Liabilities
              
              
              58,768
              
              
              
              64,909Deferred
                  Income Taxes
              
              
              892,735
              
              
              
              957,229Regulatory
                  Liabilities and Deferred Investment Tax Credits
              
              
              487,643
              
              
              
              309,724Deferred
                  Credits and Other
              
              
              235,127
              
              
              
              224,439**TOTAL**
              
              
              3,825,015
              
              
              
              3,830,774**TOTAL
                  LIABILITIES**
              
              
              5,283,980
              
              
              
              4,962,379Cumulative
                  Preferred Stock Not Subject to Mandatory Redemption
              
              
              17,763
              
              
              
              17,763Commitments
                  and Contingencies (Note 4)**COMMON
                  SHAREHOLDER’S EQUITY**Common
                  Stock – No Par Value:Authorized
                  – 30,000,000 SharesOutstanding
                  – 13,499,500 Shares
              
              
              260,458
              
              
              
              260,458Paid-in
                  Capital
              
              
              1,025,070
              
              
              
              1,024,994Retained
                  Earnings
              
              
              772,097
              
              
              
              805,513Accumulated
                  Other Comprehensive Income (Loss)
              
              
              (38,936
              )
              
              
              (54,791
              )**TOTAL**
              
              
              2,018,689
              
              
              
              2,036,174**TOTAL
                  LIABILITIES AND SHAREHOLDERS’ EQUITY**
              
              $
              7,320,432
              
              
              $
              7,016,316
 
 *See
        Condensed Notes to Condensed Financial Statements of Registrant
        Subsidiaries.*
  
 **APPALACHIAN
        POWER COMPANY AND SUBSIDIARIES**
 **CONDENSED
        CONSOLIDATED STATEMENTS OF CASH FLOWS**
 **For
        the Six Months Ended June 30, 2007 and 2006**
 **(in
        thousands)**
 **(Unaudited)**
 
 **2007**
              
              
              **2006****OPERATING
                  ACTIVITIES****Net
                  Income (Loss)**
              
              $
              (5,255
              )
              
              $
              83,241**Adjustments
                  for Noncash Items:**Depreciation
                  and Amortization
              
              
              90,236
              
              
              
              96,956Deferred
                  Income Taxes
              
              
              (17,439
              )
              
              
              (1,466
              )Extraordinary
                  Loss, Net of Tax
              
              
              78,763
              
              
              
              -Regulatory
                  Provision
              
              
              105,110
              
              
              
              -Carrying
                  Costs Income
              
              
              (14,116
              )
              
              
              (13,784
              )Mark-to-Market
                  of Risk Management Contracts
              
              
              1,377
              
              
              
              147Change
                  in Other Noncurrent Assets
              
              
              (12,254
              )
              
              
              5,690Change
                  in Other Noncurrent Liabilities
              
              
              (1,239
              )
              
              
              17,986**Changes
                  in Certain Components of Working Capital:**Accounts
                  Receivable, Net
              
              
              31,483
              
              
              
              60,345Fuel,
                  Materials and Supplies
              
              
              (20,654
              )
              
              
              (8,611
              )Margin
                  Deposits
              
              
              6,798
              
              
              
              27,872Accounts
                  Payable
              
              
              (26,786
              )
              
              
              14,993Customer
                  Deposits
              
              
              7,921
              
              
              
              (24,824
              )Accrued
                  Taxes, Net
              
              
              39,168
              
              
              
              42,357Fuel
                  Over/Under Recovery, Net
              
              
              15,221
              
              
              
              3,636Other
                  Current Assets
              
              
              (1,833
              )
              
              
              7,295Other
                  Current Liabilities
              
              
              (11,087
              )
              
              
              5,137**Net
                  Cash Flows From Operating Activities**
              
              
              265,414
              
              
              
              316,970**INVESTING
                  ACTIVITIES**Construction
                  Expenditures
              
              
              (382,501
              )
              
              
              (404,252
              )Change
                  in Other Cash Deposits, Net
              
              
              (2,678
              )
              
              
              -Change
                  in Advances to Affiliates, Net
              
              
              -
              
              
              
              (218,702
              )Proceeds
                  from Sales of Assets
              
              
              6,194
              
              
              
              4,034**Net
                  Cash Flows Used For Investing Activities**
              
              
              (378,985
              )
              
              
              (618,920
              )**FINANCING
                  ACTIVITIES**Issuance
                  of Long-term Debt – Nonaffiliated
              
              
              73,438
              
              
              
              544,364Change
                  in Advances from Affiliates, Net
              
              
              212,641
              
              
              
              (194,133
              )Retirement
                  of Long-term Debt – Nonaffiliated
              
              
              (125,006
              )
              
              
              (100,005
              )Retirement
                  of Preferred Stock
              
              
              -
              
              
              
              (14
              )Principal
                  Payments for Capital Lease Obligations
              
              
              (2,200
              )
              
              
              (2,768
              )Funds
                  From Amended Coal Contract
              
              
              -
              
              
              
              68,078Amortization
                  of Funds From Amended Coal Contract
              
              
              (20,868
              )
              
              
              (8,567
              )Dividends
                  Paid on Common Stock
              
              
              (25,000
              )
              
              
              (5,000
              )Dividends
                  Paid on Cumulative Preferred Stock
              
              
              (400
              )
              
              
              (400
              )**Net
                  Cash Flows From Financing Activities**
              
              
              112,605
              
              
              
              301,555**Net
                  Decrease in Cash and Cash Equivalents**
              
              
              (966
              )
              
              
              (395
              )**Cash
                  and Cash Equivalents at Beginning of Period**
              
              
              2,318
              
              
              
              1,741**Cash
                  and Cash Equivalents at End of Period**
              
              $
              1,352
              
              
              $
              1,346**SUPPLEMENTARY
                  INFORMATION**Cash
                  Paid for Interest, Net of Capitalized Amounts
              
              $
              69,823
              
              
              $
              51,558Net
                  Cash Paid for Income Taxes
              
              
              6,197
              
              
              
              4,562Noncash
                  Acquisitions Under Capital Leases
              
              
              1,693
              
              
              
              2,287Construction
                  Expenditures Included in Accounts Payable at June 30,
              
              
              97,044
              
              
              
              105,826*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
                  Reference**Significant
                  Accounting Matters
              Note
                  1New
                  Accounting Pronouncements and Extraordinary Item
              Note
                  2Rate
                  Matters
              Note
                  3Commitments,
                  Guarantees and Contingencies
              Note
                  4Benefit
                  Plans
              Note
                  6Business
                  Segments
              Note
                  7Income
                  Taxes
              Note
                  8Financing
                  Activities
              Note
                  9
 
 
 
 
 
       
 
 
 **COLUMBUS
        SOUTHERN POWER COMPANY**
 **AND
        SUBSIDIARIES**
                  
 
 **COLUMBUS
        SOUTHERN POWER COMPANY AND
        SUBSIDIARIES**
 **MANAGEMENT’S
        NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS**
 
 In
        March
        2007, CSPCo and AEGCo entered into a ten-year purchase power agreement (PPA)
        for
        the entire output from the Lawrenceburg Plant effective with AEGCo’s purchase of
        the plant in May 2007.  The PPA has an option for an additional
        two-year period.  I&M operates the plant under an agreement with
        AEGCo.  Under the PPA, CSPCo pays AEGCo for the capacity,
        depreciation, fuel, operation, maintenance and tax
        expenses.  These payments are due regardless of the plant’s operating
        status.  Fuel, operation and maintenance payments are based
        on actual costs incurred.  All expenses will be trued up
        periodically.
 
 **Results
        of Operations**
 
 Second
        Quarter of 2007 Compared to Second Quarter of 2006
 
 **Reconciliation
        of Second Quarter of 2006 to Second Quarter of 2007**
 **Net
        Income**
 **(in
        millions)**
 
 **Second
                  Quarter of 2006**
              
              
              
              
              $
              32**Changes
                  in Gross Margin:**Retail
                  Margins
              
              
              64Off-system
                  Sales
              
              
              10Transmission
                  Revenues
              
              
              3Other
              
              
              1**Total
                  Change in Gross Margin**
              
              
              
              
              
              
              78**Changes
                  in Operating Expenses and Other:**Other
                  Operation and Maintenance
              
              
              (8
              )Depreciation
                  and Amortization
              
              
              (3
              )Taxes
                  Other Than Income Taxes
              
              
              6Interest
                  Expense
              
              
              1**Total
                  Change in Operating Expenses and Other**
              
              
              
              
              
              
              (4
              )Income
                  Tax Expense
              
              
              
              
              
              
              (26
              )**Second
                  Quarter of 2007**
              
              
              
              
              
              $
              80
 
 Net
        Income increased $48 million to $80 million in 2007.  The key driver
        of the increase was a $78 million increase in Gross Margin primarily offset
        by a
        $26 million increase in Income Tax Expense.
 
 The
        major
        components of the increase in Gross Margin, defined as revenues less the
        related
        direct cost of fuel, including consumption of chemicals and emissions
        allowances, and purchased power were as follows:
 
 ·
              Retail
                  Margins increased $64 million primarily due to:·
              A
                  $22 million increase in rate revenues related to a $13 million
                  increase in
                  CSPCo’s RSP, a $3 million increase related to recovery of storm costs
                  and
                  a $3 million increase related to recovery of IGCC preconstruction
                  costs.  See “Ohio Rate Matters” section of Note
                  3.  The increase in recovery of storm costs was offset by the
                  amortization of deferred expenses in Other Operation and
                  Maintenance.  The increase in rate recovery of IGCC
                  preconstruction costs was offset by the amortization of deferred
                  expenses
                  in Depreciation and Amortization.·
              A
                  $20 million decrease in capacity purchases due to changes in relative
                  peak
                  demands of AEP Power Pool members under the Interconnection
                  Agreement.·
              An
                  $18 million increase in residential and commercial revenue primarily
                  due
                  to a 69% increase in cooling degree days.·
              A
                  $14 million increase in industrial revenue primarily due to the
                  addition
                  of Ormet, a major industrial customer.  The addition of Ormet
                  resulted in a $12 million increase in industrial sales.  See
                  “Ormet” section of Note 3.·
              Margins
                  from Off-system Sales increased $10 million primarily due to higher
                  power
                  prices in the east and higher trading margins.·
              Transmission
                  Revenues increased $3 million primarily due to a provision recorded
                  in the
                  second quarter of 2006 related to potential SECA refunds.  See
                  “Transmission Rate Proceedings at the FERC” section of Note
                  3.
 
 Operating
        Expenses and Other changed between years as follows:
 
 ·
              Other
                  Operation and Maintenance expenses increased $8 million primarily
                  due
                  to:·
              A
                  $4 million increase in expenses related to CSPCo’s PPA for AEGCo’s
                  Lawrenceburg Plant which began in May 2007.·
              A
                  $3 million increase in overhead line expenses due in part to the
                  amortization of deferred storm expenses recovered through a cost-recovery
                  rider.  The increase in amortization of deferred storm expenses
                  was offset by a corresponding increase in Retail
                  Margins.·
              A
                  $3 million increase in net allocated transmission costs related
                  to the
                  Transmission Equalization Agreement as a result of the addition
                  of APCo’s
                  Wyoming-Jacksons Ferry 765 kV line, which was energized and placed
                  in
                  service in June 2006.·
              Depreciation
                  and Amortization increased $3 million due to the amortization of
                  IGCC
                  preconstruction costs in 2007.  The increase in amortization of
                  IGCC preconstruction costs was offset by a corresponding increase
                  in
                  Retail Margins.·
              Taxes
                  Other Than Income Taxes decreased $6 million due to a favorable
                  true-up of
                  property taxes recorded in 2007 compared to an unfavorable true-up
                  recorded in 2006, partially offset by an increase in state excise
                  taxes.
 
 *Income
        Taxes*
 
 Income
        Tax Expense increased $26 million primarily due to an increase in pretax
        book
        income.
 
 Six
        Months Ended June 30, 2007 Compared to Six Months Ended June 30,
        2006
 
 **Reconciliation
        of Six Months Ended June 30, 2006 to Six Months Ended June 30,
        2007**
 **Net
        Income**
 **(in
        millions)**
 
 **Six
                  Months Ended June 30, 2006**
              
              
              
              
              $
              84**Changes
                  in Gross Margin:**Retail
                  Margins
              
              
              91Off-system
                  Sales
              
              
              (1
              )Transmission
                  Revenues
              
              
              (4
              )Other
              
              
              (3
              )**Total
                  Change in Gross Margin**
              
              
              
              
              
              
              83**Changes
                  in Operating Expenses and Other:**Other
                  Operation and Maintenance
              
              
              (18
              )Depreciation
                  and Amortization
              
              
              (7
              )Taxes
                  Other Than Income Taxes
              
              
              5Interest
                  Expense
              
              
              3**Total
                  Change in Operating Expenses and Other**
              
              
              
              
              
              
              (17
              )Income
                  Tax Expense
              
              
              
              
              
              
              (23
              )**Six
                  Months Ended June 30, 2007**
              
              
              
              
              
              $
              127
 
 Net
        Income increased $43 million to $127 million in 2007.  The key driver
        of the increase was an $83 million increase in Gross Margin partially offset
        by
        a $23 million increase in Income Tax Expense and a $17 million increase in
        Operating Expenses and Other.
 
 The
        major
        components of the increase in Gross Margin, defined as revenues less the
        related
        direct cost of fuel, including consumption of chemicals and emissions
        allowances, and purchased power were as follows:
 
 ·
              Retail
                  Margins increased $91 million primarily due to:·
              A
                  $36 million increase in rate revenues related to a $18 million
                  increase in
                  CSPCo’s RSP, a $6 million increase related to recovery of storm costs
                  and
                  a $6 million increase related to recovery of IGCC preconstruction
                  costs.  See “Ohio Rate Matters” section of Note
                  3.  The increase in rate recovery of storm costs was offset by
                  the amortization of deferred expenses in Other Operation and
                  Maintenance.  The increase in rate recovery of IGCC
                  preconstruction costs was offset by the amortization of deferred
                  expenses
                  in Depreciation and Amortization.·
              A
                  $28 million increase in residential and commercial revenue primarily
                  due
                  to a 72% increase in cooling degree days.·
              A
                  $21 million increase in industrial revenue primarily due to the
                  addition
                  of Ormet, a major industrial customer.  The addition of Ormet
                  resulted in a $19 million increase in industrial sales.  See
                  “Ormet” section of Note 3.·
              An
                  $18 million decrease in capacity purchases due to changes in relative
                  peak
                  demands of AEP Power Pool members under the Interconnection
                  Agreement.·
              Transmission
                  Revenues decreased $4 million primarily due to the elimination
                  of SECA
                  revenues as of April 1, 2006 offset by a provision recorded in
                  the second
                  quarter of 2006 related to potential SECA
                  refunds.  See  “Transmission Rate Proceedings at the
                  FERC” section of Note 3.·
              Other
                  revenues decreased $3 million primarily due to lower gains on sales
                  of
                  emission allowances.
 
 Operating
        Expenses and Other changed between years as follows:
 
 ·
              Other
                  Operation and Maintenance expenses increased $18 million primarily
                  due
                  to:·
              An
                  $8 million increase in overhead line expenses primarily due to
                  a $6
                  million increase in amortization of deferred storm expenses recovered
                  through a cost-recovery rider.  The increase in amortization of
                  deferred storm expenses was offset by a corresponding increase
                  in Retail
                  Margins.·
              A
                  $6 million increase in net allocated transmission costs related
                  to the
                  Transmission Equalization Agreement as a result of the addition
                  of APCo’s
                  Wyoming-Jacksons Ferry 765 kV line, which was energized and placed
                  in
                  service in June 2006.·
              A
                  $4 million increase in expenses related to CSPCo’s PPA for AEGCo’s
                  Lawrenceburg Plant which began in May 2007.·
              Depreciation
                  and Amortization increased $7 million primarily due to the amortization
                  of
                  IGCC preconstruction costs of $6 million in 2007.  The increase
                  in amortization of IGCC preconstruction costs was offset by a
                  corresponding increase in Retail Margins.·
              Taxes
                  Other Than Income Taxes decreased $5 million due to a favorable
                  true-up of
                  property taxes recorded in 2007 compared to an unfavorable true-up
                  recorded in 2006, partially offset by an increase in state excise
                  taxes.·
              Interest
                  Expense decreased $3 million primarily due to an increase in allowance
                  for
                  borrowed funds used during
                  construction.
 
 *Income
        Taxes*
 
 Income
        Tax Expense increased $23 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 2006 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 the complete discussion and analysis within AEP’s
“Quantitative and Qualitative Disclosures About Risk Management Activities”
section for disclosures about risk management activities.
 
 **VaR
        Associated with Debt Outstanding**
 
 Management
        utilizes a VaR model to measure interest rate market risk
        exposure.  The interest rate VaR model is based on a Monte Carlo
        simulation with a 95% confidence level and a one-year holding
        period.  The risk of potential loss in fair value attributable to
        exposure to interest rates primarily related to long-term debt with fixed
        interest rates was $82 million and $70 million at June 30, 2007 and December
        31,
        2006, respectively.  Management would not expect to liquidate the
        entire debt portfolio in a one-year holding period; therefore, a near term
        change in interest rates should not negatively affect results of operations
        or
        consolidated financial position.
   
 **COLUMBUS
        SOUTHERN POWER COMPANY AND SUBSIDIARIES**
 **CONDENSED
        CONSOLIDATED STATEMENTS OF INCOME**
 **For
        the Three and Six Months Ended June 30, 2007 and 2006**
 **(in
        thousands)**
 **(Unaudited)**
 
 **Three
                  Months Ended**
              
              
              **Six
                  Months Ended****2007**
              
              
              **2006**
              
              
              **2007**
              
              
              **2006****REVENUES**Electric
                  Generation, Transmission and Distribution
              
              $
              469,648
              
              
              $
              394,110
              
              
              $
              893,114
              
              
              $
              807,779Sales
                  to AEP Affiliates
              
              
              35,356
              
              
              
              21,762
              
              
              
              58,369
              
              
              
              35,531Other
              
              
              1,018
              
              
              
              1,237
              
              
              
              2,451
              
              
              
              2,567**TOTAL**
              
              
              506,022
              
              
              
              417,109
              
              
              
              953,934
              
              
              
              845,877**EXPENSES**Fuel
                  and Other Consumables Used for Electric Generation
              
              
              76,342
              
              
              
              71,213
              
              
              
              152,204
              
              
              
              141,033Purchased
                  Electricity for Resale
              
              
              32,835
              
              
              
              27,688
              
              
              
              64,146
              
              
              
              52,453Purchased
                  Electricity from AEP Affiliates
              
              
              87,788
              
              
              
              87,188
              
              
              
              171,329
              
              
              
              169,665Other
                  Operation
              
              
              62,516
              
              
              
              57,860
              
              
              
              123,675
              
              
              
              113,805Maintenance
              
              
              26,723
              
              
              
              23,502
              
              
              
              49,287
              
              
              
              41,436Depreciation
                  and Amortization
              
              
              49,446
              
              
              
              46,540
              
              
              
              99,743
              
              
              
              92,368Taxes
                  Other Than Income Taxes
              
              
              35,796
              
              
              
              41,787
              
              
              
              76,378
              
              
              
              81,289**TOTAL**
              
              
              371,446
              
              
              
              355,778
              
              
              
              736,762
              
              
              
              692,049**OPERATING
                  INCOME**
              
              
              134,576
              
              
              
              61,331
              
              
              
              217,172
              
              
              
              153,828**Other
                  Income (Expense):**Interest
                  Income
              
              
              194
              
              
              
              475
              
              
              
              616
              
              
              
              930Carrying
                  Costs Income
              
              
              1,139
              
              
              
              1,320
              
              
              
              2,231
              
              
              
              2,036Allowance
                  for Equity Funds Used During Construction
              
              
              620
              
              
              
              343
              
              
              
              1,392
              
              
              
              807Interest
                  Expense
              
              
              (16,382
              )
              
              
              (16,914
              )
              
              
              (31,663
              )
              
              
              (34,434
              )**INCOME
                  BEFORE INCOME TAXES**
              
              
              120,147
              
              
              
              46,555
              
              
              
              189,748
              
              
              
              123,167Income
                  Tax Expense
              
              
              40,125
              
              
              
              14,293
              
              
              
              62,745
              
              
              
              39,568**NET
                INCOME**
              
              
              80,022
              
              
              
              32,262
              
              
              
              127,003
              
              
              
              83,599Capital
                  Stock Expense
              
              
              40
              
              
              
              40
              
              
              
              79
              
              
              
              79**EARNINGS
                    APPLICABLE TO COMMON STOCK**
              
              $
              79,982
              
              
              $
              32,222
              
              
              $
              126,924
              
              
              $
              83,520
 
 *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 Six Months Ended June 30, 2007 and 2006**
 **(in
        thousands)**
 **(Unaudited)**
 
 **Common
                  Stock**
              
              
              **Paid-in
                  Capital**
              
              
              **Retained
                  Earnings**
              
              
              **Accumulated
                  Other Comprehensive Income (Loss)**
              
              
              **Total****DECEMBER
                  31, 2005**
              
              $
              41,026
              
              
              $
              580,035
              
              
              $
              361,365
              
              
              $
              (880
              )
              
              $
              981,546Common
                  Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (45,000
              )
              
              
              
              
              
              
              (45,000
              )Capital
                  Stock Expense
              
              
              
              
              
              
              79
              
              
              
              (79
              )
              
              
              
              
              
              
              -**TOTAL**
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              936,546**COMPREHENSIVE
                  INCOME****Other
                  Comprehensive Income, Net of Taxes:**Cash
                  Flow Hedges, Net of Tax of $3,695
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              6,861
              
              
              
              6,861**NET
                  INCOME**
              
              
              
              
              
              
              
              
              
              
              83,599
              
              
              
              
              
              
              
              83,599**TOTAL
                  COMPREHENSIVE INCOME**
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              90,460**JUNE
                  30, 2006**
              
              $
              41,026
              
              
              $
              580,114
              
              
              $
              399,885
              
              
              $
              5,981
              
              
              $
              1,027,006**DECEMBER
                  31, 2006**
              
              $
              41,026
              
              
              $
              580,192
              
              
              $
              456,787
              
              
              $
              (21,988
              )
              
              $
              1,056,017FIN
                  48 Adoption, Net of Tax
              
              
              
              
              
              
              
              
              
              
              (3,022
              )
              
              
              
              
              
              
              (3,022
              )Common
                  Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (40,000
              )
              
              
              
              
              
              
              (40,000
              )Capital
                  Stock Expense
              
              
              
              
              
              
              79
              
              
              
              (79
              )
              
              
              
              
              
              
              -**TOTAL**
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              1,012,995**COMPREHENSIVE
                  INCOME****Other
                  Comprehensive Income, Net of Taxes:**Cash
                  Flow Hedges, Net of Tax of $360
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              669
              
              
              
              669**NET
                  INCOME**
              
              
              
              
              
              
              
              
              
              
              127,003
              
              
              
              
              
              
              
              127,003**TOTAL
                  COMPREHENSIVE INCOME**
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              127,672**JUNE
                  30, 2007**
              
              $
              41,026
              
              
              $
              580,271
              
              
              $
              540,689
              
              
              $
              (21,319
              )
              
              $
              1,140,667
 
 *See
        Condensed Notes to Condensed Financial Statements of Registrant
        Subsidiaries.*
  
 **COLUMBUS
        SOUTHERN POWER COMPANY AND SUBSIDIARIES**
 **CONDENSED
        CONSOLIDATED BALANCE SHEETS**
 **ASSETS**
 **June
        30, 2007 and December 31, 2006**
 **(in
        thousands)**
 **(Unaudited)**
 
 **2007**
              
              
              **2006****CURRENT
                  ASSETS**Cash
                  and Cash Equivalents
              
              $
              1,065
              
              
              $
              1,319Accounts
                  Receivable:Customers
              
              
              51,013
              
              
              
              49,362Affiliated Companies
              
              
              35,509
              
              
              
              62,866Accrued Unbilled Revenues
              
              
              18,760
              
              
              
              11,042Miscellaneous
              
              
              6,266
              
              
              
              4,895Allowance for Uncollectible Accounts
              
              
              (707
              )
              
              
              (546
              )Total
                  Accounts Receivable
              
              
              110,841
              
              
              
              127,619Fuel
              
              
              41,922
              
              
              
              37,348Materials
                  and Supplies
              
              
              36,267
              
              
              
              31,765Emission
                  Allowances
              
              
              6,328
              
              
              
              3,493Risk
                  Management Assets
              
              
              45,433
              
              
              
              66,238Prepayments
                  and Other
              
              
              10,397
              
              
              
              20,870**TOTAL**
              
              
              252,253
              
              
              
              288,652**PROPERTY,
                  PLANT AND EQUIPMENT**Electric:Production
              
              
              2,051,385
              
              
              
              1,896,073Transmission
              
              
              491,245
              
              
              
              479,119Distribution
              
              
              1,514,251
              
              
              
              1,475,758Other
              
              
              202,545
              
              
              
              191,103Construction
                  Work in Progress
              
              
              322,114
              
              
              
              294,138**Total**
              
              
              4,581,540
              
              
              
              4,336,191Accumulated
                  Depreciation and Amortization
              
              
              1,647,537
              
              
              
              1,611,043**TOTAL
                  - NET**
              
              
              2,934,003
              
              
              
              2,725,148**OTHER
                  NONCURRENT ASSETS**Regulatory
                  Assets
              
              
              271,205
              
              
              
              298,304Long-term
                  Risk Management Assets
              
              
              46,558
              
              
              
              56,206Deferred
                  Charges and Other
              
              
              114,735
              
              
              
              152,379**TOTAL**
              
              
              432,498
              
              
              
              506,889**TOTAL
                  ASSETS**
              
              $
              3,618,754
              
              
              $
              3,520,689
 
 *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**
 **June
        30, 2007 and December 31, 2006**
 **(Unaudited)**
 
 **2007**
              
              
              **2006****CURRENT
                  LIABILITIES**
              
              **(in
                  thousands)**Advances
                  from Affiliates
              
              $
              64,003
              
              
              $
              696Accounts
                  Payable:General
              
              
              104,586
              
              
              
              112,431Affiliated
                  Companies
              
              
              42,580
              
              
              
              59,538Long-term
                  Debt Due Within One Year - Nonaffiliated
              
              
              112,000
              
              
              
              -Risk
                  Management Liabilities
              
              
              32,018
              
              
              
              49,285Customer
                  Deposits
              
              
              50,686
              
              
              
              34,991Accrued
                  Taxes
              
              
              158,915
              
              
              
              166,551Accrued
                  Interest
              
              
              23,155
              
              
              
              20,868Other
              
              
              38,262
              
              
              
              37,143**TOTAL**
              
              
              626,205
              
              
              
              481,503**NONCURRENT
                  LIABILITIES**Long-term
                  Debt – Nonaffiliated
              
              
              985,523
              
              
              
              1,097,322Long-term
                  Debt – Affiliated
              
              
              100,000
              
              
              
              100,000Long-term
                  Risk Management Liabilities
              
              
              31,956
              
              
              
              40,477Deferred
                  Income Taxes
              
              
              461,738
              
              
              
              475,888Regulatory
                  Liabilities and Deferred Investment Tax Credits
              
              
              169,757
              
              
              
              179,048Deferred
                  Credits and Other
              
              
              102,908
              
              
              
              90,434**TOTAL**
              
              
              1,851,882
              
              
              
              1,983,169**TOTAL
                  LIABILITIES**
              
              
              2,478,087
              
              
              
              2,464,672Commitments
                  and Contingencies (Note 4)**COMMON
                  SHAREHOLDER’S EQUITY**Common
                  Stock – No Par Value:Authorized
                  – 24,000,000 SharesOutstanding
                  – 16,410,426 Shares
              
              
              41,026
              
              
              
              41,026Paid-in
                  Capital
              
              
              580,271
              
              
              
              580,192Retained
                  Earnings
              
              
              540,689
              
              
              
              456,787Accumulated
                  Other Comprehensive Income (Loss)
              
              
              (21,319
              )
              
              
              (21,988
              )**TOTAL**
              
              
              1,140,667
              
              
              
              1,056,017**TOTAL
                  LIABILITIES AND SHAREHOLDER’S EQUITY**
              
              $
              3,618,754
              
              
              $
              3,520,689
 
 *See
        Condensed Notes to Condensed Financial Statements of Registrant
        Subsidiaries.*
  
 **COLUMBUS
        SOUTHERN POWER COMPANY AND SUBSIDIARIES**
 **CONDENSED
        CONSOLIDATED STATEMENTS OF CASH FLOWS**
 **For
        the Six Months Ended June 30, 2007 and 2006**
 **(in
        thousands)**
 **(Unaudited)**
 
 **2007**
              
              
              **2006****OPERATING
                  ACTIVITIES****Net
                  Income**
              
              $
              127,003
              
              
              $
              83,599**Adjustments
                  for Noncash Items:**Depreciation
                  and Amortization
              
              
              99,743
              
              
              
              92,368Deferred
                  Income Taxes
              
              
              (5,077
              )
              
              
              (250
              )Carrying
                  Costs Income
              
              
              (2,231
              )
              
              
              (2,036
              )Mark-to-Market
                  of Risk Management Contracts
              
              
              5,600
              
              
              
              (466
              )Deferred
                  Property Taxes
              
              
              39,063
              
              
              
              30,201Change
                  in Other Noncurrent Assets
              
              
              (25,985
              )
              
              
              (15,417
              )Change
                  in Other Noncurrent Liabilities
              
              
              (7,054
              )
              
              
              7,111**Changes
                  in Certain Components of Working Capital:**Accounts
                  Receivable, Net
              
              
              7,678
              
              
              
              29,274Fuel,
                  Materials and Supplies
              
              
              (4,740
              )
              
              
              (14,664
              )Accounts
                  Payable
              
              
              (10,735
              )
              
              
              16,866Customer
                  Deposits
              
              
              15,695
              
              
              
              (14,843
              )Accrued
                  Taxes, Net
              
              
              5,493
              
              
              
              (21,909
              )Other
                  Current Assets
              
              
              5,608
              
              
              
              24,796Other
                  Current Liabilities
              
              
              (1,952
              )
              
              
              (1,062
              )**Net
                  Cash Flows From Operating Activities**
              
              
              248,109
              
              
              
              213,568**INVESTING
                  ACTIVITIES**Construction
                  Expenditures
              
              
              (169,014
              )
              
              
              (137,728
              )Change
                  in Advances to Affiliates, Net
              
              
              -
              
              
              
              (12,616
              )Acquisition
                  of Darby Plant
              
              
              (102,032
              )
              
              
              -Proceeds
                  from Sale of Assets
              
              
              842
              
              
              
              1,976Other
              
              
              (20
              )
              
              
              (1,151
              )**Net
                  Cash Flows Used For Investing Activities**
              
              
              (270,224
              )
              
              
              (149,519
              )**FINANCING
                  ACTIVITIES**Change
                  in Advances from Affiliates, Net
              
              
              63,307
              
              
              
              (17,609
              )Principal
                  Payments for Capital Lease Obligations
              
              
              (1,446
              )
              
              
              (1,570
              )Dividends
                  Paid on Common Stock
              
              
              (40,000
              )
              
              
              (45,000
              )**Net
                  Cash Flows From (Used For) Financing Activities**
              
              
              21,861
              
              
              
              (64,179
              )**Net
                  Decrease in Cash and Cash Equivalents**
              
              
              (254
              )
              
              
              (130
              )**Cash
                  and Cash Equivalents at Beginning of Period**
              
              
              1,319
              
              
              
              940**Cash
                  and Cash Equivalents at End of Period**
              
              $
              1,065
              
              
              $
              810**SUPPLEMENTARY
                  INFORMATION**Cash
                  Paid for Interest, Net of Capitalized Amounts
              
              $
              31,557
              
              
              $
              32,374Net
                  Cash Paid for Income Taxes
              
              
              1,704
              
              
              
              10,713Noncash
                  Acquisitions Under Capital Leases
              
              
              1,347
              
              
              
              1,648Construction
                  Expenditures Included in Accounts Payable at June 30,
              
              
              30,659
              
              
              
              12,601Noncash
                  Assumption of Liabilities Related to Acquisition of Darby
                  Plant
              
              
              2,339
              
              
              
              -*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**
                **Reference**Significant
                  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
                  7Income
                  Taxes
              Note
                  8Financing
                  Activities
              Note
                  9
 
 
 
 
 
 
 
     
  
 **INDIANA
        MICHIGAN POWER COMPANY**
 **AND
        SUBSIDIARIES**
             
 **INDIANA
        MICHIGAN POWER COMPANY AND SUBSIDIARIES**
 **MANAGEMENT’S
        NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS**
 
 **Results
        of Operations**
 
 Second
        Quarter of 2007 Compared to Second Quarter of 2006
 
 **Reconciliation
        of Second Quarter of 2006 to Second Quarter of 2007**
 **Net
        Income**
 **(in
        millions)**
 
 **Second
                  Quarter of 2006**
              
              
              
              
              $
              29**Changes
                  in Gross Margin:**Retail
                  Margins
              
              
              (7
              )FERC
                  Municipals and Cooperatives
              
              
              16Off-system
                  Sales
              
              
              6Transmission
                  Revenues
              
              
              6Other
              
              
              2**Total
                  Change in Gross Margin**
              
              
              
              
              
              
              23**Changes
                  in Operating Expenses and Other:**Other
                  Operation and Maintenance
              
              
              (13
              )Depreciation
                  and Amortization
              
              
              (3
              )Other
                  Income
              
              
              (1
              )Interest
                  Expense
              
              
              (2
              )**Total
                  Change in Operating Expenses and Other**
              
              
              
              
              
              
              (19
              )Income
                  Tax Expense
              
              
              
              
              
              
              (3
              )**Second
                  Quarter of 2007**
              
              
              
              
              
              $
              30
 
 Net
        Income increased $1 million to $30 million in 2007.  The key drivers
        of the increase were a $23 million increase in Gross Margin offset by a $19
        million increase in Operating Expenses and Other and a $3 million increase
        in
        Income Tax Expense.
 
 The
        major
        components of the increase in Gross Margin, defined as revenues less the
        related
        direct cost of fuel, including consumption of chemicals and emissions
        allowances, and purchased power were as follows:
 
 ·
              Retail
                  Margins decreased $7 million primarily due to a $12 million reduction
                  in
                  capacity settlement revenues under the Interconnection Agreement
                  reflecting I&M’s new peak demand in July 2006 and lower revenues from
                  financial transmission rights, net of congestion, of $7 million
                  due to
                  fewer constraints in the PJM market.  Higher retail sales of $14
                  million reflecting favorable weather conditions partially offset
                  the
                  decreases.  Heating and cooling degree days increased
                  significantly in both the Indiana and Michigan
                  jurisdictions.·
              FERC
                  Municipals and Cooperatives margins increased $16 million due to
                  the
                  addition of new municipal contracts including new rates and increased
                  demand effective July 2006 and January 2007.·
              Margins
                  from Off-system Sales increased $6 million primarily due to higher
                  power
                  prices in the east and higher trading margins.·
              Transmission
                  Revenues increased $6 million primarily due to a provision recorded
                  in the
                  second quarter of 2006 for potential SECA refunds.  See
                  “Transmission Rate Proceedings at the FERC” section of Note
                  3.
 
 Operating
        Expenses and Other changed between years as follows:
 
 ·
              Other
                  Operation and Maintenance expenses increased $13 million primarily
                  due to
                  a $7 million increase in coal-fired steam plant maintenance expenses
                  resulting from a planned outage at the Rockport Plant and
                  a   $4 million increase in transmission expense due to
                  reduced credits under the Transmission Equalization
                  Agreement.  Credits decreased due to I&M’s July 2006 peak
                  and due to APCo’s addition of the Wyoming-Jacksons Ferry 765 kV line,
                  which was energized and placed in service in June 2006 thus decreasing
                  I&M’s share of the transmission investment pool.·
              Depreciation
                  and Amortization expense increased $3 million primarily due to
                  a $2
                  million increase in amortization related to capitalized software
                  development costs and a $1 million increase in depreciation related
                  to
                  capital additions.·
              Interest
                  Expense increased $2 million primarily due to an increase in outstanding
                  long-term debt and higher interest
                  rates.
 
 *Income
        Taxes*
 
 Income
        Tax Expense increased $3 million primarily due to an increase in pretax book
        income and state income taxes.
 
 Six
        Months Ended June 30, 2007 Compared to Six Months Ended June 30,
        2006
 
 **Reconciliation
        of Six Months Ended June 30, 2006 to Six Months Ended June 30,
        2007**
 **Net
        Income**
 **(in
        millions)**
 
 **Six
                  Months Ended June 30, 2006**
              
              
              
              
              $
              86**Changes
                  in Gross Margin:**Retail
                  Margins
              
              
              (30
              )FERC
                  Municipals and Cooperatives
              
              
              25Off-system
                  Sales
              
              
              2Transmission
                  Revenues
              
              
              4Other
              
              
              (5
              )**Total
                  Change in Gross Margin**
              
              
              
              
              
              
              (4
              )**Changes
                  in Operating Expenses and Other:**Other
                  Operation and Maintenance
              
              
              (20
              )Depreciation
                  and Amortization
              
              
              (10
              )Taxes
                  Other Than Income Taxes
              
              
              1Other
                  Income
              
              
              (2
              )Interest
                  Expense
              
              
              (4
              )**Total
                  Change in Operating Expenses and Other**
              
              
              
              
              
              
              (35
              )Income
                  Tax Expense
              
              
              
              
              
              
              12**Six
                  Months Ended June 30, 2007**
              
              
              
              
              
              $
              59
 
 Net
        Income decreased $27 million to $59 million in 2007.  The key drivers
        of the decrease were a $4 million decrease in Gross Margin and a $35 million
        increase in Operating Expenses and Other partially offset by a $12 million
        decrease in Income Tax Expense.
 
 The
        major
        components of the decrease in Gross Margin, defined as revenues less the
        related
        direct cost of fuel, including consumption of chemicals and emissions
        allowances, and purchased power, were as follows:
 
 ·
              Retail
                  Margins decreased $30 million primarily due to a $35 million reduction
                  in
                  capacity settlement revenues under the Interconnection Agreement
                  reflecting I&M’s new peak demand in July 2006 and lower revenues from
                  financial transmission rights, net of congestion, of $16 million
                  due to
                  fewer constraints in the PJM market.  Higher retail sales of $27
                  million reflecting favorable weather conditions partially offset
                  the
                  decreases.  Heating and cooling degree days increased
                  significantly in both the Indiana and Michigan
                  jurisdictions.·
              FERC
                  Municipals and Cooperatives margins increased $25 million due to
                  the
                  addition of new municipal contracts including new rates and increased
                  demand effective July 2006 and January 2007.·
              Transmission
                  Revenues increased $4 million primarily due to a provision recorded
                  in the
                  second quarter of 2006 for potential SECA refunds.  See
                  “Transmission Rate Proceedings at the FERC” section of Note
                  3.·
              Other
                  revenues decreased $5 million primarily due to decreased River
                  Transportation Division (RTD) revenues for barging coal and decreased
                  gains on sales of emission allowances.  RTD related expenses
                  which offset the RTD revenue decrease are included in Other Operation
                  on
                  the Condensed Consolidated Statements of Income resulting in earning
                  only
                  a return approved under regulatory
                  order.
 
 Operating
        Expenses and Other changed between years as follows:
 
 ·
              Other Operation
                  and Maintenance expenses increased $20 million primarily due to
                  a $10
                  million increase in coal-fired plant maintenance expenses resulting
                  from
                  planned outages at Rockport and Tanners Creek plants and a $10
                  million
                  increase in transmission expense due to reduced credits under the
                  Transmission Equalization Agreement.  Credits decreased due to
                  I&M’s July 2006 peak and due to APCo’s addition of the
                  Wyoming-Jacksons Ferry 765 kV line, which was energized and placed
                  in
                  service in June 2006 thus decreasing I&M’s share of the transmission
                  investment pool.·
              Depreciation
                  and Amortization expense increased $10 million primarily due to
                  a $6
                  million increase in depreciation related to capital additions and
                  a $4
                  million increase in amortization related to capitalized software
                  development costs.·
              Interest
                  Expense increased $4 million primarily due to an increase in outstanding
                  long-term debt and higher interest
                  rates.
 
 *Income
        Taxes*
 
 Income
        Tax Expense decreased $12 million primarily due to a decrease in pretax book
        income.
 
 **Critical
        Accounting Estimates**
 
 See
        the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
        Analysis of Registrant Subsidiaries” in the 2006 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 the complete discussion and analysis within AEP’s
“Quantitative and Qualitative Disclosures About Risk Management Activities”
section for disclosures about risk management activities.
 
 **VaR
        Associated with Debt Outstanding**
 
 Management
        utilizes a VaR model to measure interest rate market risk exposure. The interest
        rate VaR model is based on a Monte Carlo simulation with a 95% confidence
        level
        and a one-year holding period.  The risk of potential loss in fair
        value attributable to exposure to interest rates primarily related to long-term
        debt with fixed interest rates was $115 million and $93 million at June 30,
        2007
        and December 31, 2006, respectively. Management would not expect to liquidate
        the entire debt portfolio in a one-year holding period; therefore, a near
        term
        change in interest rates should not negatively affect results of operations
        or
        consolidated financial position.
   
 **INDIANA
        MICHIGAN POWER COMPANY AND SUBSIDIARIES**
 **CONDENSED
        CONSOLIDATED STATEMENTS OF INCOME**
 **For
        the Three and Six Months Ended June 30, 2007 and 2006**
 **(in
        thousands)**
 **(Unaudited)**
 
 **Three
                  Months Ended**
              
              
              **Six
                  Months Ended****2007**
              
              
              **2006**
              
              
              **2007**
              
              
              **2006****REVENUES**Electric
                  Generation, Transmission and Distribution
              
              $
              402,152
              
              
              $
              371,581
              
              
              $
              807,316
              
              
              $
              775,350Sales
                  to AEP Affiliates
              
              
              62,962
              
              
              
              80,401
              
              
              
              130,391
              
              
              
              168,935Other
                  – Affiliated
              
              
              14,571
              
              
              
              9,841
              
              
              
              27,238
              
              
              
              24,935Other
                  – Nonaffiliated
              
              
              6,352
              
              
              
              7,631
              
              
              
              13,961
              
              
              
              16,013**TOTAL**
              
              
              486,037
              
              
              
              469,454
              
              
              
              978,906
              
              
              
              985,233**EXPENSES**Fuel
                  and Other Consumables Used for Electric Generation
              
              
              90,650
              
              
              
              96,147
              
              
              
              186,767
              
              
              
              185,599Purchased
                  Electricity for Resale
              
              
              19,310
              
              
              
              15,533
              
              
              
              37,250
              
              
              
              26,543Purchased
                  Electricity from AEP Affiliates
              
              
              75,791
              
              
              
              80,830
              
              
              
              153,304
              
              
              
              167,252Other
                  Operation
              
              
              117,311
              
              
              
              109,388
              
              
              
              238,044
              
              
              
              221,005Maintenance
              
              
              45,725
              
              
              
              40,352
              
              
              
              88,155
              
              
              
              85,571Depreciation
                  and Amortization
              
              
              53,890
              
              
              
              50,778
              
              
              
              110,197
              
              
              
              100,493Taxes
                  Other Than Income Taxes
              
              
              19,238
              
              
              
              18,965
              
              
              
              37,232
              
              
              
              37,871**TOTAL**
              
              
              421,915
              
              
              
              411,993
              
              
              
              850,949
              
              
              
              824,334**OPERATING
                  INCOME**
              
              
              64,122
              
              
              
              57,461
              
              
              
              127,957
              
              
              
              160,899**Other
                  Income (Expense):**Interest
                  Income
              
              
              707
              
              
              
              663
              
              
              
              1,295
              
              
              
              1,357Allowance
                  for Equity Funds Used During Construction
              
              
              727
              
              
              
              1,440
              
              
              
              992
              
              
              
              3,364Interest
                  Expense
              
              
              (19,611
              )
              
              
              (17,902
              )
              
              
              (39,432
              )
              
              
              (35,435
              )**INCOME
                  BEFORE INCOME TAXES**
              
              
              45,945
              
              
              
              41,662
              
              
              
              90,812
              
              
              
              130,185Income
                  Tax Expense
              
              
              15,910
              
              
              
              13,137
              
              
              
              31,314
              
              
              
              43,782**NET
                  INCOME**
              
              
              30,035
              
              
              
              28,525
              
              
              
              59,498
              
              
              
              86,403Preferred
                  Stock Dividend Requirements
              
              
              85
              
              
              
              85
              
              
              
              170
              
              
              
              170**EARNINGS
                  APPLICABLE TO COMMON STOCK**
              
              $
              29,950
              
              
              $
              28,440
              
              
              $
              59,328
              
              
              $
              86,233
 
 *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 Six Months Ended June 30, 2007 and 2006**
 **(in
        thousands)**
 **(Unaudited)**
 
 **Common
                  Stock**
              
              
              **Paid-in
                  Capital**
              
              
              **Retained
                  Earnings**
              
              
              **Accumulated
                  Other Comprehensive Income (Loss)**
              
              
              **Total****DECEMBER
                  31, 2005**
              
              $
              56,584
              
              
              $
              861,290
              
              
              $
              305,787
              
              
              $
              (3,569
              )
              
              $
              1,220,092Common
                  Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (20,000
              )
              
              
              
              
              
              
              (20,000
              )Preferred
                  Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (170
              )
              
              
              
              
              
              
              (170
              )**TOTAL**
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              1,199,922**COMPREHENSIVE
                  INCOME****Other
                  Comprehensive Income, Net of Taxes:**Cash
                  Flow Hedges, Net of Tax of $4,685
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              8,701
              
              
              
              8,701**NET
                  INCOME**
              
              
              
              
              
              
              
              
              
              
              86,403
              
              
              
              
              
              
              
              86,403**TOTAL
                  COMPREHENSIVE INCOME**
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              95,104**JUNE
                  30, 2006**
              
              $
              56,584
              
              
              $
              861,290
              
              
              $
              372,020
              
              
              $
              5,132
              
              
              $
              1,295,026**DECEMBER
                  31, 2006**
              
              $
              56,584
              
              
              $
              861,290
              
              
              $
              386,616
              
              
              $
              (15,051
              )
              
              $
              1,289,439FIN
                  48 Adoption, Net of Tax
              
              
              
              
              
              
              
              
              
              
              327
              
              
              
              
              
              
              
              327Common
                  Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (20,000
              )
              
              
              
              
              
              
              (20,000
              )Preferred
                  Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (170
              )
              
              
              
              
              
              
              (170
              )Gain
                  on Reacquired Preferred Stock
              
              
              
              
              
              
              1
              
              
              
              
              
              
              
              
              
              
              
              1**TOTAL**
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              1,269,597**COMPREHENSIVE
                  INCOME****Other
                  Comprehensive Income, Net of Taxes:**Cash
                  Flow Hedges, Net of Tax of $649
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              1,206
              
              
              
              1,206**NET
                  INCOME**
              
              
              
              
              
              
              
              
              
              
              59,498
              
              
              
              
              
              
              
              59,498**TOTAL
                  COMPREHENSIVE INCOME**
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              60,704**JUNE
                  30, 2007**
              
              $
              56,584
              
              
              $
              861,291
              
              
              $
              426,271
              
              
              $
              (13,845
              )
              
              $
              1,330,301
 
 *See
        Condensed Notes to Condensed Financial Statements of Registrant
        Subsidiaries.*
   
 **INDIANA
        MICHIGAN POWER COMPANY AND SUBSIDIARIES**
 **CONDENSED
        CONSOLIDATED BALANCE SHEETS**
 **ASSETS**
 **June
        30, 2007 and December 31, 2006**
 **(in
        thousands)**
 **(Unaudited)**
 
 **2007**
              
              
              **2006****CURRENT
                  ASSETS**Cash
                  and Cash Equivalents
              
              $
              607
              
              
              $
              1,369Accounts
                  Receivable:Customers
              
              
              74,465
              
              
              
              82,102Affiliated
                  Companies
              
              
              68,135
              
              
              
              108,288Accrued
                  Unbilled Revenues
              
              
              3,947
              
              
              
              2,206Miscellaneous
              
              
              1,648
              
              
              
              1,838Allowance
                  for Uncollectible Accounts
              
              
              (729
              )
              
              
              (601
              )Total
                  Accounts Receivable
              
              
              147,466
              
              
              
              193,833Fuel
              
              
              51,416
              
              
              
              64,669Materials
                  and Supplies
              
              
              137,849
              
              
              
              129,953Risk
                  Management Assets
              
              
              47,684
              
              
              
              69,752Accrued
                  Tax Benefits
              
              
              -
              
              
              
              27,378Prepayments
                  and Other
              
              
              9,740
              
              
              
              15,170**TOTAL**
              
              
              394,762
              
              
              
              502,124**PROPERTY,
                  PLANT AND EQUIPMENT**Electric:Production
              
              
              3,402,290
              
              
              
              3,363,813Transmission
              
              
              1,062,935
              
              
              
              1,047,264Distribution
              
              
              1,159,964
              
              
              
              1,102,033Other
                  (including nuclear fuel and coal mining)
              
              
              556,848
              
              
              
              529,727Construction
                  Work in Progress
              
              
              150,684
              
              
              
              183,893**Total**
              
              
              6,332,721
              
              
              
              6,226,730Accumulated
                  Depreciation, Depletion and Amortization
              
              
              2,970,351
              
              
              
              2,914,131**TOTAL
                  - NET**
              
              
              3,362,370
              
              
              
              3,312,599**OTHER
                  NONCURRENT ASSETS**Regulatory
                  Assets
              
              
              274,468
              
              
              
              314,805Spent
                  Nuclear Fuel and Decommissioning Trusts
              
              
              1,310,871
              
              
              
              1,248,319Long-term
                  Risk Management Assets
              
              
              48,908
              
              
              
              59,137Deferred
                  Charges and Other
              
              
              108,343
              
              
              
              109,453**TOTAL**
              
              
              1,742,590
              
              
              
              1,731,714**TOTAL
                  ASSETS**
              
              $
              5,499,722
              
              
              $
              5,546,437
 
 *See
        Condensed Notes to Condensed Financial Statements of Registrant
        Subsidiaries.*
 
 
 **INDIANA
        MICHIGAN POWER COMPANY AND SUBSIDIARIES**
 **CONDENSED
        CONSOLIDATED BALANCE SHEETS**
 **LIABILITIES
        AND SHAREHOLDERS’ EQUITY**
 **June
        30, 2007 and December 31, 2006**
 **(Unaudited)**
 
 **2007**
              
              
              **2006****CURRENT
                  LIABILITIES**
              
              **(in
                  thousands)**Advances
                  from Affiliates
              
              $
              14,941
              
              
              $
              91,173Accounts
                  Payable:General
              
              
              120,551
              
              
              
              146,733Affiliated
                  Companies
              
              
              53,583
              
              
              
              65,497Long-term
                  Debt Due Within One Year – Nonaffiliated
              
              
              -
              
              
              
              50,000Risk
                  Management Liabilities
              
              
              33,508
              
              
              
              52,083Customer
                  Deposits
              
              
              36,490
              
              
              
              34,946Accrued
                  Taxes
              
              
              100,860
              
              
              
              59,652Other
              
              
              113,497
              
              
              
              128,461**TOTAL**
              
              
              473,430
              
              
              
              628,545**NONCURRENT
                  LIABILITIES**Long-term
                  Debt – Nonaffiliated
              
              
              1,561,600
              
              
              
              1,505,135Long-term
                  Risk Management Liabilities
              
              
              33,545
              
              
              
              42,641Deferred
                  Income Taxes
              
              
              305,148
              
              
              
              335,000Regulatory
                  Liabilities and Deferred Investment Tax Credits
              
              
              784,082
              
              
              
              753,402Asset
                  Retirement Obligations
              
              
              831,051
              
              
              
              809,853Deferred
                  Credits and Other
              
              
              172,485
              
              
              
              174,340**TOTAL**
              
              
              3,687,911
              
              
              
              3,620,371**TOTAL
                  LIABILITIES**
              
              
              4,161,341
              
              
              
              4,248,916Cumulative
                  Preferred Stock Not Subject to Mandatory Redemption
              
              
              8,080
              
              
              
              8,082Commitments
                  and Contingencies (Note 4)**COMMON
                  SHAREHOLDER’S EQUITY**Common
                  Stock – No Par Value:Authorized
                  – 2,500,000 SharesOutstanding
                  – 1,400,000 Shares
              
              
              56,584
              
              
              
              56,584Paid-in
                  Capital
              
              
              861,291
              
              
              
              861,290Retained
                  Earnings
              
              
              426,271
              
              
              
              386,616Accumulated
                  Other Comprehensive Income (Loss)
              
              
              (13,845
              )
              
              
              (15,051
              )**TOTAL**
              
              
              1,330,301
              
              
              
              1,289,439**TOTAL
                  LIABILITIES AND SHAREHOLDERS’ EQUITY**
              
              $
              5,499,722
              
              
              $
              5,546,437
 
 *See
        Condensed Notes to Condensed Financial Statements of Registrant
        Subsidiaries.*
   
 **INDIANA
        MICHIGAN POWER COMPANY AND SUBSIDIARIES**
 **CONDENSED
        CONSOLIDATED STATEMENTS OF CASH FLOWS**
 **For
        the Six Months Ended June 30, 2007 and 2006**
 **(in
        thousands)**
 **(Unaudited)**
 
 **2007**
              
              
              **2006****OPERATING
                  ACTIVITIES****Net
                  Income**
              
              $
              59,498
              
              
              $
              86,403**Adjustments
                  for Noncash Items:**Depreciation
                  and Amortization
              
              
              110,197
              
              
              
              100,493Deferred
                  Income Taxes
              
              
              (9,547
              )
              
              
              9,562Deferred
                  Investment Tax Credits
              
              
              (3,471
              )
              
              
              (3,640
              )Amortization
                  (Deferral) of Incremental Nuclear Refueling Outage Expenses,
                  Net
              
              
              23,099
              
              
              
              (12,111
              )Amortization
                  of Nuclear Fuel
              
              
              33,003
              
              
              
              24,928Mark-to-Market
                  of Risk Management Contracts
              
              
              5,607
              
              
              
              (634
              )Change
                  in Other Noncurrent Assets
              
              
              (12,308
              )
              
              
              7,630Change
                  in Other Noncurrent Liabilities
              
              
              22,896
              
              
              
              14,701**Changes
                  in Certain Components of Working Capital:**Accounts
                  Receivable, Net
              
              
              36,805
              
              
              
              56,894Fuel,
                  Materials and Supplies
              
              
              9,911
              
              
              
              (12,092
              )Accounts
                  Payable
              
              
              (46,049
              )
              
              
              4,221Customer
                  Deposits
              
              
              1,544
              
              
              
              (14,867
              )Accrued
                  Taxes, Net
              
              
              72,977
              
              
              
              28,256Other
                  Current Assets
              
              
              4,595
              
              
              
              21,921Other
                  Current Liabilities
              
              
              (17,858
              )
              
              
              (21,559
              )**Net
                  Cash Flows From Operating Activities**
              
              
              290,899
              
              
              
              290,106**INVESTING
                  ACTIVITIES**Construction
                  Expenditures
              
              
              (124,252
              )
              
              
              (169,491
              )Purchases
                  of Investment Securities
              
              
              (409,163
              )
              
              
              (434,212
              )Sales
                  of Investment Securities
              
              
              370,986
              
              
              
              405,716Acquisitions
                  of Nuclear Fuel
              
              
              (30,498
              )
              
              
              (35,195
              )Other
              
              
              292
              
              
              
              2,273**Net
                  Cash Flows Used For Investing Activities**
              
              
              (192,635
              )
              
              
              (230,909
              )**FINANCING
                  ACTIVITIES**Issuance
                  of Long-term Debt – Nonaffiliated
              
              
              -
              
              
              
              49,745Change
                  in Advances from Affiliates, Net
              
              
              (76,232
              )
              
              
              (35,953
              )Retirement
                  of Long-term Debt – Nonaffiliated
              
              
              -
              
              
              
              (50,000
              )Retirement
                  of Cumulative Preferred Stock
              
              
              (2
              )
              
              
              -Principal
                  Payments for Capital Lease Obligations
              
              
              (2,622
              )
              
              
              (3,139
              )Dividends
                  Paid on Common Stock
              
              
              (20,000
              )
              
              
              (20,000
              )Dividends
                  Paid on Cumulative Preferred Stock
              
              
              (170
              )
              
              
              (170
              )**Net
                  Cash Flows Used For Financing Activities**
              
              
              (99,026
              )
              
              
              (59,517
              )**Net
                  Decrease in Cash and Cash Equivalents**
              
              
              (762
              )
              
              
              (320
              )**Cash
                  and Cash Equivalents at Beginning of Period**
              
              
              1,369
              
              
              
              854**Cash
                  and Cash Equivalents at End of Period**
              
              $
              607
              
              
              $
              534**SUPPLEMENTARY
                  INFORMATION**Cash
                  Paid for Interest, Net of Capitalized Amounts
              
              $
              32,082
              
              
              $
              32,959Net
                  Cash Paid (Received) for Income Taxes
              
              
              (20,001
              )
              
              
              12,031Noncash
                  Acquisitions Under Capital Leases
              
              
              1,160
              
              
              
              3,185Construction
                  Expenditures Included in Accounts Payable at June 30,
              
              
              24,145
              
              
              
              18,031Acquisition
                  of Nuclear Fuel in Accounts Payable at June 30,
              
              
              30,867
              
              
              
              25,780*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**
                **Reference**Significant
                  Accounting Matters
              Note
                  1New
                  Accounting Pronouncements and Extraordinary Item
              Note
                  2Rate
                  Matters
              Note
                  3Commitments,
                  Guarantees and Contingencies
              Note
                  4Benefit
                  Plans
              Note
                  6Business
                  Segments
              Note
                  7Income
                  Taxes
              Note
                  8Financing
                  Activities
              Note
                  9
 
 
  
  
      
 
 
 
 **OHIO
        POWER COMPANY CONSOLIDATED**
                
 **OHIO
        POWER COMPANY CONSOLIDATED**
 **MANAGEMENT’S
        FINANCIAL DISCUSSION AND ANALYSIS**
 
 **Results
        of Operations**
 
 Second
        Quarter of 2007 Compared to Second Quarter of 2006
 
 **Reconciliation
        of Second Quarter of 2006 to Second Quarter of 2007**
 **Net
        Income**
 **(in
        millions)**
 
 **Second
                  Quarter of 2006**
              
              
              
              
              $
              23**Changes
                  in Gross Margin:**Retail
                  Margins
              
              
              59Off-system
                  Sales
              
              
              4Transmission
                  Revenues
              
              
              4Other
              
              
              (4
              )**Total
                  Change in Gross Margin**
              
              
              
              
              
              
              63**Changes
                  in Operating Expenses and Other:**Other
                  Operation and Maintenance
              
              
              33Depreciation
                  and Amortization
              
              
              (7
              )Taxes
                  Other Than Income Taxes
              
              
              (2
              )Interest
                  Expense
              
              
              (9
              )**Total
                  Change in Operating Expenses and Other**
              
              
              
              
              
              
              15Income
                  Tax Expense
              
              
              
              
              
              
              (27
              )**Second
                  Quarter of 2007**
              
              
              
              
              
              $
              74
 
 Net
        Income increased $51 million to $74 million in 2007.  The key drivers
        of the increase were a $63 million increase in Gross Margin and a $15 million
        decrease in Operating Expenses and Other offset by a $27 million increase
        in
        Income Tax Expense.
 
 The
        major
        components of the increase in Gross Margin, defined as revenues less the
        related
        direct cost of fuel, including consumption of chemicals and emissions
        allowances, and purchased power were as follows:
 
 ·
              Retail
                  Margins increased $59 million primarily due to the
                  following:·
              A
                  $16 million increase in capacity settlements under the Interconnection
                  Agreement related to certain affiliates’ peaks and the June 2006
                  expiration of OPCo’s supplemental capacity and energy obligation to
                  Buckeye Power, Inc. under the Cardinal Station
                  Agreement.·
              A
                  $14 million increase in industrial revenue primarily due to the
                  addition
                  of Ormet, a major industrial customer.  The addition of Ormet
                  resulted in a $12 million increase in industrial sales.  See
                  “Ormet” section of Note 3.·
              A
                  $13 million increase in rate revenues primarily related to an $11
                  million
                  increase in OPCo’s RSP, a $3 million increase related to rate recovery of
                  storm costs and a $3 million increase related to rate recovery
                  of IGCC
                  preconstruction costs.  See “Ohio Rate Matters” section of Note
                  3.  The increase in rate recovery of storm costs was offset by
                  the amortization of deferred expenses in Other Operation and
                  Maintenance.  The increase in rate recovery of IGCC
                  preconstruction costs was offset by the amortization of deferred
                  expenses
                  in Depreciation and Amortization.·
              A
                  $13 million increase in residential and commercial revenue primarily
                  due
                  to a 71% increase in cooling degree days.·
              A
                  $12 million increase in fuel margins.·
              Margins
                  from Off-system Sales increased $4 million primarily due to a $15
                  million
                  increase in trading margins as the result of higher power prices
                  in the
                  east offset by an $8 million decrease related to OPCo’s purchase power and
                  sale agreement with Dow Chemical Company (Dow) which ended in November
                  2006 and a $3 million decrease in OPCo’s allocated share of off-system
                  sales revenue due to an affiliate’s new peak.  Margins related
                  to Dow were offset by a corresponding decrease in Other Operation
                  and
                  Maintenance expenses.  See “OPCo Indemnification Agreement with
                  AEP Resources” section of Note 16 in the 2006 Annual Report for further
                  discussion related to Dow.·
              Transmission
                  Revenues increased $4 million primarily due to a provision recorded
                  in the
                  second quarter of 2006 related to potential SECA refunds.  See
                  “Transmission Rate Proceedings at the FERC” section of Note
                  3.·
              Other
                  revenues decreased $4 million primarily due to a $3 million decrease
                  related to the April 2006 expiration of an obligation to sell supplemental
                  capacity and energy to Buckeye Power, Inc. under the Cardinal Station
                  Agreement and a $1 million decrease in gains on sales of emission
                  allowances.
 
 Operating
        Expenses and Other changed between years as follows:
 
 ·
              Other
                  Operation and Maintenance expenses decreased $33 million primarily
                  due
                  to:·
              An
                  $18 million decrease in maintenance from planned and forced outages
                  at the
                  Gavin, Muskingum River, Kammer and Sporn Plants related to boiler
                  tube
                  inspections in 2006.·
              An
                  $8 million decrease due to the absence of maintenance and rental
                  expenses
                  related to OPCo’s purchase power and sale agreement with Dow which ended
                  in November 2006.  The decrease in Other Operation and
                  Maintenance expenses related to Dow were offset by a corresponding
                  decrease in margins from Off-system Sales.·
              A
                  $5 million decrease in removal costs at the Mitchell, Sporn and
                  Amos
                  Plants related to outages in 2006.These
                  amounts were offset by:·
              A
                  $3 million increase in overhead line expenses due in part to the
                  amortization of deferred storm expenses recovered through a cost-recovery
                  rider.  The increase was offset by a corresponding increase in
                  Retail Margins.·
              Depreciation
                  and Amortization increased $7 million primarily due to a $6 million
                  increase in depreciation related to environmental improvements
                  placed in
                  service at the Mitchell Plant and the amortization of IGCC preconstruction
                  costs of $3 million.  These increases were offset by a $2
                  million decrease in amortization of a regulatory liability related
                  to
                  Ormet.  See “Ormet” section of Note 3.  The increase
                  in amortization of IGCC preconstruction costs was offset by a
                  corresponding increase in Retail Margins.·
              Interest
                  Expense increased $9 million due to long-term debt issuances since
                  May
                  2006.
 
 *Income
        Taxes*
 
 Income
        Tax Expense increased $27 million primarily due to an increase in pretax
        book
        income.
 
 Six
        Months Ended June 30, 2007 Compared to Six Months Ended June 30,
        2006
 
 **Reconciliation
        of Six Months Ended June 30, 2006 to Six Months Ended June 30,
        2007**
 **Net
        Income**
 **(in
        millions)**
 
 **Six
                  Months Ended June 30, 2006**
              
              
              
              
              $
              118**Changes
                  in Gross Margin:**Retail
                  Margins
              
              
              118Off-system
                  Sales
              
              
              (17
              )Transmission
                  Revenues
              
              
              (6
              )Other
              
              
              (14
              )**Total
                  Change in Gross Margin**
              
              
              
              
              
              
              81**Changes
                  in Operating Expenses and Other:**Other
                  Operation and Maintenance
              
              
              5Depreciation
                  and Amortization
              
              
              (12
              )Taxes
                  Other Than Income Taxes
              
              
              (3
              )Interest
                  Expense
              
              
              (12
              )**Total
                  Change in Operating Expenses and Other**
              
              
              
              
              
              
              (22
              )Income
                  Tax Expense
              
              
              
              
              
              
              (23
              )**Six
                  Months Ended June 30, 2007**
              
              
              
              
              
              $
              154
 
 Net
        Income increased $36 million to $154 million in 2007.  The key driver
        of the increase was an $81 million increase in Gross Margin offset by a $23
        million increase in Income Tax Expense and a $22 million increase in Operating
        Expenses and Other.
 
 The
        major
        components of the increase in Gross Margin, defined as revenues less the
        related
        direct cost of fuel, including consumption of chemicals and emissions
        allowances, and purchased power were as follows:
 
 ·
              Retail
                  Margins increased $118 million primarily due to the
                  following:·
              A
                  $41 million increase in capacity settlements under the Interconnection
                  Agreement related to certain affiliates’ peaks and the June 2006
                  expiration of OPCo’s supplemental capacity and energy obligation to
                  Buckeye Power, Inc. under the Cardinal Station
                  Agreement.·
              A
                  $35 million increase in rate revenues primarily related to a $20
                  million
                  increase in OPCo’s RSP, a $6 million increase related to rate recovery of
                  storm costs and a $6 million increase related to rate recovery
                  of IGCC
                  preconstruction costs.  See “Ohio Rate Matters” section of Note
                  3.  The increase in rate recovery of storm costs was offset by
                  the amortization of deferred expenses in Other Operation and
                  Maintenance.  The increase in rate recovery of IGCC
                  preconstruction costs was offset by the amortization of deferred
                  expenses
                  in Depreciation and Amortization.·
              A
                  $20 million increase in residential and commercial revenue primarily
                  due
                  to a 73% increase in cooling degree days.·
              An
                  $18 million increase in industrial revenue due to the addition
                  of Ormet, a
                  major industrial customer.  See “Ormet” section of Note
                  3.These
                  increases were partially offset by:·
              An
                  $8 million decrease in revenues associated with SO2
                  allowances
                  received in 2006 from Buckeye Power, Inc. under the Cardinal Station
                  Allowances Agreement.·
              Margins
                  from Off-system Sales decreased $17 million primarily due to a
                  $20 million
                  decrease in OPCo’s allocated share of off-system sales revenues due to an
                  affiliate’s new peak and a $9 million decrease in margins related to
                  OPCo’s purchase power and sale agreement with Dow which ended in November
                  2006.  These decreases were offset by higher trading margins of
                  $11 million as the result of higher power prices in the east and
                  a change
                  in the allocation of off-system sales margins under the SIA effective
                  April 1, 2006.  Margins related to Dow were offset by a
                  corresponding decrease in Other Operation and Maintenance
                  expenses.·
              Transmission
                  Revenues decreased $6 million primarily due to the elimination
                  of SECA
                  revenues as of April 1, 2006 offset by a provision recorded in
                  the second
                  quarter of 2006 related to potential SECA refunds.  See
                  “Transmission Rate Proceedings at the FERC” section of Note
                  3.·
              Other
                  revenues decreased $14 million primarily due to a $7 million decrease
                  related to the April 2006 expiration of an obligation to sell supplemental
                  capacity and energy to Buckeye Power, Inc. under the Cardinal Station
                  Agreement and a $4 million decrease in gains on sales of emission
                  allowances.
 
 Operating
        Expenses and Other changed between years as follows:
 
 ·
              Other
                  Operation and Maintenance expenses decreased $5 million primarily
                  due to
                  the following:·
              A
                  $16 million decrease in maintenance from planned and forced outages
                  at the
                  Muskingum River, Kammer and Sporn Plants related to boiler tube
                  inspections in 2006.·
              A
                  $9 million decrease in maintenance and rental expenses related
                  to OPCo’s
                  purchase power and sale agreement with Dow which ended in November
                  2006.  This decrease was offset by a corresponding decrease in
                  margins from Off-system Sales.These
                  decreases were partially offset by:·
              A
                  $7 million increase in removal costs related to planned and forced
                  outages
                  at the Gavin, Mitchell and Cardinal Plants.·
              A
                  $6 million increase in overhead line expenses due in part to the
                  amortization of deferred storm expenses recovered through a cost-recovery
                  rider.  The increase was offset by a corresponding increase in
                  Retail Margins.·
              A
                  $5 million increase due to the February 2006 adjustment of liabilities
                  related to sold coal companies.·
              Depreciation
                  and Amortization increased $12 million primarily due to a $9 million
                  increase in depreciation related to environmental improvements
                  placed in
                  service at the Mitchell Plant and the amortization of IGCC preconstruction
                  costs of $6 million in 2007.  These increases were offset by a
                  $3 million decrease in amortization of a regulatory liability related
                  to
                  Ormet.  See “Ormet” section of Note 3.  The increase
                  in amortization of IGCC preconstruction costs was offset by a
                  corresponding increase in Retail Margins.·
              Interest
                  Expense increased $12 million primarily due to a $15 million increase
                  related to long-term debt issuances since May 2006 offset by a
                  $5 million
                  increase in allowance for borrowed funds used during
                  construction.
 
 *Income
        Taxes*
 
 Income
        Tax Expense increased $23 million primarily due to an increase in pretax
        book
        income and state income taxes.
 
 **Financial
        Condition**
 
 **Credit
        Ratings**
 
 The
        rating agencies currently have OPCo on stable outlook. Current ratings are
        as
        follows:
 
 **Moody’s**
              
              **S&P**
              
              **Fitch**Senior
                  Unsecured Debt
              A3
              
              BBB
              
              BBB+
 
 **Cash
        Flow**
 
 Cash
        flows for the six months ended June 30, 2007 and 2006 were as
        follows:
 **2007**
              
              
              **2006****(in
                  thousands)****Cash
                  and Cash Equivalents at Beginning of Period**
              
              $
              1,625
              
              
              $
              1,240Cash
                  Flows From (Used For):Operating
                  Activities
              
              
              279,029
              
              
              
              321,944Investing
                  Activities
              
              
              (560,262
              )
              
              
              (512,468
              )Financing
                  Activities
              
              
              282,607
              
              
              
              190,274Net
                  Increase (Decrease) in Cash and Cash Equivalents
              
              
              1,374
              
              
              
              (250
              )**Cash
                  and Cash Equivalents at End of Period**
              
              $
              2,999
              
              
              $
              990
 
 *Operating
        Activities*
 
 Net
        Cash
        Flows From Operating Activities were $279 million in 2007.  OPCo
        produced Net Income of $154 million during the period and a noncash expense
        item
        of $169 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.  Accounts Payable had a $47 million cash
        outflow partially due to emission allowance payments in January
        2007.  Accrued Taxes, Net, had a $47 million cash inflow primarily due
        to an increase of federal income tax related accruals offset by temporary
        timing
        differences of payments for property taxes.  Fuel, Materials and
        Supplies had a $42 million cash outflow primarily due to an increase in coal
        inventory in preparation for the summer cooling season and an increase in
        materials related to projects at the Mitchell, Amos, Gavin and Sporn
        Plants.
 
 Net
        Cash
        Flows From Operating Activities were $322 million in 2006.  OPCo
        produced Net Income of $118 million during the period and a noncash expense
        item
        of $157 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 prior period activity in working capital
        primarily relates to a number of items.  Accounts Receivable, Net had
        a $98 million cash inflow primarily due to collected receivables from OPCo’s
        affiliates related to power sales, settled litigation and emission
        allowances.  Fuel, Materials and Supplies had a $56 million cash
        outflow primarily due to an increase in coal inventory in preparation for
        the
        summer cooling season.  Accounts Payable had a $43 million cash
        outflow primarily due to timing differences for payments to affiliates related
        to the AEP Power Pool.
 
 *Investing
        Activities*
 
 Net
        Cash
        Flows Used For Investing Activities were $560 million and $512 million in
        2007
        and 2006, respectively.  Construction Expenditures were $566 million
        and $482 million in 2007 and 2006, 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.  In January 2007, environmental upgrades were completed for
        Unit 2 at the Mitchell Plant.  For the remainder of 2007, OPCo expects
        construction expenditures to be approximately $265 million.
 
 *Financing
        Activities*
 
 Net
        Cash
        Flows From Financing Activities were $283 million in 2007.  OPCo
        issued Senior Unsecured Notes for $400 million and $65 million of Pollution
        Control Bonds.  OPCo repaid borrowings of $165 million from the
        Utility Money Pool.
 
 Net
        Cash
        Flows From Financing Activities were $190 million for 2006.  OPCo
        issued Senior Unsecured Notes for $350 million and $65 million of Pollution
        Control Bonds.  OPCo retired Notes Payable-Affiliated of $200
        million.  OPCo repaid borrowings of $70 million from the Utility Money
        Pool and received a Capital Contribution from Parent of $70
        million.
 
 **Financing
        Activity**
 
 Long-term
        debt issuances and retirements during the first six months of 2007
        were:
 
 Issuances
 **Principal**
                **Amount**
              
              **Interest**
              
              **Due****Type
                  of Debt**
              
              
              **Rate**
              
              **Date****(in
                  thousands)**
              
              **(%)**Pollution
                  Control Bonds
              
              $
              65,000
              
              4.90
              
              2037Senior
                  Unsecured Notes
              
              
              400,000
              
              Variable
              
              2010
 
 Retirements
 **Principal**
                **Amount**
              
              **Interest**
              
              **Due****Type
                  of Debt**
              
              
              **Rate**
              
              **Date****(in
                  thousands)**
              
              **(%)**Notes
                  Payable – Nonaffiliated
              
              $
              2,927
              
              6.81
              
              2008Notes
                  Payable – Nonaffiliated
              
              
              6,000
              
              6.27
              
              2009
 
 **Liquidity**
 
 OPCo
        has
        solid investment grade ratings, which provide ready access to capital markets
        in
        order to issue new debt, refinance short-term debt or refinance long-term
        debt
        maturities.  In addition, OPCo participates in the Utility Money Pool,
        which provides access to AEP’s liquidity.
 
 **Summary
        Obligation Information**
 
 A
        summary
        of contractual obligations is included in the 2006 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, 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 pending litigation and regulatory
        proceedings, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and
        Contingencies in the 2006 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 results of operations, 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 2006 Annual Report for a discussion
        of the estimates and judgments required for regulatory accounting, revenue
        recognition, the valuation of long-lived assets, pension and other
        postretirement benefits and the impact of new accounting
        pronouncements.
 
 **Adoption
        of New Accounting Pronouncements**
 
 See
        the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for a discussion of adoption of new accounting
        pronouncements.
   
 **QUANTITATIVE
        AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT
        ACTIVITIES**
 
 **Market
        Risks**
 
 Risk
        management assets and liabilities are managed by AEPSC as agent.  The
        related risk management policies and procedures are instituted and administered
        by AEPSC.  See complete discussion within AEP’s “Quantitative and
        Qualitative Disclosures About Risk Management Activities”
section.  The following tables provide information about AEP’s risk
        management activities’ effect on OPCo.
 
 **MTM
        Risk Management Contract Net Assets**
 
 The
        following two tables summarize the various mark-to-market (MTM) positions
        included in the condensed consolidated balance sheet as of June 30, 2007
        and the
        reasons for changes in total MTM value as compared to December 31,
        2006.
 
 **Reconciliation
        of MTM Risk Management Contracts to**
 **Condensed
        Consolidated Balance Sheet**
 **As
        of June 30, 2007**
 **(in
        thousands)**
 
 **MTM
                  Risk Management Contracts**
              
              
              **Cash
                  Flow Hedges**
              
              
              **DETM
                  Assignment (a)**
              
              
              **Total**Current
                  Assets
              
              $
              50,040
              
              
              $
              7,267
              
              
              $
              -
              
              
              $
              57,307Noncurrent
                  Assets
              
              
              55,122
              
              
              
              1,143
              
              
              
              -
              
              
              
              56,265**Total
                  MTM Derivative Contract Assets**
              
              
              105,162
              
              
              
              8,410
              
              
              
              -
              
              
              
              113,572Current
                  Liabilities
              
              
              (40,629
              )
              
              
              (174
              )
              
              
              (2,315
              )
              
              
              (43,118
              )Noncurrent
                  Liabilities
              
              
              (34,290
              )
              
              
              (56
              )
              
              
              (4,898
              )
              
              
              (39,244
              )**Total
                  MTM Derivative Contract****Liabilities**
              
              
              (74,919
              )
              
              
              (230
              )
              
              
              (7,213
              )
              
              
              (82,362
              )**Total
                  MTM Derivative Contract Net Assets
                  (Liabilities)**
              
              $
              30,243
              
              
              $
              8,180
              
              
              $
              (7,213
              )
              
              $
              31,210
 
 (a)
              See
                  “Natural Gas Contracts with DETM” section of Note 16 in the 2006 Annual
                  Report.
 
 **MTM
        Risk Management Contract Net Assets**
 **Six
        Months Ended June 30, 2007**
 **(in
        thousands)**
 
 **Total
                  MTM Risk Management Contract Net Assets at December 31,
                  2006**
              
              $
              33,042(Gain)
                  Loss from Contracts Realized/Settled During the Period and Entered
                  in a
                  Prior Period
              
              
              (5,664
              )Fair
                  Value of New Contracts at Inception When Entered During the Period
                  (a)
              
              
              311Net
                  Option Premiums Paid/(Received) for Unexercised or Unexpired Option
                  Contracts Entered During the Period
              
              
              332Change
                  in Fair Value Due to Valuation Methodology Changes on Forward
                  Contracts
              
              
              -Changes
                  in Fair Value Due to Market Fluctuations During the Period
                  (b)
              
              
              2,670Changes
                  in Fair Value Allocated to Regulated Jurisdictions (c)
              
              
              (448
              )**Total
                  MTM Risk Management Contract Net Assets**
              
              
              30,243Net
                  Cash Flow Hedge Contracts
              
              
              8,180DETM
                  Assignment (d)
              
              
              (7,213
              )**Total
                  MTM Risk Management Contract Net Assets at June 30,
                  2007**
              
              $
              31,210
 
 (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.  Inception value is only recorded if observable market
                  data can be obtained for valuation inputs for the entire contract
                  term.  The contract prices are valued against market curves
                  associated with the delivery location and delivery
                  term.(b)
              Market
                  fluctuations are attributable to various factors such as supply/demand,
                  weather, storage, etc.(c)
              “Changes
                  in Fair Value Allocated to Regulated Jurisdictions” relates to the net
                  gains (losses) of those contracts that are not reflected in the
                  Condensed
                  Consolidated Statements of Income.  These net gains (losses) are
                  recorded as regulatory liabilities/assets for those subsidiaries
                  that
                  operate in regulated jurisdictions.(d)
              See
                  “Natural Gas Contracts with DETM” section of Note 16 in the 2006 Annual
                  Report.
 
 **Maturity
        and Source of Fair Value of MTM Risk Management Contract Net
        Assets**
 
 The
        following table presents:
 
 ·
              The
                  method of measuring fair value used in determining the carrying
                  amount of
                  total MTM asset or liability (external sources or modeled
                  internally).·
              The
                  maturity, by year, of net assets/liabilities to give an indication
                  of when
                  these MTM amounts will settle and generate
                  cash.
 
 **Maturity
        and Source of Fair Value of MTM**
 **Risk
        Management Contract Net Assets**
 **Fair
        Value of Contracts as of June 30, 2007**
 **(in
        thousands)**
 
 **Remainder**
                **2007**
              
              
              **2008**
              
              
              **2009**
              
              
              **2010**
              
              
              **2011**
              
              
              **After**
                **2011**
              
              
              **Total**Prices
                  Actively Quoted –Exchange Traded Contracts
              
              $
              3,646
              
              
              $
              (2,762
              )
              
              $
              185
              
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              1,069Prices
                  Provided by Other ExternalSources
                  –
                OTC BrokerQuotes (a)
              
              
              3,153
              
              
              
              10,662
              
              
              
              8,581
              
              
              
              3,706
              
              
              
              -
              
              
              
              -
              
              
              
              26,102Prices
                  Based on Models and Other Valuation Methods (b)
              
              
              (1,363
              )
              
              
              (2,084
              )
              
              
              1,078
              
              
              
              3,562
              
              
              
              810
              
              
              
              1,069
              
              
              
              3,072**Total**
              
              $
              5,436
              
              
              $
              5,816
              
              
              $
              9,844
              
              
              $
              7,268
              
              
              $
              810
              
              
              $
              1,069
              
              
              $
              30,243
 
 (a)
              “Prices
                  Provided by Other External Sources – OTC Broker Quotes” reflects
                  information obtained from over-the-counter brokers, industry services,
                  or
                  multiple-party on-line platforms.(b)
              “Prices
                  Based on Models and Other Valuation Methods” is used in absence of
                  independent information from external sources.  Modeled
                  information is derived using valuation models developed by the
                  reporting
                  entity, reflecting when appropriate, option pricing theory, discounted
                  cash flow concepts, valuation adjustments, etc. and may require
                  projection
                  of prices for underlying commodities beyond the period that prices
                  are
                  available from third-party sources.  In addition, where external
                  pricing information or market liquidity are limited, such valuations
                  are
                  classified as modeled.  The determination of the point at which
                  a market is no longer liquid for placing it in the modeled category
                  varies
                  by market.  Contract values that are measured using models or
                  valuation methods other than active quotes or OTC broker quotes
                  (because
                  of the lack of such data for all delivery quantities, locations
                  and
                  periods) incorporate in the model or other valuation methods, to
                  the
                  extent possible, OTC broker quotes and active quotes for deliveries
                  in
                  years and at locations for which such quotes are available including
                  values determinable by other third party
                  transactions.
 
 
 **Cash
        Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI)
        on
        the Condensed Consolidated Balance Sheet**
 
 OPCo
        is
        exposed to market fluctuations in energy commodity prices impacting power
        operations.  Management monitors these risks on future operations and
        may use various commodity instruments designated in qualifying cash flow
        hedge
        strategies to mitigate the impact of these fluctuations on future cash
        flows.  Management does not hedge all commodity price
        risk.
 
 Management
        uses interest rate derivative transactions to manage interest rate risk related
        to anticipated borrowings of fixed-rate debt.  Management does not
        hedge all interest rate risk.
 
 Management
        uses forward contracts and collars as cash flow hedges to lock in prices
        on
        certain transactions denominated in foreign currencies where deemed
        necessary.  Management does not hedge all foreign currency
        exposure.
 
 The
        following table provides the detail on designated, effective cash flow hedges
        included in AOCI on the Condensed Consolidated Balance Sheets and the reasons
        for the changes from December 31, 2006 to June 30, 2007.  Only
        contracts designated as cash flow hedges are recorded in
        AOCI.  Therefore, economic hedge contracts that are not designated as
        effective cash flow hedges are marked-to-market and included in the previous
        risk management tables.  All amounts are presented net of related
        income taxes.
 
 **Total
        Accumulated Other Comprehensive Income (Loss) Activity**
 **Six
        Months Ended June 30, 2007**
 **(in
        thousands)**
 
 **Power**
              
              
              **Foreign**
                **Currency**
              
              
              **Interest
                  Rate**
              
              
              **Total****Beginning
                  Balance in AOCI December 31, 2006**
              
              $
              4,040
              
              
              $
              (331
              )
              
              $
              3,553
              
              
              $
              7,262Changes
                  in Fair Value
              
              
              3,617
              
              
              
              -
              
              
              
              563
              
              
              
              4,180Reclassifications
                  from AOCI to Net Income for Cash Flow Hedges Settled
              
              
              (2,810
              )
              
              
              7
              
              
              
              (406
              )
              
              
              (3,209
              )**Ending
                  Balance in AOCI June 30, 2007**
              
              $
              4,847
              
              
              $
              (324
              )
              
              $
              3,710
              
              
              $
              8,233
 
 The
        portion of cash flow hedges in AOCI expected to be reclassified to earnings
        during the next twelve months is a $5,504 thousand gain.
 
 **Credit
        Risk**
 
 Counterparty
        credit quality and exposure is generally consistent with that of
        AEP.
 
 **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 June 30, 2007, a near
        term typical change in commodity prices is not expected to have a material
        effect on results of operations, cash flows or financial condition.
 
 The
        following table shows the end, high, average, and low market risk as measured
        by
        VaR for the periods indicated:
 
 **Six
                  Months Ended June 30, 2007**
              
              
              
              
              **Twelve
                  Months Ended December 31, 2006****(in
                  thousands)**
              
              
              
              
              **(in
                  thousands)****End**
              
              **High**
              
              **Average**
              
              **Low**
              
              
              
              
              **End**
              
              **High**
              
              **Average**
              
              **Low**$360
              
              $2,054
              
              $679
              
              $195
              
              
              
              
              $573
              
              $1,451
              
              $500
              
              $271
 
 The
        High
        VaR for the twelve months ended December 31, 2006 occurred in the third quarter
        due to volatility in the ECAR/PJM region.
 
 **VaR
        Associated with Debt Outstanding**
 
 Management
        utilizes a VaR model to measure interest rate market risk
        exposure.  The interest rate VaR model is based on a Monte Carlo
        simulation with a 95% confidence level and a one-year holding
        period.  The risk of potential loss in fair value attributable to
        exposure to interest rates primarily related to long-term debt with fixed
        interest rates was $147 million and $110 million at June 30, 2007 and December
        31, 2006, respectively.  Management would not expect to liquidate the
        entire debt portfolio in a one-year holding period; therefore, a near term
        change in interest rates should not negatively affect results of operations
        or
        consolidated financial position.
   
 **OHIO
        POWER COMPANY CONSOLIDATED**
 **CONDENSED
        CONSOLIDATED STATEMENTS OF INCOME**
 **For
        the Three and Six Months Ended June 30, 2007 and 2006**
 **(in
        thousands)**
 **(Unaudited)**
 
 **Three
                  Months Ended**
              
              
              **Six
                  Months Ended****2007**
              
              
              **2006**
              
              
              **2007**
              
              
              **2006****REVENUES**Electric
                  Generation, Transmission and Distribution
              
              $
              480,445
              
              
              $
              453,064
              
              
              $
              972,979
              
              
              $
              997,703Sales
                  to AEP Affiliates
              
              
              180,205
              
              
              
              154,648
              
              
              
              359,099
              
              
              
              303,907Other
                  - Affiliated
              
              
              6,817
              
              
              
              3,866
              
              
              
              10,855
              
              
              
              7,575Other
                  - Nonaffiliated
              
              
              3,466
              
              
              
              4,429
              
              
              
              7,441
              
              
              
              9,428**TOTAL**
              
              
              670,933
              
              
              
              616,007
              
              
              
              1,350,374
              
              
              
              1,318,613**EXPENSES**Fuel
                  and Other Consumables Used for Electric Generation
              
              
              201,338
              
              
              
              211,538
              
              
              
              399,631
              
              
              
              446,668Purchased
                  Electricity for Resale
              
              
              27,868
              
              
              
              26,313
              
              
              
              52,722
              
              
              
              48,027Purchased
                  Electricity from AEP Affiliates
              
              
              28,745
              
              
              
              28,091
              
              
              
              49,711
              
              
              
              56,663Other
                  Operation
              
              
              86,972
              
              
              
              99,189
              
              
              
              189,959
              
              
              
              185,818Maintenance
              
              
              50,617
              
              
              
              71,416
              
              
              
              109,765
              
              
              
              118,940Depreciation
                  and Amortization
              
              
              84,779
              
              
              
              77,855
              
              
              
              169,055
              
              
              
              156,676Taxes
                  Other Than Income Taxes
              
              
              50,320
              
              
              
              48,536
              
              
              
              98,705
              
              
              
              95,689**TOTAL**
              
              
              530,639
              
              
              
              562,938
              
              
              
              1,069,548
              
              
              
              1,108,481**OPERATING
                  INCOME**
              
              
              140,294
              
              
              
              53,069
              
              
              
              280,826
              
              
              
              210,132**Other
                  Income (Expense):**Interest
                  Income
              
              
              472
              
              
              
              595
              
              
              
              884
              
              
              
              1,232Carrying
                  Costs Income
              
              
              3,594
              
              
              
              3,451
              
              
              
              7,135
              
              
              
              6,834Allowance
                  for Equity Funds Used During Construction
              
              
              446
              
              
              
              398
              
              
              
              1,017
              
              
              
              1,136Interest
                  Expense
              
              
              (33,734
              )
              
              
              (24,437
              )
              
              
              (59,665
              )
              
              
              (47,851
              )**INCOME
                  BEFORE INCOME TAXES**
              
              
              111,072
              
              
              
              33,076
              
              
              
              230,197
              
              
              
              171,483Income
                  Tax Expense
              
              
              36,732
              
              
              
              9,677
              
              
              
              76,596
              
              
              
              53,052**NET
                  INCOME**
              
              
              74,340
              
              
              
              23,399
              
              
              
              153,601
              
              
              
              118,431Preferred
                  Stock Dividend Requirements
              
              
              183
              
              
              
              183
              
              
              
              366
              
              
              
              366**EARNINGS
                  APPLICABLE TO COMMON STOCK**
              
              $
              74,157
              
              
              $
              23,216
              
              
              $
              153,235
              
              
              $
              118,065
 
 *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 COMMON SHAREHOLDER’S**
 **EQUITY
        AND COMPREHENSIVE INCOME (LOSS)**
 **For
        the Six Months Ended June 30, 2007 and 2006**
 **(in
        thousands)**
 **(Unaudited)**
 
 **Common
                  Stock**
              
              
              **Paid-in
                  Capital**
              
              
              **Retained
                  Earnings**
              
              
              **Accumulated
                  Other Comprehensive Income (Loss)**
              
              
              **Total****DECEMBER
                  31, 2005**
              
              $
              321,201
              
              
              $
              466,637
              
              
              $
              979,354
              
              
              $
              755
              
              
              $
              1,767,947Capital
                  Contribution From Parent
              
              
              
              
              
              
              70,000
              
              
              
              
              
              
              
              
              
              
              
              70,000Preferred
                  Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (366
              )
              
              
              
              
              
              
              (366
              )Gain
                  on Reacquired Preferred Stock
              
              
              
              
              
              
              2
              
              
              
              
              
              
              
              
              
              
              
              2**TOTAL**
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              1,837,583**COMPREHENSIVE
                  INCOME****Other
                  Comprehensive Income, Net of Taxes:**Cash
                  Flow Hedges, Net of Tax of $5,708
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              10,600
              
              
              
              10,600**NET
                  INCOME**
              
              
              
              
              
              
              
              
              
              
              118,431
              
              
              
              
              
              
              
              118,431**TOTAL
                  COMPREHENSIVE INCOME**
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              129,031**JUNE
                  30, 2006**
              
              $
              321,201
              
              
              $
              536,639
              
              
              $
              1,097,419
              
              
              $
              11,355
              
              
              $
              1,966,614**DECEMBER
                  31, 2006**
              
              $
              321,201
              
              
              $
              536,639
              
              
              $
              1,207,265
              
              
              $
              (56,763
              )
              
              $
              2,008,342FIN
                  48 Adoption, Net of Tax
              
              
              
              
              
              
              
              
              
              
              (5,380
              )
              
              
              
              
              
              
              (5,380
              )Preferred
                  Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (366
              )
              
              
              
              
              
              
              (366
              )**TOTAL**
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              2,002,596**COMPREHENSIVE
                  INCOME****Other
                  Comprehensive Income, Net of Taxes:**Cash
                  Flow Hedges, Net of Tax of $523
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              971
              
              
              
              971**NET
                  INCOME**
              
              
              
              
              
              
              
              
              
              
              153,601
              
              
              
              
              
              
              
              153,601**TOTAL
                  COMPREHENSIVE INCOME**
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              154,572**JUNE
                  30, 2007**
              
              $
              321,201
              
              
              $
              536,639
              
              
              $
              1,355,120
              
              
              $
              (55,792
              )
              
              $
              2,157,168
 
 *See
        Condensed Notes to Condensed Financial Statements of Registrant
        Subsidiaries.*
  
 **OHIO
        POWER COMPANY CONSOLIDATED**
 **CONDENSED
        CONSOLIDATED BALANCE SHEETS**
 **ASSETS**
 **June
        30, 2007 and December 31, 2006**
 **(in
        thousands)**
 **(Unaudited)**
 
 **2007**
              
              
              **2006****CURRENT
                  ASSETS**Cash
                  and Cash Equivalents
              
              $
              2,999
              
              
              $
              1,625Accounts
                  Receivable:Customers
              
              
              89,097
              
              
              
              86,116Affiliated Companies
              
              
              104,214
              
              
              
              108,214Accrued Unbilled Revenues
              
              
              15,956
              
              
              
              10,106Miscellaneous
              
              
              4,624
              
              
              
              1,819Allowance for Uncollectible Accounts
              
              
              (1,004
              )
              
              
              (824
              )Total
                  Accounts Receivable
              
              
              212,887
              
              
              
              205,431Fuel
              
              
              159,637
              
              
              
              120,441Materials
                  and Supplies
              
              
              85,650
              
              
              
              74,840Emission
                  Allowances
              
              
              8,817
              
              
              
              10,388Risk
                  Management Assets
              
              
              57,307
              
              
              
              86,947Accrued
                  Tax Benefits
              
              
              2,747
              
              
              
              22,909Prepayments
                  and Other
              
              
              16,524
              
              
              
              18,416**TOTAL**
              
              
              546,568
              
              
              
              540,997**PROPERTY,
                  PLANT AND EQUIPMENT**Electric:Production
              
              
              5,492,398
              
              
              
              4,413,340Transmission
              
              
              1,050,149
              
              
              
              1,030,934Distribution
              
              
              1,355,421
              
              
              
              1,322,103Other
              
              
              306,100
              
              
              
              299,637Construction
                  Work in Progress
              
              
              620,350
              
              
              
              1,339,631**Total**
              
              
              8,824,418
              
              
              
              8,405,645Accumulated
                  Depreciation and Amortization
              
              
              2,871,803
              
              
              
              2,836,584**TOTAL
                  - NET**
              
              
              5,952,615
              
              
              
              5,569,061**OTHER
                  NONCURRENT ASSETS**Regulatory
                  Assets
              
              
              366,748
              
              
              
              414,180Long-term
                  Risk Management Assets
              
              
              56,265
              
              
              
              70,092Deferred
                  Charges and Other
              
              
              201,227
              
              
              
              224,403**TOTAL**
              
              
              624,240
              
              
              
              708,675**TOTAL
                  ASSETS**
              
              $
              7,123,423
              
              
              $
              6,818,733
 
 *See
        Condensed Notes to Condensed Financial Statements of Registrant
        Subsidiaries.*
  
 **OHIO
        POWER COMPANY CONSOLIDATED**
 **CONDENSED
        CONSOLIDATED BALANCE SHEETS**
 **LIABILITIES
        AND SHAREHOLDERS’ EQUITY**
 **June
        30, 2007 and December 31, 2006**
 **(Unaudited)**
 
 **2007**
              
              
              **2006****CURRENT
                  LIABILITIES**
              
              **(in
                  thousands)**Advances
                  from Affiliates
              
              $
              16,583
              
              
              $
              181,281Accounts
                  Payable:General
              
              
              167,508
              
              
              
              250,025Affiliated Companies
              
              
              110,113
              
              
              
              145,197Short-term
                  Debt – Nonaffiliated
              
              
              -
              
              
              
              1,203Long-term
                  Debt Due Within One Year – Nonaffiliated
              
              
              16,390
              
              
              
              17,854Risk
                  Management Liabilities
              
              
              43,118
              
              
              
              73,386Customer
                  Deposits
              
              
              40,431
              
              
              
              31,465Accrued
                  Taxes
              
              
              187,851
              
              
              
              165,338Accrued
                  Interest
              
              
              44,612
              
              
              
              35,497Other
              
              
              108,545
              
              
              
              123,631**TOTAL**
              
              
              735,151
              
              
              
              1,024,877**NONCURRENT
                  LIABILITIES**Long-term
                  Debt – Nonaffiliated
              
              
              2,641,779
              
              
              
              2,183,887Long-term
                  Debt – Affiliated
              
              
              200,000
              
              
              
              200,000Long-term
                  Risk Management Liabilities
              
              
              39,244
              
              
              
              52,929Deferred
                  Income Taxes
              
              
              893,989
              
              
              
              911,221Regulatory
                  Liabilities and Deferred Investment Tax Credits
              
              
              169,805
              
              
              
              185,895Deferred
                  Credits and Other
              
              
              252,350
              
              
              
              219,127**TOTAL**
              
              
              4,197,167
              
              
              
              3,753,059**TOTAL
                  LIABILITIES**
              
              
              4,932,318
              
              
              
              4,777,936Minority
                  Interest
              
              
              17,310
              
              
              
              15,825Cumulative
                  Preferred Stock Not Subject to Mandatory Redemption
              
              
              16,627
              
              
              
              16,630Commitments
                  and Contingencies (Note 4)**COMMON
                  SHAREHOLDER’S EQUITY**Common
                  Stock – No Par Value:Authorized
                  – 40,000,000 SharesOutstanding
                  – 27,952,473 Shares
              
              
              321,201
              
              
              
              321,201Paid-in
                  Capital
              
              
              536,639
              
              
              
              536,639Retained
                  Earnings
              
              
              1,355,120
              
              
              
              1,207,265Accumulated
                  Other Comprehensive Income (Loss)
              
              
              (55,792
              )
              
              
              (56,763
              )**TOTAL**
              
              
              2,157,168
              
              
              
              2,008,342**TOTAL
                  LIABILITIES AND SHAREHOLDERS’ EQUITY**
              
              $
              7,123,423
              
              
              $
              6,818,733
 
 *See
        Condensed Notes to Condensed Financial Statements of Registrant
        Subsidiaries.*
  
 **OHIO
        POWER COMPANY CONSOLIDATED**
 **CONDENSED
        CONSOLIDATED STATEMENTS OF CASH FLOWS**
 **For
        the Six Months Ended June 30, 2007 and 2006**
 **(in
        thousands)**
 **(Unaudited)**
 
 **2007**
              
              
              **2006****OPERATING
                  ACTIVITIES****Net
                  Income**
              
              $
              153,601
              
              
              $
              118,431**Adjustments
                  for Noncash Items:**Depreciation
                  and Amortization
              
              
              169,055
              
              
              
              156,676Deferred
                  Income Taxes
              
              
              550
              
              
              
              (8,073
              )Carrying
                  Costs Income
              
              
              (7,135
              )
              
              
              (6,834
              )Mark-to-Market
                  of Risk Management Contracts
              
              
              1,509
              
              
              
              1,263Deferred
                  Property Taxes
              
              
              34,629
              
              
              
              35,550Change
                  in Other Noncurrent Assets
              
              
              (18,338
              )
              
              
              4,898Change
                  in Other Noncurrent Liabilities
              
              
              272
              
              
              
              16,355**Changes
                  in Certain Components of Working Capital:**Accounts
                  Receivable, Net
              
              
              (18,273
              )
              
              
              97,832Fuel,
                  Materials and Supplies
              
              
              (42,452
              )
              
              
              (56,075
              )Accounts
                  Payable
              
              
              (46,758
              )
              
              
              (42,878
              )Accrued
                  Taxes, Net
              
              
              46,587
              
              
              
              (7,233
              )Other
                  Current Assets
              
              
              1,545
              
              
              
              35,848Other
                  Current Liabilities
              
              
              4,237
              
              
              
              (23,816
              )**Net
                  Cash Flows From Operating Activities**
              
              
              279,029
              
              
              
              321,944**INVESTING
                  ACTIVITIES**Construction
                  Expenditures
              
              
              (565,832
              )
              
              
              (481,541
              )Change
                  in Advances to Affiliates, Net
              
              
              -
              
              
              
              (36,787
              )Proceeds
                  from Sales of Assets
              
              
              5,594
              
              
              
              7,511Other
              
              
              (24
              )
              
              
              (1,651
              )**Net
                  Cash Flows Used For Investing Activities**
              
              
              (560,262
              )
              
              
              (512,468
              )**FINANCING
                  ACTIVITIES**Capital
                  Contribution from Parent
              
              
              -
              
              
              
              70,000Issuance
                  of Long-term Debt – Nonaffiliated
              
              
              461,324
              
              
              
              405,839Change
                  in Short-term Debt, Net – Nonaffiliated
              
              
              (1,203
              )
              
              
              (5,094
              )Change
                  in Advances from Affiliates, Net
              
              
              (164,698
              )
              
              
              (70,071
              )Retirement
                  of Long-term Debt – Nonaffiliated
              
              
              (8,927
              )
              
              
              (6,177
              )Retirement
                  of Long-term Debt – Affiliated
              
              
              -
              
              
              
              (200,000
              )Retirement
                  of Cumulative Preferred Stock
              
              
              (2
              )
              
              
              (8
              )Principal
                  Payments for Capital Lease Obligations
              
              
              (3,521
              )
              
              
              (3,849
              )Dividends
                  Paid on Cumulative Preferred Stock
              
              
              (366
              )
              
              
              (366
              )**Net
                  Cash Flows From Financing Activities**
              
              
              282,607
              
              
              
              190,274**Net
                  Increase (Decrease) in Cash and Cash Equivalents**
              
              
              1,374
              
              
              
              (250
              )**Cash
                  and Cash Equivalents at Beginning of Period**
              
              
              1,625
              
              
              
              1,240**Cash
                  and Cash Equivalents at End of Period**
              
              $
              2,999
              
              
              $
              990**SUPPLEMENTARY
                  INFORMATION**Cash
                  Paid for Interest, Net of Capitalized Amounts
              
              $
              51,991
              
              
              $
              43,794Net
                  Cash Paid (Received) for Income Taxes
              
              
              (9,193
              )
              
              
              24,077Noncash
                  Acquisitions Under Capital Leases
              
              
              1,036
              
              
              
              1,662Construction
                  Expenditures Included in Accounts Payable at June 30,
              
              
              65,936
              
              
              
              97,389*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**
                **Reference**Significant
                  Accounting Matters
              Note
                  1New
                  Accounting Pronouncements and Extraordinary Item
              Note
                  2Rate
                  Matters
              Note
                  3Commitments,
                  Guarantees and Contingencies
              Note
                  4Benefit
                  Plans
              Note
                  6Business
                  Segments
              Note
                  7Income
                  Taxes
              Note
                  8Financing
                  Activities
              Note
                  9
 
 
 
 
 
   
 
  
 
 **PUBLIC
        SERVICE COMPANY OF OKLAHOMA**
                    
 **PUBLIC
        SERVICE COMPANY OF OKLAHOMA**
 **MANAGEMENT’S
        NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS**
 
 
 **Results
        of Operations**
 
 Second
        Quarter of 2007 Compared to Second Quarter of 2006
 
 **Reconciliation
        of Second Quarter of 2006 to Second Quarter of 2007**
 **Net
        Income**
 **(in
        millions)**
 
 **Second
                  Quarter of 2006**
              
              
              
              
              $
              15**Changes
                  in Gross Margin:**Retail
                  and Off-system Sales Margins
              
              
              (2
              )Transmission
                  Revenues
              
              
              (1
              )Other
              
              
              (2
              )**Total
                  Change in Gross Margin**
              
              
              
              
              
              
              (5
              )**Changes
                  in Operating Expenses and Other:**Other
                  Operation and Maintenance
              
              
              (3
              )Depreciation
                  and Amortization
              
              
              (1
              )Interest
                  Expense
              
              
              (3
              )**Total
                  Change in Operating Expenses and Other**
              
              
              
              
              
              
              (7
              )Income
                  Tax Expense
              
              
              
              
              
              
              3**Second
                  Quarter of 2007**
              
              
              
              
              
              $
              6
 
 Net
        Income decreased $9 million to $6 million in 2007.  The key drivers of
        the decreased income were a $5 million decrease in Gross Margin and a $7
        million
        increase in Operating Expenses and Other, partially offset by a $3 million
        decrease in Income Tax Expense.
 
 The
        major
        components of the decrease in Gross Margin, defined as revenues less the
        related
        direct cost of fuel, including consumption of chemicals and emissions
        allowances, and purchased power were as follows:
 
 ·
              Retail
                  and Off-system Sales Margins decreased $2 million primarily due
                  to a
                  decrease in retail margins resulting from a 28% decrease in cooling
                  days,
                  partially offset by an increase in Off-system Sales Margins, 75%
                  of which
                  flows through the fuel adjustment clause to retail
                  customers.·
              Other
                  revenues decreased $2 million primarily due to lower gains on sales
                  of
                  emission allowances and lower billings to outside parties for construction
                  services.
 
 Operating
        Expenses and Other increased between years as follows:
 
 ·
              Other
                  Operation and Maintenance expenses increased $3 million primarily
                  due to
                  an $8 million increase in generation operation and maintenance
                  expense
                  primarily during planned outages at PSO’s Northeastern and Southwestern
                  plants.  This increase was partially offset by a $5 million
                  decrease in distribution expenses, mostly due to a $7 million adjustment
                  to capitalize costs related to a January 2007 ice
                  storm.·
              Interest
                  Expense increased $3 million primarily due to increased
                  borrowings.
 
 *Income
        Taxes*
 
 Income
        Tax Expense decreased $3 million primarily due to a decrease in pretax book
        income, offset in part by state income taxes.
 
 
 Six
        Months Ended June 30, 2007 Compared to Six Months Ended June 30,
        2006
 
 **Reconciliation
        of Six Months Ended June 30, 2006 to Six Months Ended June 30,
        2007**
 **Net
        Income (Loss)**
 **(in
        millions)**
 
 **Six
                  Months Ended June 30, 2006**
              
              
              
              
              $
              9**Changes
                  in Gross Margin:**Retail
                  and Off-system Sales Margins
              
              
              2Transmission
                  Revenues
              
              
              1Other
              
              
              (3
              )**Total
                  Change in Gross Margin**
              
              
              
              
              
              
              -**Changes
                  in Operating Expenses and Other:**Other
                  Operation and Maintenance
              
              
              (29
              )Depreciation
                  and Amortization
              
              
              (3
              )Interest
                  Expense
              
              
              (5
              )**Total
                  Change in Operating Expenses and Other**
              
              
              
              
              
              
              (37
              )Income
                  Tax Expense
              
              
              
              
              
              
              14**Six
                  Months Ended June 30, 2007**
              
              
              
              
              
              $
              (14
              )
 
 Net
        Income decreased $23 million to a $14 million loss in 2007.  The key
        driver of the decreased income was a $37 million increase in Operating Expenses
        and Other, partially offset by a $14 million decrease in Income Tax
        Expense.
 
 The
        major
        changes 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 $2 million primarily due
                  to an
                  increase in margins from Off-System Sales, 75% of which flows through
                  the
                  fuel adjustment clause to retail customers, partially offset by
                  a decrease
                  in retail margins resulting from a 25% decrease in cooling degree
                  days.·
              Other
                  revenues decreased $3 million primarily due to lower billings to
                  outside
                  parties for construction services, as well as the absence of a 2006
                  settlement received from an electric
                  cooperative.
 
 Operating
        Expenses and Other increased between years as follows:
 
 ·
              Other
                  Operation and Maintenance expenses increased $29 million primarily
                  due to
                  a $15 million increase in distribution maintenance expense primarily
                  due
                  to a January 2007 ice storm and a $10 million increase in generation
                  operation and maintenance expense primarily during planned outages
                  at
                  PSO’s Oklaunion, Riverside, Northeastern and Southwestern
                  plants.·
              Depreciation
                  and Amortization increased $3 million due to higher depreciable
                  asset
                  balances.·
              Interest
                  Expense increased $5 million primarily due to increased
                  borrowings.
 
 *Income
        Taxes*
 
 Income
        Tax Expense decreased $14 million primarily due to a decrease in pretax book
        income.
 
 **Critical
        Accounting Estimates**
 
 See
        the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
        Analysis of Registrant Subsidiaries” in the 2006 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 the complete discussion and analysis within AEP’s
“Quantitative and Qualitative Disclosures About Risk Management Activities”
section for disclosures about risk management activities.
 
 **VaR
        Associated with Debt Outstanding**
 
 Management
        utilizes a VaR model to measure interest rate market risk exposure. The interest
        rate VaR model is based on a Monte Carlo simulation with a 95% confidence
        level
        and a one-year holding period.  The risk of potential loss in fair
        value attributable to exposure to interest rates primarily related to long-term
        debt with fixed interest rates was $46 million and $39 million at June 30,
        2007
        and December 31, 2006, respectively.  Management would not expect to
        liquidate the entire debt portfolio in a one-year holding period; therefore,
        a
        near term change in interest rates should not negatively affect results of
        operations or financial position.
 
 
 
 **PUBLIC
        SERVICE COMPANY OF OKLAHOMA**
 **CONDENSED
        STATEMENTS OF OPERATIONS**
 **For
        the Three and Six Months Ended June 30, 2007 and 2006**
 **(in
        thousands)**
 **(Unaudited)**
 
 **Three
                  Months Ended**
              
              
              **Six
                  Months Ended****2007**
              
              
              **2006**
              
              
              **2007**
              
              
              **2006****REVENUES**Electric
                  Generation, Transmission and Distribution
              
              $
              304,820
              
              
              $
              333,313
              
              
              $
              594,900
              
              
              $
              672,914Sales
                  to AEP Affiliates
              
              
              16,275
              
              
              
              12,545
              
              
              
              40,868
              
              
              
              26,613Other
              
              
              544
              
              
              
              1,188
              
              
              
              1,184
              
              
              
              2,248**TOTAL**
              
              
              321,639
              
              
              
              347,046
              
              
              
              636,952
              
              
              
              701,775**EXPENSES**Fuel
                  and Other Consumables Used for Electric Generation
              
              
              113,633
              
              
              
              150,976
              
              
              
              256,148
              
              
              
              364,149Purchased
                  Electricity for Resale
              
              
              70,145
              
              
              
              56,358
              
              
              
              137,554
              
              
              
              89,575Purchased
                  Electricity from AEP Affiliates
              
              
              18,979
              
              
              
              15,880
              
              
              
              32,463
              
              
              
              37,111Other
                  Operation
              
              
              42,345
              
              
              
              39,985
              
              
              
              83,352
              
              
              
              76,741Maintenance
              
              
              22,177
              
              
              
              22,033
              
              
              
              65,262
              
              
              
              42,340Depreciation
                  and Amortization
              
              
              22,992
              
              
              
              21,713
              
              
              
              45,698
              
              
              
              42,845Taxes
                  Other Than Income Taxes
              
              
              9,890
              
              
              
              10,077
              
              
              
              20,184
              
              
              
              20,153**TOTAL**
              
              
              300,161
              
              
              
              317,022
              
              
              
              640,661
              
              
              
              672,914**OPERATING
                  INCOME (LOSS)**
              
              
              21,478
              
              
              
              30,024
              
              
              
              (3,709
              )
              
              
              28,861Other
                  Income
              
              
              562
              
              
              
              211
              
              
              
              1,208
              
              
              
              780Interest
                  Expense
              
              
              (12,785
              )
              
              
              (9,634
              )
              
              
              (24,168
              )
              
              
              (18,769
              )**INCOME
                  (LOSS) BEFORE INCOME TAXES**
              
              
              9,255
              
              
              
              20,601
              
              
              
              (26,669
              )
              
              
              10,872Income
                  Tax Expense (Credit)
              
              
              2,960
              
              
              
              5,963
              
              
              
              (12,538
              )
              
              
              1,591**NET
                  INCOME (LOSS)**
              
              
              6,295
              
              
              
              14,638
              
              
              
              (14,131
              )
              
              
              9,281Preferred
                  Stock Dividend Requirements
              
              
              53
              
              
              
              53
              
              
              
              106
              
              
              
              106**EARNINGS
                  (LOSS) APPLICABLE TO COMMON   STOCK**
              
              $
              6,242
              
              
              $
              14,585
              
              
              $
              (14,237
              )
              
              $
              9,175
 
 *The
                  common stock of PSO is owned by a wholly-owned subsidiary of
                  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 Six Months Ended June 30, 2007 and 2006**
 **(in
        thousands)**
 **(Unaudited)**
 
 **Common
                  Stock**
              
              
              **Paid-in
                  Capital**
              
              
              **Retained
                  Earnings**
              
              
              **Accumulated
                  Other Comprehensive Income (Loss)**
              
              
              **Total****DECEMBER
                  31, 2005**
              
              $
              157,230
              
              
              $
              230,016
              
              
              $
              162,615
              
              
              $
              (1,264
              )
              
              $
              548,597Preferred
                  Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (106
              )
              
              
              
              
              
              
              (106
              )**TOTAL**
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              548,491**COMPREHENSIVE
                  INCOME****Other
                  Comprehensive Income,** **Net of
                  Taxes:**Cash
                  Flow Hedges, Net of Tax of $375
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              696
              
              
              
              696**NET
                  INCOME**
              
              
              
              
              
              
              
              
              
              
              9,281
              
              
              
              
              
              
              
              9,281**TOTAL
                  COMPREHENSIVE INCOME**
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              9,977**JUNE
                  30, 2006**
              
              $
              157,230
              
              
              $
              230,016
              
              
              $
              171,790
              
              
              $
              (568
              )
              
              $
              558,468**DECEMBER
                  31, 2006**
              
              $
              157,230
              
              
              $
              230,016
              
              
              $
              199,262
              
              
              $
              (1,070
              )
              
              $
              585,438FIN
                  48 Adoption, Net of Tax
              
              
              
              
              
              
              
              
              
              
              (386
              )
              
              
              
              
              
              
              (386
              )Capital
                  Contribution from Parent
              
              
              
              
              
              
              40,000
              
              
              
              
              
              
              
              
              
              
              
              40,000Preferred
                  Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (106
              )
              
              
              
              
              
              
              (106
              )**TOTAL**
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              624,946**COMPREHENSIVE
                  LOSS****Other
                  Comprehensive Income, Net of Taxes:**Cash
                  Flow Hedges, Net of Tax of $49
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              91
              
              
              
              91**NET
                  LOSS**
              
              
              
              
              
              
              
              
              
              
              (14,131
              )
              
              
              
              
              
              
              (14,131
              )**TOTAL
                  COMPREHENSIVE LOSS**
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              (14,040
              )**JUNE
                  30, 2007**
              
              $
              157,230
              
              
              $
              270,016
              
              
              $
              184,639
              
              
              $
              (979
              )
              
              $
              610,906
 
 *See
        Condensed Notes to Condensed Financial Statements of Registrant
        Subsidiaries.*
   
 **PUBLIC
        SERVICE COMPANY OF OKLAHOMA**
 **CONDENSED
        BALANCE SHEETS**
 **ASSETS**
 **June
        30, 2007 and December 31, 2006**
 **(in
        thousands)**
 **(Unaudited)**
 
 **2007**
              
              
              **2006****CURRENT
                  ASSETS**Cash
                  and Cash Equivalents
              
              $
              908
              
              
              $
              1,651Accounts
                  Receivable:Customers
              
              
              52,773
              
              
              
              70,319Affiliated
                  Companies
              
              
              68,499
              
              
              
              73,318Miscellaneous
              
              
              13,251
              
              
              
              10,270Allowance
                  for Uncollectible Accounts
              
              
              (34
              )
              
              
              (5
              )Total
                  Accounts Receivable
              
              
              134,489
              
              
              
              153,902Fuel
              
              
              22,063
              
              
              
              20,082Materials
                  and Supplies
              
              
              54,818
              
              
              
              48,375Risk
                  Management Assets
              
              
              54,372
              
              
              
              100,802Accrued
                  Tax Benefits
              
              
              26,900
              
              
              
              4,679Regulatory
                  Asset for Under-Recovered Fuel Costs
              
              
              21,069
              
              
              
              7,557Margin
                  Deposits
              
              
              18,284
              
              
              
              35,270Prepayments
                  and Other
              
              
              17,849
              
              
              
              5,732**TOTAL**
              
              
              350,752
              
              
              
              378,050**PROPERTY,
                  PLANT AND EQUIPMENT**Electric:Production
              
              
              1,109,356
              
              
              
              1,091,910Transmission
              
              
              543,722
              
              
              
              503,638Distribution
              
              
              1,284,347
              
              
              
              1,215,236Other
              
              
              240,542
              
              
              
              234,227Construction
                  Work in Progress
              
              
              151,764
              
              
              
              141,283**Total**
              
              
              3,329,731
              
              
              
              3,186,294Accumulated
                  Depreciation and Amortization
              
              
              1,203,048
              
              
              
              1,187,107**TOTAL
                  - NET**
              
              
              2,126,683
              
              
              
              1,999,187**OTHER
                  NONCURRENT ASSETS**Regulatory
                  Assets
              
              
              153,154
              
              
              
              142,905Long-term
                  Risk Management Assets
              
              
              9,200
              
              
              
              17,066Employee
                  Benefits and Pension Assets
              
              
              29,362
              
              
              
              30,161Deferred
                  Charges and Other
              
              
              27,832
              
              
              
              11,677**TOTAL**
              
              
              219,548
              
              
              
              201,809**TOTAL
                  ASSETS**
              
              $
              2,696,983
              
              
              $
              2,579,046
 
 *See
        Condensed Notes to Condensed Financial Statements of Registrant
        Subsidiaries.*
 
 **PUBLIC
        SERVICE COMPANY OF OKLAHOMA**
 **CONDENSED
        BALANCE SHEETS**
 **LIABILITIES
        AND SHAREHOLDERS’ EQUITY**
 **June
        30, 2007 and December 31, 2006**
 **(Unaudited)**
 
 **2007**
              
              
              **2006****CURRENT
                  LIABILITIES**
              
              **(in
                  thousands)**Advances
                  from Affiliates
              
              $
              216,239
              
              
              $
              76,323Accounts
                  Payable:General
              
              
              168,779
              
              
              
              165,618Affiliated
                  Companies
              
              
              80,116
              
              
              
              65,134Long-term
                  Debt Due Within One Year – Nonaffiliated
              
              
              12,660
              
              
              
              -Risk
                  Management Liabilities
              
              
              42,748
              
              
              
              88,469Customer
                  Deposits
              
              
              42,435
              
              
              
              51,335Accrued
                  Taxes
              
              
              34,327
              
              
              
              19,984Other
              
              
              33,671
              
              
              
              58,651**TOTAL**
              
              
              630,975
              
              
              
              525,514**NONCURRENT
                  LIABILITIES**Long-term
                  Debt – Nonaffiliated
              
              
              670,087
              
              
              
              669,998Long-term
                  Risk Management Liabilities
              
              
              6,481
              
              
              
              11,448Deferred
                  Income Taxes
              
              
              417,789
              
              
              
              414,197Regulatory
                  Liabilities and Deferred Investment Tax Credits
              
              
              295,381
              
              
              
              315,584Deferred
                  Credits and Other
              
              
              60,102
              
              
              
              51,605**TOTAL**
              
              
              1,449,840
              
              
              
              1,462,832**TOTAL
                  LIABILITIES**
              
              
              2,080,815
              
              
              
              1,988,346Cumulative
                  Preferred Stock Not Subject to Mandatory Redemption
              
              
              5,262
              
              
              
              5,262Commitments
                  and Contingencies (Note 4)**COMMON
                  SHAREHOLDER’S EQUITY**Common
                  Stock – $15 Par Value Per Share:Authorized
                  – 11,000,000 SharesIssued
                  – 10,482,000 SharesOutstanding
                  – 9,013,000 Shares
              
              
              157,230
              
              
              
              157,230Paid-in
                  Capital
              
              
              270,016
              
              
              
              230,016Retained
                  Earnings
              
              
              184,639
              
              
              
              199,262Accumulated
                  Other Comprehensive Income (Loss)
              
              
              (979
              )
              
              
              (1,070
              )**TOTAL**
              
              
              610,906
              
              
              
              585,438**TOTAL
                  LIABILITIES AND SHAREHOLDERS’ EQUITY**
              
              $
              2,696,983
              
              
              $
              2,579,046
 
 *See
        Condensed Notes to Condensed Financial Statements of Registrant
        Subsidiaries.*
   
 **PUBLIC
        SERVICE COMPANY OF OKLAHOMA**
 **CONDENSED
        STATEMENTS OF CASH FLOWS**
 **For
        the Six Months Ended June 30, 2007 and 2006**
 **(in
        thousands)**
 **(Unaudited)**
 
 **2007**
              
              
              **2006****OPERATING
                  ACTIVITIES****Net
                  Income (Loss)**
              
              $
              (14,131
              )
              
              $
              9,281**Adjustments
                  for Noncash Items:**Depreciation
                  and Amortization
              
              
              45,698
              
              
              
              42,845Deferred
                  Income Taxes
              
              
              11,059
              
              
              
              (22,319
              )Mark-to-Market
                  of Risk Management Contracts
              
              
              3,608
              
              
              
              (11,979
              )Deferred
                  Property Taxes
              
              
              (16,539
              )
              
              
              (16,196
              )Change
                  in Other Noncurrent Assets
              
              
              (26,291
              )
              
              
              9,441Change
                  in Other Noncurrent Liabilities
              
              
              (22,811
              )
              
              
              (8,232
              )**Changes
                  in Certain Components of Working Capital:**Accounts
                  Receivable, Net
              
              
              19,413
              
              
              
              8,080Fuel,
                  Materials and Supplies
              
              
              (8,414
              )
              
              
              (6,816
              )Margin
                  Deposits
              
              
              16,986
              
              
              
              (46,917
              )Accounts
                  Payable
              
              
              11,810
              
              
              
              28,517Customer
                  Deposits
              
              
              (8,900
              )
              
              
              1,495Accrued
                  Taxes, Net
              
              
              (6,888
              )
              
              
              33,976Fuel
                Over/Under Recovery, Net
              
              
              (13,512
              )
              
              
              75,097Other
                  Current Assets
              
              
              597
              
              
              
              1,655Other
                  Current Liabilities
              
              
              (22,228
              )
              
              
              (19,221
              )**Net
                  Cash Flows From (Used For) Operating Activities**
              
              
              (30,543
              )
              
              
              78,707**INVESTING
                  ACTIVITIES**Construction
                  Expenditures
              
              
              (151,973
              )
              
              
              (91,617
              )Change
                  in Other Cash Deposits, Net
              
              
              (12,896
              )
              
              
              6Other
              
              
              3,109
              
              
              
              -**Net
                  Cash Flows Used For Investing Activities**
              
              
              (161,760
              )
              
              
              (91,611
              )**FINANCING
                  ACTIVITIES**Capital
                  Contribution from Parent
              
              
              40,000
              
              
              
              -Issuance
                  of Long-term Debt – Nonaffiliated
              
              
              12,495
              
              
              
              -Change
                  in Advances from Affiliates, Net
              
              
              139,916
              
              
              
              63,948Retirement
                  of Long-term Debt – Affiliated
              
              
              -
              
              
              
              (50,000
              )Principal
                  Payments for Capital Lease Obligations
              
              
              (745
              )
              
              
              (457
              )Dividends
                  Paid on Cumulative Preferred Stock
              
              
              (106
              )
              
              
              (106
              )**Net
                  Cash Flows From Financing Activities**
              
              
              191,560
              
              
              
              13,385**Net
                  Increase (Decrease) in Cash and Cash Equivalents**
              
              
              (743
              )
              
              
              481**Cash
                  and Cash Equivalents at Beginning of Period**
              
              
              1,651
              
              
              
              1,520**Cash
                  and Cash Equivalents at End of Period**
              
              $
              908
              
              
              $
              2,001**SUPPLEMENTARY
                  INFORMATION**Cash
                  Paid for Interest, Net of Capitalized Amounts
              
              $
              21,339
              
              
              $
              17,461Net
                  Cash Paid (Received) for Income Taxes
              
              
              (2,353
              )
              
              
              5,656Noncash
                  Acquisitions Under Capital Leases
              
              
              434
              
              
              
              1,780Construction
                  Expenditures Included in Accounts Payable at June 30,
              
              
              21,261
              
              
              
              5,943
  *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.
 
 **Footnote Reference**Significant
                  Accounting Matters
              Note
                  1New
                  Accounting Pronouncements and Extraordinary Item
              Note
                  2Rate
                  Matters
              Note
                  3Commitments,
                  Guarantees and Contingencies
              Note
                  4Benefit
                  Plans
              Note
                  6Business
                  Segments
              Note
                  7Income
                  Taxes
              Note
                  8Financing
                  Activities
              Note
                  9
 
 
 
 
 
   
     
 
 
 **SOUTHWESTERN
        ELECTRIC POWER COMPANY CONSOLIDATED**
               
 
 **SOUTHWESTERN
        ELECTRIC POWER COMPANY
        CONSOLIDATED**
 **MANAGEMENT’S
        FINANCIAL DISCUSSION AND ANALYSIS**
 
 **Results
        of Operations**
 
 Second
        Quarter of 2007 Compared to Second Quarter of 2006
 
 **Reconciliation
        of Second Quarter of 2006 to Second Quarter of 2007**
 **Net
        Income**
 **(in
        millions)**
 
 **Second
                  Quarter of 2006**
              
              
              
              
              $
              28**Changes
                  in Gross Margin:**Retail
                  and Off-system Sales Margins (a)
              
              
              (28
              )Transmission
                  Revenues
              
              
              (1
              )Other
              
              
              (3
              )**Total
                  Change in Gross Margin**
              
              
              
              
              
              
              (32
              )**Changes
                  in Operating Expenses and Other:**Other
                  Operation and Maintenance
              
              
              (4
              )Depreciation
                  and Amortization
              
              
              (2
              )Taxes
                  Other Than Income Taxes
              
              
              (1
              )Other
                  Income
              
              
              2Interest
                  Expense
              
              
              (3
              )**Total
                  Change in Operating Expenses and Other**
              
              
              
              
              
              
              (8
              )Income
                  Tax Expense
              
              
              
              
              
              
              14**Second
                  Quarter of 2007**
              
              
              
              
              
              $
              2
 
 (a)
              Includes
                  firm wholesale sales to municipals and
                  cooperatives.
 
 Net
        Income decreased $26 million to $2 million in 2007.  The key drivers
        of the decrease were a $32 million decrease in Gross Margin and an $8 million
        increase in Operating Expenses and Other, partially offset by a $14 million
        decrease in Income Tax Expense.
 
 The
        major
        components of the decrease in Gross Margin, defined as revenues less the
        related
        direct cost of fuel, including consumption of chemicals and emissions
        allowances, and purchased power were as follows:
 
 ·
              Retail
                  and Off-system Sales Margins decreased $28 million primarily due
                  to a $25
                  million provision related to a SWEPCo Texas fuel reconciliation
                  proceeding.  See “SWEPCo Fuel Reconciliation – Texas” section of
                  Note 3.·
              Other
                  revenues decreased $3 million primarily due to a $4 million decrease
                  in
                  revenue from coal deliveries from SWEPCo's mining subsidiary, Dolet
                  Hills Lignite Company, LLC, to outside parties.  The decrease
                  was offset by a corresponding decrease in Other Operation and Maintenance
                  expenses from mining operations as discussed
                  below.
 
 Operating
        Expenses and Other changed between years as follows:
 
 ·
              Other
                  Operation and Maintenance expenses increased $4 million due to
                  a $7
                  million increase in generation operation and maintenance expenses
                  and a $4
                  million increase in distribution expenses due to higher overhead
                  line
                  maintenance, partially offset by a $5 million decrease in expenses
                  primarily resulting from decreased coal deliveries from SWEPCo's
                  mining
                  subsidiary, Dolet Hills Lignite Company, LLC, due to planned and
                  forced
                  outages at the Dolet Hills Generating Station, which is jointly-owned
                  by
                  SWEPCo and Cleco Corporation, a nonaffiliated entity.·
              Interest
                  Expense increased $3 million primarily due to increased
                  borrowings.
 
 *Income
        Taxes*
 
 Income
        Tax Expense decreased $14 million primarily due to a decrease in pretax book
        income.
 
 Six
        Months Ended June 30, 2007 Compared to Six Months Ended June 30,
        2006
 
 **Reconciliation
        of Six Months Ended June 30, 2006 to Six Months Ended June 30,
        2007**
 **Net
        Income**
 **(in
        millions)**
 
 **Six
                  Months Ended June 30, 2006**
              
              
              
              
              $
              46**Changes
                  in Gross Margin:**Retail
                  and Off-system Sales Margins (a)
              
              
              (29
              )Transmission
                  Revenues
              
              
              (1
              )Other
              
              
              (8
              )**Total
                  Change in Gross Margin**
              
              
              
              
              
              
              (38
              )**Changes
                  in Operating Expenses and Other:**Other
                  Operation and Maintenance
              
              
              (10
              )Depreciation
                  and Amortization
              
              
              (3
              )Taxes
                  Other Than Income Taxes
              
              
              (1
              )Other
                  Income
              
              
              3Interest
                  Expense
              
              
              (6
              )**Total
                  Change in Operating Expenses and Other**
              
              
              
              
              
              
              (17
              )Income
                  Tax Expense
              
              
              
              
              
              
              20**Six
                  Months Ended June 30, 2007**
              
              
              
              
              
              $
              11
 
 (a)
              Includes
                  firm wholesale sales to municipals and
                  cooperatives.
 
 Net
        Income decreased $35 million to $11 million in 2007.  The key drivers
        of the decrease were a $38 million decrease in Gross Margin and a $17 million
        increase in Operating Expenses and Other, offset by a $20 million decrease
        in
        Income Tax Expense.
 
 The
        major
        components of the decrease in Gross Margin, defined as revenues less the
        related
        direct cost of fuel, including consumption of chemicals and emissions
        allowances, and purchased power were as follows:
 
 ·
              Retail
                  and Off-system Sales Margins decreased $29 million primarily due
                  to a $25
                  million provision related to a SWEPCo Texas fuel reconciliation
                  proceeding.  See “SWEPCo Fuel Reconciliation – Texas” section of
                  Note 3.·
              Other
                  revenues decreased $8 million primarily due to a $6 million decrease
                  in
                  revenue from coal deliveries from SWEPCo's mining subsidiary, Dolet
                  Hills Lignite Company, LLC, to outside parties and a $2 million
                  decrease
                  in gains on sales of emission allowances.  The decreased revenue
                  from coal deliveries was offset by a corresponding decrease in
                  Other
                  Operation and Maintenance expenses from mining operations as discussed
                  below.
 
 Operating
        Expenses and Other changed between years as follows:
 
 ·
              Other
                  Operation and Maintenance expenses increased $10 million primarily
                  due to
                  an $8 million increase in generation operation and maintenance,
                  a $5
                  million increase in distribution expenses due to higher overhead
                  line
                  maintenance and a $3 million increase in transmission expenses
                  related to
                  higher SPP administration fees, partially offset by a $6 million
                  decrease
                  in expenses primarily resulting from decreased coal deliveries
                  from SWEPCo's mining subsidiary, Dolet Hills Lignite Company, LLC,
                  due to planned and forced outages at the Dolet Hills Generating
                  Station,
                  which is jointly-owned by SWEPCo and Cleco Corporation, a nonaffiliated
                  entity.·
              Interest
                  Expense increased $6 million primarily due to increased
                  borrowings.
 
 *Income
        Taxes*
 
 Income
        Tax Expense decreased $20 million primarily due to a decrease in pretax book
        income.
 
 **Financial
        Condition**
 
 **Credit
        Ratings**
 
 The
        rating agencies currently have SWEPCo on stable outlook.  Current
        ratings are as follows:
 
 **Moody’s**
              
              **S&P**
              
              **Fitch**First
                  Mortgage Bonds
              A3
              
              A-
              
              ASenior
                  Unsecured Debt
              Baa1
              
              BBB
              
              A-
 
 **Cash
        Flow**
 
 Cash
        flows for the six months ended June 30, 2007 and 2006 were as
        follows:
 
 **2007**
              
              
              **2006****(in
                  thousands)****Cash
                  and Cash Equivalents at Beginning of Period**
              
              $
              2,618
              
              
              $
              3,049Cash
                  Flows From (Used For):Operating
                  Activities
              
              
              120,597
              
              
              
              76,154Investing
                  Activities
              
              
              (253,267
              )
              
              
              (123,275
              )Financing
                  Activities
              
              
              131,610
              
              
              
              46,180**Net
                  Decrease in Cash and Cash Equivalents**
              
              
              (1,060
              )
              
              
              (941
              )**Cash
                  and Cash Equivalents at End of Period**
              
              $
              1,558
              
              
              $
              2,108
 
 *Operating
        Activities*
 
 Net
        Cash
        Flows From Operating Activities were $121 million in 2007.  SWEPCo
        produced Net Income of $11 million during the period and noncash expense
        items
        of $69 million for Depreciation and Amortization and $25 million related
        to the
        Provision for Fuel Disallowance recorded as the result of an ALJ ruling in
        SWEPCo’s Texas fuel reconciliation proceeding.  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 $36 million inflow from Accrued Taxes, Net was the
        result of increased accruals related to property and income
        taxes.  The $27 million inflow from Accounts Receivable, Net was
        primarily due to the assignment of certain ERCOT contracts to an affiliate
        company.  The $20 million inflow from Margin Deposits was due to
        decreased trading-related deposits resulting from normal trading
        activities.
 
 Net
        Cash
        Flows From Operating Activities were $76 million in 2006.  SWEPCo
        produced Net Income of $46 million during the period and noncash expense
        items
        of $66 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 $60 million inflow from Accounts
        Payable was the result of higher energy purchases.  The $53 million
        outflow from Margin Deposits was due to increased trading-related deposits
        resulting from the amended SIA.  In addition, SWEPCo’s $37 million
        inflow related to Fuel Over/Under Recovery, Net was primarily due to the
        new
        fuel surcharges effective December 2005 in its Arkansas service territory
        and in
        January 2006 in its Texas service territory.  The $23 million outflow
        from Fuel, Materials and Supplies was the result of increased fuel
        purchases.
 
 *Investing
        Activities*
 
 Cash
        Flows Used For Investing Activities during 2007 and 2006 were $253 million
        and
        $123 million, respectively.  The $250 million of cash flows for
        Construction Expenditures during 2007 were primarily related to new generation
        facilities.  The cash flows during 2006 were comprised primarily of
        Construction Expenditures related to projects for improved transmission and
        distribution service reliability.
  *Financing
        Activities*
 
 Cash
        Flows From Financing Activities were $132 million during 2007.  SWEPCo
        issued $250 million of Senior Unsecured Notes and had a net decrease of $135
        million in borrowings from the Utility Money Pool.  SWEPCo received
        $25 million of capital contributions from Parent Company.
 
 Cash
        Flows From Financing Activities were $46 million during 2006.  SWEPCo
        refinanced $82 million of Pollution Control Bonds and retired $87 million
        of
        long-term debt.  SWEPCo had a net increase of $65 million in
        borrowings from the Utility Money Pool and paid $20 million in common stock
        dividends.
 
 **Financing
        Activity**
 
 Long-term
        debt issuances and retirements during the first six months of 2007
        were:
 
 Issuances
 **Principal**
                **Amount**
              
              **Interest**
              
              **Due****Type
                  of Debt**
              
              
              **Rate**
              
              **Date****(in
                  thousands)**
              
              **(%)**Senior
                  Unsecured Notes
              
              $
              250,000
              
              5.55
              
              2017
 
 Retirements
 **Principal**
                **Amount**
              
              **Interest**
              
              **Due****Type
                  of Debt**
              
              
              **Rate**
              
              **Date****(in
                  thousands)**
              
              **(%)**Notes
                  Payable – Nonaffiliated
              
              $
              3,109
              
              4.47
              
              2011Notes
                  Payable – Nonaffiliated
              
              
              4,000
              
              6.36
              
              2007Notes
                  Payable – Nonaffiliated
              
              
              1,500
              
              Variable
              
              2008
 
 **Liquidity**
 
 SWEPCo
        has solid investment grade ratings, which provides ready access to capital
        markets in order to issue new debt or refinance long-term debt
        maturities.  In addition, SWEPCo participates in the Utility Money
        Pool, which provides access to AEP’s liquidity.
 
 **Summary
        Obligation Information**
 
 A
        summary
        of SWEPCo’s contractual obligations is included in its 2006 Annual Report and
        has not changed significantly from year-end other than the debt issuance
        and
        retirements discussed in “Cash Flow” and “Financing Activity” above and Energy
        and Capacity Purchase Contracts.  Effective January 1, 2007, SWEPCo
        transferred a significant amount of ERCOT energy marketing contracts to AEP
        Energy Partners (AEPEP), thereby decreasing its future obligations in Energy
        and
        Capacity Purchase Contracts.  See “ERCOT Contracts Transferred to
        AEPEP” section of Note 1.
 
 **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, SWEPCo 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 pending litigation and regulatory
        proceedings, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and
        Contingencies in the 2006 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 SWEPCo’s results of operations, financial condition and cash
        flows.
 
 ***New
        Generation***
 
 In
        December 2005, SWEPCo sought proposals for new peaking, intermediate and
        base
        load generation to be online between 2008 and 2011.  In May 2006,
        SWEPCo announced plans to construct new generation to satisfy the demands
        of its
        customers.  Plans include the construction of up to 480 MW of
        simple-cycle natural gas combustion turbine peaking generation in Tontitown,
        Arkansas and a 480 MW combined-cycle natural gas fired intermediate plant
        at its
        existing Arsenal Hill Power Plant in Shreveport, Louisiana.  SWEPCo
        also plans to build the Turk plant, a new 600 MW base load coal plant, with
        a
        73% ownership share, in Hempstead County, Arkansas by 2011 to meet the long-term
        generation needs of its customers.  Preliminary cost estimates for
        SWEPCo’s share of these new facilities are approximately $1.4 billion (this
        total includes all three plants, but excludes the related transmission
        investment and AFUDC).  Expenditures related to construction of all of
        these facilities are expected to total $349 million in 2007.  These
        new facilities are subject to regulatory approvals from SWEPCo’s three state
        commissions.  Mattison plant, the peaking generation facility in
        Tontitown, Arkansas has been approved by all three state
        commissions.  Mattison plant, Units 3 and 4 began commercial operation
        in July 2007, with the remaining two units scheduled for completion in December
        2007.  All four units of the Mattison plant are expected to be
        completed in advance of the originally planned 2008 commercial operation
        date.  Construction is expected to begin in the second half of 2007 on
        the base load facility and in 2008 on the intermediate facility, both upon
        approval from SWEPCo’s three state commissions.
 
 See
        the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for additional discussion of factors relevant to SWEPCo.
 
 **Critical
        Accounting Estimates**
 
 See
        the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
        Analysis of Registrant Subsidiaries” in the 2006 Annual Report for a discussion
        of the estimates and judgments required for regulatory accounting, revenue
        recognition, the valuation of long-lived assets, pension and other
        postretirement benefits and the impact of new accounting
        pronouncements.
 
 **Adoption
        of New Accounting Pronouncements**
 
 See
        the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for a discussion of adoption of new accounting
        pronouncements.
   
 **QUANTITATIVE
        AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT
        ACTIVITIES**
 
 **Market
        Risks**
 
 Risk
        management assets and liabilities are managed by AEPSC as agent.  The
        related risk management policies and procedures are instituted and administered
        by AEPSC.  See complete discussion within AEP’s “Quantitative and
        Qualitative Disclosures About Risk Management Activities”
section.  The following tables provide information about AEP’s risk
        management activities’ effect on SWEPCo.
 
 **MTM
        Risk Management Contract Net Assets**
 
 The
        following two tables summarize the various mark-to-market (MTM) positions
        included in the condensed consolidated balance sheet as of June 30, 2007
        and the
        reasons for changes in total MTM value as compared to December 31,
        2006.
  **Reconciliation
        of MTM Risk Management Contracts to**
 **Condensed
        Consolidated Balance Sheet**
 **As
        of June 30, 2007**
 **(in
        thousands)**
 
 **MTM
                  Risk Management Contracts**
              
              
              **Cash
                  Flow Hedges**
              
              
              **Total**Current
                  Assets
              
              $
              64,354
              
              
              $
              8
              
              
              $
              64,362Noncurrent
                  Assets
              
              
              10,929
              
              
              
              50
              
              
              
              10,979**Total
                  MTM Derivative Contract Assets**
              
              
              75,283
              
              
              
              58
              
              
              
              75,341Current
                  Liabilities
              
              
              (51,054
              )
              
              
              (12
              )
              
              
              (51,066
              )Noncurrent
                  Liabilities
              
              
              (7,822
              )
              
              
              -
              
              
              
              (7,822
              )**Total
                  MTM Derivative Contract Liabilities**
              
              
              (58,876
              )
              
              
              (12
              )
              
              
              (58,888
              )**Total
                  MTM Derivative Contract Net Assets (Liabilities)**
              
              $
              16,407
              
              
              $
              46
              
              
              $
              16,453
 
 **MTM
        Risk Management Contract Net Assets**
 **Six
        Months Ended June 30, 2007**
 **(in
        thousands)**
 
 **Total
                  MTM Risk Management Contract Net Assets at December 31,
                  2006**
              
              $
              20,166(Gain)
                  Loss from Contracts Realized/Settled During the Period and Entered
                  in a
                  Prior Period
              
              
              (2,885
              )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
              
              
              -Change
                  in Fair Value Due to Valuation Methodology Changes on Forward
                  Contracts
              
              
              -Changes
                  in Fair Value Due to Market Fluctuations During the Period
                  (b)
              
              
              1,853Changes
                  in Fair Value Allocated to Regulated Jurisdictions (c)
              
              
              (2,727
              )**Total
                  MTM Risk Management Contract Net Assets**
              
              
              16,407Net
                  Cash Flow Hedge Contracts
              
              
              46**Total
                  MTM Risk Management Contract Net Assets at June 30,
                  2007**
              
              $
              16,453
 
 (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.  Inception value is only recorded if observable market
                  data can be obtained for valuation inputs for the entire contract
                  term.  The contract prices are valued against market curves
                  associated with the delivery location and delivery
                  term.(b)
              Market
                  fluctuations are attributable to various factors such as supply/demand,
                  weather, etc.(c)
              “Changes
                  in Fair Value Allocated to Regulated Jurisdictions” relates to the net
                  gains (losses) of those contracts that are not reflected in the
                  Condensed
                  Consolidated Statements of Income.  These net gains (losses) are
                  recorded as regulatory liabilities/assets for those subsidiaries
                  that
                  operate in regulated jurisdictions.
  **Maturity
        and Source of Fair Value of MTM Risk Management Contract Net
        Assets**
 
 The
        following table presents:
 
 ·
              The
                  method of measuring fair value used in determining the carrying
                  amount of
                  total MTM asset or liability (external sources or modeled
                  internally).·
              The
                  maturity, by year, of net assets/liabilities to give an indication
                  of when
                  these MTM amounts will settle and generate
                  cash.
 
 **Maturity
        and Source of Fair Value of MTM**
 **Risk
        Management Contract Net Assets**
 **Fair
        Value of Contracts as of June 30, 2007**
 **(in
        thousands)**
 
 **Remainder**
                **2007**
              
              
              **2008**
              
              
              **2009**
              
              
              **2010**
              
              
              **2011**
              
              
              **After**
                **2011**
              
              
              **Total**Prices
                  Actively Quoted – ExchangeTraded
                  Contracts
              
              $
              (10,100
              )
              
              $
              1,544
              
              
              $
              (247
              )
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              (8,803
              )Prices
                  Provided by Other ExternalSources
                  -
                OTC BrokerQuotes
                  (a)
              
              
              21,341
              
              
              
              4,080
              
              
              
              (711
              )
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              24,710Prices
                  Based on Models and OtherValuation
                  Methods (b)
              
              
              (1,494
              )
              
              
              521
              
              
              
              1,471
              
              
              
              2
              
              
              
              -
              
              
              
              -
              
              
              
              500**Total**
              
              $
              9,747
              
              
              $
              6,145
              
              
              $
              513
              
              
              $
              2
              
              
              $
              -
              
              
              $
              -
              
              
              $
              16,407
 
 (a)
              “Prices
                  Provided by Other External Sources – OTC Broker Quotes” reflects
                  information obtained from over-the-counter brokers, industry services,
                  or
                  multiple-party on-line platforms.(b)
              “Prices
                  Based on Models and Other Valuation Methods” is used in absence of
                  independent information from external sources.  Modeled
                  information is derived using valuation models developed by the
                  reporting
                  entity, reflecting when appropriate, option pricing theory, discounted
                  cash flow concepts, valuation adjustments, etc. and may require
                  projection
                  of prices for underlying commodities beyond the period that prices
                  are
                  available from third-party sources.  In addition, where external
                  pricing information or market liquidity are limited, such valuations
                  are
                  classified as modeled.  The determination of the point at which
                  a market is no longer liquid for placing it in the modeled category
                  varies
                  by market.  Contract values that are measured using models or
                  valuation methods other than active quotes or OTC broker quotes
                  (because
                  of the lack of such data for all delivery quantities, locations
                  and
                  periods) incorporate in the model or other valuation methods, to
                  the
                  extent possible, OTC broker quotes and active quotes for deliveries
                  in
                  years and at locations for which such quotes are available including
                  values determinable by other third party
                  transactions.
 
 **Cash
        Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI)
        on
        the Condensed Consolidated Balance Sheet**
 
 SWEPCo
        is
        exposed to market fluctuations in energy commodity prices impacting power
        operations.  Management monitors these risks on future operations and
        may use various commodity instruments designated in qualifying cash flow
        hedge
        strategies to mitigate the impact of these fluctuations on the future cash
        flows.  Management does not hedge all commodity price
        risk.
 
 Management
        uses interest rate derivative transactions to manage interest rate risk related
        to anticipated borrowings of fixed-rate debt.  Management does not
        hedge all interest rate risk.
 
 Management
        uses forward contracts and collars as cash flow hedges to lock in prices
        on
        certain transactions denominated in foreign currencies where deemed
        necessary.  Management does not hedge all foreign currency
        exposure.
 
 The
        following table provides the detail on designated, effective cash flow hedges
        included in AOCI on the Condensed Consolidated Balance Sheets and the reasons
        for the changes from December 31, 2006 to June 30, 2007.  Only
        contracts designated as cash flow hedges are recorded in
        AOCI.  Therefore, economic hedge contracts that are not designated as
        effective cash flow hedges are marked-to-market and included in the previous
        risk management tables.  All amounts are presented net of related
        income taxes.
 
 **Total
        Accumulated Other Comprehensive Income (Loss) Activity**
 **Six
        Months Ended June 30, 2007**
 **(in
        thousands)**
 
 **Interest**
                **Rate**
              
              
              **Foreign**
                **Currency**
              
              
              **Total****Beginning
                  Balance in AOCI December 31, 2006**
              
              $
              (6,435
              )
              
              $
              25
              
              
              $
              (6,410
              )Changes
                  in Fair Value
              
              
              (1,019
              )
              
              
              549
              
              
              
              (470
              )Reclassifications
                  from AOCI to Net Income for
                Cash Flow Hedges Settled
              
              
              391
              
              
              
              -
              
              
              
              391**Ending
                  Balance in AOCI June 30, 2007**
              
              $
              (7,063
              )
              
              $
              574
              
              
              $
              (6,489
              )
 
 The
        portion of cash flow hedges in AOCI expected to be reclassified to earnings
        during the next twelve months is a $249 thousand loss.
 
 **Credit
        Risk**
 
 Counterparty
        credit quality and exposure is generally consistent with that of
        AEP.
 
 **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 June 30, 2007, a near term
        typical change in commodity prices is not expected to have a material effect
        on
        results of operations, cash flows or financial condition.
 
 The
        following table shows the end, high, average, and low market risk as measured
        by
        VaR for the periods indicated:
 
 **Six
                  Months Ended June 30, 2007**
              
              
              
              
              **Twelve
                  Months Ended December 31, 2006****(in
                  thousands)**
              
              
              
              
              **(in
                  thousands)****End**
              
              **High**
              
              **Average**
              
              **Low**
              
              
              
              
              **End**
              
              **High**
              
              **Average**
              
              **Low**$118
              
              $245
              
              $97
              
              $25
              
              
              
              
              $447
              
              $2,171
              
              $794
              
              $68
 
 The
        High
        VaR for the twelve months ended December 31, 2006 occurred in the fourth
        quarter
        due to volatility in the ERCOT region.
 
 **VaR
        Associated with Debt Outstanding**
 
 Management
        also utilizes a VaR model to measure interest rate market risk exposure.
        The
        interest rate VaR model is based on a Monte Carlo simulation with a 95%
        confidence level and a one-year holding period.  The risk of potential
        loss in fair value attributable to exposure to interest rates primarily related
        to long-term debt with fixed interest rates was $44 million and $25 million
        at
        June 30, 2007 and December 31, 2006, respectively.  Management would
        not expect to liquidate the entire debt portfolio in a one-year holding period;
        therefore, a near term change in interest rates should not negatively affect
        results of operations or consolidated financial position.
   
 **SOUTHWESTERN
        ELECTRIC POWER COMPANY CONSOLIDATED**
 **CONDENSED
        CONSOLIDATED STATEMENTS OF INCOME**
 **For
        the Three and Six Months Ended June 30, 2007 and 2006**
 **(in
        thousands)**
 **(Unaudited)**
 
 **Three
                  Months Ended**
              
              
              **Six
                  Months Ended****2007**
              
              
              **2006**
              
              
              **2007**
              
              
              **2006****REVENUES**Electric
                  Generation, Transmission and Distribution
              
              $
              329,250
              
              
              $
              349,650
              
              
              $
              656,534
              
              
              $
              643,643Sales
                  to AEP Affiliates
              
              
              16,237
              
              
              
              9,414
              
              
              
              32,652
              
              
              
              20,179Other
              
              
              535
              
              
              
              420
              
              
              
              935
              
              
              
              794**TOTAL**
              
              
              346,022
              
              
              
              359,484
              
              
              
              690,121
              
              
              
              664,616**EXPENSES**Fuel
                  and Other Consumables Used for Electric Generation
              
              
              125,994
              
              
              
              118,271
              
              
              
              237,981
              
              
              
              208,932Purchased
                  Electricity for Resale
              
              
              56,870
              
              
              
              44,884
              
              
              
              109,368
              
              
              
              74,102Purchased
                  Electricity from AEP Affiliates
              
              
              16,085
              
              
              
              16,826
              
              
              
              39,002
              
              
              
              40,163Other
                  Operation
              
              
              50,204
              
              
              
              53,216
              
              
              
              103,987
              
              
              
              102,916Maintenance
              
              
              29,721
              
              
              
              22,231
              
              
              
              56,060
              
              
              
              46,888Depreciation
                  and Amortization
              
              
              34,668
              
              
              
              32,959
              
              
              
              68,790
              
              
              
              65,576Taxes
                  Other Than Income Taxes
              
              
              17,540
              
              
              
              16,165
              
              
              
              33,531
              
              
              
              32,147**TOTAL**
              
              
              331,082
              
              
              
              304,552
              
              
              
              648,719
              
              
              
              570,724**OPERATING
                  INCOME**
              
              
              14,940
              
              
              
              54,932
              
              
              
              41,402
              
              
              
              93,892Other
                  Income
              
              
              3,338
              
              
              
              840
              
              
              
              5,434
              
              
              
              1,568Interest
                  Expense
              
              
              (17,235
              )
              
              
              (14,073
              )
              
              
              (32,725
              )
              
              
              (26,844
              )**INCOME
                  BEFORE INCOME TAXES AND**
                **MINORITY
                  INTEREST EXPENSE**
              
              
              1,043
              
              
              
              41,699
              
              
              
              14,111
              
              
              
              68,616Income
                  Tax Expense (Credit)
              
              
              (1,553
              )
              
              
              12,491
              
              
              
              1,068
              
              
              
              21,314Minority
                  Interest Expense
              
              
              972
              
              
              
              896
              
              
              
              1,814
              
              
              
              1,118**NET
                  INCOME**
              
              
              1,624
              
              
              
              28,312
              
              
              
              11,229
              
              
              
              46,184Preferred
                  Stock Dividend Requirements
              
              
              57
              
              
              
              58
              
              
              
              114
              
              
              
              115**EARNINGS
                  APPLICABLE TO COMMON STOCK**
              
              $
              1,567
              
              
              $
              28,254
              
              
              $
              11,115
              
              
              $
              46,069
 
 *The
                  common stock of SWEPCo is owned by a wholly-owned subsidiary of
                  AEP.*
 
 *See
                  Condensed Notes to Condensed Financial Statements of Registrant
                  Subsidiaries.*
 
 
 
 **SOUTHWESTERN
        ELECTRIC POWER COMPANY CONSOLIDATED**
 **CONDENSED
        CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S**
 **EQUITY
        AND COMPREHENSIVE INCOME (LOSS)**
 **For
        the Six Months Ended June 30, 2007 and 2006**
 **(in
        thousands)**
 **(Unaudited)**
 
 **Common
                  Stock**
              
              
              **Paid-in
                  Capital**
              
              
              **Retained
                  Earnings**
              
              
              **Accumulated
                  Other Comprehensive Income (Loss)**
              
              
              **Total****DECEMBER
                  31, 2005**
              
              $
              135,660
              
              
              $
              245,003
              
              
              $
              407,844
              
              
              $
              (6,129
              )
              
              $
              782,378Common
                  Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (20,000
              )
              
              
              
              
              
              
              (20,000
              )Preferred
                  Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (115
              )
              
              
              
              
              
              
              (115
              )**TOTAL**
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              762,263**COMPREHENSIVE
                  INCOME****Other
                  Comprehensive Income,** **Net of
                  Taxes:**Cash
                  Flow Hedges, Net of Tax of $519
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              964
              
              
              
              964**NET
                  INCOME**
              
              
              
              
              
              
              
              
              
              
              46,184
              
              
              
              
              
              
              
              46,184**TOTAL
                  COMPREHENSIVE INCOME**
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              47,148**JUNE
                  30, 2006**
              
              $
              135,660
              
              
              $
              245,003
              
              
              $
              433,913
              
              
              $
              (5,165
              )
              
              $
              809,411**DECEMBER
                  31, 2006**
              
              $
              135,660
              
              
              $
              245,003
              
              
              $
              459,338
              
              
              $
              (18,799
              )
              
              $
              821,202FIN
                  48 Adoption, Net of Tax
              
              
              
              
              
              
              
              
              
              
              (1,642
              )
              
              
              
              
              
              
              (1,642
              )Capital
                  Contribution from Parent Company
              
              
              
              
              
              
              25,000
              
              
              
              
              
              
              
              
              
              
              
              25,000Preferred
                  Stock Dividends
              
              
              
              
              
              
              
              
              
              
              (114
              )
              
              
              
              
              
              
              (114
              )**TOTAL**
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              844,446**COMPREHENSIVE
                  INCOME****Other
                  Comprehensive Loss, Net of Taxes:**Cash
                  Flow Hedges, Net of Tax of $172
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              (79
              )
              
              
              (79
              )**NET
                  INCOME**
              
              
              
              
              
              
              
              
              
              
              11,229
              
              
              
              
              
              
              
              11,229**TOTAL
                  COMPREHENSIVE INCOME**
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              11,150**JUNE
                  30, 2007**
              
              $
              135,660
              
              
              $
              270,003
              
              
              $
              468,811
              
              
              $
              (18,878
              )
              
              $
              855,596
 
 *See
        Condensed Notes to Condensed Financial Statements of Registrant
        Subsidiaries.*
  
  **SOUTHWESTERN
        ELECTRIC POWER COMPANY CONSOLIDATED**
 **CONDENSED
        CONSOLIDATED BALANCE SHEETS**
 **ASSETS**
 **June
        30, 2007 and December 31, 2006**
 **(in
        thousands)**
 **(Unaudited)**
 
 **2007**
              
              
              **2006****CURRENT
                  ASSETS**Cash
                  and Cash Equivalents
              
              $
              1,558
              
              
              $
              2,618Accounts
                  Receivable:Customers
              
              
              66,047
              
              
              
              88,245Affiliated
                  Companies
              
              
              54,004
              
              
              
              59,679Miscellaneous
              
              
              9,473
              
              
              
              8,595Allowance
                  for Uncollectible Accounts
              
              
              (32
              )
              
              
              (130
              )Total
                  Accounts Receivable
              
              
              129,492
              
              
              
              156,389Fuel
              
              
              77,717
              
              
              
              69,426Materials
                  and Supplies
              
              
              48,847
              
              
              
              46,001Risk
                  Management Assets
              
              
              64,362
              
              
              
              120,036Margin
                  Deposits
              
              
              21,940
              
              
              
              41,579Prepayments
                  and Other
              
              
              22,284
              
              
              
              18,256**TOTAL**
              
              
              366,200
              
              
              
              454,305**PROPERTY,
                  PLANT AND EQUIPMENT**Electric:Production
              
              
              1,596,040
              
              
              
              1,576,200Transmission
              
              
              710,732
              
              
              
              668,008Distribution
              
              
              1,279,426
              
              
              
              1,228,948Other
              
              
              615,126
              
              
              
              595,429Construction
                  Work in Progress
              
              
              392,402
              
              
              
              259,662**Total**
              
              
              4,593,726
              
              
              
              4,328,247Accumulated
                  Depreciation and Amortization
              
              
              1,884,582
              
              
              
              1,834,145**TOTAL
                  - NET**
              
              
              2,709,144
              
              
              
              2,494,102**OTHER
                  NONCURRENT ASSETS**Regulatory
                  Assets
              
              
              138,155
              
              
              
              156,420Long-term
                  Risk Management Assets
              
              
              10,979
              
              
              
              20,531Employee
                  Benefits and Pension Assets
              
              
              24,576
              
              
              
              26,029Deferred
                  Charges and Other
              
              
              62,266
              
              
              
              39,581**TOTAL**
              
              
              235,976
              
              
              
              242,561**TOTAL
                  ASSETS**
              
              $
              3,311,320
              
              
              $
              3,190,968
 
 *See
        Condensed Notes to Condensed Financial Statements of Registrant
        Subsidiaries.*
  
 **SOUTHWESTERN
        ELECTRIC POWER COMPANY CONSOLIDATED**
 **CONDENSED
        CONSOLIDATED BALANCE SHEETS**
 **LIABILITIES
        AND SHAREHOLDERS’ EQUITY**
 **June
        30, 2007 and December 31, 2006**
 **(Unaudited)**
 
 **2007**
              
              
              **2006****CURRENT
                  LIABILITIES**
              
              **(in
                  thousands)**Advances
                  from Affiliates
              
              $
              53,955
              
              
              $
              188,965Accounts
                  Payable:General
              
              
              157,564
              
              
              
              140,424Affiliated
                  Companies
              
              
              70,842
              
              
              
              68,680Short-term
                  Debt – Nonaffiliated
              
              
              22,373
              
              
              
              17,143Long-term
                  Debt Due Within One Year – Nonaffiliated
              
              
              97,406
              
              
              
              102,312Risk
                  Management Liabilities
              
              
              51,066
              
              
              
              109,578Customer
                  Deposits
              
              
              38,233
              
              
              
              48,277Accrued
                  Taxes
              
              
              67,335
              
              
              
              31,591Regulatory
                  Liability for Over-Recovered Fuel Costs
              
              
              51,805
              
              
              
              26,012Other
              
              
              75,835
              
              
              
              85,086**TOTAL**
              
              
              686,414
              
              
              
              818,068**NONCURRENT
                  LIABILITIES**Long-term
                  Debt – Nonaffiliated
              
              
              819,450
              
              
              
              576,694Long-term
                  Debt – Affiliated
              
              
              50,000
              
              
              
              50,000Long-term
                  Risk Management Liabilities
              
              
              7,822
              
              
              
              14,083Deferred
                  Income Taxes
              
              
              348,760
              
              
              
              374,548Regulatory
                  Liabilities and Deferred Investment Tax Credits
              
              
              339,243
              
              
              
              346,774Deferred
                  Credits and Other
              
              
              197,615
              
              
              
              183,087**TOTAL**
              
              
              1,762,890
              
              
              
              1,545,186**TOTAL
                  LIABILITIES**
              
              
              2,449,304
              
              
              
              2,363,254Minority
                  Interest
              
              
              1,723
              
              
              
              1,815Cumulative
                  Preferred Stock Not Subject to Mandatory Redemption
              
              
              4,697
              
              
              
              4,697Commitments
                  and Contingencies (Note 4)**COMMON
                  SHAREHOLDER’S EQUITY**Common
                  Stock – Par Value – $18 Per Share:Authorized
                  – 7,600,000 SharesOutstanding
                  – 7,536,640 Shares
              
              
              135,660
              
              
              
              135,660Paid-in
                  Capital
              
              
              270,003
              
              
              
              245,003Retained
                  Earnings
              
              
              468,811
              
              
              
              459,338Accumulated
                  Other Comprehensive Income (Loss)
              
              
              (18,878
              )
              
              
              (18,799
              )**TOTAL**
              
              
              855,596
              
              
              
              821,202**TOTAL
                  LIABILITIES AND SHAREHOLDERS’ EQUITY**
              
              $
              3,311,320
              
              
              $
              3,190,968
 
 *See
        Condensed Notes to Condensed Financial Statements of Registrant
        Subsidiaries.*
 
  **SOUTHWESTERN
        ELECTRIC POWER COMPANY CONSOLIDATED**
 **CONDENSED
        CONSOLIDATED STATEMENTS OF CASH FLOWS**
 **For
        the Six Months Ended June 30, 2007 and 2006**
 **(in
        thousands)**
 **(Unaudited)**
 
 **2007**
              
              
              **2006****OPERATING
                  ACTIVITIES****Net
                  Income**
              
              $
              11,229
              
              
              $
              46,184**Adjustments
                  for Noncash Items:**Depreciation
                  and Amortization
              
              
              68,790
              
              
              
              65,576Deferred
                  Income Taxes
              
              
              (21,658
              )
              
              
              (15,511
              )Provision
                  for Fuel Disallowance
              
              
              24,500
              
              
              
              -Mark-to-Market
                  of Risk Management Contracts
              
              
              3,759
              
              
              
              (14,213
              )Deferred
                  Property Taxes
              
              
              (19,210
              )
              
              
              (18,593
              )Change
                  in Other Noncurrent Assets
              
              
              (107
              )
              
              
              16,538Change
                  in Other Noncurrent Liabilities
              
              
              (7,932
              )
              
              
              (16,419
              )**Changes
                  in Certain Components of Working Capital:**Accounts
                  Receivable, Net
              
              
              26,897
              
              
              
              (15,662
              )Fuel,
                  Materials and Supplies
              
              
              (11,126
              )
              
              
              (23,003
              )Margin
                  Deposits
              
              
              19,639
              
              
              
              (52,838
              )Accounts
                  Payable
              
              
              8,388
              
              
              
              60,158Customer
                  Deposits
              
              
              (10,044
              )
              
              
              3,763Accrued
                  Taxes, Net
              
              
              36,445
              
              
              
              19,153Fuel Over/Under Recovery, Net
              
              
              1,293
              
              
              
              37,377Other
                  Current Assets
              
              
              1,266
              
              
              
              3,560Other
                  Current Liabilities
              
              
              (11,532
              )
              
              
              (19,916
              )**Net
                  Cash Flows From Operating Activities**
              
              
              120,597
              
              
              
              76,154**INVESTING
                  ACTIVITIES**Construction
                  Expenditures
              
              
              (250,409
              )
              
              
              (122,616
              )Other
              
              
              (2,858
              )
              
              
              (659
              )**Net
                  Cash Flows Used For Investing Activities**
              
              
              (253,267
              )
              
              
              (123,275
              )**FINANCING
                  ACTIVITIES**Capital
                  Contribution from Parent
              
              
              25,000
              
              
              
              -Issuance
                  of Long-term Debt – Nonaffiliated
              
              
              247,496
              
              
              
              80,593Change
                  in Short-term Debt, Net – Nonaffiliated
              
              
              5,230
              
              
              
              8,855Change
                  in Advances from Affiliates, Net
              
              
              (135,010
              )
              
              
              64,873Retirement
                  of Long-term Debt – Nonaffiliated
              
              
              (8,609
              )
              
              
              (86,594
              )Principal
                  Payments for Capital Lease Obligations
              
              
              (2,383
              )
              
              
              (1,432
              )Dividends
                  Paid on Common Stock
              
              
              -
              
              
              
              (20,000
              )Dividends
                  Paid on Cumulative Preferred Stock
              
              
              (114
              )
              
              
              (115
              )**Net
                  Cash Flows From Financing Activities**
              
              
              131,610
              
              
              
              46,180**Net
                  Decrease in Cash and Cash Equivalents**
              
              
              (1,060
              )
              
              
              (941
              )**Cash
                  and Cash Equivalents at Beginning of Period**
              
              
              2,618
              
              
              
              3,049**Cash
                  and Cash Equivalents at End of Period**
              
              $
              1,558
              
              
              $
              2,108**SUPPLEMENTARY
                  INFORMATION**Cash
                  Paid for Interest, Net of Capitalized Amounts
              
              $
              25,876
              
              
              $
              24,840Net
                  Cash Paid for Income Taxes
              
              
              10,617
              
              
              
              42,788Noncash
                  Acquisitions Under Capital Leases
              
              
              6,511
              
              
              
              5,537Construction
                  Expenditures Included in Accounts Payable at June 30,
              
              
              38,630
              
              
              
              8,326
 
 *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
                  Reference**Significant
                  Accounting Matters
              Note
                  1New
                  Accounting Pronouncements and Extraordinary Item
              Note
                  2Rate
                  Matters
              Note
                  3Commitments,
                  Guarantees and Contingencies
              Note
                  4Benefit
                  Plans
              Note
                  6Business
                  Segments
              Note
                  7Income
                  Taxes
              Note
                  8Financing
                  Activities
              Note
                  9




**CONDENSED
        NOTES TO CONDENSED FINANCIAL STATEMENTS OF**
 **REGISTRANT
        SUBSIDIARIES**
 
 The
                  condensed notes to condensed financial statements that
                  follow are a combined presentation for the Registrant
                  Subsidiaries.  The following list indicates the registrants to
                  which the footnotes apply:1.
              Significant Accounting Matters
              APCo,
                  CSPCo, I&M, OPCo, PSO, SWEPCo2.
              New Accounting Pronouncements 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
              CSPCo6.
              Benefit Plans
              APCo,
                  CSPCo, I&M, OPCo, PSO, SWEPCo7.
              Business Segments
              APCo,
                  CSPCo, I&M, OPCo, PSO, SWEPCo8.
              Income Taxes
              APCo,
                  CSPCo, I&M, OPCo, PSO, SWEPCo9.
              Financing Activities
              APCo,
                  CSPCo, I&M, OPCo, PSO,
                  SWEPCo
  
  **1.**
              **SIGNIFICANT ACCOUNTING
                  MATTERS**
 
 ***General***
 
 The
        accompanying unaudited condensed financial statements and footnotes were
        prepared in accordance with accounting principles generally accepted in the
        United States of America (GAAP) for interim financial information and with
        the
        instructions to Form 10-Q and Article 10 of Regulation S-X of the
        SEC.  Accordingly, they do not include all the information and
        footnotes required by GAAP for complete financial statements.
 
 In
        the
        opinion of management, the unaudited interim financial statements reflect
        all
        normal and recurring accruals and adjustments necessary for a fair presentation
        of the results of operations, financial position and cash flows for the interim
        periods for each Registrant Subsidiary.  The results of operations for
        the six months ended June 30, 2007 are not necessarily indicative of results
        that may be expected for the year ending December 31, 2007.  The
        accompanying condensed financial statements are unaudited and should be read
        in
        conjunction with the audited 2006 financial statements and notes thereto,
        which
        are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K for the
        year ended December 31, 2006 as filed with the SEC on February 28,
        2007.
 
 ***Property,
        Plant and Equipment and Equity Investments***
 
 Electric
        utility property, plant and equipment are stated at original purchase cost.
        Property, plant and equipment of nonregulated operations and other investments
        are stated at fair market value at acquisition (or as adjusted for any
        applicable impairments) plus the original cost of property acquired or
        constructed since the acquisition, less disposals.  Additions, major
        replacements and betterments are added to the plant accounts.  Normal
        and routine retirements from the plant accounts, net of salvage, are charged
        to
        accumulated depreciation for both cost-based rate-regulated and nonregulated
        operations under the group composite method of depreciation.  The
        group composite method of depreciation assumes that on average, asset components
        are retired at the end of their useful lives and thus there is no gain or
        loss.  The equipment in each primary electric plant account is
        identified as a separate group.  Under the group composite method of
        depreciation, continuous interim routine replacements of items such as boiler
        tubes, pumps, motors, etc. result in the original cost, less salvage, being
        charged to accumulated depreciation.  For the nonregulated generation
        assets, a gain or loss would be recorded if the retirement is not considered
        an
        interim routine replacement.  The depreciation rates that are
        established for the generating plants take into account the past history
        of
        interim capital replacements and the amount of salvage
        received.  These rates and the related lives are subject to periodic
        review.  Removal costs are charged to regulatory liabilities for
        cost-based rate-regulated operations and charged to expense for nonregulated
        operations.  The costs of labor, materials and overhead incurred to
        operate and maintain the plants are included in operating expenses.
 
 Long-lived
        assets are required to be tested for impairment when it is determined that
        the
        carrying value of the assets may no longer be recoverable or when the assets
        meet the held for sale criteria under SFAS 144, “Accounting for the Impairment
        or Disposal of Long-Lived Assets.”  Equity investments are required to
        be tested for impairment when it is determined there may be an other than
        temporary loss in value.
 
 The
        fair
        value of an asset or investment is the amount at which that asset or investment
        could be bought or sold in a current transaction between willing parties,
        as
        opposed to a forced or liquidation sale.  Quoted market prices in
        active markets are the best evidence of fair value and are used as the basis
        for
        the measurement, if available.  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.
 
 ***Revenue
        Recognition***
 
 *Traditional
        Electricity Supply and Delivery Activities*
 
 Registrant
        Subsidiaries recognize revenues from retail and wholesale electricity supply
        sales and electricity transmission and distribution delivery
        services.  Registrant Subsidiaries recognize the revenues in the
        financial statements upon delivery of the energy to the customer and include
        unbilled as well as billed amounts.  In accordance with the applicable
        state commission regulatory treatment, PSO and SWEPCo do not record the fuel
        portion of unbilled revenue.
  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, and the AEP East companies
        purchase power back from the same RTO to supply power to their respective
        loads.  These power sales and purchases are reported on a net basis as
        revenues in the financial statements.  Other RTOs in which the
        Registrant Subsidiaries operate do not function in the same manner as
        PJM.  They function as balancing organizations and not as an
        exchange.
 
 Physical
        energy purchases including those from all RTOs that are identified as
        non-trading, but excluding PJM purchases described in the preceding paragraph,
        are accounted for on a gross basis in Purchased Electricity for Resale in
        the
        financial statements.
 
 In
        general, Registrant Subsidiaries record expenses upon receipt of purchased
        electricity and when expenses are incurred, with the exception of certain
        power
        purchase contracts that are derivatives and accounted for using MTM accounting
        where generation/supply rates are not cost-based regulated, such as in Ohio
        and
        the ERCOT portion of Texas.  In jurisdictions where the
        generation/supply business is subject to cost-based regulation, the unrealized
        MTM amounts are deferred as regulatory assets (for losses) and regulatory
        liabilities (for gains).
 
 Beginning
        in July 2004, as a result of the sale of generation assets in AEP’s west zone,
        AEP’s west zone is short capacity and must purchase physical power to supply
        retail and wholesale customers.  For power purchased under derivative
        contracts in AEP’s west zone where the AEP West companies are short capacity,
        they recognize as revenues the unrealized gains and losses (other than those
        subject to regulatory deferral) that result from measuring these contracts
        at
        fair value during the period before settlement.  If the contract
        results in the physical delivery of power from a RTO or any other counterparty,
        the Registrant Subsidiaries reverse the previously recorded unrealized gains
        and
        losses from MTM valuations and record the settled amounts gross as Purchased
        Energy for Resale.  If the contract does not result in physical
        delivery, the Registrant Subsidiaries reverse the previously recorded unrealized
        gains and losses from MTM valuations and record the settled amounts as revenues
        in the financial statements on a net basis.
 
 *Energy
        Marketing and Risk Management Activities*
 
 All
        of
        the Registrant Subsidiaries engage in wholesale electricity, coal and emission
        allowances marketing and risk management activities focused on wholesale
        markets
        where Registrant Subsidiaries own assets.  Registrant Subsidiaries’
activities include the purchase and sale of energy under forward contracts
        at
        fixed and variable prices and the buying and selling of financial energy
        contracts which include exchange traded futures and options, and
        over-the-counter options and swaps.  The Registrant Subsidiaries
        engage in certain energy marketing and risk management transactions with
        RTOs.
 
 Registrant
        Subsidiaries recognize revenues and expenses from wholesale marketing and
        risk
        management transactions that are not derivatives upon delivery of the
        commodity.  Registrant Subsidiaries use MTM accounting for wholesale
        marketing and risk management transactions that are derivatives unless the
        derivative is designated in a qualifying cash flow or fair value hedge
        relationship, or as a normal purchase or sale.  The unrealized and
        realized gains and losses on wholesale marketing and risk management
        transactions that are accounted for using MTM are included in revenues in
        the
        financial statements on a net basis.  In jurisdictions subject to
        cost-based regulation, the unrealized MTM amounts are deferred as regulatory
        assets (for losses) and regulatory liabilities (for
        gains).  Unrealized MTM gains and losses are included on the balance
        sheets as Risk Management Assets or Liabilities as appropriate.
 
 Certain
        wholesale marketing and risk management transactions are designated as hedges
        of
        future cash flows as a result of forecasted transactions (cash flow hedge)
        or a
        hedge of a recognized asset, liability or firm commitment (fair value
        hedge).  The gains or losses on derivatives designated as fair value
        hedges are recognized in revenues in the financial statements in the period
        of
        change together with the offsetting losses or gains on the hedged item
        attributable to the risks being hedged.  For derivatives designated as
        cash flow hedges, the effective portion of the derivative’s gain or loss is
        initially reported as a component of Accumulated Other Comprehensive Income
        (Loss) and, depending upon the specific nature of the risk being hedged,
        subsequently reclassified into revenues or expenses in the financial statements
        when the forecasted transaction is realized and affects earnings.  The
        ineffective portion of the gain or loss is recognized in revenues in the
        financial statements immediately, except in those jurisdictions subject to
        cost-based regulation.  In those regulated jurisdictions the
        Registrant Subsidiaries defer the ineffective portion as regulatory assets
        (for
        losses) and regulatory liabilities (for gains).
 
 ***Components
        of Accumulated Other Comprehensive Income (Loss)
        (AOCI)***
 
 AOCI
        is
        included on the balance sheets in the common shareholder’s equity
        section.  AOCI for Registrant Subsidiaries as of June 30, 2007 and
        December 31, 2006 is shown in the following table:
 
 **June
                  30,**
              
              
              **December
                  31,****2007**
              
              
              **2006****Components**
              
              **(in
                  thousands)****Cash
                  Flow Hedges:**APCo
              
              $
              2,063
              
              
              $
              (2,547
              )CSPCo
              
              
              4,067
              
              
              
              3,398I&M
              
              
              (7,756
              )
              
              
              (8,962
              )OPCo
              
              
              8,233
              
              
              
              7,262PSO
              
              
              (979
              )
              
              
              (1,070
              )SWEPCo
              
              
              (6,489
              )
              
              
              (6,410
              )**SFAS
                  158 Costs:**APCo
              
              $
              (40,999
              )
              
              $
              (52,244
              )CSPCo
              
              
              (25,386
              )
              
              
              (25,386
              )I&M
              
              
              (6,089
              )
              
              
              (6,089
              )OPCo
              
              
              (64,025
              )
              
              
              (64,025
              )SWEPCo
              
              
              (12,389
              )
              
              
              (12,389
              )
 
 ***Related
        Party Transactions***
 
 **Lawrenceburg
        Unit Power Agreement** (**UPA) between CSPCo and
        AEGCo**
 
 In
        March
        2007, CSPCo and AEGCo entered into a 10-year UPA for the entire output from
        the
        Lawrenceburg Plant effective with AEGCo’s purchase of the plant in May
        2007.  The UPA has an option for an additional 2-year
        period.  I&M operates the plant under an agreement with
        AEGCo.
 
 Under
        the
        UPA, CSPCo pays AEGCo for the capacity, depreciation, fuel, operation and
        maintenance and tax expenses.  These payments are due regardless of
        whether the plant is operating.  The fuel and operation and
        maintenance payments are based on actual costs incurred.  All expenses
        are trued up periodically.
 
 CSPCo
        paid AEGCo $15.9 million in the second quarter of 2007.  On its 2007
        Condensed Consolidated Statement of Income, CSPCo recorded these purchases
        in
        Other Operation expense for the capacity and depreciation portion, and in
        Purchased Electricity from AEP Affiliates for the variable cost
        portion.
 
 **ERCOT
        Contracts Transferred to AEPEP**
 
 Effective
        January 1, 2007, PSO and SWEPCo transferred certain existing ERCOT energy
        marketing contracts to AEPEP and entered into intercompany financial and
        physical purchase and sale agreements with AEPEP.  This was done to
        lock in PSO and SWEPCo’s margins on ERCOT trading and marketing contracts and to
        transfer the future associated commodity price and credit risk to
        AEPEP.  The contracts will mature over the next three
        years.
 
 PSO
        and
        SWEPCo have historically presented third party ERCOT trading and marketing
        activity on a net basis in Revenues - Electric Generation, Transmission and
        Distribution.  The applicable ERCOT third party trading and marketing
        contracts that were not transferred to AEPEP will remain until maturity on
        PSO
        and SWEPCo and will be presented on a net basis in Sales to AEP Affiliates
        on
        PSO’s and SWEPCo’s Statements of Income.
  The
        following table indicates the sales to AEPEP and the amounts reclassified
        from
        third party to affiliate:
 
 **For
                  the Three Months Ended June 30, 2007****Net
                  Settlement**
                **With
                  AEPEP**
              
              **Third
                  Party Amounts**
                **Reclassified
                  to Affiliate**
              
              **Net
                  Amount included in Sales to AEP Affiliates****Company**
              **(in
                  thousands)**PSO
              
              $
              33,293
              
              
              $
              (30,307
              )
              
              $
              2,986SWEPCo
              
              
              46,678
              
              
              
              (43,160
              )
              
              
              3,518
 
 **For
                  the Six Months Ended June 30,
                  2007****Net
                  Settlement**
                **With
                  AEPEP**
              
              **Third
                  Party Amounts**
                **Reclassified
                  to Affiliate**
              
              **Net
                  Amount included in Sales to AEP
                  Affiliates****Company**
              **(in
                  thousands)**PSO
              
              $
              76,443
              
              
              $
              (66,144
              )
              
              $
              10,299SWEPCo
              
              
              93,554
              
              
              
              (81,419
              )
              
              
              12,135
 
 The
        following table indicates the affiliated portion of risk management assets
        and
        liabilities reflected on PSO’s and SWEPCo’s balance sheets associated with these
        contracts:
  **As
                  of June 30, 2007****PSO**
              
              
              **SWEPCo****Current**
              
              **(in
                  thousands)**Risk
                  Management Assets
              
              $
              12,513
              
              
              $
              14,743Risk
                  Management Liabilities
              
              
              (1,894
              )
              
              
              (2,231
              )**Noncurrent**Long-term
                  Risk Management Assets
              
              $
              943
              
              
              $
              1,111Long-term
                  Risk Management Liabilities
              
              
              (2,946
              )
              
              
              (3,471
              )
 
 **Texas
        Restructuring – SPP**
 
 In
        August
        2006, the PUCT adopted a rule extending the delay in implementation of customer
        choice in the SPP area of Texas until no sooner than January 1,
        2011.  SWEPCo’s and approximately 3% of TNC’s businesses were in
        SPP.  A petition was filed in May 2006 requesting approval to transfer
        Mutual Energy SWEPCO L.P.’s (a subsidiary of AEP C&I Company, LLC) customers
        and TNC’s facilities and certificated service territory located in the SPP area
        to SWEPCo.  In January 2007, the final regulatory approval was
        received for the transfers.  The transfers were effective February
        2007 and were recorded at net book value of $11.6 million.  The
        Arkansas Public Service Commission’s approval requires SWEPCo to amend its fuel
        recovery tariff so that Arkansas customers do not pay the incremental cost
        of
        serving the additional load.
 
 ***Reclassifications***
 
 Certain
        prior period financial statement items have been reclassified to conform
        to
        current period presentation.  These revisions had no impact on the
        Registrant Subsidiaries’ previously reported results of operations or changes in
        shareholders’ equity.
 
 On
        their
        statements of income, the Registrant Subsidiaries reclassified regulatory
        credits related to regulatory asset cost deferral on ARO from Depreciation
        and
        Amortization to Other Operation and Maintenance to offset the ARO accretion
        expense.  The following table shows the credits reclassified by the
        Registrant Subsidiaries in 2006:
 
 **Three
                  Months Ended**
              
              
              **Six
                  Months Ended****June
                  30, 2006**
              
              
              **June
                  30, 2006****Company**
              **(in
                  thousands)**APCo
              
              $
              302
              
              
              
              
              $
              598I&M
              
              
              6,118
              
              
              
              
              
              11,707
  **2.**
              **NEW
                  ACCOUNTING PRONOUNCEMENTS AND EXTRAORDINARY
                  ITEM**
 
 **NEW
        ACCOUNTING PRONOUNCEMENTS**
 
 Upon
        issuance of exposure drafts or final pronouncements, management thoroughly
        reviews the new accounting literature to determine the relevance, if any,
        to the
        Registrant Subsidiaries’ business.  The following represents a summary
        of new pronouncements issued or implemented in 2007 and standards issued
        but not
        implemented that management has determined relate to the Registrant
        Subsidiaries’ operations.
 
 ***SFAS
        157 “Fair Value Measurements” (SFAS 157)***
 
 In
        September 2006, the FASB issued SFAS 157, enhancing existing guidance for
        fair
        value measurement of assets and liabilities and instruments measured at fair
        value that are classified in shareholders’ equity.  The statement
        defines fair value, establishes a fair value measurement framework and expands
        fair value disclosures.  It emphasizes that fair value is market-based
        with the highest measurement hierarchy being market prices in active
        markets.  The standard requires fair value measurements be disclosed
        by hierarchy level and an entity include its own credit standing in the
        measurement of its liabilities and modifies the transaction price
        presumption.
 
 SFAS
        157
        is effective for interim and annual periods in fiscal years beginning after
        November 15, 2007.  Management expects that the adoption of this
        standard will impact MTM valuations of certain contracts, but is unable to
        quantify the effect.  Although the statement is applied prospectively
        upon adoption, the effect of certain transactions is applied retrospectively
        as
        of the beginning of the fiscal year of application, with a cumulative effect
        adjustment to the appropriate balance sheet items.  The Registrant
        Subsidiaries will adopt SFAS 157 effective January 1, 2008.
 
 ***SFAS
        159 “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS
        159)***
 
 In
        February 2007, the FASB issued SFAS 159, permitting entities to choose to
        measure many financial instruments and certain other items at fair
        value.  The standard also establishes presentation and disclosure
        requirements designed to facilitate comparison between entities that choose
        different measurement attributes for similar types of assets and
        liabilities.
 
 SFAS
        159
        is effective for annual periods in fiscal years beginning after November
        15,
        2007.  If the fair value option is elected, the effect of the first
        remeasurement to fair value is reported as a cumulative effect adjustment
        to the
        opening balance of retained earnings.  In the event the Registrant
        Subsidiaries elect the fair value option promulgated by this standard, the
        valuations of certain assets and liabilities may be impacted.  The
        statement is applied prospectively upon adoption.  The Registrant
        Subsidiaries will adopt SFAS 159 effective January 1,
        2008.  Management expects the adoption of this standard to have an
        immaterial impact on the financial statements.
 
 ***EITF
        Issue No. 06-11 “Accounting for Income Tax Benefits of Dividends on Share-Based
        Payment Awards”   (EITF 06-11)***
 
 In
        June
        2007, the FASB ratified the EITF consensus on the treatment of income tax
        benefits of dividends on employee share-based compensation.  The issue
        is how a company should recognize the income tax benefit received on dividends
        that are paid to employees holding equity-classified nonvested shares,
        equity-classified nonvested share units, or equity-classified outstanding
        share
        options and charged to retained earnings under SFAS 123R, “Share-Based
        Payments.”  Under EITF 06-11, a realized income tax benefit from
        dividends or dividend equivalents that are charged to retained earnings and
        are
        paid to employees for equity-classified nonvested equity shares, nonvested
        equity share units, and outstanding equity share options should be recognized
        as
        an increase to additional paid-in capital.
 
 EITF
        06-11 will be applied prospectively to the income tax benefits of dividends
        on
        equity-classified employee share-based payment awards that are declared in
        fiscal years beginning after September 15, 2007.  Management expects
        that the adoption of this standard will have an immaterial effect on the
        financial statements.  The Registrant Subsidiaries will adopt EITF
        06-11 effective January 1, 2008.
  ***FIN
          48 “Accounting for Uncertainty in Income Taxes” and FASB Staff Position FIN 48-1
“Definition of Settlement in FASB Interpretation No. 48” (FIN
          48)***
  In
        July
        2006, the FASB issued FASB Interpretation No. 48 “Accounting for Uncertainty in
        Income Taxes” and in May 2007, the FASB issued FASB Staff Position FIN 48-1
“Definition of *Settlement* in FASB Interpretation No.
        48.”  FIN 48 clarifies the accounting for uncertainty in income taxes
        recognized in an enterprise’s financial statements by prescribing a recognition
        threshold (whether a tax position is more likely than not to be sustained)
        without which, the benefit of that position is not recognized in the financial
        statements.  It requires a measurement determination for recognized
        tax positions based on the largest amount of benefit that is greater than
        50
        percent likely of being realized upon ultimate settlement.  FIN 48
        also provides guidance on derecognition, classification, interest and penalties,
        accounting in interim periods, disclosure and transition.
 
 FIN
        48
        requires that the cumulative effect of applying this interpretation be reported
        and disclosed as an adjustment to the opening balance of retained earnings
        for
        that fiscal year and presented separately.  The Registrant
        Subsidiaries adopted FIN 48 effective January 1, 2007.  The impact of
        this interpretation was an unfavorable (favorable) adjustment to retained
        earnings as follows:
 
 **Company**
              
              **(in
                  thousands)**APCo
              
              $
              2,685CSPCo
              
              
              3,022I&M
              
              
              (327
              )OPCo
              
              
              5,380PSO
              
              
              386SWEPCo
              
              
              1,642
 
 ***FIN
        39-1 “Amendment of FASB Interpretation No. 39”***
 
 In
        April
        2007, the FASB issued FIN 39-1.  It amends FASB Interpretation No. 39,
“Offsetting of Amounts Related to Certain Contracts” by replacing the
        interpretation’s definition of contracts with the definition of derivative
        instruments per SFAS 133.  It also requires entities that offset fair
        values of derivatives with the same party under a netting agreement to also
        net
        the fair values (or approximate fair values) of related cash
        collateral.  The entities must disclose whether or not they offset
        fair values of derivatives and related cash collateral and amounts recognized
        for cash collateral payables and receivables at the end of each reporting
        period.
 
 FIN
        39-1
        is effective for fiscal years beginning after November 15,
        2007.  Management expects this standard to change the method of
        netting certain balance sheet amounts but is unable to quantify the
        effect.  It requires retrospective application as a change in
        accounting principle for all periods presented.  The Registrant
        Subsidiaries will adopt FIN 39-1 effective January 1, 2008.
 
 ***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 operations and financial position that may result from any such
        future changes.  The FASB is currently working on several projects
        including business combinations, revenue recognition, liabilities and equity,
        derivatives disclosures, emission allowances, leases, insurance, subsequent
        events and related tax impacts.  Management also expects to see more
        FASB projects as a result of its desire to converge International Accounting
        Standards with GAAP.  The ultimate pronouncements resulting from these
        and future projects could have an impact on future results of operations
        and
        financial position.
 
 **EXTRAORDINARY
        ITEM**
 
 APCo
        recorded an extraordinary loss of $118 million ($79 million, net of tax)
        during
        the second quarter of 2007 for the establishment of regulatory assets and
        liabilities related to the Virginia generation operations.  In 2000,
        APCo discontinued SFAS 71 regulatory accounting for the Virginia jurisdiction
        due to the passage of legislation for customer choice and
        deregulation.  In April 2007, Virginia passed legislation to establish
        electric regulation again.  See “Virginia Restructuring” in Note
        3.
  **3.**
              **RATE
                  MATTERS**
 
 As
        discussed in the 2006 Annual Report, the Registrant Subsidiaries are involved
        in
        rate and regulatory proceedings at the FERC and their state
        commissions.  The Rate Matters note within the 2006 Annual Report
        should be read in conjunction with this report to gain a complete understanding
        of material rate matters still pending that could impact results of operations,
        cash flows and possibly financial condition.  The following discusses
        ratemaking developments in 2007 and updates the 2006 Annual Report.
 
 **Ohio
        Rate Matters**
 
 ***Ohio
        Restructuring and Rate Stabilization Plans – Affecting CSPCo and
        OPCo***
 
 In
        January 2007, CSPCo and OPCo filed with the PUCO under the 4% provision of
        their
        RSPs to increase their annual generation rates for 2007 by $24 million and
        $8
        million, respectively, to recover governmentally-mandated
        costs.  Pursuant to the RSPs, CSPCo and OPCo implemented these
        proposed increases effective with the first billing cycle in May
        2007.  These increases are subject to refund until the PUCO issues a
        final order in the matter.  The PUCO staff and intervenors have
        proposed disallowances.  The revenues collected, subject to refund,
        are immaterial through June 30, 2007.  Management is unable to
        determine the impact, if any, of potential refunds or rider reductions on
        future
        results of operations and cash flows.   The hearing is completed
        and initial post-hearing and reply briefs have been filed.  A final
        order is expected in late third quarter or early fourth quarter of
        2007.
 
 In
        March
        2007, CSPCo filed an application under the 4% provision of the RSP to adjust
        the
        Power Acquisition Rider (PAR) which was authorized in 2005 by the PUCO in
        connection with CSPCo's acquisition of Monongahela Power Company's certified
        territory in Ohio and a new purchase power contract to serve the
        load.  The PUCO approved the requested increase in the PAR, which is
        expected to increase CSPCo's revenues by $22 million and $38 million for
        2007
        and 2008, respectively.
 
 In
        March
        2007, CSPCo and OPCo filed a settlement agreement at the PUCO resolving the
        Ohio
        Supreme Court's remand of the PUCO’s RSP order.  The Supreme Court
        indicated concern with the absence of a competitive bid process as an
        alternative to the generation rates set by the RSP.  In response, the
        settling parties agreed to have CSPCo and OPCo take bids for Renewable Energy
        Certificates (RECs).  CSPCo and OPCo will give customers the option to
        pay a generation rate premium that would encourage the development of renewable
        energy sources by reimbursing CSPCo and OPCo for the cost of the RECs and
        the
        administrative costs of the program.  The Office of Consumers’
Counsel, the Ohio Partners for Affordable Energy, the Ohio Energy Group and
        the
        PUCO staff supported this settlement agreement.  In May 2007, the PUCO
        adopted the settlement agreement in its entirety.  The settlement, as
        approved, fully compensates CSPCo and OPCo regarding the cost of the
        program.
 
 CSPCo
        and
        OPCo are involved in discussions with various stakeholders in Ohio regarding
        potential legislation to address the period following the expiration of the
        RSPs
        on December 31, 2008.  At this time, management is unable to predict
        whether CSPCo and OPCo will transition to market pricing, as permitted by
        the
        current Ohio restructuring legislation, extend their RSP rates, with or without
        modification, or become subject to a legislative reinstatement of some form
        of
        cost-based regulation for their generation supply business on January 1,
        2009
        when the RSP period ends.
 
 ***Customer
        Choice Deferrals – Affecting CSPCo and OPCo***
 
 As
        provided in the restructuring settlement agreement approved by the PUCO in
        2000,
        CSPCo and OPCo established regulatory assets for customer choice implementation
        costs and related carrying costs in excess of $20 million each for recovery
        in
        the next general base rate filing which changes distribution rates after
        December 31, 2007 for OPCo and December 31, 2008 for
        CSPCo.   Pursuant to the RSPs, recovery of these amounts for OPCo
        was further deferred until the next base rate filing to change distribution
        rates after the end of the RSP period of December 31, 2008.  Through
        June 30, 2007, CSPCo and OPCo incurred $51 million and $52 million,
        respectively, of such costs and established regulatory assets of $25 million
        and
        $26 million, respectively, for such costs.  CSPCo and OPCo each have
        not recognized $6 million of equity carrying costs, which are recognizable
        when
        collected.  In 2007, CSPCo and OPCo incurred $2 million each of such
        costs and established regulatory assets of $1 million each for such
        costs.  Management believes that the deferred customer choice
        implementation costs were prudently incurred to implement customer choice
        in
        Ohio and are probable of recovery in future distribution
        rates.  However, failure to recover such costs will have an adverse
        effect on results of operations 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.  The application proposed three phases of
        cost recovery associated with the IGCC plant:  Phase 1, recovery of
        $24 million in pre-construction costs during 2006; Phase 2, concurrent recovery
        of construction-financing costs; and Phase 3, recovery or refund in distribution
        rates of any difference between the market-based standard service offer price
        for generation and the cost of operating and maintaining the plant, including
        a
        return on and return of the ultimate cost to construct the plant, originally
        projected to be $1.2 billion, along with fuel, consumables and replacement
        power
        costs.  The proposed recoveries in Phases 1 and 2 would be applied
        against the 4% limit on additional generation rate increases CSPCo and OPCo
        could request under their RSPs.
 
 In
        April
        2006, the PUCO issued an order authorizing CSPCo and OPCo to implement Phase
        1
        of the cost recovery proposal.  In June 2006, the PUCO issued another
        order approving a tariff to recover Phase 1 pre-construction costs over a
        period
        of no more than twelve months effective July 1, 2006.  Through June
        30, 2007, CSPCo and OPCo each recorded pre-construction IGCC regulatory assets
        of $10 million and each collected the entire $12 million approved by the
        PUCO.  CSPCo and OPCo expect to incur additional pre-construction
        costs equal to or greater than the $12 million each recovered.  As of
        June 30, 2007, CSPCo and OPCo have recorded a liability of $2 million each
        for
        the over-recovered portion.  The PUCO indicated that if CSPCo and OPCo
        have not commenced a continuous course of construction of the IGCC plant
        within
        five years of the June 2006 PUCO order, all amounts collected for
        pre-construction costs, associated with items that may be utilized in IGCC
        projects to be built by AEP at other sites, must be refunded to Ohio ratepayers
        with interest.  The PUCO deferred ruling on cost recovery for Phases 2
        and 3 until further hearings are held.  A date for further rehearings
        has not been set.
 
 In
        August
        2006, the Ohio Industrial Energy Users, Ohio Consumers’ Counsel, FirstEnergy
        Solutions and Ohio Energy Group filed four separate appeals of the PUCO’s order
        in the IGCC proceeding.  The Ohio Supreme Court has scheduled oral
        arguments for these appeals in October 2007.  Management believes that
        the PUCO’s authorization to begin collection of Phase 1 rates is
        lawful.  Management, however, cannot predict the outcome of these
        appeals.  If the PUCO’s order is found to be unlawful, CSPCo and OPCo
        could be required to refund Phase 1 cost-related recoveries.
 
 Pending
        the outcome of the Supreme Court litigation, CSPCo and OPCo announced they
        may
        delay the start of construction of the IGCC plant. Recent estimates of the
        cost
        to build an IGCC plant are $2.2 billion.  CSPCo and OPCo may need to
        request an extension to the 5 year start of construction requirement if the
        commencement of construction is delayed beyond 2011.  In July 2007,
        CSPCo and OPCo filed a status report with the PUCO referencing APCo’s IGCC West
        Virginia filing.  See the “West Virginia IGCC Plant” section within
        West Virginia Rate Matters of this note.
 
 ***Distribution
        Reliability Plan – Affecting CSPCo and OPCo***
 
 In
        January 2006, CSPCo and OPCo initiated a proceeding at the PUCO seeking a
        new
        distribution rate rider to fund enhanced distribution reliability
        programs.  In the fourth quarter of 2006, as directed by the PUCO,
        CSPCo and OPCo filed a proposed enhanced reliability plan.  The plan
        contemplated CSPCo and OPCo recovering approximately $28 million and $43
        million, respectively, in additional distribution revenue during an eighteen
        month period beginning July 2007.  In January 2007, the Ohio
        Consumers’ Counsel filed testimony, which argued that CSPCo and OPCo should be
        required to improve distribution service reliability with funds from their
        existing rates.
 
 In
        April
        2007, CSPCo and OPCo filed a joint motion with the PUCO staff, the Ohio
        Consumers’ Counsel, the Appalachian People’s Action Coalition, the Ohio Partners
        for Affordable Energy and the Ohio Manufacturers Association to withdraw
        the
        proposed enhanced reliability plan.  The motion was granted in May
        2007.  CSPCo and OPCo do not intend to implement the enhanced
        reliability plan without recovery of any incremental costs.
 
 ***Ormet
        – Affecting CSPCo and OPCo***
 
 Effective
        January 1, 2007, CSPCo and OPCo began to serve Ormet, a major industrial
        customer with a 520 MW load, under a PUCO-encouraged settlement
        agreement.  The settlement agreement between CSPCo and OPCo, Ormet,
        its employees’ union and certain other interested parties was approved by the
        PUCO in November 2006.   The settlement agreement provides for
        the recovery in 2007 and 2008 by CSPCo and OPCo of the difference between
        $43
        per MWH to be paid by Ormet for power and a PUCO-approved market price, if
        higher.  The recovery will be accomplished by the amortization of a
        $57 million ($15 million for CSPCo and $42 million for OPCo) Ohio franchise
        tax
        phase-out regulatory liability recorded in 2005 and, if that is insufficient,
        an
        increase in RSP generation rates under the additional 4% provision of the
        RSPs.  The $43 per MWH price to be paid by Ormet for generation
        services is above the industrial RSP generation tariff but below current
        market
        prices.  In December 2006, CSPCo and OPCo submitted a market price of
        $47.69 per MWH for 2007, which was approved by the PUCO in June
        2007.  CSPCo and OPCo have each amortized $3 million of their Ohio
        Franchise Tax phase-out tax regulatory liability to income through June 30,
        2007.  If the PUCO approves a lower-than-market price in 2008, it
        could have an adverse effect on future results of operations and cash
        flows.  If CSPCo and OPCo serve the Ormet load after 2008 without any
        special provisions, they could experience incremental costs to acquire
        additional capacity to meet their reserve requirements and/or forgo off-system
        sales margins, which could have an adverse effect on future results of
        operations and cash flows.
 
 **Texas
        Rate Matters**
 
 ***SWEPCo
        Fuel Reconciliation – Texas – Affecting SWEPCo***
 
 In
        June
        2006, SWEPCo filed a fuel reconciliation proceeding with the PUCT for its
        Texas
        retail operations for the three-year reconciliation period ended December
        31,
        2005.  SWEPCo sought, in the proceedings, to include under-recoveries
        related to the reconciliation period of $50 million.  In January 2007,
        intervenors filed testimony recommending that SWEPCo’s reconcilable fuel costs
        be reduced.  The PUCT staff and intervenor disallowances ranged from
        $10 million to $28 million.  In June 2007, an ALJ issued a Proposal
        for Decision recommending a $17 million disallowance.  Results of
        operations for the second quarter of 2007 were adversely affected by $25
        million
        as a result of reflecting the ALJ’s decision.  In July 2007, the PUCT
        orally affirmed the ALJ report.  A final order is expected in the
        third quarter of 2007.  Management is unable to predict the ultimate
        outcome of this proceeding or its additional effect on future results of
        operations and cash flows.
 
 **Virginia
        Rate Matters**
 
 ***Virginia
        Restructuring – Affecting APCo***
 
 In
        April
        2004, Virginia enacted legislation that amended the Virginia Electric Utility
        Restructuring Act extending the transition period to market rates for the
        generation and supply of electricity, including the extension of capped rates,
        through December 31, 2010.  The legislation provided APCo with
        specified cost recovery opportunities during the extended capped rate period,
        including two optional bundled general base rate changes and an opportunity
        for
        timely recovery, through a separate rate mechanism, of certain unrecovered
        incremental environmental and reliability costs incurred on and after July
        1,
        2004.  Under the amended restructuring law, APCo continues to have an
        active fuel clause recovery mechanism in Virginia and continues to practice
        deferred fuel accounting.  Also, under the amended restructuring law,
        APCo has the right to defer incremental environmental compliance costs and
        incremental E&R costs for future recovery, to the extent such costs are not
        being recovered, and amortizes a portion of such deferrals commensurate with
        their recovery.
 
 In
        April
        2007, the Virginia legislature adopted a comprehensive law providing for
        the
        re-regulation of electric utilities’ generation and supply
        rates.  These amendments shorten the transition period by two years
        (from 2010 to 2008) after which rates for retail generation and supply will
        return to a form of cost-based regulation in lieu of market-based
        rates.  The legislation provides for, among other things, biennial
        rate reviews beginning in 2009; rate adjustment clauses for the recovery
        of the
        costs of (a) transmission services and new transmission investments, (b)
        demand
        side management, load management, and energy efficiency programs, (c) renewable
        energy programs, and (d) environmental retrofit and new generation investments;
        significant return on equity enhancements for investments in new generation
        and,
        subject to Virginia SCC approval, certain environmental retrofits, and a
        floor
        on the allowed return on equity based on the average earned return on equities’
of regional vertically integrated electric utilities.  Effective July
        1, 2007, the amendments allow utilities to retain a minimum of 25% of the
        margins from off-system sales with the remaining margins from such sales
        credited against fuel factor expenses with a true-up to actual.  The
        legislation also allows APCo to continue to defer and recover incremental
        environmental and reliability costs incurred through December 31,
        2008.  The new re-regulation legislation should result in significant
        positive effects on APCo’s future earnings and cash flows from the mandated
        enhanced future returns on equity, the reduction of regulatory lag from the
        opportunities to adjust base rates on a biennial basis and the new opportunities
        to request timely recovery of certain new costs not included in base
        rates.
 
 With
        the new re-regulation legislation of cost-based regulation, APCo’s
        generation business again meets the criteria for application of regulatory
        accounting principles under SFAS 71.  The extraordinary pretax
        reduction in APCo’s earnings and shareholder’s equity from reapplication of SFAS
        71 regulatory accounting of $118 million ($79 million, net of tax) was recorded
        in the second quarter of 2007.  This extraordinary net loss primarily
        relates to the reestablishment of $139 million in net generation-related
        customer-provided removal costs as a regulatory liability, offset by the
        restoration of $21 million of deferred state income taxes as a regulatory
        asset.  In addition, APCo established a regulatory asset of $17
        million for qualifying SFAS 158 pension costs of the generation operations
        that,
        for ratemaking purposes, are deferred for future recovery under the new
        law.  AOCI and Deferred Income Taxes increased by $11 million and $6
        million, respectively.
 
 ***Virginia
        Base Rate Case – Affecting APCo***
 
 In
        May
        2006, APCo filed a request with the Virginia SCC seeking an increase in base
        rates of $225 million to recover increasing costs including the cost of its
        investment in environmental equipment and a return on equity of
        11.5%.  In addition, APCo requested to move off-system sales margins,
        currently credited to customers through base rates, to the fuel factor where
        they can be trued-up to actual.  APCo also proposed to share the
        off-system sales margins with customers with 40% going to reduce rates and
        60%
        being retained by APCo.  This proposed off-system sales fuel rate
        credit, which was estimated to be $27 million, partially offsets the $225
        million requested increase in base rates for a net increase in base rate
        revenues of $198 million.  The major components of the $225 million
        base rate request included $73 million for the impact of removing off-system
        sales margins from the rate year ending September 30, 2007, $60 million mainly
        due to projected net environmental plant additions through September 30,
        2007
        and $48 million for return on equity.
 
 In
        May
        2006, the Virginia SCC issued an order, consistent with Virginia law, placing
        the net requested base rate increase of $198 million into effect on October
        2,
        2006, subject to refund.  The $198 million base rate increase that was
        collected, subject to refund, includes recovery of incremental E&R costs
        projected to be incurred during the rate year beginning October
        2006.  These incremental E&R costs can be deferred and recovered
        through the E&R surcharge mechanism if not recovered through base
        rates.  In October 2006, the Virginia SCC staff filed its direct
        testimony recommending a base rate increase of $13 million with a return
        on
        equity of 9.9% and no off-system sales margin sharing.  Other
        intervenors recommended base rate increases ranging from $42 million to $112
        million.  APCo filed rebuttal testimony in November
        2006.  Hearings were held in December 2006.
 
 In
        March
        2007, the Hearing Examiner issued a report recommending a $76 million increase
        in APCo’s base rates and a $45 million credit to the fuel factor for off-system
        sales margins resulting in a net $31 million recommended rate
        increase.   In May 2007, the Virginia SCC issued a final order
        approving an overall annual base rate increase of $24 million effective as
        of
        October 2006.  The final order approved a return on equity of 10.0%
        and limited forward-looking ratemaking adjustments to June 30, 2006 as opposed
        to September 30, 2007 as proposed.  In addition, the final order
        excluded a portion of APCo's requested E&R costs in base
        rates.  However, APCo was able to defer unrecovered incremental
        E&R costs incurred after October 1, 2006 and will recover those costs
        through the E&R surcharge mechanism.  The order also provided for
        a retroactive annual reduction in depreciation to January 1, 2006 of
        approximately $11 million per year and a deferral and recovery of ARO costs
        over
        10 years.  The final order further provides that off-system sales
        margins of $101 million be credited to customers through a separate base
        rate
        margin rider which is not trued-up to actual margins.  The final order
        did not implement the minimum 25% sharing percentage for off-system sales
        margins embodied in the new re-regulation legislation, which is effective
        with
        the first fuel clause filing after July 1, 2007.  This sharing
        requirement in the new re-regulation legislation also includes a
        true-up to actual off-system sales margins.
 
 As
        a
        result of the final order, APCo’s second quarter pretax earnings decreased by
        approximately $3 million due to a decrease in revenues of $42 million net
        of a
        recorded provision for refund and related interest offset by (a) a $15 million
        net effect from the deferral of unrecovered incremental E&R costs incurred
        from October 1, 2006 through June 30, 2007 to be collected in a future E&R
        filing, (b) a $9 million net deferral of ARO costs to be recovered over 10
        years
        and (c) a $15 million retroactive decrease in depreciation
        expense.  In addition to the favorable effect of the base rate
        increase in the second half of 2007, APCo expects to defer for future recovery
        unrecovered incremental E&R costs incurred of $20 million to $25 million and
        reduce depreciation and amortization expense by a net $5
        million.  APCo will complete the refund by August
        2007.  APCo’s Other Current Liabilities includes accrued refunds of
        $127 million and $22 million as of June 30, 2007 and December 31, 2006,
        respectively.  Management expects pretax earnings for 2007 to be
        favorably affected by the ordered May 2007 rate increase.
 
 ***Virginia
        E&R Costs Recovery Filing – Affecting APCo***
 
 In
        July
        2007, APCo filed a request with the Virginia SCC seeking recovery over the
        twelve months beginning December 1, 2007 of approximately $60 million of
        unrecovered incremental E&R costs inclusive of carrying costs thereon
        incurred from October 1, 2005 through September 30, 2006.  APCo will
        file for recovery in 2008 of E&R cost deferrals incurred and recorded after
        September 30, 2006.
 
 ***Virginia
        Fuel Clause Filing – Affecting APCo***
 
 In
        July
        2007, APCo filed an application with the Virginia SCC to seek an increase,
        effective September 1, 2007, to the current fuel factor of $33 million in
        annualized revenue requirements for fuel costs and a sharing of the benefits
        of
        off-system sales between APCo and its customers.  This filing was made
        in compliance with the minimum 25% retention of off-system sales margins
        provision of the new re-regulation legislation which is effective with the
        first
        fuel clause filing after July 1, 2007.  This sharing requirement in
        the new law also includes a true-up to actual off-system sales
        margins.  In addition, APCo requested authorization to defer for
        future recovery the difference between off-system sales margins credited
        to
        customers at 100% of the ordered amount through the current margin rider
        and 75%
        of actual off-system sales margins as provided in the new law from July 1,
        2007
        until the new fuel rate becomes effective.
 
 ***West
        Virginia IGCC Plant – Affecting APCo***
 
 In
        July
        2007, APCo filed a request with the Virginia SCC to recover, over the twelve
        months beginning January 1, 2009, a return on projected construction work
        in
        progress including development, design and planning costs from July 1, 2007
        through December 31, 2009 estimated to be $45 million associated with a proposed
        629 MW IGCC plant to be constructed in West Virginia for an estimated cost
        of
        $2.2 billion.  APCo is requesting authorization to defer a return on
        actual pre-construction costs incurred beginning July 1, 2007 until such
        costs
        are recovered, starting January 1, 2009 in accordance with the new re-regulation
        legislation.  See “West Virginia IGCC Plant” section within West
        Virginia Rate Matters below.
 
 **West
        Virginia Rate Matters**
 
 ***APCo
        and WPCo ENEC Filing – Affecting APCo***
 
 In
        April
        2007, the WVPSC issued an order establishing an investigation and hearing
        concerning APCo’s and WPCo’s 2007 Expanded Net Energy Cost (ENEC) compliance
        filing.  The ENEC is an expanded form of fuel clause mechanism, which
        includes all energy-related costs including fuel, purchased power expenses,
        off-system sales credits and other energy/transmission
        items.   In the March 2007 ENEC joint filing, APCo and WPCo filed
        for an increase of approximately $91 million including a $65 million increase
        in
        ENEC and a $26 million increase in construction cost surcharges to become
        effective July 1, 2007.  In June 2007, the WVPSC issued an order
        approving, without modification, a joint stipulation and agreement for
        settlement reached among the parties.  The settlement agreement
        provided for an increase in annual non-base revenues of approximately $77
        million effective July 1, 2007.  This annual revenue increase
        primarily includes $50 million of ENEC and $26 million of construction cost
        surcharges.  The ENEC portion of the increase is subject to a true-up,
        which should avoid an under-recovery of ENEC costs if they exceed the $50
        million.
 
 ***West
        Virginia IGCC Plant – Affecting APCo***
 
 In
        January 2006, APCo filed a petition with the WVPSC requesting its approval
        of a
        Certificate of Public Convenience and Necessity (CCN) to construct a 629
        MW IGCC
        plant adjacent to APCo’s existing Mountaineer Generating Station in Mason
        County, WV.
 
 In
        June
        2007, APCo filed testimony with the WVPSC supporting the requests for a CCN
        and
        for pre-approval of a surcharge rate mechanism to provide for the timely
        recovery of both 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.  If
        APCo receives all necessary approvals, the plant could be completed as early
        as
        mid-2012 and currently is expected to cost an estimated $2.2
        billion**.**In July 2007, the WVPSC staff and
        intervenors filed to delay the procedural schedule by 90 days.  APCo
        supported the changes to the procedural schedule.  The statutory
        decision deadline was revised to March 2008.  In July 2007, the WVPSC
        approved the revised procedural schedule.  Through June 30, 2007, APCo
        deferred pre-construction IGCC costs totaling $11 million.  If the
        plant is not built and these costs are not recoverable, future results of
        operations and cash flows would be adversely affected.
 
 **Indiana
        Rate Matters**
 
 ***Indiana
        Depreciation Study Filing – Affecting I&M***
 
 In
        February 2007, I&M filed a request with the IURC for approval of revised
        book depreciation rates effective January 1, 2007.  The filing
        included a settlement agreement entered into with the Indiana Office of the
        Utility Consumer Counsel (OUCC) that would provide direct benefits to I&M's
        customers if new lower depreciation rates were approved by the
        IURC.  The direct benefits would include a $5 million credit to fuel
        costs and an approximate $8 million smart metering pilot program.  In
        addition, if the agreement were to be approved, I&M would initiate a general
        rate proceeding on or before July 1, 2007 and initiate two studies, one to
        investigate a general smart metering program and the other to study the market
        viability of demand side management programs.  Based on the
        depreciation study included in the filing, I&M recommended and the
        settlement agreed to a decrease in pretax annual depreciation expense on
        an
        Indiana jurisdictional basis of approximately $69 million reflecting an
        NRC-approved 20-year extension of the Cook Plant licenses for Units 1 and
        2 and
        an extension of the service life of the Tanners Creek coal-fired generating
        units.  This petition was not a request for a change in customers’
electric service rates.  As proposed, the book depreciation reduction
        would increase earnings, but would not impact cash flows until rates are
        revised. Base and fuel rates were frozen in Indiana through June 30,
        2007.  The IURC held a public hearing in April 2007.  In
        June 2007, the IURC approved the settlement agreement, but modified the
        effective date of the new depreciation rates upon the filing by I&M of a
        general rate petition.  See “Indiana Rate Filing” section
        below.  On June 19, 2007, I&M and the OUCC notified the IURC the
        parties would accept the modification to the settlement agreement and I&M
        filed its rate petition.
 
 The
        settlement agreement modification reduced book depreciation rates, which
        will
        result in an increase of $37 million in pretax earnings for the period June
        19,
        2007 to December 31, 2007.  The $37 million increase is partially
        offset by a $5 million regulatory liability, recorded in June 2007, to provide
        for the agreed-upon fuel credit.  I&M’s approved depreciation
        rates are subject to further review in the general rate
        case.  I&M’s earnings will continue to benefit until the base
        rates are revised to include lower depreciation rates, at which time cash
        flows
        will be adversely affected.  Management expects new base rates will
        become effective in late 2008 or early 2009.
 
 ***Indiana
        Rate Filing – Affecting I&M***
 
 In
        June
        2007, I&M filed a rate notification petition with the IURC regarding its
        intent to file for a base rate increase with a proposed test year ended
        September 30, 2007.  The petition indicated, among other things, the
        filing would include a request to implement rate tracker mechanisms for certain
        variable components of the cost of service including AEP Power Pool capacity
        settlements, PJM RTO costs, reliability enhancement costs, DSM/energy efficiency
        program costs, off-system sales margins, and net environmental compliance
        costs.  The petition requests the IURC to approve the test year period
        and the inclusion of the above trackers in the rate
        filing.  Management expects to file the case in late 2007 or early
        2008 with a decision expected in late 2008 or early 2009.
 
 ***Indiana
        Rate Cap – Affecting I&M***
 
 Effective
        July 1, 2007, I&M’s rate cap ended for both base and fuel
        rates.  I&M’s fuel factor increased with the July 2007 billing
        month to recover the projected cost of fuel.  I&M will resume
        deferring through revenues any under/over-recovered fuel costs for future
        recovery/refund.  Under the capped rates, I&M was unable to
        recover $44 million of fuel costs since 2004 of which $7 million adversely
        impacted 2007 pretax earnings through June 30, 2007.  Future results
        of operations should no longer be impacted by fuel costs.
 
 **Oklahoma
        Rate Matters**
 
 ***PSO
        Fuel and Purchased Power and its Possible Impact on AEP East companies and
        AEP
        West companies***
 
 In
        2002,
        PSO under-recovered $44 million of purchased power costs through its fuel
        clause
        resulting from a reallocation among AEP West companies of purchased power
        costs
        for periods prior to January 1, 2002.  In July 2003, PSO proposed
        collection of those reallocated costs over eighteen months.  In August
        2003, the OCC staff filed testimony recommending PSO recover $42 million
        of the
        reallocated purchased power costs over three years and PSO reduced its
        regulatory asset deferral by $2 million.  The OCC subsequently
        expanded the case to include a full prudence review of PSO’s 2001 fuel and
        purchased power practices.  In January 2006, the OCC staff and
        intervenors issued supplemental testimony alleging that AEP deviated from
        the
        FERC-approved method of allocating off-system sales margins between AEP East
        companies and AEP West companies and among AEP West companies.  The
        OCC staff proposed that the OCC offset the $42 million of under-recovered
        fuel
        with the proposed reallocation of off-system sales margins of $27 million
        to $37
        million and with $9 million of purchased power reallocation attributed to
        wholesale customers, which they claimed had not been refunded.  In
        February 2006, the OCC staff filed a report concluding that the $9 million
        of
        reallocated purchased power costs assigned to wholesale customers had been
        refunded, thus removing that issue from its recommendation.
 
 In
        2004,
        an Oklahoma ALJ found that the OCC lacks authority to examine whether PSO
        deviated from the FERC-approved allocation methodology and held that any
        such
        complaints should be addressed at the FERC.  The OCC has not ruled on
        appeals by intervenors of the ALJ’s finding.  The United States
        District Court for the Western District of Texas issued orders in September
        2005
        regarding a TNC fuel proceeding and in August 2006 regarding a TCC fuel
        proceeding, preempting the PUCT from reallocating off-system sales margins
        between the AEP East companies and AEP West companies.  The federal
        court agreed that the FERC has sole jurisdiction over that
        allocation.  The PUCT appealed the ruling. The United States Court of
        Appeals for the Fifth Circuit, issued a decision in December 2006 regarding
        the
        TNC fuel proceeding that affirmed the United States District Court
        ruling.  In April 2007, the PUCT petitioned the United States Supreme
        Court for a review of the Court of Appeal’s order.
 
 PSO
        does
        not agree with the intervenors’ and the OCC staff’s recommendations and
        proposals other than the staff’s original recommendation that PSO be allowed to
        recover the $42 million over three years and will defend its right to recover
        its under-recovered fuel balance.  Management believes that if the
        position taken by the federal courts in the Texas proceeding is applied to
        PSO’s
        case, then the OCC should be preempted from disallowing fuel recoveries for
        alleged improper allocations of off-system sales margins between AEP East
        companies and AEP West companies.  The OCC or another party could file
        a complaint at the FERC alleging the allocation of off-system sales margins
        to
        PSO is improper, which could result in an adverse effect on future results
        of
        operations and cash flows for AEP and the AEP East
        companies.  However, to date, there has been no claim asserted at the
        FERC that AEP deviated from the FERC approved allocation methodologies, but
        even
        if one were asserted, management believes that the OCC or another party would
        not prevail.
 
 In
        June
        2005, the OCC issued an order directing its staff to conduct a prudence review
        of PSO’s fuel and purchased power practices for the year 2003.  The
        OCC staff filed testimony finding no disallowances in the test year
        data.  The Attorney General of Oklahoma filed testimony stating that
        they could not determine if PSO’s gas procurement activities were prudent, but
        did not include a recommended disallowance.  However, an intervenor
        filed testimony in June 2006 proposing the disallowance of $22 million in
        fuel
        costs based on a historical review of potential hedging opportunities that
        he
        alleges existed during the year.  A hearing was held in August 2006
        and management expects a recommendation from the ALJ in the second half of
        2007.
 
 In
        February 2006, a law was enacted requiring the OCC to conduct prudence reviews
        on all generation and fuel procurement processes, practices and costs on
        either
        a two or three-year cycle depending on the number of customers
        served.  PSO is subject to the required biennial
        reviews.  PSO filed its testimony in June 2007 covering the year
        2005.
 
 In
        May
        2007, PSO filed an application to adjust its fuel/purchase power
        rates.  In the filing, PSO netted the $42 million of under-recovered
        pre-2002 reallocated purchased power costs against their current $48 million
        over-recovered fuel balance.  In oral discussions, the OCC staff did
        not oppose the netting of the balances.  The $6 million net
        over-recovered fuel/purchased power cost deferral balance will be refunded
        over
        the twelve month period beginning June 2007.  To date, no party has
        objected to the offset.
  Management
        cannot predict the outcome of the pending fuel and purchased power costs
        and
        prudence reviews, planned future reviews or the current fuel adjustment clause
        filing, but believes that PSO’s fuel and purchased power procurement practices
        and costs are prudent and properly incurred.  If the OCC disagrees and
        disallows fuel or purchased power costs including the pre-2002 reallocation
        of
        purchased power costs incurred by PSO, it would have an adverse effect on
        future
        results of operations and cash flows.
 
 ***Oklahoma
        Rate Filing – Affecting PSO***
 
 In
        November 2006, PSO filed a request to increase base rates by $50 million
        for
        Oklahoma jurisdictional customers with a proposed effective date in the second
        quarter of 2007.  PSO sought a return on equity of
        11.75%.  PSO also proposed a formula rate plan that, if approved as
        filed, will permit PSO to defer any unrecovered costs as a result of a revenue
        deficiency that exceeds 50 basis points of the allowed return on equity for
        recovery within twelve months beginning six months after the test
        year.  The proposed formula rate plan would enable PSO to recover on a
        timely basis the cost of its new generation, transmission and distribution
        construction (including carrying costs during construction), provide the
        opportunity to achieve the approved return on equity and prevent the
        capitalization of a significant amount of AFUDC that would have been recorded
        during the construction time period to be recovered in the future through
        depreciation expense.
 
 In
        March
        2007, the OCC staff and various intervenors filed testimony.  The
        recommendations were base rate reductions that ranged from $18 million to
        $52
        million.  The recommended returns on equity ranged from 9.25% to
        10.09%.  These recommendations included reductions in depreciation
        expense of approximately $25 million, which has no earnings
        impact.  The OCC staff filed testimony supporting a formula rate plan,
        generally similar to the one proposed by PSO.  In April 2007, PSO
        filed rebuttal testimony regarding various issues raised by the OCC staff
        and
        the intervenors.  In connection with the filing of rebuttal testimony,
        PSO reduced its base rate request by $2 million.    The ALJ
        issued a report in May 2007 recommending a 10.5% return on equity, but did
        not
        compute an overall revenue requirement.  The ALJ’s report did not
        recommend adopting a formula rate plan, but did recommend recovery through
        a
        rider of certain generation and transmission projects’ financing costs during
        construction.  However, the report also contained an alternative
        recommendation that the OCC could delay a decision on the rider and take
        up this
        issue in PSO’s application seeking regulatory approval of the coal-fueled
        generating unit.  The OCC’s discussions during deliberations have
        centered around a return on equity of 9.75%.  PSO implemented interim
        rates, subject to refund, for residential customers beginning July
        2007.  The interim rate implements a key provision of the rate case on
        which there seems to be agreement at the OCC, and is estimated to increase
        revenues by approximately $4 million in 2007 and $9 million on an annual
        basis.  Other components of the rate case will be implemented once the
        OCC issues a final order, which is expected in early August 2007.
 
 Management
        is unable to predict the final outcome of these proceedings. However, if
        rates
        are not increased in an amount sufficient to recover expected unavoidable
        cost
        increases, future results of operations, cash flows and possibly financial
        condition could be adversely affected.
 
 ***Lawton
        and Peaking Generation Settlement Agreement – Affecting
        PSO***
 
 On
        November 26, 2003, pursuant to an application by Lawton Cogeneration, L.L.C.
        (Lawton) seeking approval of a Power Supply Agreement (the Agreement) with
        PSO
        and associated avoided cost payments, the OCC issued an order approving the
        Agreement and setting the avoided costs.
 
 In
        December 2003, PSO filed an appeal of the OCC’s order with the Oklahoma Supreme
        Court (the Court).  In the appeal, PSO maintained that the OCC
        exceeded its authority under state and federal laws to require PSO to enter
        into
        the Agreement.  The Court issued a decision on June 21, 2005,
        affirming portions of the OCC’s order and remanding certain
        provisions.  The Court affirmed the OCC’s finding that Lawton
        established a legally-enforceable obligation and ruled that it was within
        the
        OCC’s discretion to award a 20-year contract and to base the capacity payment
        on
        a peaking unit.  The Court directed the OCC to revisit its
        determination of PSO’s avoided energy cost. Hearings were held on the remanded
        issues in April and May 2006.
 
 In
        April
        2007, all parties in the case filed a settlement agreement with the OCC
        resolving all issues. The OCC approved the settlement agreement in April
        2007.  The OCC staff, the Attorney General, the Oklahoma Industrial
        Energy Consumers and Lawton Cogeneration, L.L.C supported this settlement
        agreement.  The settlement agreement provides for a purchase fee of
        $35 million to be paid by PSO to Lawton and for Lawton to provide, at PSO’s
        direction, all rights to the Lawton Cogeneration Facility including permits,
        options and engineering studies.  PSO paid the $35 million purchase
        fee in June 2007 and recorded the purchase fee as a regulatory asset and
        will
        recover it through a rider over a three-year period with a carrying charge
        of
        8.25% beginning in September 2007.  In addition, PSO will recover
        through a rider, subject to a $135 million cost cap, all of the traditional
        costs associated with plant in service of its new peaking units to be located
        at
        the Southwestern Station and Riverside Station at the time these units are
        placed in service.  PSO expects these units will have a substantially
        lower plant-in-service cost than the proposed Lawton Cogeneration
        Facility.  PSO may request approval from the OCC for recovery of costs
        exceeding the cost cap if special circumstances occur necessitating a higher
        level of costs.  Such costs will continue to be recovered through the
        rider until cost recovery occurs through base rates or formula rates in a
        subsequent proceeding.  Under the settlement, PSO must file a rate
        case within eighteen months of the beginning of recovery through the rider
        unless the OCC approves a formula-based rate mechanism that provides for
        recovery of the peaking units.  Once the cost recovery for the new
        peaking units begins in mid-2008, PSO expects annual revenues of an estimated
        $36 million related to cost recovery of the peaking units and the purchase
        fee.
 
 **Louisiana
        Rate Matters**
 
 ***Louisiana
        Compliance Filing – Affecting SWEPCo***
 
 In
        October 2002, SWEPCo filed detailed financial information typically utilized
        in
        a revenue requirement filing, including a jurisdictional cost of service,
        with
        the LPSC.  This filing was required by the LPSC as a result of its
        order approving the merger between AEP and CSW.  Due to multiple
        delays, in April 2006, the LPSC and SWEPCo agreed to update the financial
        information based on a 2005 test year.  SWEPCo filed updated financial
        review schedules in May 2006 showing a return on equity of 9.44% compared
        to the
        previously-authorized return on equity of 11.1%.
 
 In
        July
        2006, the LPSC staff’s consultants filed direct testimony recommending a base
        rate reduction in the range of $12 million to $20 million for SWEPCo’s Louisiana
        jurisdiction customers, based on a proposed 10% return on equity.  The
        recommended reduction range is subject to SWEPCo validating certain ongoing
        operations and maintenance expense levels.  SWEPCo filed rebuttal
        testimony in October 2006 strongly refuting the consultants’
recommendations.  In December 2006, the LPSC staff’s consultants filed
        reply testimony asserting that SWEPCo’s Louisiana base rates are excessive by
        $17 million which includes a proposed return on equity of
        9.8%.  SWEPCo filed rebuttal testimony in January
        2007.  Constructive settlement negotiations are making meaningful
        progress.  At this time, management is unable to predict the outcome
        of this proceeding.  If a rate reduction is ultimately ordered, it
        would adversely affect future results of operations, cash flows and possibly
        financial condition.
 
 **FERC
        Rate Matters**
 
 ***Transmission
        Rate Proceedings at the FERC – Affecting APCo, CSPCo, I&M and
        OPCo***
 
 *The
        FERC PJM Regional Transmission Rate Proceeding*
 
 At
        AEP’s
        urging, the FERC instituted an investigation of PJM’s zonal rate regime,
        indicating that the present rate regime may need to be replaced through
        establishment of regional rates that would compensate AEP and other transmission
        owners for the regional transmission facilities they provide to PJM, which
        provides service for the benefit of customers throughout PJM.  In
        September 2005, AEP and a nonaffiliated utility (Allegheny Power or AP) jointly
        filed a regional transmission rate design proposal with the
        FERC.  This filing proposed and supported a new PJM rate regime
        generally referred to as a Highway/Byway rate design.
 
 Parties
        to the regional rate proceeding proposed the following rate
        regimes:
 
 ·
              AEP/AP proposed a Highway/Byway rate design
                  in
                  which:·
              The cost of all transmission facilities in
                  the PJM
                  region operated at 345 kV or higher would be included in a “Highway” rate
                  that all load serving entities (LSEs) would pay based on peak
                  demand.  The AEP/AP proposal would produce about $125 million in
                  net revenues per year for AEP from users in other zones of
                  PJM.·
              The cost of transmission facilities operating
                  at lower
                  voltages would be collected in the zones where those costs are
                  presently
                  charged under PJM’s existing rate design.·
              Two other utilities, Baltimore Gas & Electric
                  Company (BG&E) and Old Dominion Electric Cooperative (ODEC), proposed
                  a Highway/Byway rate that includes transmission facilities above
                  200 kV in
                  the Highway rate, which would have produced lower net revenues
                  for AEP
                  than the AEP/AP proposal.·
              In another competing Highway/Byway proposal,
                  a group of
                  LSEs proposed rates that would include existing 500 kV and higher
                  voltage
                  facilities and new facilities above 200 kV in the Highway rate,
                  which
                  would also have produced lower net revenues for AEP than the AEP/AP
                  proposal.·
              In January 2006, the FERC staff issued testimony
                  and
                  exhibits supporting phase-in of a PJM-wide flat rate or “Postage Stamp”
                  type of rate design that would socialize the cost of all transmission
                  facilities.  The proposed rate design would have initially
                  produced much lower net transmission revenues for AEP than the
                  AEP/AP
                  proposal, but could produce slightly higher net revenues when fully
                  phased
                  in.
 
 All
        of
        these proposals were challenged by a majority of other transmission owners
        in
        the PJM region, who favored continuation of the existing PJM rate design
        which
        provides AEP with no compensation for through and out traffic on its east
        zone
        transmission system.  Hearings were held in April 2006 and the ALJ
        issued an initial decision in July 2006.  The ALJ found the existing
        PJM zonal rate design to be unjust and determined that it should be
        replaced.  The ALJ found that the Highway/Byway rates proposed by
        AEP/AP and BG&E/ODEC to be just and reasonable alternatives.  The
        ALJ also found FERC staff’s proposed Postage Stamp rate to be just and
        reasonable and recommended that it be adopted.  The ALJ also found
        that the effective date of the rate change should be April 1, 2006 to coincide
        with SECA rate elimination.  Because the Postage Stamp rate was found
        to produce greater cost shifts than other proposals, the judge also recommended
        that the new regional design be phased-in.  Without a phase-in, the
        Postage Stamp method would produce more revenue for AEP than the AEP/AP
        proposal. However, the proposed phase-in of Postage Stamp rates would delay
        the
        full favorable impact of those new regional rates until about 2012.
 
 AEP
        filed
        briefs noting exceptions to the initial decision and replies to the exceptions
        of other parties.  AEP argued that a phase-in should not be
        required.  Nevertheless, AEP argued that if the FERC adopts the
        Postage Stamp rate and a phase-in plan, the revenue collections curtailed
        by the
        phase-in should be deferred and paid later with interest.
 
 Since
        the
        FERC’s decision in 2005 to cease through-and-out rates and replace them
        temporarily with SECA rates which ceased on April 1, 2006, the AEP East
        companies increased their retail rates in all states except Indiana and Michigan
        to recover lost through-and-out transmission service (T&O) and SECA
        revenues.
 
 In
        April
        2007, the FERC issued an order reversing the ALJ’s decision.  The FERC
        ruled that the current PJM rate design is just and reasonable for existing
        transmission facilities.  However, the FERC ruled that the cost of new
        facilities of 500 kV and above would be shared among all PJM
        participants.  As a result of this order, the AEP East companies’
retail customers will bear the full cost of the existing AEP east transmission
        zone facilities although others use them.  Presently AEP is collecting
        the full cost of those facilities from its retail customers with the exception
        of Indiana and Michigan customers.  As a result of this order, the AEP
        East companies’ customers will also be charged a share of the cost of future new
        500 kV and higher voltage transmission facilities built in PJM, most of which
        are expected to be upgrades of the facilities in other zones of
        PJM.  The AEP East companies will need to obtain regulatory approvals
        for recovery of any costs of new facilities that are assigned to them as
        a
        result of this order, if upheld.  AEP has requested rehearing of this
        order.  Management cannot estimate at this time what effect, if any,
        this order will have on their future construction of new east transmission
        facilities, results of operations, cash flows and financial
        condition.
 
 The
        AEP
        East companies presently recover from retail customers approximately 85%
        of the
        lost T&O/SECA transmission revenues of $128 million a
        year.  Future results of operations, cash flows and financial
        condition will continue to be adversely affected in Indiana and Michigan
        until
        these lost T&O/SECA transmission revenues are recovered in retail
        rates.
 
 *SECA
        Revenue Subject to Refund*
 
 The
        AEP
        East companies ceased collecting T&O revenues in accordance with FERC
        orders, and collected SECA rates to mitigate the loss of T&O revenues from
        December 1, 2004 through March 31, 2006, when SECA rates
        expired.  Intervenors objected to the 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 or
        surcharge.  The AEP East companies paid SECA rates to other utilities
        at considerably lesser amounts than 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.  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
 
 Approximately
        $19 million of these recorded SECA revenues billed by PJM were not
        collected.  The AEP East companies filed a motion with the FERC to
        force payment of these uncollected SECA billings.
 
 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 was not 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.
 
 Since
        the
        implementation of SECA rates in December 2004, the AEP East companies recorded
        approximately $220 million of gross SECA revenues, subject to
        refund.  In 2006, the AEP East companies provided reserves of $37
        million in net refunds for current and future SECA settlements with all of
        AEP’s
        SECA customers.  APCo’s, CSPCo’s, I&M’s and OPCo’s portions of the
        reserve are as follows:
 
 **Company**
              
              **(in
                  millions)**APCo
              
              $
              12.0CSPCo
              
              
              6.7I&M
              
              
              7.0OPCo
              
              
              9.1
  The
          AEP
          East companies reached settlements with certain SECA customers related
          to
          approximately $69 million of such revenues for a net refund of $3
          million.  The AEP East companies are in the process of completing two
          settlements-in-principle on an additional $36 million of SECA revenues
          and
          expect to make net refunds of $4 million when those settlements are
          approved.  Thus, completed and in-process settlements cover $105
          million of SECA revenues and will consume about $7 million of the reserves
          for
          refunds, leaving approximately $115 million of contested SECA revenues
          and $30
          million of refund reserves.  If the ALJ’s initial decision were upheld
          in its entirety, it would disallow approximately $90 million of the AEP
          East
          companies’ remaining $115 million of unsettled gross SECA
          revenues.  Based on recent settlement experience and the expectation
          that most of the $115 million of unsettled SECA revenues will be settled,
          management believes that the remaining reserve will be
          adequate.
 
 In
        September 2006, AEP, together with Exelon Corporation and The Dayton Power
        and
        Light Company, filed an extensive post-hearing brief and reply brief noting
        exceptions to the ALJ’s initial decision and asking the FERC to reverse the
        decision in large part.  Management believes that the FERC should
        reject the 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.  As directed by the FERC, management is working to settle the
        remaining $115 million of unsettled revenues within the remaining reserve
        balance.  Although management believes it has meritorious arguments
        and can settle with the remaining customers within the amount provided,
        management cannot predict the ultimate outcome of ongoing settlement talks
        and,
        if necessary, any future FERC proceedings or court appeals.  If the
        FERC adopts the ALJ’s decision and/or AEP cannot settle a significant portion of
        the remaining unsettled claims within the amount provided, it will have an
        adverse effect on future results of operations and cash flows.
 
 ***SPP
        Transmission Formula Rate Filing***
 
 In
        June
        2007, AEPSC filed revised tariff sheets on behalf of PSO and SWEPCo for the
        AEP
        pricing zone of the SPP OATT.  The revised tariff sheets seek to
        establish an up-to-date revenue requirement for SPP transmission services
        over
        the facilities of PSO and SWEPCo and implement a transmission cost of service
        formula rate.
 
 PSO
        and
        SWEPCo requested an effective date of September 1, 2007 for the revised
        tariff.  FERC could suspend the effective date until February 1,
        2008.  The primary impact of the filed revised tariff will be an
        increase in network transmission service revenues from nonaffiliated municipal
        and rural cooperative utilities in the AEP Zone.  If the proposed
        formula rate and requested return on equity are approved, the 2008 network
        transmission service revenues from nonaffiliates will increase by approximately
        $10 million compared to the revenues that would result from the presently
        approved network transmission rate.  PSO and SWEPCo take service under
        the same rate, and will also incur the increased OATT rates resulting from
        the
        filing, but will receive corresponding revenue to offset the
        increase.  This filing will not directly impact retail
        rates.
 
 **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 2006 Annual Report should be read in conjunction
        with this report.
 
 **GUARANTEES**
 
 There
        are
        certain immaterial liabilities recorded for guarantees in accordance with
        FASB
        Interpretation No. 45 “Guarantor’s Accounting and Disclosure Requirements for
        Guarantees, Including Indirect Guarantees of Indebtedness of
        Others.”  There is no collateral held in relation to any
        guarantees.  In the event any guarantee is drawn, there is no recourse
        to third parties unless specified below.
 
 ***Letters
        of Credit***
 
 Certain
        Registrant Subsidiaries enter into standby letters of credit (LOCs) with
        third
        parties.  These LOCs cover items such as insurance programs, security
        deposits, debt service reserves and credit enhancements for issued
        bonds.  All of these LOCs were issued in the subsidiaries’ ordinary
        course of business.  At June 30, 2007, the maximum future payments of
        the LOCs include $1 million and $4 million for I&M and SWEPCo, respectively,
        with maturities ranging from December 2007 to March 2008.
 
 ***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 $85 million.  Since SWEPCo uses self-bonding, the
        guarantee provides for SWEPCo to commit to use its resources to complete
        the
        reclamation in the event the work is not completed by Sabine Mining Company
        (Sabine), an entity consolidated under FIN 46.  This guarantee ends
        upon depletion of reserves and completion of final reclamation.  Based
        on the latest study, it is estimated the reserves will be depleted in 2029
        with
        final reclamation completed by 2036, at an estimated cost of approximately
        $39
        million.  As of June 30, 2007, SWEPCo collected approximately $31
        million through a rider for final mine closure costs, which is recorded in
        Deferred Credits and Other on SWEPCo’s Condensed Consolidated Balance
        Sheets.
 
 Sabine
        charges SWEPCo, its only customer, all of its costs.  SWEPCo passes
        these costs through its fuel clause.
  ***Indemnifications
        and Other Guarantees***
 
 *Contracts*
 
 All
        of
        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 June 30, 2007, the Registrant
        Subsidiaries entered into sale agreements including 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
        Operating Lease*
 
 Certain
        Registrant Subsidiaries lease certain equipment under a master operating
        lease.  Under the lease agreement, the lessor is guaranteed to receive
        up to 87% of the unamortized balance of the equipment at the end of the lease
        term.  If the fair market value of the leased equipment is below the
        unamortized balance at the end of the lease term, the subsidiary has committed
        to pay the difference between the fair market value and the unamortized balance,
        with the total guarantee not to exceed 87% of the unamortized
        balance.  At June 30, 2007, the maximum potential loss by subsidiary
        for these lease agreements assuming the fair market value of the equipment
        is
        zero at the end of the lease term was as follows:
 **Maximum
                  Potential Loss****Company**
              
              **(in
                  millions)**APCo
              
              $
              8CSPCo
              
              
              4I&M
              
              
              6OPCo
              
              
              8PSO
              
              
              5SWEPCo
              
              
              6
 
 **CONTINGENCIES**
 
 ***Federal
        EPA Complaint and Notice of Violation – Affecting APCo, CSPCo, I&M, and
        OPCo***
 
 The
        Federal EPA, certain special interest groups and a number of states allege
        that
        APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities including the
        Tennessee Valley Authority, Alabama Power Company, Cincinnati Gas & Electric
        Company, Ohio Edison Company, Southern Indiana Gas & Electric Company,
        Illinois Power Company, Tampa Electric Company, Virginia Electric Power Company
        and Duke Energy, modified certain units at coal-fired generating plants in
        violation of the NSR requirements of the CAA.  The Federal EPA filed
        its complaints against AEP subsidiaries in U.S. District Court for the Southern
        District of Ohio.  The alleged modifications occurred at the AEP
        System’s generating units over a 20-year period.  A bench trial on the
        liability issues was held during July 2005.  In June 2006, the judge
        stayed the liability decision pending the issuance of a decision by the U.S.
        Supreme Court in the Duke Energy case.
 
 Under
        the
        CAA, if a plant undertakes a major modification that results in an emissions
        increase, permitting requirements might be triggered and the plant may be
        required to install additional pollution control technology.  This
        requirement does not apply to routine maintenance, replacement of degraded
        equipment or failed components or other repairs needed for the reliable,
        safe
        and efficient operation of the plant.  The CAA authorizes civil
        penalties of up to $27,500 ($32,500 after March 15, 2004) per day per violation
        at each generating unit.  In 2001, the District Court ruled claims for
        civil penalties based on activities that occurred more than five years before
        the filing date of the complaints cannot be imposed.  There is no time
        limit on claims for injunctive relief.
 
 The
        Federal EPA and eight northeastern states each filed an additional complaint
        containing additional allegations against the Amos and Conesville
        plants.  APCo and CSPCo filed an answer to the northeastern states’
complaint and the Federal EPA’s complaint, denying the allegations and stating
        their defenses.  Cases are also pending that could affect CSPCo’s
        share of jointly-owned units at Beckjord (12.5% owned), Zimmer (25.4% owned),
        and Stuart (26% owned) Stations.  Similar cases have been filed
        against other nonaffiliated utilities, including Allegheny Energy, Eastern
        Kentucky Electric Cooperative, Public Service Enterprise Group, Santee Cooper,
        Wisconsin Electric Power Company, Mirant, NRG Energy and Niagara
        Mohawk.  Several of these cases were resolved through consent
        decrees.
 
 Courts
        have reached different conclusions regarding whether the activities at issue
        in
        these cases are routine maintenance, repair, or replacement, and therefore
        are
        excluded from NSR.  Similarly, courts have reached different results
        regarding whether the activities at issue increased emissions from the power
        plants.  Appeals on these and other issues were filed in certain
        appellate courts, including a petition to appeal to the U.S. Supreme Court
        that
        was granted in the Duke Energy case.  The Federal EPA issued a final
        rule that would exclude activities similar to those challenged in these cases
        from NSR as “routine replacements.”  In March 2006, the Court of
        Appeals for the District of Columbia Circuit issued a decision vacating the
        rule.  The Court denied the Federal EPA’s request for rehearing, and
        the Federal EPA and other parties filed a petition for review by the U.S.
        Supreme Court.  In April 2007, the Supreme Court denied the petition
        for review.  The Federal EPA also proposed a rule that would define
“emissions increases” in a way that most of the challenged activities would be
        excluded from NSR.
 
 On
        April
        2, 2007, the U.S. Supreme Court reversed the Fourth Circuit Court of Appeals’
decision that had supported the statutory construction argument of Duke Energy
        in its NSR proceeding.  In a unanimous decision, the Court ruled that
        the Federal EPA was not obligated to define “major modification” in two
        different CAA provisions in the same way.  The Court also found that
        the Fourth Circuit’s interpretation of “major modification” as applying only to
        projects that increased hourly emission rates amounted to an invalidation
        of the
        relevant Federal EPA regulations, which under the CAA can only be challenged
        in
        the Court of Appeals within 60 days of the Federal EPA
        rulemaking.  The U.S. Supreme Court did acknowledge, however, that
        Duke Energy may argue on remand that the Federal EPA has been inconsistent
        in
        its interpretations of the CAA and the regulations and may not retroactively
        change 20 years of accepted practice.
 
 In
        addition to providing guidance on certain of the merits of the NSR proceedings
        brought against APCo, CSPCo, I&M and OPCo in U.S. District Court for the
        Southern District of Ohio, the U.S. Supreme Court’s issuance of a ruling in the
        Duke Energy cases has an impact on the timing of the NSR
        proceedings.  The court that heard the trial on liability issues will
        likely issue its decision during the third quarter of 2007.  A bench
        trial on remedy issues, if necessary, is likely to begin in the second half
        of
        2007.
 
 Management
        is unable to estimate the loss or range of loss related to any contingent
        liability, if any, AEP subsidiaries might have for civil penalties under
        the CAA
        proceedings.  Management is also unable to predict the timing of
        resolution of these matters due to the number of alleged violations and the
        significant number of issues yet to be determined by the Court.  If
        AEP subsidiaries do not prevail, management believes AEP subsidiaries can
        recover any capital and operating costs of additional pollution control
        equipment that may be required through regulated rates and market prices
        for
        electricity.  If any of the AEP subsidiaries are unable to recover
        such costs or if material penalties are imposed, it would adversely affect
        future results of operations, cash flows and possibly financial condition.
 
 ***Notice
        of Enforcement and Notice of Citizen Suit – Affecting
        SWEPCo***
 
 In
        March
        2005, two special interest groups, Sierra Club and Public Citizen, filed
        a
        complaint in Federal District Court for the Eastern District of Texas alleging
        violations of the CAA at SWEPCo’s Welsh Plant.  SWEPCo filed a
        response to the complaint in May 2005.  A trial in this matter is
        scheduled for the third quarter of 2007.
 
 In
        2004,
        the Texas Commission on Environmental Quality (TCEQ) issued a Notice of
        Enforcement to SWEPCo relating to the Welsh Plant containing a summary of
        findings resulting from a compliance investigation at the plant.  In
        April 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition
        recommending the entry of an enforcement order to undertake certain corrective
        actions and assessing an administrative penalty of approximately $228 thousand
        against SWEPCo based on alleged violations of certain representations regarding
        heat input in SWEPCo’s permit application and the violations of certain
        recordkeeping and reporting requirements.  SWEPCo responded to the
        preliminary report and petition in May 2005.  The enforcement order
        contains a recommendation that would limit the heat input on each Welsh unit
        to
        the referenced heat input contained within the permit application within
        10 days
        of the issuance of a final TCEQ order and until a permit amendment is
        issued.  SWEPCo had previously requested a permit alteration to remove
        the reference to a specific heat input value for each Welsh unit and to clarify
        the sulfur content requirement for fuels consumed at the plant.  A
        permit alteration was issued in March 2007 removing the heat input references
        from the Welsh permit and clarifying the sulfur content of fuels burned at
        the
        plant is limited to 0.5% on an as-received basis.  The Sierra Club and
        Public Citizen filed a motion to overturn the permit alteration.  In
        June 2007, TCEQ denied that motion.
 
 Management
        is unable to predict the timing of any future action by TCEQ or the special
        interest groups or the effect of such actions on results of operations, cash
        flows or financial condition.
 
 ***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 defendants’ motion to dismiss the lawsuits
        was granted in September 2005.  The dismissal was appealed to the
        Second Circuit Court of Appeals.  Briefing and oral argument have
        concluded.  On April 2, 2007, the U.S. Supreme Court issued a decision
        holding that the Federal EPA has authority to regulate emissions of
        CO2 and other greenhouse gases under the CAA, which may impact the
        Second Circuit’s analysis of these issues.  The Second Circuit
        requested supplemental briefs addressing the impact of the Supreme Court’s
        decision on this case.  Management believes the actions are without
        merit and intends to defend against the claims.
 
 ***TEM
        Litigation – Affecting OPCo***
 
 OPCo
        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 dated November 15,
        2000
        (PPA).  Beginning May 1, 2003, OPCo tendered replacement capacity,
        energy and ancillary services to TEM pursuant to the PPA that TEM rejected
        as
        nonconforming.
 
 In
        2003,
        TEM and OPCo separately filed declaratory judgment actions in the United
        States
        District Court for the Southern District of New York.  OPCo alleged
        that TEM breached the PPA, and sought a determination of its rights under
        the
        PPA.  TEM alleged that the PPA never became enforceable, or
        alternatively, that the PPA was terminated as the result of OPCo’s
        breaches.  The corporate parent of TEM (SUEZ-TRACTEBEL S.A.) provided
        a limited guaranty.
 
 In
        2005,
        a federal judge ruled that TEM had breached the contract and awarded damages
        to
        OPCo of $123 million plus prejudgment interest.  Any eventual proceeds
        will be recorded as a gain when received.
 
 In
        May
        2007, the United States Court of Appeals for the Second Circuit ruled that
        the
        lower court was correct in finding that TEM breached the PPA and OPCo did
        not
        breach the PPA.  It also ruled that the lower court applied an
        incorrect standard in denying OPCo any damages for TEM’s breach of the 20-year
        term of the PPA holding that OPCo is entitled to the benefit of its bargain
        and
        that the trial court must determine damages.  The Court of Appeals
        vacated OPCo’s $123 million judgment for damages against TEM related to
        replacement products and remanded the issue for further
        proceedings.
 
 ***Coal
        Transportation Dispute – Affecting PSO***
 
 PSO,
        TCC,
        TNC, the Oklahoma Municipal Power Authority and the Public Utilities Board
        of
        the City of Brownsville, Texas, as joint owners of a generating station,
        disputed transportation costs for coal received between July 2000 and the
        present time.  The joint plant remitted less than the amount billed
        and the dispute is pending before the Surface Transportation
        Board.  Based upon a weighted average probability analysis of possible
        outcomes, PSO, as operator of the plant, recorded provisions for possible
        loss
        in 2004, 2005, 2006 and the first six months of 2007.  The provision
        was deferred as a regulatory asset under PSO’s fuel mechanism and immaterially
        affected income for TCC and TNC for their respective ownership
        shares.  Management continues to work toward mitigating the disputed
        amounts to the extent possible.
  ***Coal
        Transportation Rate Dispute - Affecting PSO***
 
 In
        1985,
        the Burlington Northern Railroad Co. (now BNSF) entered into a coal
        transportation agreement with PSO.  The agreement contained a base
        rate subject to adjustment, a rate floor, a reopener provision and an
        arbitration provision.  In 1992, PSO reopened the pricing
        provision.  The parties failed to reach an agreement and the matter
        was arbitrated, with the arbitration panel establishing a lowered rate as
        of
        July 1, 1992 (the 1992 Rate), and modifying the rate adjustment
        formula.  The decision did not mention the rate floor.  From
        April 1996 through the contract termination in December 2001, the 1992 Rate
        exceeded the adjusted rate, determined according to the decision.  PSO
        paid the adjusted rate and contended that the panel eliminated the rate
        floor.  BNSF invoiced at the 1992 Rate and contended that the 1992
        Rate was the new rate floor.  At the end of 1991, PSO terminated the
        contract by paying a termination fee, as required by the
        agreement.  BNSF contends that the termination fee should have been
        calculated on the 1992 Rate, not the adjusted rate, resulting in an underpayment
        of approximately $9.5 million, including interest.
 
 This
        matter was submitted to an arbitration board.  In April 2006, the
        arbitration board filed its decision, denying BNSF’s underpayments
        claim.  PSO filed a request for an order confirming the arbitration
        award and a request for entry of judgment on the award with the U.S. District
        Court for the Northern District of Oklahoma.  On July 14, 2006, the
        U.S. District Court issued an order confirming the arbitration
        award.  On July 24, 2006, BNSF filed a Motion to Reconsider the July
        14, 2006 Arbitration Confirmation Order and Final Judgment and its Motion
        to
        Vacate and Correct the Arbitration Award with the U.S. District
        Court.  In February 2007, the U.S. District Court granted BNSF’s
        Motion to Reconsider.  PSO filed a substantive response to BNSF’s
        motion and BNSF filed a reply.  Management continues to work toward
        mitigating the disputed amounts to the extent possible.
 
 ***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.  An ALJ
        recommended rejection of the complaint, holding that the markets for future
        delivery were not dysfunctional, and that the Nevada utilities failed to
        demonstrate that the public interest required that changes be made to the
        contracts.  In June 2003, the FERC issued an order affirming the ALJ’s
        decision.  In December 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.  In May 2007, the Registrant Subsidiaries, along with
        other sellers involved in the case, sought review of the Ninth Circuit’s
        decision by the U.S. Supreme Court.  The Solicitor General of the
        United States has asked the Supreme Court for an extension of time, until
        August
        6, 2007, to respond to the petitions for review.  Management is unable
        to predict the outcome of these proceedings or their impact on future results
        of
        operations and cash flows.  The Registrant Subsidiaries asserted
        claims against certain companies that sold power to them, which was resold
        to
        the Nevada utilities, seeking to recover a portion of any amounts the Registrant
        Subsidiaries may owe to the Nevada utilities.
 
 **5.**
              **ACQUISITION**
 
 ***Darby
        Electric Generating Station – Affecting CSPCo***
 
 In
        November 2006, CSPCo agreed to purchase Darby Electric Generating Station
        (Darby) from DPL Energy, LLC, a subsidiary of The Dayton Power and Light
        Company, for $102 million and the assumption of liabilities of $2
        million.  CSPCo completed the purchase in April 2007.  The
        Darby plant is located near Mount Sterling, Ohio and is a natural gas, simple
        cycle power plant with a generating capacity of 480 MW.
  **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.
 
 The
        Registrant Subsidiaries adopted SFAS 158 as of December 31, 2006.  The
        Registrant Subsidiaries recorded a SFAS 71 regulatory asset for qualifying
        SFAS
        158 costs of regulated operations that for ratemaking purposes are deferred
        for
        future recovery.
 
 ***Components
        of Net Periodic Benefit Cost***
 
 The
        following table provides the components of AEP’s net periodic benefit cost for
        the plans for the three and six months ended June 30, 2007 and
        2006:
  **Other****Postretirement****Pension
                  Plans**
              
              
              **Benefit
                  Plans****2007**
              
              
              **2006**
              
              
              **2007**
              
              
              **2006****Three
                  Months Ended June 30, 2007 and 2006**
              
              **(in
                  millions)**Service
                  Cost
              
              $
              23
              
              
              $
              24
              
              
              $
              11
              
              
              $
              10Interest
                  Cost
              
              
              57
              
              
              
              57
              
              
              
              26
              
              
              
              25Expected
                  Return on Plan Assets
              
              
              (82
              )
              
              
              (83
              )
              
              
              (26
              )
              
              
              (23
              )Amortization
                  of Transition Obligation
              
              
              -
              
              
              
              -
              
              
              
              7
              
              
              
              7Amortization
                  of Net Actuarial Loss
              
              
              14
              
              
              
              19
              
              
              
              3
              
              
              
              5**Net
                  Periodic Benefit Cost**
              
              $
              12
              
              
              $
              17
              
              
              $
              21
              
              
              $
              24
 
 **Other****Postretirement****Pension
                  Plans**
              
              
              **Benefit
                  Plans****2007**
              
              
              **2006**
              
              
              **2007**
              
              
              **2006****Six
                  Months Ended June 30, 2007 and 2006**
              
              **(in
                  millions)**Service
                  Cost
              
              $
              47
              
              
              $
              48
              
              
              $
              21
              
              
              $
              20Interest
                  Cost
              
              
              116
              
              
              
              114
              
              
              
              52
              
              
              
              50Expected
                  Return on Plan Assets
              
              
              (167
              )
              
              
              (166
              )
              
              
              (52
              )
              
              
              (46
              )Amortization
                  of Transition Obligation
              
              
              -
              
              
              
              -
              
              
              
              14
              
              
              
              14Amortization
                  of Net Actuarial Loss
              
              
              29
              
              
              
              39
              
              
              
              6
              
              
              
              10**Net
                  Periodic Benefit Cost**
              
              $
              25
              
              
              $
              35
              
              
              $
              41
              
              
              $
              48
  The
        following table provides the net periodic benefit cost (credit) for the plans
        by
        Registrant Subsidiary for the three and six months ended June 30, 2007 and
        2006:
  **Pension
                  Plans**
              
              
              **Other
                  Postretirement**
                **Benefit
                  Plans****2007**
              
              
              **2006**
              
              
              **2007**
              
              
              **2006****Three
                  Months Ended June 30, 2007 and 2006**
              
              **(in
                  thousands)**APCo
              
              $
              842
              
              
              $
              1,469
              
              
              $
              3,560
              
              
              $
              4,489CSPCo
              
              
              (258
              )
              
              
              205
              
              
              
              1,491
              
              
              
              1,805I&M
              
              
              1,900
              
              
              
              2,330
              
              
              
              2,531
              
              
              
              2,953OPCo
              
              
              245
              
              
              
              829
              
              
              
              2,801
              
              
              
              3,396PSO
              
              
              424
              
              
              
              979
              
              
              
              1,430
              
              
              
              1,588SWEPCo
              
              
              747
              
              
              
              1,225
              
              
              
              1,419
              
              
              
              1,578
 
 **Pension
                  Plans**
              
              
              **Other
                  Postretirement**
                **Benefit
                  Plans****2007**
              
              
              **2006**
              
              
              **2007**
              
              
              **2006****Six
                  Months Ended June 30, 2007 and 2006**
              
              **(in
                  thousands)**APCo
              
              $
              1,684
              
              
              $
              2,937
              
              
              $
              7,120
              
              
              $
              8,978CSPCo
              
              
              (515
              )
              
              
              410
              
              
              
              2,982
              
              
              
              3,610I&M
              
              
              3,800
              
              
              
              4,661
              
              
              
              5,061
              
              
              
              5,906OPCo
              
              
              490
              
              
              
              1,655
              
              
              
              5,603
              
              
              
              6,792PSO
              
              
              848
              
              
              
              1,956
              
              
              
              2,861
              
              
              
              3,176SWEPCo
              
              
              1,493
              
              
              
              2,450
              
              
              
              2,838
              
              
              
              3,156
 
 **7.**
              **BUSINESS
                  SEGMENTS**
 
 All
        of
        AEP’s Registrant Subsidiaries have one reportable segment.  The one
        reportable segment is an integrated electricity generation, transmission
        and
        distribution business.  All of the Registrant Subsidiaries’ other
        activities are insignificant.  The Registrant Subsidiaries’ operations
        are managed on an integrated basis because of the substantial impact of
        cost-based rates and regulatory oversight on the business process, cost
        structures and operating results.
 
 **8.**
              **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 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 approximates a separate return result for each company in the
        consolidated group.
 
 ***Audit
        Status***
 
 The
        Registrant Subsidiaries also file income tax returns in various state and
        local
        jurisdictions.  With few exceptions, the Registrant Subsidiaries are
        no longer subject to U.S. federal, state and local income tax examinations
        by
        tax authorities for years before 2000.  The IRS and other taxing
        authorities routinely examine the tax returns.  Management believes
        that the Registrant Subsidiaries have filed tax returns with positions that
        may
        be challenged by the tax authorities.  The Registrant Subsidiaries are
        currently under examination in several state and local
        jurisdictions.  However, management does not believe that the ultimate
        resolution of these audits will materially impact results of
        operations.
 
 The
        AEP
        System settled with the IRS on all issues from the audits of consolidated
        federal income tax returns for years prior to 1997.  The AEP System
        effectively settled all outstanding proposed IRS adjustments for years 1997
        through 1999 and through June 2000 for the CSW pre-merger tax period and
        anticipates payment for the agreed adjustments to occur during
        2007.  Returns for the years 2000 through 2005 are presently being
        audited by the IRS and management anticipates that the audit of the 2000
        through
        2003 years will be completed by the end of 2007.
  ***FIN
        48 Adoption***
 
 The
        Registrant Subsidiaries adopted the provisions of FIN 48 on January 1,
        2007.  As a result of the implementation of FIN 48, the approximate
        increase (decrease) in the liabilities for unrecognized tax benefits, as
        well as
        related interest expense and penalties, which was accounted for as a reduction
        to the January 1, 2007 balance of retained earnings was recognized by each
        Registrant Subsidiary as follows:
 
 **Company**
              
              **(in
                  thousands)**APCo
              
              $
              2,685CSPCo
              
              
              3,022I&M
              
              
              (327
              )OPCo
              
              
              5,380PSO
              
              
              386SWEPCo
              
              
              1,642
 
 At
        January 1, 2007, the total amount of unrecognized tax benefits under FIN
        48 for
        each Registrant Subsidiary was as follows:
  **Company**
              
              **(in
                  millions)**APCo
              
              $
              21.7CSPCo
              
              
              25.0I&M
              
              
              18.2OPCo
              
              
              49.8PSO
              
              
              8.9SWEPCo
              
              
              7.1
 
 Management
        believes it is reasonably possible that there will be a net decrease in
        unrecognized tax benefits due to the settlement of audits and the expiration
        of
        statute of limitations within 12 months of the reporting date for each
        Registrant Subsidiary as follows:
  **Company**
              
              **(in
                  millions)**APCo
              
              $
              5.5CSPCo
              
              
              9.3I&M
              
              
              6.0OPCo
              
              
              9.0PSO
              
              
              4.4SWEPCo
              
              
              2.8
 
 At
        January 1, 2007, the total amount of unrecognized tax benefits that, if
        recognized, would affect the effective tax rate for each Registrant Subsidiary
        was as follows:
 
 **Company**
              
              **(in
                  millions)**APCo
              
              $
              5.4CSPCo
              
              
              13.8I&M
              
              
              5.4OPCo
              
              
              23.4PSO
              
              
              1.2SWEPCo
              
              
              1.2
 
 At
        January 1, 2007, tax positions for each Registrant Subsidiary, for which
        the
        ultimate deductibility is highly certain but the timing of such deductibility
        is
        uncertain, was as follows:
 
 **Company**
              
              **(in
                  millions)**APCo
              
              $
              13.7CSPCo
              
              
              3.9I&M
              
              
              10.3OPCo
              
              
              14.2PSO
              
              
              7.1SWEPCo
              
              
              5.1
 
 Because
        of the impact of deferred tax accounting, other than interest and penalties,
        the
        disallowance of the shorter deductibility period would not affect the annual
        effective tax rate but would accelerate the payment of cash to the taxing
        authority to an earlier period.
 
 Prior
        to
        the adoption of FIN 48, the Registrant Subsidiaries recorded interest and
        penalty accruals related to income tax positions in tax accrual
        accounts.  With the adoption of FIN 48, the Registrant Subsidiaries
        began recognizing interest accruals related to income tax positions in interest
        expense and penalties in Other Operations.  As of January 1, 2007,
        each Registrant Subsidiary accrued for the payment of uncertain interest
        and
        penalties as follows:
 
 **Company**
              
              **(in
                  millions)**APCo
              
              $
              4.6CSPCo
              
              
              1.7I&M
              
              
              2.8OPCo
              
              
              4.3PSO
              
              
              2.7SWEPCo
              
              
              2.0
 
 ***Michigan
        Tax Restructuring (Affecting I&M)***
 
 On
        July
        12, 2007, the Governor of Michigan signed Michigan Senate Bill 0094 (MBT
        Act)
        and related companion bills into law providing a comprehensive restructuring
        of
        Michigan’s principal business tax.  The new law is effective January
        1, 2008 and replaces the Michigan Single Business Tax that is scheduled to
        expire at the end of 2007.  The MBT Act is composed of a new tax which
        will be calculated based upon two components:  a business income tax
        imposed at a rate of 4.95% and a modified gross receipts tax imposed at a
        rate
        of 0.80%, which will collectively be referred to as the BIT/GRT tax
        calculation.  The new law also includes significant credits for
        engaging in Michigan-based activity.
 
 I&M
        is in the process of evaluating the impact of the MBT Act.  It is
        expected that the application of the MBT Act will not materially affect
        I&M’s results of operations, cash flows or financial condition.
 
 **9.**
              **FINANCING
                  ACTIVITIES**
 
 ***Long-term
        Debt***
 
 Long-term
        debt and other securities issued, retired and principal payments made during
        the
        first six months of 2007 were:
  **Company**
              
              **Type
                  of Debt**
              
              **Principal
                  Amount**
              
              **Interest
                  Rate**
              
              **Due
                  Date****(in
                  thousands)**
              
              **(%)****Issuances:**APCo
              
              Pollution
                  Control Bonds
              
              $
              75,000
              
              Variable
              
              2037OPCo
              
              Pollution
                  Control Bonds
              
              
              65,000
              
              4.90
              
              2037OPCo
              
              Senior
                  Unsecured Notes
              
              
              400,000
              
              Variable
              
              2010PSO
              
              Pollution
                  Control Bonds
              
              
              12,660
              
              4.45
              
              2020SWEPCo
              
              Senior
                  Unsecured Notes
              
              
              250,000
              
              5.55
              
              2017
  In
        May
        2007, I&M remarketed its outstanding $50 million pollution control bonds,
        resulting in a new interest rate of 4.625%.  No proceeds were received
        related to this remarketing.  The principal amount of the pollution
        control bonds is reflected in Long-term Debt on I&M’s Condensed Consolidated
        Balance Sheet as of June 30, 2007.
 
 **Company**
              
              **Type
                  of Debt**
              
              **Principal
                  Amount**
              
              **Interest
                  Rate**
              
              **Due
                  Date****(in
                  thousands)**
              
              **(%)****Retirements
                  and**
                **Principal
                  Payments:**APCo
              
              Senior
                  Unsecured Notes
              
              $
              125,000
              
              Variable
              
              2007APCo
              
              Other
              
              
              6
              
              13.718
              
              2026OPCo
              
              Notes
                  Payable
              
              
              2,927
              
              6.81
              
              2008OPCo
              
              Notes
                  Payable
              
              
              6,000
              
              6.27
              
              2009SWEPCo
              
              Notes
                  Payable
              
              
              3,109
              
              4.47
              
              2011SWEPCo
              
              Notes
                  Payable
              
              
              4,000
              
              6.36
              
              2007SWEPCo
              
              Notes
                  Payable
              
              
              1,500
              
              Variable
              
              2008
 
 In
        July
        2007, PSO redeemed $13 million of 6.00% Pollution Control Bonds due in
        2020.
 
 ***Lines
        of Credit – AEP System***
 
 The
        AEP
        System uses a corporate borrowing program to meet the short-term borrowing
        needs
        of its subsidiaries.  The corporate borrowing program includes a
        Utility Money Pool, which funds the utility subsidiaries.  The AEP
        System corporate borrowing program 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 June 30, 2007 and
        December 31, 2006 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 six months ended June 30, 2007 are described in the following
        table:
 
 **Maximum
                  Borrowings**
                **from
                  Utility**
                **Money
                  Pool**
              
              
              **Maximum**
                **Loans
                  to**
                **Utility**
                **Money
                  Pool**
              
              
              **Average
                  Borrowings**
                **from
                  Utility**
                **Money
                  Pool**
              
              
              **Average**
                **Loans
                  to**
                **Utility
                  Money**
                **Pool**
              
              
              **Borrowings**
                **from
                  Utility Money Pool as of**
                **June
                  30, 2007**
              
              
              **Authorized**
                **Short-Term
                  Borrowing**
                **Limit****Company**
              
              **(in
                  thousands)**APCo
              
              $
              247,616
              
              
              $
              -
              
              
              $
              103,925
              
              
              $
              -
              
              
              $
              247,616
              
              
              $
              600,000CSPCo
              
              
              117,890
              
              
              
              35,270
              
              
              
              53,692
              
              
              
              13,190
              
              
              
              64,003
              
              
              
              350,000I&M
              
              
              100,374
              
              
              
              -
              
              
              
              60,659
              
              
              
              -
              
              
              
              14,941
              
              
              
              500,000OPCo
              
              
              447,335
              
              
              
              1,564
              
              
              
              209,965
              
              
              
              1,564
              
              
              
              16,583
              
              
              
              600,000PSO
              
              
              216,239
              
              
              
              -
              
              
              
              111,567
              
              
              
              -
              
              
              
              216,239
              
              
              
              300,000SWEPCo
              
              
              240,786
              
              
              
              48,979
              
              
              
              70,927
              
              
              
              29,653
              
              
              
              53,955
              
              
              
              350,000
 
 The
        maximum and minimum interest rates for funds either borrowed from or loaned
        to
        the Utility Money Pool were as follows:
  **Six
                  Months Ended June 30,****2007**
              
              
              **2006**Maximum
                  Interest Rate
              
              
              5.46
              %
              
              
              5.39
              %Minimum
                  Interest Rate
              
              
              5.30
              %
              
              
              4.19
              %
  The
        average interest rates for funds borrowed from and loaned to the Utility
        Money
        Pool for the six months ended June 30, 2007 and 2006 are summarized for all
        Registrant Subsidiaries in the following table:
 
 **Average
                  Interest Rate for Funds**
                **Borrowed
                  from the Utility Money Pool for**
                **Six
                  Months Ended June 30,**
              
              
              **Average
                  Interest Rate for Funds**
                **Loaned
                  to the Utility Money Pool for**
                **Six
                  Months Ended June 30,****2007**
              
              
              **2006**
              
              
              **2007**
              
              
              **2006****Company**
              
              **(in
                  percentage)**APCo
              
              
              5.36
              
              
              
              4.62
              
              
              
              -
              
              
              
              5.05CSPCo
              
              
              5.37
              
              
              
              4.73
              
              
              
              5.33
              
              
              
              4.91I&M
              
              
              5.35
              
              
              
              4.76
              
              
              
              -
              
              
              
              -OPCo
              
              
              5.35
              
              
              
              4.86
              
              
              
              5.43
              
              
              
              5.30PSO
              
              
              5.36
              
              
              
              4.91
              
              
              
              -
              
              
              
              -SWEPCo
              
              
              5.36
              
              
              
              4.92
              
              
              
              5.34
              
              
              
              -
 
 ***Short-term
        Debt***
 
 The
        Registrant Subsidiaries’ outstanding short-term debt was as
        follows:
 
 **June
                  30, 2007**
              
              **December
                  31, 2006****Type
                  of Debt**
              **Outstanding**
                **Amount**
              
              
              **Interest**
                **Rate**
              
              **Outstanding**
                **Amount**
              
              
              **Interest**
                **Rate****Company**
              
              
              **(in
                  millions)**
              
              
              
              
              **(in
                  millions)**OPCo
              
              Commercial
                  Paper – JMG
              
              
              $
              -
              
              
              
              -
              
              
              
              $
              1
              
              
              
              5.56
              %SWEPCo
              
              Line
                  of Credit – Sabine
              
              
              
              22
              
              
              
              6.20
              %
              
              
              
              17
              
              
              
              6.38
              %
 
 ***Dividend
        Restrictions***
 
 Under
        the
        Federal Power Act, the Registrant Subsidiaries are restricted from paying
        dividends out of stated capital.
 
 ***Sale
        of Receivables – AEP Credit***
 
 In
        July
        2007, AEP extended AEP Credit’s sale of receivables agreement.  The
        sale of receivables agreement provides commitments of $600 million from a
        bank
        conduit to purchase receivables from AEP Credit.  This agreement will
        expire in November 2007.  AEP intends to renew or replace this
        agreement.  AEP Credit purchases accounts receivable through purchase
        agreements with CSPCo, I&M, OPCo, PSO, SWEPCo and a portion of
        APCo.  Since APCo does not have regulatory authority to sell accounts
        receivable in all of its regulatory jurisdictions, only a portion of APCo’s
        accounts receivable are sold to AEP Credit.
  
  **COMBINED
        MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT
        SUBSIDIARIES**
 
 The
        following is a combined presentation of certain components of the registrants’
management’s discussion and analysis.  The information in this section
        completes the information necessary for management’s discussion and analysis of
        financial condition and results of operations and is meant to be read with
        (i)
        Management’s Financial Discussion and Analysis, (ii) financial statements and
        (iii) footnotes of each individual registrant.  The combined
        Management’s Discussion and Analysis of Registrant Subsidiaries section of the
        2006 Annual Report should also be read in conjunction with this
        report.
 
 **Significant
        Factors**
 
 **Ohio
        Restructuring**
 
 CSPCo
        and
        OPCo are involved in discussions with various stakeholders in Ohio about
        potential legislation to address the period following the expiration of the
        RSPs
        on December 31, 2008.  At this time, management is unable to predict
        whether CSPCo and OPCo will transition to market pricing, as permitted by
        the
        current Ohio restructuring legislation, extend their RSP rates, with or without
        modification, or become subject to a legislative reinstatement of some form
        of
        cost-based regulation for their generation supply business on January 1,
        2009
        when the RSP period ends.
 
 **Ohio
        New Generation**
 
 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.  The application proposed three phases of
        cost recovery associated with the IGCC plant:  Phase 1, recovery of
        $24 million in pre-construction costs during 2006; Phase 2, concurrent recovery
        of construction-financing costs; and Phase 3, recovery or refund in distribution
        rates of any difference between the market-based standard service offer price
        for generation and the cost of operating and maintaining the plant, including
        a
        return on and return of the ultimate cost to construct the plant, originally
        projected to be $1.2 billion, along with fuel, consumables and replacement
        power
        costs.  The proposed recoveries in Phases 1 and 2 would be applied
        against the 4% limit on additional generation rate increases CSPCo and OPCo
        could request under their RSPs.
 
 In
        April
        2006, the PUCO issued an order authorizing CSPCo and OPCo to implement Phase
        1
        of the cost recovery proposal.  In June 2006, the PUCO issued another
        order approving a tariff to recover Phase 1 pre-construction costs over a
        period
        of no more than twelve months effective July 1, 2006.  Through June
        30, 2007, CSPCo and OPCo each recorded pre-construction IGCC regulatory assets
        of $10 million and each collected the entire $12 million approved by the
        PUCO.  CSPCo and OPCo expect to incur additional pre-construction
        costs equal to or greater than the $12 million each recovered.  As of
        June 30, 2007, CSPCo and OPCo have recorded a liability of $2 million each
        for
        the over-recovered portion.  The PUCO indicated that if CSPCo and OPCo
        have not commenced a continuous course of construction of the IGCC plant
        within
        five years of the June 2006 PUCO order, all charges collected for
        pre-construction costs, associated with items that may be utilized in IGCC
        projects to be built by AEP at other sites, must be refunded to Ohio ratepayers
        with interest.  The PUCO deferred ruling on cost recovery for Phases 2
        and 3 until further hearings are held.  A date for further rehearings
        has not been set.
 
 In
        August
        2006, the Ohio Industrial Energy Users, Ohio Consumers’ Counsel, FirstEnergy
        Solutions and Ohio Energy Group filed four separate appeals of the PUCO’s order
        in the IGCC proceeding.  The Ohio Supreme Court has scheduled oral
        arguments for these appeals in October 2007.   Management
        believes that the PUCO’s authorization to begin collection of Phase 1 rates is
        lawful.  Management, however, cannot predict the outcome of these
        appeals.  If the PUCO’s order is found to be unlawful, CSPCo and OPCo
        could be required to refund Phase 1 cost-related recoveries.
 
 Pending
        the outcome of the Supreme Court litigation, CSPCo and OPCo announced they
        may
        delay the start of construction of the IGCC plant.  Recent estimates
        of the cost to build an IGCC plant are $2.2 billion.  CSPCo and OPCo
        may need to request an extension to the 5 year start of construction requirement
        if the commencement of construction is delayed beyond 2011.  In July
        2007, CSPCo and OPCo filed a status report with the PUCO referencing APCo’s IGCC
        West Virginia filing.
 
 **SECA
        Revenue Subject to Refund**
 
 The
        AEP
        East companies ceased collecting T&O revenues in accordance with FERC
        orders, and collected SECA rates to mitigate the loss of T&O revenues from
        December 1, 2004 through March 31, 2006, when SECA rates
        expired.  Intervenors objected to the 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 or
        surcharge.  The AEP East companies paid SECA rates to other utilities
        at considerably lesser amounts than 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.  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
  Approximately
        $19 million of these recorded SECA revenues billed by PJM were not
        collected.  The AEP East companies filed a motion with the FERC to
        force payment of these uncollected SECA billings.
 
 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 was not 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.
 
 Since
        the
        implementation of SECA rates in December 2004, the AEP East companies recorded
        approximately $220 million of gross SECA revenues, subject to
        refund.  In 2006, the AEP East companies provided reserves of $37
        million in net refunds for current and future SECA settlements with all of
        AEP’s
        SECA customers.  APCo’s,
        CSPCo’s, I&M’s and OPCo’s portions of the reserve are as
        follows: 
 **Company**
                
                **(in
                    millions)**APCo
                
                $
                12.0CSPCo
                
                
                6.7I&M
                
                
                7.0OPCo
                
                
                9.1
  The
          AEP
          East companies reached settlements with certain SECA customers related
          to
          approximately $69 million of such revenues for a net refund of $3
          million.  The AEP East companies are in the process of completing two
          settlements-in-principle on an additional $36 million of SECA revenues
          and
          expect to make net refunds of $4 million when those settlements are
          approved.  Thus, completed and in-process settlements cover $105
          million of SECA revenues and will consume about $7 million of the reserves
          for
          refunds, leaving approximately $115 million of contested SECA revenues
          and $30
          million of refund reserves.  If the ALJ’s initial decision were upheld
          in its entirety, it would disallow approximately $90 million of the AEP
          East
          companies’ remaining $115 million of unsettled gross SECA
          revenues.  Based on recent settlement experience and the expectation
          that most of the $115 million of unsettled SECA revenues will be settled,
          management believes that the remaining reserve will be
          adequate.
 
 In
        September 2006, AEP, together with Exelon Corporation and The Dayton Power
        and
        Light Company, filed an extensive post-hearing brief and reply brief noting
        exceptions to the ALJ’s initial decision and asking the FERC to reverse the
        decision in large part.  Management believes that the FERC should
        reject the 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.  As directed by the FERC, management is working to settle the
        remaining $115 million of unsettled revenues within the remaining reserve
        balance.  Although management believes it has meritorious arguments
        and can settle with the remaining customers within the amount provided,
        management cannot predict the ultimate outcome of ongoing settlement talks
        and,
        if necessary, any future FERC proceedings or court appeals.  If the
        FERC adopts the ALJ’s decision and/or AEP cannot settle a significant portion of
        the remaining unsettled claims within the amount provided, it will have an
        adverse effect on future results of operations and cash flows.
 
 **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 Clean Air Act (CAA) to reduce
                  emissions of sulfur dioxide (SO2), nitrogen oxide
                  (NOx), particulate matter (PM) and mercury from fossil
                  fuel-fired power plants; and·
              Requirements
                  under the Clean Water Act (CWA) to reduce the
                  impacts of water intake structures on aquatic species at certain
                  power
                  plants.
 
 In
        addition, the Registrant Subsidiaries are engaged in litigation with respect
        to
        certain environmental matters, have been notified of potential responsibility
        for the clean-up of contaminated sites and incur costs for disposal of spent
        nuclear fuel and future decommissioning of I&M’s nuclear
        units.  Management also monitors possible future requirements to
        reduce carbon dioxide (CO2) 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 2006 Annual Report.
 
 ***Environmental
        Litigation***
 
 New
        Source Review (NSR) Litigation:  In 1999, the Federal EPA, a
        number of states and certain special interest groups filed complaints alleging
        that APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities including the
        Tennessee Valley Authority, Alabama Power Company, Cincinnati Gas & Electric
        Company, Ohio Edison Company, Southern Indiana Gas & Electric Company,
        Illinois Power Company, Tampa Electric Company, Virginia Electric Power Company
        and Duke Energy,  modified certain units at coal-fired generating
        plants in violation of the NSR requirements of the CAA.  Several
        similar complaints were filed in 1999 and thereafter against nonaffiliated
        utilities including Allegheny Energy, Eastern Kentucky Electric Cooperative,
        Public Service Enterprise Group, Santee Cooper, Wisconsin Electric Power
        Company, Mirant, NRG Energy and Niagara Mohawk.  Several of these
        cases were resolved through consent decrees.  The alleged
        modifications at the Registrant Subsidiaries’ power plants occurred over a
        20-year period.  A bench trial on the liability issues was held during
        2005.  In June 2006, the judge stayed the liability decision pending
        the issuance of a decision by the U.S. Supreme Court in the Duke Energy
        case.
 
 Under
        the
        CAA, if a plant undertakes a major modification that directly results in
        an
        emissions increase, permitting requirements might be triggered and the plant
        may
        be required to install additional pollution control technology.  This
        requirement does not apply to activities such as routine maintenance,
        replacement of degraded equipment or failed components, or other repairs
        needed
        for the reliable, safe and efficient operation of the plant.
 
 Courts
        that considered whether the activities at issue in these cases are routine
        maintenance, repair, or replacement, and therefore are excluded from NSR,
        reached different conclusions.  Similarly, courts that considered
        whether the activities at issue increased emissions from the power plants
        have
        reached different results.  Appeals on these and other issues were
        filed in certain appellate courts, including a petition to appeal to the
        U.S.
        Supreme Court that was granted in the Duke Energy case.
 
 In
        April
        2007, the U.S. Supreme Court reversed the Fourth Circuit Court of Appeals’
decision that had supported the statutory construction argument of Duke Energy
        in its NSR proceeding.  In a unanimous decision, the Court ruled that
        the Federal EPA was not obligated to define “major modification” in two
        different CAA provisions in the same way.  The Court also found that
        the Fourth Circuit’s interpretation of “major modification” as applying only to
        projects that increased hourly emission rates amounted to an invalidation
        of the
        relevant Federal EPA regulations, which under the CAA can only be challenged
        in
        the Court of Appeals within 60 days of the Federal EPA
        rulemaking.  The U.S. Supreme Court did acknowledge, however, that
        Duke Energy may argue on remand that the Federal EPA has been inconsistent
        in
        its interpretations of the CAA and the regulations and may not retroactively
        change 20 years of accepted practice.
 
 In
        addition to providing guidance on certain of the merits of the NSR proceedings
        brought against APCo, CSPCo, I&M and OPCo, the U.S. Supreme Court’s issuance
        of a ruling in the Duke Energy cases has an impact on the timing of the NSR
        proceedings.  The court indicated an intent to issue a decision on
        liability in the third quarter of 2007.  A bench trial on remedy
        issues, if necessary, is likely to begin in the second half of
        2007.
 
 Management
        is unable to estimate the loss or range of loss related to any contingent
        liability, if any, the Registrant Subsidiaries might have for civil penalties
        under the CAA proceedings.  Management is also unable to predict the
        timing of resolution of these matters due to the number of alleged violations
        and the significant number of issues to be determined by the
        court.  If the Registrant Subsidiaries do not prevail, management
        believes the Registrant Subsidiaries can recover any capital and operating
        costs
        of additional pollution control equipment that may be required through regulated
        rates and market prices for electricity.  If the Registrant
        Subsidiaries are unable to recover such costs or if material penalties are
        imposed, it would adversely affect future results of operations, cash flows
        and
        possibly financial condition.
 
 ***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.  Management expected additional capital and operating expenses,
        which the Federal EPA estimated could be $193 million for AEP System
        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.
 
 **Estimated
                  Compliance Investments****Company**
              
              **(in
                  millions)**APCo
              
              $
              21CSPCo
              
              
              19I&M
              
              
              118OPCo
              
              
              31
 
 The
        rule
        was challenged in the courts by states, advocacy organizations and
        industry.  In January 2007, the Second Circuit Court of Appeals issued
        a decision remanding significant portions of the rule to the Federal
        EPA.  In July 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.  Management cannot predict further action of
        the Federal EPA or what effect it may have on similar requirements adopted
        by
        the states.  Management may seek further review or relief from the
        schedules included in the permits.
 
 **Adoption
        of New Accounting Pronouncements**
 
 FIN
        48
        clarifies the accounting for uncertainty in income taxes recognized in an
        enterprise’s financial statements by prescribing a recognition threshold
        (whether a tax position is more likely than not to be sustained) without
        which,
        the benefit of that position is not recognized in the financial
        statements.  It requires a measurement determination for recognized
        tax positions based on the largest amount of benefit that is greater than
        50
        percent likely of being realized upon ultimate settlement.  FIN 48
        also provides guidance on derecognition, classification, interest and penalties,
        accounting in interim periods, disclosure and transition.  FIN 48
        requires that the cumulative effect of applying this interpretation be reported
        and disclosed as an adjustment to the opening balance of retained earnings
        for
        that fiscal year and presented separately.  The Registrant
        Subsidiaries adopted FIN 48 effective January 1, 2007.  See “FIN 48
“Accounting for Uncertainty in Income Taxes” and FASB Staff Position FIN 48-1
“Definition of *Settlement* in FASB Interpretation No. 48”” section of
        Note 2 and see Note 8 – Income Taxes.  The impact of this
        interpretation was an unfavorable (favorable) adjustment to retained earnings
        as
        follows:
 
 **Company**
              
              **(in
                  thousands)**APCo
              
              $
              2,685CSPCo
              
              
              3,022I&M
              
              
              (327
              )OPCo
              
              
              5,380PSO
              
              
              386SWEPCo
              
              
              1,642
  
  **CONTROLS
        AND PROCEDURES**
 
 During
        the second quarter of 2007, 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
        June 30, 2007 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 second quarter of 2007 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 Note 4, *Commitments,
        Guarantees and Contingencies,*incorporated herein by
        reference.
 
 **Item
        1A.  Risk Factors**
 
 Our
        Annual Report on Form 10-K for the year ended December 31, 2006 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 2006 Annual Report on Form 10-K.
 
 **General
        Risks of Our Regulated Operations**
 
 **Our
        request for rate recovery of additional costs may not be approved in
        Texas.***(Applies to AEP.)*
 
 TCC
        has
        filed a request with the PUCT to increase its transmission and distribution
        rates.  The rate request includes the amounts charged for the delivery
        of electricity over TCC ́s transmission and distribution lines. TCC is seeking
        approval of an $81 million increase, which includes the expiration of $20
        million in billing credits that the PUCT required in approving the merger
        of CSW
        into AEP.  The credits have been in place since 2000. TCC is
        requesting a return on equity of 11.25% with a capital structure of
        approximately 60% debt/40% equity.  As part of rebuttal testimony
        filed in April 2007, TCC reduced its base rate request by $11 million and
        reduced its return on equity by 0.5%.  If the PUCT denies the
        requested rate recovery, it could adversely impact future results of operations,
        cash flows and financial condition.
 
 **Our
        request for rate recovery of additional costs may not be approved in
        Oklahoma.***(Applies to AEP and PSO.)*
 
 PSO
        filed
        a request with the OCC in November 2006 seeking approval of a $50 million
        overall increase in base rates, an annually adjusted rate mechanism to recover
        the expected significant investment PSO will be making in new facilities,
        several new and restructured tariffs to allow PSO to begin to reduce the
        relationship between its revenues and its sales volumes, and to implement
        some
        demand side management tariffs.  PSO ́s planned investments over the
        next five years include new generation facilities ($1.12 billion), new and
        refurbished transmission substations and lines ($302 million) and new
        distribution lines and equipment ($582 million).  In April 2007, PSO
        filed rebuttal testimony regarding various issues raised by the OCC Staff
        and
        the intervenors.  As part of rebuttal testimony, PSO reduced its base
        rate request by $2 million.  If the OCC denies the requested rate
        recovery, it could adversely impact future results of operations, cash flows
        and
        financial condition.
  **The
        amount we charged third parties for using our transmission facilities has
        been
        reduced, is subject to refund and may not be completely restored in the
        future.*****(Applies to AEP, APCo, CSPCo, I&M and
        OPCo.)*
 
 In
        July
        2003, the FERC issued an order directing PJM and MISO to make compliance
        filings
        for their respective tariffs to eliminate the transaction-based charges for
        through and out (T&O) transmission service on transactions where the energy
        is delivered within those RTOs.  The elimination of the T&O rates
        reduces the transmission service revenues collected by the RTOs and thereby
        reduces the revenues received by transmission owners under the RTOs’ revenue
        distribution protocols. To mitigate the impact of lost T&O revenues, the
        FERC approved temporary replacement seams elimination cost allocation (SECA)
        transition rates beginning in December 2004 and extending through March
        2006.  Intervenors objected to this decision; therefore the SECA fees
        we collected ($220 million) are subject to refund.  Approximately $19
        million of the SECA revenues that we billed were never collected.  AEP
        filed a motion with the FERC to force payment of these SECA
        billings.
 
 A
        hearing
        was held in May 2006 to determine whether any of the SECA revenues should
        be
        refunded. In August 2006, the 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 was not 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
        unpaid SECA rates must be paid in the recommended reduced amount.  The
        FERC has not ruled on the matter.  If the FERC upholds the decision of
        the ALJ, it would disallow $90 million of the AEP East companies’ remaining $135
        million of unsettled gross SECA revenues.  We have recorded provisions
        in the aggregate amount of $37 million related to the potential refund of
        SECA
        rates. After completed and in-process settlements of SECA revenues that will
        consume about $7 million of the reserves for refunds, the AEP East companies
        will have a remaining reserve balance of $30 million to settle the remaining
        unsettled gross SECA revenues.
 
 SECA
        transition rates expired on March 31, 2006 and did not fully compensate AEP
        East
        companies for ongoing lost T&O revenues.  As a result of rate
        relief in certain jurisdictions, however, approximately 85% of the ongoing
        lost
        T&O revenues are now being recovered from native load customers of AEP East
        companies in those jurisdictions.  The portion attributable to
        Virginia is being collected subject to refund.
 
 In
        addition to seeking retail rate recovery from native load customers in the
        applicable states, AEP and another member of PJM have filed an application
        with
        the FERC seeking compensation from other unaffiliated members of PJM for
        the
        costs associated with those members’ use of the filers’ the AEP East companies
        respective transmission assets.  A majority of PJM members have filed
        in opposition to the proposal.  Hearings were held in April
        2006.  An ALJ recommended a rate design that would result in greater
        recovery for AEP than the proposal AEP had submitted.  The ALJ also
        recommended, however, that the design be phased-in, which could limit the
        amount
        of recovery for AEP.  In April 2007, the FERC issued an order
        reversing the ALJ decision.  The FERC ruled that the current PJM rate
        design is just and reasonable.  The FERC further ruled that the cost
        of new facilities of 500 kV and above would be shared among all PJM
        participants.  Management cannot estimate at this time what affect, if
        any, this order will have on our future construction of new east transmission
        facilities, results of operations, cash flows and financial
        condition.
 
 **We
        are exposed to losses resulting from the bankruptcy of Enron
        Corp.***(Applies to AEP.)*
 
 On
        June
        1, 2001, we purchased HPL from Enron Corp. (Enron). Later that year, Enron
        and
        its subsidiaries filed bankruptcy proceedings in the U.S. Bankruptcy Court
        for
        the Southern District of New York. Various HPL-related contingencies and
        indemnities from Enron remained unsettled at the date of Enron’s
        bankruptcy.  In connection with the 2001 acquisition of HPL, we
        entered into an agreement with BAM Lease Company, which granted HPL the
        exclusive right to use approximately 65 BCF of cushion gas required for the
        normal operation of the Bammel gas storage facility.  At the time of
        our acquisition of HPL, Bank of America (BOA) and certain other banks (together
        with BOA, BOA Syndicate) and Enron entered into an agreement granting HPL
        the
        exclusive use of 65 BCF of cushion gas.  Additionally, 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, HPL was informed by the BOA Syndicate of a purported default
        by
        Enron under the terms of the financing arrangement.  We purchased 10
        BCF of gas from Enron and are currently litigating the rights to the remaining
        55 BCF of cushion gas.
 
 In
        February 2004, in connection with BOA’s dispute, Enron filed Notices of
        Rejection regarding the cushion gas use agreement and other incidental
        agreements.  We have objected to Enron’s attempted rejection of these
        agreements.  In 2005, we sold HPL, including the Bammel gas storage
        facility.  We indemnified the purchaser for damages, if any, arising
        from the litigation with BOA.  Management is unable to predict the
        final resolution of these disputes, however the impact on results of operations,
        cash flows and financial condition could be material.
 
 **Risks
        Relating To State Restructuring**
 
 **In
        Ohio, our costs may not be recovered and rates may be reduced.***(Applies to AEP, OPCo and CSPCo.)*
 
 In
        January 2007, CSPCo and OPCo filed with the PUCO under the 4% provision of
        their
        RSPs to increase their annual generation rates for 2007 by $24 million and
        $8
        million, respectively, to recover governmentally-mandated
        costs.  Pursuant to the RSPs, CSPCo and OPCo implemented these
        proposed increases effective with the first billing cycle in May
        2007.  These increases are subject to refund until the PUCO issues a
        final order in the matter.  The PUCO staff and intervenors have
        proposed disallowances.  Management is unable to determine the impact
        of any potential refunds or rider reductions on future results of operations
        and
        cash flows.
 
 In
        March
        2007, CSPCo filed an application under the 4% provision of the RSP to adjust
        the
        Power Acquisition Rider (PAR) which was authorized in 2005 by the PUCO in
        connection with CSPCo's acquisition of Monongahela Power Company's certified
        territory in Ohio and a new purchase power contract to serve the
        load.  The PUCO approved an adjustment to the PAR, which is expected
        to increase CSPCo's revenues by $22 million and $38 million for 2007 and
        2008,
        respectively.
  CSPCo
        and
        OPCo are involved in discussions with various stakeholders in Ohio about
        potential legislation to address the period following the expiration of the
        RSPs
        on December 31, 2008.  At this time, management is unable to predict
        whether CSPCo and OPCo will transition to market pricing, as permitted by
        the
        current Ohio restructuring legislation, extend their RSP rates, with or without
        modification, or become subject to a legislative reinstatement of some form
        of
        cost-based regulation for their generation supply business on January 1,
        2009
        when the RSP period ends.
 
 **Some
        laws and regulations governing restructuring in Virginia have not yet been
        interpreted and could harm our business, operating results and financial
        condition.***(Applies to AEP and APCo.)*
 
 Virginia
        restructuring legislation was enacted in 1999 providing for retail choice
        of
        generation suppliers to be phased in over two years beginning January 1,
        2002.  It required jurisdictional utilities to unbundle their power
        supply and energy delivery rates and to file functional separation plans
        by
        January 1, 2002.  APCo filed its plan with the Virginia SCC and,
        following Virginia SCC approval of a settlement agreement, now operates in
        Virginia as a functionally separated electric utility charging unbundled
        rates
        for its retail sales of electricity.  The settlement agreement
        addressed functional separation, leaving decisions related to legal separation
        for later Virginia SCC consideration.  While the electric
        restructuring law in Virginia established the general framework governing
        the
        retail electric market, it required the Virginia SCC to issue rules and
        determinations implementing the law.
 
 In
        April
        2007, Virginia enacted a law providing for cost-based regulation of electric
        utilities’ generation/supply rates.  Results of operations and
        financial condition could be adversely affected when APCo complies with new
        re-regulation legislation applicable to its generation and supply
        business.
 
 **There
        is uncertainty as to our recovery of stranded costs resulting from industry
        restructuring in Texas.***(Applies to
        AEP.)*
 
 Restructuring
        legislation in Texas required utilities with stranded costs to use market-based
        methods to value certain generating assets for determining stranded
        costs.  We elected to use the sale of assets method to determine the
        market value of TCC’s generation assets for stranded cost
        purposes.  In general terms, the amount of stranded costs under this
        market valuation methodology is the amount by which the book value of generating
        assets, including regulatory assets and liabilities that were not securitized,
        exceeds the market value of the generation assets, as measured by the net
        proceeds from the sale of the assets. In May 2005, TCC filed its stranded
        cost
        quantification application with the PUCT seeking recovery of $2.4 billion
        of net
        stranded generation costs and other recoverable true-up items.  A
        final order was issued in April 2006.  In the final order, the PUCT
        determined TCC’s net stranded generation costs and other recoverable true-up
        items to be approximately $1.475 billion.  We have appealed the PUCT’s
        final order seeking additional recovery consistent with the Texas Restructuring
        Legislation and related rules, other parties have appealed the PUCT’s final
        order as unwarranted or too large.  In a preliminary ruling filed in
        February 2007, the Texas state district court (District Court) adjudicating
        the
        appeal of the final order in the true-up proceeding found that the PUCT erred
        in
        several respects, including the method used to determine stranded costs and
        the
        awarding of certain carrying costs.  Following the preliminary ruling,
        the court granted a rehearing of the issue regarding the method to determine
        stranded costs.
 
 In
        March
        2007, the District Court judge reversed the earlier preliminary decision
        concluding the sale of assets method to value TCC’s nuclear plant was
        appropriate.  It is expected that the parties and intervenors will
        appeal various portions of the District Court ruling along with other items
        to
        the Texas Court of Appeals.  Management cannot predict the ultimate
        outcome of any future court appeals or any future remanded PUCT
        proceeding.
 
 **Risks
        Related to Owning and Operating Generation Assets and Selling
        Power**
 
 **Our
        costs of compliance with environmental laws are significant and the cost
        of
        compliance with future environmental laws could harm our cash flow and
        profitability.***(Applies to AEP and each Registrant
        Subsidiary.)*
 
 Our
        operations are subject to extensive federal, state and local environmental
        statutes, rules and regulations relating to air quality, water quality, waste
        management, natural resources and health and safety.  Compliance with
        these legal requirements requires us to commit significant capital toward
        environmental monitoring, installation of pollution control equipment, emission
        fees and permits at all of our facilities.  These expenditures have
        been significant in the past, and we expect that they will increase in the
        future.  On April 2, 2007, the U.S. Supreme Court issued a decision
        holding that the Federal EPA has authority to regulate emissions of CO2and other greenhouse gases under the CAA.  Costs of compliance
        with environmental regulations could adversely affect our results of operations
        and financial position, especially if emission and/or discharge limits are
        tightened, more extensive permitting requirements are imposed, additional
        substances become regulated and the number and types of assets we operate
        increase.  All of our estimates are subject to significant
        uncertainties about the outcome of several interrelated assumptions and
        variables, including timing of implementation, required levels of reductions,
        allocation requirements of the new rules and our selected compliance
        alternatives.  As a result, we cannot estimate our compliance costs
        with certainty.  The actual costs to comply could differ significantly
        from our estimates.  All of the costs are incremental to our current
        investment base and operating cost structure.
 
 **If
        Federal and/or State requirements are imposed on electric utility companies
        mandating further emission reductions, including limitations on****CO****2****emissions,
        such requirements could make some of our electric generating units uneconomical
        to maintain or operate.***(Applies to AEP and each
        Registrant Subsidiary.)*
 
 Emissions
        of nitrogen and sulfur oxides, mercury and particulates from fossil fueled
        generating plants are potentially subject to increased regulations, controls
        and
        mitigation expenses.  Environmental advocacy groups, other
        organizations and some agencies in the United States are focusing considerable
        attention on CO2 emissions from power generation facilities and their
        potential role in climate change.  Although several bills have been
        introduced in Congress that would compel CO2 emission reductions,
        none have advanced through the legislature.  On April 2, 2007, the
        U.S. Supreme Court issued a decision holding that the Federal EPA has authority
        to regulate emissions of CO2 and other greenhouse gases under the
        CAA.  Future changes in environmental regulations governing these
        pollutants could make some of our electric generating units uneconomical
        to
        maintain or operate.  In addition, any legal obligation that would
        require us to substantially reduce our emissions beyond present levels could
        require extensive mitigation efforts and, in the case of CO2
        legislation, would raise uncertainty about the future viability of fossil
        fuels,
        particularly coal, as an energy source for new and existing electric generation
        facilities.  While mandatory requirements for further emission
        reductions from our fossil fleet do not appear to be imminent, we continue
        to
        monitor regulatory and legislative developments in this area.
 
 **Governmental
        authorities may assess penalties on us if it is determined that we have not
        complied with environmental laws and
        regulations.*****(Applies to AEP and each Registrant
        Subsidiary.)*
 
 If
        we
        fail to comply with environmental laws and regulations, even if caused by
        factors beyond our control, that failure may result in the assessment of
        civil
        or criminal penalties and fines against us.  Recent lawsuits by the
        Federal EPA and various states filed against us highlight the environmental
        risks faced by generating facilities, in general, and coal-fired generating
        facilities, in particular.
 
 Since
        1999, we have been involved in litigation regarding generating plant emissions
        under the CAA.  The Federal EPA and a number of states alleged that we
        and other unaffiliated utilities modified certain units at coal-fired generating
        plants in violation of the CAA.  The Federal EPA filed complaints
        against certain AEP subsidiaries in U.S. District Court for the Southern
        District of Ohio.  A separate lawsuit initiated by certain special
        interest groups was consolidated with the Federal EPA case.  The
        alleged modification of the generating units occurred over a 20-year
        period.  A bench trial on the liability issues was held during July
        2005.  Briefing has concluded and the court has indicated an intent to
        issue a decision on liability.  Additionally, in July 2004 attorneys
        general of eight states and others sued AEP and other utilities alleging
        that
        CO2 emissions from power generating facilities constitute a public
        nuisance under federal common law.  The trial court dismissed the
        suits and plaintiffs have appealed the dismissal.  While we believe
        the claims are without merit, the costs associated with reducing CO2
        emissions could harm our business and our results of operations and financial
        position.
 
 If
        these
        or other future actions are resolved against us, substantial modifications
        of
        our existing coal-fired power plants could be required.  In addition,
        we could be required to invest significantly in additional emission control
        equipment, accelerate the timing of capital expenditures, pay penalties and/or
        halt operations.  Moreover, our results of operations and financial
        position could be reduced due to the timing of recovery of these investments
        and
        the expense of ongoing litigation.
 
 **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 June 30, 2007 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
                  Programs**04/01/07
–
04/30/07
              
              
              -
              
              
              
              $
              -
              
              
              
              -
              
              
              $
              -05/01/07
–
05/31/07
              
              
              2
              
              (a)
              
              
              73
              
              
              
              -
              
              
              
              -06/01/07
–
06/30/07
              
              
              20
              
              (b)
              
              
              70
              
              
              
              -
              
              
              
              -
 
 (a)
              I&M repurchased 2 shares of its 4.13% cumulative
                  preferred stock, in a privately-negotiated transaction outside
                  of an
                  announced program.(b)
              I&M repurchased 20 shares of its 4.13% cumulative
                  preferred stock, in privately-negotiated transactions outside of
                  an
                  announced program.
 
 **Item
        4. Submission of Matters to a Vote of Security
        Holders**
 
 AEP
 
 The
        annual meeting of shareholders was held in Shreveport, Louisiana, on April
        24,
        2007.  The holders of shares entitled to vote at the meeting or their
        proxies cast votes at the meeting with respect to the following three matters,
        as indicated below:
 
 1.
              Election
                  of thirteen directors to hold office until the next
                  annual meeting and until their successors are duly
                  elected.  Each nominee for director received the votes of
                  shareholders as follows:
 
 **Number
                  of Shares Voted For**
              
              
              **Number
                  of Shares Abstaining**E.
                  R. Brooks
              
              
              334,998,592
              
              
              
              8,663,576Donald
                  M. Carlton
              
              
              336,014,182
              
              
              
              7,647,986Ralph
                  D. Crosby, Jr.
              
              
              335,978,026
              
              
              
              7,684,142John
                  P. DesBarres
              
              
              335,974,155
              
              
              
              7,688,013Robert
                  W. Fri
              
              
              332,637,218
              
              
              
              11,024,950Linda
                  A. Goodspeed
              
              
              336,200,472
              
              
              
              7,461,696William
                  R. Howell
              
              
              335,739,069
              
              
              
              7,923,099Lester
                  A. Hudson, Jr.
              
              
              333,116,412
              
              
              
              10,545,756Michael
                  G. Morris
              
              
              332,139,748
              
              
              
              11,522,420Lionel
                  L. Nowell, III
              
              
              336,254,000
              
              
              
              7,408,168Richard
                  L. Sandor
              
              
              332,152,005
              
              
              
              11,510,163Donald
                  G. Smith
              
              
              333,270,480
              
              
              
              10,391,688Kathryn
                  D. Sullivan
              
              
              336,273,055
              
              
              
              7,389,113
 
 2.
              Approval
                  of the AEP Senior Officer Incentive Plan.  The proposal was
                  approved by a vote of the shareholders as
                  follows:
 
 Votes
                  FOR
              
              317,166,316Votes
                  AGAINST
              
              20,791,784Votes
                  ABSTAINED
              
              5,704,068
 
 
 3.
              Ratification
                  of the appointment of the firm of Deloitte & Touche LLP as the
                  independent registered public accounting firm for 2007.  The
                  proposal was approved by a vote of the shareholders as
                  follows:
 
 Votes
                  FOR
              
              335,620,502Votes
                  AGAINST
              
              4,752,625Votes
                  ABSTAINED
              
              3,289,041
 
 APCo
 
 The
        annual meeting of stockholders was held on April 24, 2007 at 1 Riverside
        Plaza,
        Columbus, Ohio.  At the meeting, 13,499,500 votes were cast FOR each
        of the following nine persons for election as directors and there were no
        votes
        withheld and such persons were elected directors to hold office for one year
        or
        until their successors are elected and qualify:
 
 Nicholas
                  K. Akins
              
              Robert
                  P. PowersCarl
                  L. English
              
              Stephen
                  P. SmithJohn
                  B. Keane
              
              Susan
                  TomaskyHolly
                  K. Koeppel
              
              Dennis
                  E. WelchMichael
                  G. Morris
  I&M
 
 Pursuant
        to action by written consent in lieu of an annual meeting of the sole
        shareholder dated April 24, 2007, the following thirteen persons were elected
        directors to hold office for one year or until their successors are elected
        and
        qualify:
 
 Nicholas
                  K. Akins
              
              Marc
                  E. LewisKarl
                  G. Boyd
              
              Susanne
                  M. Moorman RoweCarl
                  L. English
              
              Michael
                  G. MorrisAllen
                  R. Glassburn
              
              Helen
                  J. MurrayJoAnn
                  M. Grevenow
              
              Robert
                  P. PowersPatrick
                  C. Hale
              
              Susan
                  TomaskyHolly
                  K. Koeppel
 
 OPCo
 
 The
        annual meeting of shareholders was held on May 1, 2007 at 1 Riverside Plaza,
        Columbus, Ohio.  At the meeting there were 27,952,473 votes cast FOR
        each of the following nine persons for election as directors and there were
        no
        votes withheld and such persons were elected directors to hold office for
        one
        year or until their successors are elected and qualify:
 
 Nicholas
                  K. Akins
              
              Robert
                  P. PowersCarl
                  L. English
              
              Stephen
                  P. SmithJohn
                  B. Keane
              
              Susan
                  TomaskyHolly
                  K. Koeppel
              
              Dennis
                  E. WelchMichael
                  G. Morris
 
 SWEPCo
 
 Pursuant
        to action by written consent in lieu of an annual meeting of the sole
        shareholder dated April 11, 2007, the following nine persons were elected
        directors to hold office for one year or until their successors are elected
        and
        qualify:
 
 Nicholas
                  K. Akins
              
              Holly
                  K. KoeppelCarl
                  L. English
              
              Stephen
                  P. SmithThomas
                  M. Hagan
              
              Susan
                  TomaskyJohn
                  B. Keane
              
              Dennis
                  E. WelchMichael
                  G. Morris
 
 
 **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*
 
 31(a)
–
        Certification of AEP Chief Executive Officer Pursuant to Section 302 of the
        Sarbanes-Oxley Act of 2002.
 31(c)
–
        Certification of AEP Chief Financial Officer Pursuant to Section 302 of the
        Sarbanes-Oxley Act of 2002.
 
 *APCo,
        CSPCo, I&M, OPCo, PSO and SWEPCo*
 
 31(b)
–
        Certification of Registrant Subsidiaries’ Chief Executive Officer Pursuant to
        Section 302 of the Sarbanes-Oxley Act of 2002.
 31(d)
–
        Certification of Registrant Subsidiaries’ Chief Financial Officer Pursuant to
        Section 302 of the Sarbanes-Oxley Act of 2002.
 
 *AEP,
        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. BuonaiutoJoseph
                  M. BuonaiutoController
                  and Chief Accounting OfficerAPPALACHIAN
                  POWER COMPANYCOLUMBUS
                  SOUTHERN POWER COMPANYINDIANA
                  MICHIGAN POWER COMPANYOHIO
                  POWER COMPANYPUBLIC
                  SERVICE COMPANY OF OKLAHOMASOUTHWESTERN
                  ELECTRIC POWER COMPANYBy: /s/Joseph
                  M. BuonaiutoJoseph
                  M. BuonaiutoController
                  and Chief Accounting OfficerDate:  August
                3, 2007