UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended September 30, 2009March 31, 2010
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from ____ to ____

Commission Registrant, State of Incorporation, I.R.S. Employer
File Number Address of Principal Executive Offices, and Telephone Number Identification No.
     
1-3525 AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation) 13-4922640
1-3457 APPALACHIAN POWER COMPANY (A Virginia Corporation) 54-0124790
1-2680 COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation) 31-4154203
1-3570 INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation) 35-0410455
1-6543 OHIO POWER COMPANY (An Ohio Corporation) 31-4271000
0-343 PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation) 73-0410895
1-3146 SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation) 72-0323455
     
All Registrants 1 Riverside Plaza, Columbus, Ohio 43215-2373  
  Telephone (614) 716-1000  

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
YesX No  

Indicate by check mark whether American Electric Power Company, Inc. has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
YesX No  

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

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

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

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).
Yes  NoX 

Columbus Southern Power Company and Indiana Michigan Power Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.

 
 
 


  
Number of shares of common stock outstanding of the registrants at
October 28, 2009April 29, 2010
    
American Electric Power Company, Inc. 477,658,465                            478,873,651
  ($6.50 par value)
Appalachian Power Company  13,499,500
 
  (no par value)
Columbus Southern Power Company  16,410,426
 
  (no par value)
Indiana Michigan Power Company  1,400,000
 
  (no par value)
Ohio Power Company  27,952,473
 
  (no par value)
Public Service Company of Oklahoma  9,013,000
 
  ($15 par value)
Southwestern Electric Power Company  7,536,640
 
  ($18 par value)

 
 
 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX TO QUARTERLY REPORTS ON FORM 10-Q
September 30, 2009March 31, 2010

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

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



 
 
 

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

Term Meaning

AEGCo AEP Generating Company, an AEP electric utility subsidiary.
AEP or Parent American Electric Power Company, Inc.
AEP Consolidated AEP and its majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP East companies APCo, CSPCo, I&M, KPCo and OPCo.
AEP Power Pool Members are APCo, CSPCo, I&M, KPCo and OPCo.  The Pool shares the generation, cost of generation and resultant wholesale off-system sales of the member companies.
AEP System or the System American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEP West companies PSO, SWEPCo, TCC and TNC.
AEPSC American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries.
AFUDC Allowance for Funds Used During Construction.
ALJAdministrative Law Judge.
AOCI Accumulated Other Comprehensive Income.
APBAccounting Principles Board Opinion.
APCo Appalachian Power Company, an AEP electric utility subsidiary.
APSC Arkansas Public Service Commission.
ASU Accounting Standards Update issued by the Financial Accounting Standards Board.Standard Update.
CAA Clean Air Act.
CLECOCentral Louisiana Electric Company, a nonaffiliated utility company.
CO2
 Carbon Dioxide.Dioxide and other greenhouse gases.
Cook Plant Donald C. Cook Nuclear Plant, a two-unit, 2,1102,191 MW nuclear plant owned by I&M.
CSPCo Columbus Southern Power Company, an AEP electric utility subsidiary.
CSWCentral and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the legal name of Central and South West Corporation was changed to AEP Utilities, Inc.).
CSW Operating AgreementAgreement, dated January 1, 1997, by and among PSO, SWEPCo, TCC and TNC governing generating capacity allocation.  This agreement was amended in May 2006 to remove TCC and TNC.  AEPSC acts as the agent.
CTC Competition Transition Charge.
CWIP Construction Work in Progress.
DETMDuke Energy Trading and Marketing L.L.C., a risk management counterparty.
DHLC Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo that is a consolidated variable interest entity.SWEPCo.
E&R Environmental compliance and transmission and distribution system reliability.
EaREarnings at Risk, a method to quantify risk exposure.
EIS Energy Insurance Services, Inc., a protected cellnonaffiliated captive insurance company that is a consolidated variable interest entity.
EITFFinancial Accounting Standards Board’s Emerging Issues Task Force.
EITF 06-10EITF Issue No. 06-10 “Accounting for Collateral Assignment Split-Dollar Life Insurance Arrangements.”
ENECExpanded Net Energy Cost.
EPSEarnings Per Share.company.
ERCOT Electric Reliability Council of Texas.
ERISAEmployee Retirement Income Security Act of 1974, as amended.
ESP Electric Security Plan.Plans, filed with the PUCO, pursuant to the Ohio Amendments.
ETT Electric Transmission Texas, LLC, a 50%an equity interest joint venture withbetween AEP Utilities, Inc. and MidAmerican Energy Holdings Company Texas Transco, LLC formed to own and operate electric transmission facilities in ERCOT.
FAC Fuel Adjustment Clause.
FASB Financial Accounting Standards Board.
Federal EPA United States Environmental Protection Agency.
FERC Federal Energy Regulatory Commission.
FSPFGD FASB Staff Position.
FSP SFAS 107-1 and APB 28-1FSP SFAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments.”Flue Gas Desulfurization or Scrubbers.
FTR Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP Accounting Principles Generally Accepted in the United States of America.
GHGGreenhouse gases.
I&M Indiana Michigan Power Company, an AEP electric utility subsidiary.
IGCC Integrated Gasification Combined Cycle, technology that turns coal into a cleaner-burning gas.
Interconnection Agreement Agreement, dated July 6, 1951, as amended, by and among APCo, CSPCo, I&M, KPCo and OPCo, defining the sharing of costs and benefits associated with their respective generating plants.
IRS Internal Revenue Service.
IURC Indiana Utility Regulatory Commission.
JBRJet Bubbling Reactor.
JMGJMG Funding LP.
KGPCo Kingsport Power Company, an AEP electric distribution subsidiary.
KPCo Kentucky Power Company, an AEP electric utility subsidiary.
KPSCKentucky Public Service Commission.
kV Kilovolt.
KWH Kilowatthour.
LPSC Louisiana Public Service Commission.
MISO Midwest Independent Transmission System Operator.
MLR Member load ratio, the method used to allocate AEP Power Pool transactions to its members.
MMBtu Million British Thermal Units.
MPSCMichigan Public Service Commission.
MTM Mark-to-Market.
MW Megawatt.
MWH Megawatthour.
NEILNuclear Electric Insurance Limited.
NOx
 Nitrogen oxide.
Nonutility Money Pool AEP Consolidated’sAEP’s Nonutility Money Pool.
NSR New Source Review.
OCC Corporation Commission of the State of Oklahoma.
OPCo Ohio Power Company, an AEP electric utility subsidiary.
OPEB Other Postretirement Benefit Plans.
OTC Over the counter.
OVEC Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
PATHPotomac Appalachian Transmission Highline, LLC and its subsidiaries, a joint venture with Allegheny Energy Inc. formed to own and operate electric transmission facilities in PJM.
PJM Pennsylvania – New Jersey – Maryland regional transmission organization.
PMParticulate Matter.
PSO Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO Public Utilities Commission of Ohio.
PUCT Public Utility Commission of Texas.
REPTexas Retail Electric Provider.
Registrant Subsidiaries AEP subsidiaries which are SEC registrants; APCo, CSPCo, I&M, OPCo, PSO and SWEPCo.
Risk Management Contracts Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana, owned by AEGCo and I&M.
RSPRate Stabilization Plan.
RTO Regional Transmission Organization.
S&P Standard and Poor’s.
SECSabine United States Securities and Exchange Commission.Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity.
SECASeams Elimination Cost Allocation.
SEETSignificant Excess Earnings Test.
SFASStatement of Financial Accounting Standards issued by the Financial Accounting Standards Board.
SFAS 157Statement of Financial Accounting Standards No. 157, “Fair Value Measurements.”
SIA System Integration Agreement.
SNF Spent Nuclear Fuel.
SO2
 Sulfur Dioxide.
SPP Southwest Power Pool.
Stall Unit J. Lamar Stall Unit at Arsenal Hill Plant.
SWEPCo Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC AEP Texas Central Company, an AEP electric utility subsidiary.
TEMSUEZ Energy Marketing NA, Inc. (formerly known as Tractebel Energy Marketing, Inc.).
Texas Restructuring   Legislation Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC AEP Texas North Company, an AEP electric utility subsidiary.
True-up Proceeding A filing made under the Texas Restructuring Legislation to finalize the amount of stranded costs and other true-up items and the recovery of such amounts.
Turk Plant John W. Turk, Jr. Plant.
Utility Money Pool AEP System’s Utility Money Pool.
VaRValue at Risk, a method to quantify risk exposure.
VIE Variable Interest Entity.
Virginia SCC Virginia State Corporation Commission.
WPCo Wheeling Power Company, an AEP electric distribution subsidiary.
WVPSC Public Service Commission of West Virginia.

 
 
 

FORWARD-LOOKING INFORMATION

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

·The economic climate and growth in, or contraction within, our service territory and changes in market demand and demographic patterns.
·Inflationary or deflationary interest rate trends.
·Volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impairing our ability to finance new capital projects and refinance existing debt at attractive rates.
·The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material.
·Electric load and customer growth.
·Weather conditions, including storms.storms, and our ability to recover significant storm restoration costs through applicable rate mechanisms.
·Available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.
·Availability of necessary generating capacity and the performance of our generating plants including ourplants.
·Our ability to restorerecover I&M’s Donald C. Cook Nuclear Plant Unit 1 in a timely manner.restoration costs through warranty, insurance and the regulatory process.
·Our ability to recover regulatory assets and stranded costs in connection with deregulation.
·Our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.
·Our ability to build or acquire generating capacity, including the Turk Plant, and transmission line facilities (including our ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs (including the costs of projects that are cancelled) through applicable rate cases or competitive rates.
·New legislation, litigation and government regulation, including requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances or additional regulation of fly ash and similar combustion products that could impact the continued operation and cost recovery of our plants.
·Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions (including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance).
·Resolution of litigation (including theour dispute with Bank of America).
·Our ability to constrain operation and maintenance costs.
·Our ability to develop and execute a strategy based on a view regarding prices of electricity, natural gas and other energy-related commodities.
·Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market.
·Actions of rating agencies, including changes in the ratings of debt.
·Volatility and changes in markets for electricity, natural gas, coal, nuclear fuel and other energy-related commodities.
·Changes in utility regulation, including the implementation of the recently passed utility lawESPs and related regulation in Ohio and the allocation of costs within regional transmission organizations, including PJM and SPP.
·Accounting pronouncements periodically issued by accounting standard-setting bodies.
·The impact of volatility in the capital markets on the value of the investments held by our pension, other postretirement benefit plans and nuclear decommissioning trust and the impact on future funding requirements.
·Prices and demand for power that we generate and sell at wholesale.
·Changes in technology, particularly with respect to new, developing or alternative sources of generation.
·Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes and other catastrophic events.
·Our ability to recover through rates the remaining unrecovered investment, if any, in generating units that may be retired before the end of their previously projected useful lives.

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

 
 
 

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

EXECUTIVE OVERVIEW

Economic SlowdownConditions

OurIn comparing first quarter 2010 results to the prior year, retail margins increased due to rate increases in various jurisdictions and higher residential anddemand for electricity as a result of favorable weather.  Additionally, margins from off-system sales increased in 2010 primarily due to higher physical sales in our eastern region reflecting favorable generation availability.  These margins were partially offset by lower commercial KWH sales appeardue to be relatively stable; nevertheless, some segmentscontinued weaknesses in the economy and lower industrial KWH sales due to reduced operations by several of our service territories are experiencing slowdowns.  Welargest industrial customers.
Company-wide Staffing and Budget Review

Due to the continued slow recovery in the U.S. economy and a corresponding negative impact on energy consumption, we are currently monitoring the following trends:conducting initiatives to achieve workforce reductions and significantly reduce other operation and maintenance spending.  Achieving these goals will involve identifying process improvements, streamlining organizational designs and developing other efficiencies that can deliver additional sustainable savings.

·
Margins from Off-system Sales - Margins from off-system sales continue to decrease due to reductions in sales volumes and weak market power prices, reflecting reduced overall demand for electricity.  For the first nine months of 2009 in comparison to the first nine months of 2008, off-system sales volumes decreased by 58%.
·
Industrial KWH Sales - Industrial KWH sales for both the three months and nine months ended September 30, 2009 were down 17%.  Approximately half of the decrease in the first nine months of 2009 was due to cutbacks or closures by 10 of our large metals producing customers.  We also experienced continued significant decreases in KWH sales to customers in the transportation, plastics, rubber and paper manufacturing industries.
·
Risk of Loss of Major Industrial Customers - We maintain close contact with each of our major industrial customers individually with respect to their expected electric needs.  We factor our industrial customer analyses into our operational planning.  In September 2009, Ormet, a major industrial customer currently operating at a reduced load of approximately 330 MW (Ormet operated at an approximate 500 MW load in 2008), announced that it will continue operations at this reduced level at least through the end of 2009.

Regulatory Activity

Our significant 20092010 rate proceedings include:

·
Kentucky – In December 2009, KPCo filed a base rate case with the KPSC to increase base revenues by $124 million annually based on an 11.75% return on common equity.  In April 2010, the Kentucky Industrial Utility Customers recommended an annual base revenue increase of no more than $41 million.  New rates are expected to become effective in July 2010.
ArkansasMichigan -– In September 2009, SWEPCo reachedJanuary 2010, I&M filed for a rate change settlement agreement that provides for an $18$63 million increase in annual Michigan base rates based on an 11.75% return on common equity.  I&M can request interim rates, subject to refund, after six months.  The MPSC must issue a final order within one year.
Ohio – Ohio law requires the PUCO to determine, following the end of each year of the ESP, if rate adjustments included in the ESP resulted in significantly excessive earnings.  If the rate adjustments, in the aggregate, result in significantly excessive earnings, the excess amount would be returned to customers.  The PUCO’s decision determining a methodology is not expected to be finalized until a filing is made by CSPCo and OPCo in 2010 related to 2009 earnings and the PUCO issues an order thereon.  As a result, CSPCo and OPCo are unable to determine whether they will be required to return any of their Ohio revenues based uponto customers.
Oklahoma – In 2009, the OCC approved PSO’s Capital Reliability Rider (CRR) filing which requires PSO to file a base rate case no later than July 2010.
Texas – In April 2010, a settlement was approved by the PUCT to increase SWEPCo’s base rates by approximately $15 million annually, effective May 2010, including a return on equity of 10.25% and a decrease in annual depreciation rates of $10 million.  The combination of these factors should contribute an additional $28 million in annual pretax income to SWEPCo annually.10.33%.  The settlement agreement also includesallows SWEPCo a separate$10 million one-year surcharge rider of approximately $11 million annually for the recovery of carryingto recover additional vegetation management costs depreciation and operation and maintenance expenses on the Stall Unit once it is placed in service as expected in mid-2010.  Approval of the settlement by the APSC is expected in the fourth quarter of 2009.that SWEPCo must spend within two years.
 
·
Indiana - In March 2009, the IURC approved a modified rate settlement agreement that provides for an annual increase in revenues of $42 million, including a $19 million increase in revenue from base rates and $23 million in additional tracker revenues for certain incurred costs, subject to true-up.
·
Ohio - In March 2009, and as amended in July 2009, the PUCO issued an order that modified and approved CSPCo’s and OPCo’s ESP filings.  Among other things, the ESP order authorized capped increases to revenues during the three-year ESP period and also authorized a fuel adjustment clause (FAC) which allows CSPCo and OPCo to phase-in and defer actual FAC costs incurred in excess of the caps, that will be trued-up, subject to annual caps.  The projected revenue increases for CSPCo and OPCo are listed below:

 Projected Revenue Increases 
 2009 2010 2011 
 (in millions) 
CSPCo $94  $109  $116 
OPCo  103   125   153 
In addition to the revenue increases, net income will be positively affected by the material noncash FAC deferrals from 2009 through 2011.  These deferrals will be collected through a non-bypassable surcharge from 2012 through 2018.
·
Oklahoma - In October 2009, all but two of the parties to PSO’s Capital Reliability Rider filing agreed to a stipulation that was filed with the OCC for PSO to collect no more than $30 million under the CRR on an annual basis beginning January 2010 until PSO’s next base rate order.
·
Texas - In August 2009, SWEPCo filed a rate case with the PUCT to increase non-fuel base rates by approximately $75 million annually including return on equity of 11.5%.  The filing includes financing cost riders of $32 million related to construction of the Stall Unit and Turk Plant, a vegetation management rider of $16 million and other requested increases of $27 million.  The proposed filing would increase SWEPCo’s annual pretax income by approximately $51 million.
·
Virginia -– In July 2009, APCo requestedfiled a generation and distribution base rate increase with the Virginia SCC of $169$154 million annually (later adjusted to $154 million) based on a 13.35% return on common equity.  The newVirginia SCC staff and intervenors have recommended revenue increases ranging from $33 million to $94 million.  Interim rates, will become effective, subject to refund, became effective in December 2009 but were discontinued in February 2010 when Virginia newly enacted legislation suspended the collection of interim rates.  The Virginia SCC is required to issue a final order no later than December 2009.July 2010 with new rates effective August 2010.
 
In August 2009, the Virginia SCC issued an order which provides for a $130 million fuel revenue increase.  If actual fuel costs are greater or less than the projected fuel costs, APCo will seek appropriate adjustments in APCo’s next fuel factor proceeding.
·
West Virginia - In September 2009,– APCo provided notice to the WVPSC issued an order granting a $355 million increase over a four-year phase-in period.  The order lowered annual coal cost projections by $27 million and deferred recovery of unrecovered ENEC deferrals related to price increases on certain renegotiated coal contracts.  The WVPSC indicated that it would review the prudency of these additional costs in the next ENEC proceeding and APCo will adjust rates appropriately.intends to file a base rate case during 2010.
2010 Health Care Legislation

Mountaineer Carbon CaptureThe Patient Protection and Storage Project

In January 2008, APCoAffordable Care Act and ALSTOM Power, Inc., an unrelated third party, entered into an agreement to jointly construct a CO2 capture demonstration facility.  APCothe related Health Care and Education Reconciliation Act (Health Care Acts) were enacted in March 2010.  The Health Care Acts amend tax rules so that the portion of employer health care costs that are reimbursed by the Medicare Part D prescription drug subsidy will also construct and ownno longer be deductible by the necessary facilities to store CO2.  APCo’s combined estimated costemployer for its necessary storage facilities and its sharefederal income tax purposes effective for years beginning after December 31, 2012.  Because of the CO2 capture demonstration facility is $74 million.  In September 2009, the capture portionloss of the project was placed into service andfuture tax deduction, a reduction in October 2009, APCo started injecting CO2 successfully in underground storage.

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

Turk Plant

In August 2006, SWEPCo announced plans to build the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas.  SWEPCo submitted filings with the APSC, the PUCT and the LPSC seeking certification of the plant.  SWEPCo owns 73% of the Turk Plant and will operate the completed facility.

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

In November 2008, SWEPCo received the required air permit approval from the Arkansas Department of Environmental Quality and commenced construction at the site.  In December 2008, certain parties filed an appeal of the air permit approval with the Arkansas Pollution Control and Ecology Commission (APCEC).  The APCEC decision is still pending and not expected until 2010.  These same parties have filed a petition with the Federal EPA to review the air permit.  The petition will be acted on by December 2009, accordingdeferred tax asset related to the termsnondeductible OPEB liabilities accrued to date was recorded in March 2010.  This reduction did not materially affect our cash flows or financial condition.  For the three months ended March 31, 2010, deferred tax assets decreased $56 million, partially offset by recording net tax regulatory assets of a recent settlement between the petitioners and the Federal EPA.  The Turk Plant cannot be placed in service without an air permit.

Pension Trust Fund

Recent recovery$35 million in our pension asset values and the IRS modificationjurisdictions with regulated operations, resulting in a decrease in net income of interest calculation rules reduced our estimated 2010 contribution for both qualified and nonqualified pension plans to $62 million from our previously disclosed estimated contribution of $453$21 million.  The present estimated contribution for both qualified and nonqualified pension plans for 2011 is $389 million.  These estimates may vary significantly based on market returns, changes in actuarial assumptions, management discretion to contribute more than the minimum requirement and other factors.

Risk Management Contracts

We have risk management contracts with numerous counterparties.  Since open risk management contracts are valued based on changes in market prices of the related commodities, our exposures change daily. Our risk management organization monitors these exposures on a daily basis to limit our economic and financial statement impact on a counterparty basis.  At September 30, 2009, our credit exposure net of collateral was approximately $886 million of which approximately 88% is to investment grade counterparties.  At September 30, 2009, our exposure to financial institutions was $26 million (all investment grade), which represents 3% of our total credit exposure net of collateral.

Capital Expenditures

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

Fuel Inventory

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

RESULTS OF OPERATIONS

SegmentsSEGMENTS

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

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

AEP River Operations
·Commercial barging operations that annually transport approximately 33 million tons of coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers.

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

The table below presents our consolidated Net Income Before Discontinued Operations and Extraordinary Loss by segment for the three and nine months ended September 30, 2009March 31, 2010 and 2008.2009.
 
Three Months Ended September 30, Nine Months Ended September 30, Three Months Ended March 31, 
2009 2008 2009 2008 2010 2009 
(in millions) (in millions) 
Utility Operations $448  $359  $1,121  $1,036  $344  $346 
AEP River Operations  10   11   22   21   3   11 
Generation and Marketing  5   16   33   43   10   24 
All Other (a)  (17)  (10)  (45)  133   (11)  (18)
Income Before Discontinued Operations and Extraordinary Loss $446  $376  $1,131  $1,233 
Net Income $346  $363 

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

AEP ConsolidatedCONSOLIDATED

ThirdFirst Quarter of 20092010 Compared to ThirdFirst Quarter of 20082009

Net Income Before Discontinued Operations and Extraordinary Loss in 2009 increased $702010 decreased $17 million compared to 20082009 primarily due to an increasethe impact of OPEB taxes recorded in Utility Operations segment earningsthe first quarter of $89 million.  The increase in Utility Operations segment net income primarily relates2010 related to rate increases in our Indiana, Ohio, Oklahoma and Virginia service territories partially offset by lower retail sales volumes as well as lower off-system sales margins due to lower sales volumes and lower market prices.the tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits.

Average basic shares outstanding increased to 477478 million in 2010 from 407 million in 2009 from 402 million in 2008 primarily due to the April 2009 issuance of 69 million shares of AEP common stock.stock in April 2009.  Actual shares outstanding were 477479 million as of September 30, 2009.

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

Income Before Discontinued Operations and Extraordinary Loss in 2009 decreased $102 million compared to 2008 primarily due to income of $164 million (net of tax) in 2008 from the cash settlement of a power purchase and sale agreement with TEM.  For our Utility Operations segment, Income Before Discontinued Operations and Extraordinary Loss increased $85 million primarily due to rate increases in our Indiana, Ohio, Oklahoma and Virginia service territories partially offset by lower retail sales volumes as well as lower off-system sales margins due to lower sales volumes and lower market prices.

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

Utility OperationsMarch 31, 2010.

Our Utility Operations segment primarily includes regulated revenues with direct and variable offsetting expenses and net reported commodity trading operations.  results of operations are discussed below by operating segment.

UTILITY OPERATIONS

We believe that a discussion of the results from our Utility Operations segment on a gross margin basis is most appropriate in order to further understand the key drivers of the segment.  Gross margin represents utility operating revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power.

 Three Months Ended 
 
Three Months Ended
September 30,
  
Nine Months Ended
September 30,
  March 31, 
 2009  2008  2009  2008  2010  2009 
 (in millions)  (in millions) 
Revenues $3,389  $3,968  $9,712  $10,575  $3,426  $3,267 
Fuel and Purchased Power  1,145   1,841   3,337   4,428   1,247   1,196 
Gross Margin  2,244   2,127   6,375   6,147   2,179   2,071 
Depreciation and Amortization  412   379   1,173   1,099   398   373 
Other Operating Expenses  988   1,034   2,975   3,001   1,040   994 
Operating Income  844   714   2,227   2,047   741   704 
Other Income, Net  42   47   97   138   43   30 
Interest Expense  232   224   679   650   235   220 
Income Tax Expense  206   178   524   499   205   168 
Income Before Discontinued Operations and Extraordinary Loss $448  $359  $1,121  $1,036 
        
Net Income $344  $346 

Summary of KWH Energy Sales
For for Utility Operations
For the Three and Nine Months Ended September 30,March 31, 2010 and 2009 and 2008

Three Months Ended
September 30,
 
Nine Months Ended
September 30,
Energy/Delivery Summary2009 2008 2009 2008  2010  2009 
(in millions of KWH)  (in millions of KWH) 
Retail:       Retail:      
Residential15,967  15,965  44,731  44,986 Residential  17,774   16,371 
Commercial13,569  13,731  37,773  38,099 Commercial  11,475   11,610 
Industrial13,641  16,409  40,564  48,915 Industrial  13,381   13,522 
Miscellaneous800   846  2,289  2,381 Miscellaneous  713   719 
Total Retail (a)43,977  46,951  125,357  134,381 Total Retail (a)  43,343   42,222 
                
Wholesale8,289  13,165  22,233  35,904 Wholesale  8,137   6,774 
                
Total KWHs52,266   60,116  147,590  170,285 Total KWHs  51,480   48,996 

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

Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.  In general, degree day changes in our eastern region have a larger effect on net income than changes in our western region due to the relative size of the two regions and the associated number of customers within each.  Cooling degree days and heating degree days in our service territory for the three and nine months ended September 30, 2009 and 2008 were as follows:
each region.
Summary of Heating and Cooling Degree Days for Utility Operations
For the Three and Nine Months Ended September 30,March 31, 2010 and 2009 and 2008

Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 2010  2009 
2009 2008 2009 2008 (in degree days) 
(in degree days)
Weather Summary       
Eastern Region             
Actual – Heating (a)6  -  2,062  1,966   1,900   1,820 
Normal – Heating (b)7  7  1,969  1,950   1,741   1,791 
               
Actual – Cooling (c)509  659  813  936   -   5 
Normal – Cooling (b)703  687  993  969   3   3 
               
Western Region (d)
       
Western Region
        
Actual – Heating (a)-  -  902  981   759   513 
Normal – Heating (b)2  2  941  967   574   579 
               
Actual – Cooling (c)1,170  1,251  1,878  1,955 
Actual – Cooling (d)  20   99 
Normal – Cooling (b)1,401  1,402  2,080  2,074   58   56 

(a)Eastern regionRegion and western regionWestern 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 regionRegion cooling degree days are calculated on a 65 degree temperature base.
(d)Western region statistics representRegion cooling degree days are calculated on a 65 degree temperature base for PSO/SWEPCo customerand a 70 degree temperature base only.for TCC/TNC.

Third
First Quarter of 20092010 Compared to ThirdFirst Quarter of 20082009

Reconciliation of ThirdFirst Quarter 2009 to First Quarter of 2008 to Third Quarter of 20092010
Net Income from Utility Operations Before Discontinued Operations and Extraordinary Loss
(in millions)

Third Quarter of 2008    $359 
First Quarter of 2009    $346 
              
Changes in Gross Margin:              
Retail Margins  281       169     
Off-system Sales  (226)      12     
Transmission Revenues  10       10     
Other Revenues  52       (83)    
Total Change in Gross Margin      117       108 
                
Total Expenses and Other:                
Other Operation and Maintenance  52       (37)    
Gain on Sales of Assets, Net  (2)    
Depreciation and Amortization  (33)      (25)    
Taxes Other Than Income Taxes  (4)      (9)    
Interest and Investment Income  (8)      (3)    
Carrying Costs Income  (9)      5     
Allowance for Equity Funds Used During Construction  12       8     
Interest Expense  (8)      (15)    
Equity Earnings of Unconsolidated Subsidiaries  3     
Total Expenses and Other      -       (73)
                
Income Tax Expense      (28)      (37)
                
Third Quarter of 2009     $448 
First Quarter of 2010     $344 

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·Retail Margins increased $281$169 million primarily due to the following:
 ·An $87A $52 million increase related to the PUCO’s approval of our Ohio ESPs, a $43 millionan increase related to basein interim rates in Virginia and the recovery of E&R costs in Virginia and construction financing costs in West Virginia, a $22$31 million increase related to the PUCO’s approval of our Ohio ESPs, a $12 million net rate increase for I&M, an $11 million increase in base rates in Oklahoma and a $7$22 million netof rate increase for I&M.increases in our other jurisdictions.
 ·A $151$38 million increase in fuel margins in Ohioweather-related usage primarily due to the deferral of fuel costs by CSPCoa 4% increase in heating degree days in our eastern region and OPCoa 48% increase in 2009.  The PUCO’s March 2009 approval of CSPCo’s and OPCo’s ESPs allows for the deferral and recovery of fuel and related costs during the ESP period.  See “Ohio Electric Security Plan Filings” section of Note 3.heating degree days in our western region.
 ·A $90$20 million increase resultingin fuel margins due to higher fuel and purchased power costs recorded in 2009 related to the Cook Plant Unit 1 shutdown.  This increase in fuel margins was offset by a corresponding decrease in Other Revenues as discussed below.
·These increases were offset by a $37 million decrease in non-weather usage due to reduced operations by several significant industrial customers, reduced usage by commercial customers due to difficult economic conditions and the termination of an I&M unit power agreement.
·Margins from reduced sharing of off-systemOff-system Sales increased $12 million primarily due to higher physical sales margins with retail customersvolumes in our eastern service territoryregion reflecting favorable generation availability.
·Transmission Revenues increased $10 million primarily due to aincreased revenues in the ERCOT, PJM and SPP regions.
·Other Revenues decreased $83 million primarily due to the Cook Plant accidental outage insurance proceeds of $54 million in the first quarter of 2009.  I&M reduced customer bills by approximately $20 million in the first quarter of 2009 for the cost of replacement power during the outage period.  This decrease in total off-system sales.revenues was offset by a corresponding increase in Retail Margins as discussed above.  Other Revenues also decreased due to lower gains on sales of emission allowances of $19 million.

Total Expenses and Other and Income Tax Expense changed between years as follows:

·Other Operation and Maintenance expenses increased $37 million primarily due to the following:
·A $26 million increase in demand side management, energy efficiency and vegetation management programs.
·A $23 million increase in transmission expenses, including base transmission work, RTO fees and transmission service expenses.
·A $19 million increase in system improvements, reliability and other distribution expenses.
·A $14 million increase in administrative and general expenses primarily for employee benefits.
·A $5 million increase in plant outage and other plant operating and maintenance expenses.
 These increases were partially offset by:
 ·A $61$35 million decrease in margins from industrial sales due to reduced operating levels and suspended operations by certain large industrial customers in our service territories.
·A $42 million decrease in usage primarily due to a 23% decrease in cooling degree days in our eastern region.
·A $19 million decrease in fuel margins due to higher fuel and purchased power costs related to the Cook Plant Unit 1 shutdown.  This decrease in fuel margins was offset by a corresponding increase in Other Revenues as discussed below.
·Margins from Off-system Sales decreased $226 million primarily due to lower physical sales volumes and lower margins in our eastern service territory reflecting lower market prices, partially offset by higher trading and marketing margins.
·Transmission Revenues increased $10 million primarily due to increased rates in the ERCOT and SPP regions.
·Other Revenues increased $52 million primarily due to Cook Plant accidental outage insurance policy proceeds of $46 million.  Of these insurance proceeds, $19 million were used to reduce customer bills.  This increase in revenues was offset by a corresponding decrease in Retail Margins as discussed above.  See “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.

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

·Other Operation and Maintenance expenses decreased $52 million primarily due to the following:
·A $37 million decrease in storm restoration expenses.
 ·A $23$15 million decrease in plant operating and maintenance expenses.
·A $10 million decrease in transmission expense including lower forestry expenses, RTO fees and reliability expenses.
·An $8 million decrease related to the establishment of a regulatory asset in Virginia for the deferral of transmission costs.
·A $7 million decrease in customer service expenses.
These decreases were partially offset by:
·A $30 million increase in administrative and general expenses, primarily employee medical expenses.
·An $11 million increase in distribution reliabilitylow income assistance programs and other expenses.customer accounts expense.
·Depreciation and Amortization increased $33$25 million primarily due to higher depreciable property balances as the result ofnew environmental improvements placed in service at OPCo and various other increases in depreciable property additions and higher depreciation rates for OPCo related to shortened depreciable lives for certain generating facilities.balances.
·Interest and InvestmentTaxes Other Than Income decreased $8 million primarily due to the 2008 favorable effect of interest income related to federal income tax refunds filed with the IRS.
·Carrying Costs Income decreasedTaxes increased $9 million primarily due to the completion of reliability deferralsincreases in Virginia in December 2008property and the decrease of environmental deferrals in Virginia in 2009.other taxes.
·Allowance for Equity Funds Used During Construction increased $12$8 million as a result ofrelated to construction projects at SWEPCo’s Turk Plant and Stall Unit and the reapplication of “Regulated Operations” accounting guidance for the generation portion of SWEPCo’s Texas retail jurisdiction effective Aprilthe second quarter of 2009.  See “Texas Rate Matters – Texas Restructuring – SPP” section of Note 3.
·Interest Expense increased $8$15 million primarily due to increasedan increase in long-term debt.debt and a decrease in the debt component of AFUDC due to lower CWIP balances at APCo, CSPCo and OPCo.
·Income Tax Expense increased $28 million primarily due to an increase in pretax income, partially offset by state income taxes and changes in certain book/tax differences accounted for on a flow-through basis.

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

Reconciliation of Nine Months Ended September 30, 2008 to Nine Months Ended September 30, 2009
Income from Utility Operations Before Discontinued Operations and Extraordinary Loss
(in millions)

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

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·Retail Margins increased $570 million primarily due to the following:
·A $183 million increase related to the PUCO’s approval of our Ohio ESPs, a $147 million increase related to base rates and recovery of E&R costs in Virginia and construction financing costs in West Virginia, a $63 million increase in base rates in Oklahoma and a $32 million net rate increase for I&M.
·A $207 million increase resulting from reduced sharing of off-system sales margins with retail customers in our eastern service territory due to a decrease in total off-system sales.
·A $199 million increase in fuel margins in Ohio due to the deferral of fuel costs by CSPCo and OPCo in 2009.  The PUCO’s March 2009 approval of CSPCo’s and OPCo’s ESPs allows for the deferral and recovery of fuel and related costs during the ESP period.  See “Ohio Electric Security Plan Filings” section of Note 3.
These increases were partially offset by:
·A $150 million decrease in margins from industrial sales due to reduced operating levels and suspended operations by certain large industrial customers in our service territories.
·A $59 million decrease in fuel margins due to higher fuel and purchased power costs related to the Cook Plant Unit 1 shutdown.  This decrease in fuel margins was offset by a corresponding increase in Other Revenues as discussed below.
·A $34 million decrease in usage primarily due to a 13% decrease in cooling degree days in our eastern region.
·A $29 million decrease related to favorable coal contract amendments in 2008.
·Margins from Off-system Sales decreased $517 million primarily due to lower physical sales volumes and lower margins in our eastern service territory reflecting lower market prices, partially offset by higher trading and marketing margins.
·Transmission Revenues increased $22 million primarily due to increased rates in the ERCOT and SPP regions.
·Other Revenues increased $153 million primarily due to Cook Plant accidental outage insurance policy proceeds of $145 million.  Of these insurance proceeds, $59 million were used to reduce customer bills.  This increase in revenues was offset by a corresponding decrease in Retail Margins as discussed above.  See “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.

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

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

AEP River OperationsRIVER OPERATIONS

ThirdFirst Quarter of 20092010 Compared to ThirdFirst Quarter of 20082009

Net Income Before Discontinued Operations and Extraordinary Loss from our AEP River Operations segment decreased from $11 million in 20082009 to $10$3 million in 20092010 primarily due to lower revenues as a resultreduced grain loadings, higher fuel and other operating expenses and the recording of a weak import market.

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

Income Before Discontinued Operations and Extraordinary Loss from our AEP River Operations segment increased from $21 million in 2008 to $22 million in 2009 primarily due to lower fuel costs and gainsgain on the sale of two older towboats.  These increases were partially offset by lower revenues as a result of a weak import market.towboats in 2009.

Generation and MarketingGENERATION AND MARKETING

ThirdFirst Quarter of 20092010 Compared to ThirdFirst Quarter of 20082009

Net Income Before Discontinued Operations and Extraordinary Loss from our Generation and Marketing segment decreased from $16 million in 2008 to $5$24 million in 2009 to $10 million in 2010 primarily due to lower gross margins at the Oklaunion Plant as a resultreduced inception gains from ERCOT marketing activities partially offset by improved plant performance and hedging activities on our generation assets.

ALL OTHER

First Quarter of lower power prices in ERCOT.

Nine Months Ended September 30, 20092010 Compared to Nine Months Ended September 30, 2008First Quarter of 2009

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

All Other

Third Quarter of 2009 Compared to Third Quarter of 2008

Income Before Discontinued Operations and ExtraordinaryNet Loss from All Other decreased from a loss of $10$18 million in 20082009 to a loss of $17$11 million in 2009.

Nine Months Ended September 30, 2009 Compared2010 due to Nine Months Ended September 30, 2008

Income Before Discontinued Operations and Extraordinary Loss from All Other decreased from income of $133 million in 2008 to a loss of $45 million in 2009.  In 2008, we had after-tax income of $164 million from a litigation settlement of a power purchase and sale agreement with TEM.  The settlement was recorded as a pretax credit to Asset Impairments and Other Related Charges of $255 million in the accompanying Condensed Consolidated Statements of Income.lower Parent related expenses.

AEP System Income TaxesSYSTEM INCOME TAXES

First Quarter of 2010 Compared to First Quarter of 2009

Income Tax Expense increased $16$28 million in the thirdfirst quarter of 2009 compared to the third quarter of 20082010 primarily due to an increase in pretax book income, partially offset bythe regulatory accounting treatment of state income taxes, and changes in certainother book/tax differences which are accounted for on a flow-through basis.

Income Tax Expense decreased $73 million inbasis and the nine-month period ended September 30, 2009 compared totax treatment associated with the nine-month period ended September 30, 2008 primarily due to a decrease in pretax book income.future reimbursement of Medicare Part D retiree prescription drug benefits.

FINANCIAL CONDITION

We measure our financial condition by the strength of our balance sheet and the liquidity provided by our cash flows.  During the first quarter of 2010, we maintained our strong financial condition as reflected by our long-term debt issuances of $658 million primarily to fund our construction program and refinance debt maturities.

Debt and Equity Capitalization    
  September 30, 2009 December 31, 2008
  ($ in millions)
Long-term Debt, including amounts due within one year $17,253  56.2% $15,983  55.6%
Short-term Debt  352  1.1     1,976  6.9   
Total Debt  17,605  57.3     17,959  62.5   
Preferred Stock of Subsidiaries  61  0.2     61  0.2   
AEP Common Equity  13,064  42.5     10,693  37.2   
Noncontrolling Interests  -  -     17  0.1   
           
Total Debt and Equity Capitalization $30,730  100.0% $28,730  100.0%
DEBT AND EQUITY CAPITALIZATION
  March 31, 2010 December 31, 2009
  ($ in millions)
Long-term Debt, including amounts due within one year $17,534  54.8% $17,498  56.8%
Short-term Debt  1,063  3.3     126  0.4   
Total Debt  18,597  58.1     17,624  57.2   
Preferred Stock of Subsidiaries  61  0.2     61  0.2   
AEP Common Equity  13,324  41.7     13,140  42.6   
           
Total Debt and Equity Capitalization $31,982  100.0% $30,825  100.0%

Our ratio of debt-to-totaldebt to total capital decreasedincreased from 62.5%57.2% to 58.1% in 2008 to 57.3% in 2009the first quarter of 2010 primarily due to the issuancean increase in short-term debt of 69$651 million new common sharesas a result of a change in an accounting standard applicable to our sale of receivables agreement and the applicationan increase of the proceeds to reduce debt.$280 million in commercial paper outstanding.

LiquidityApproximately $1.1 billion of our $18 billion of outstanding long-term debt will mature during the remaining three quarters of 2010, excluding payments due for securitization bonds which we recover directly from ratepayers.  In 2009, OPCo issued $500 million of 5.375% senior unsecured notes which we used in April 2010 to pay $400 million of OPCo’s senior unsecured notes at maturity.  We issued $658 million of long-term debt during the first quarter of 2010.  We believe that our projected cash flows from operating activities are sufficient to support our ongoing operations.

LIQUIDITY

Liquidity, or access to cash, is an important factor in determining our financial stability.  We believe we have adequate liquidity under our existing credit facilities.  At September 30, 2009,March 31, 2010, we had $3.6 billion in aggregate credit facility commitments to support our operations.  Additional liquidity is available from cash from operations and a sale of receivables agreement.  We are committed to maintaining adequate liquidity.  We generally use short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged.  Sources of long-term funding include issuance of long-term debt, sale-leaseback or leasing agreements or common stock.

Capital Markets

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

Approximately $1.7 billion of our $17 billion of outstanding long-term debt will mature in 2010, excluding payments due for securitization bonds which we recover directly from ratepayers.  We intend to refinance or repay our debt maturities.  In September 2009, OPCo issued $500 million of 5.375% senior unsecured notes which may be used to pay at maturity some of its outstanding debt due in 2010.  We believe that our projected cash flows from operating activities are sufficient to support our ongoing operations.

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments.  At September 30, 2009,March 31, 2010, our available liquidity was approximately $3.6$3.3 billion as illustrated in the table below:
  Amount  Maturity
  (in millions)   
Commercial Paper Backup:     
Revolving Credit Facility $1,500  March 2011
Revolving Credit Facility  1,454 (a)April 2012
Revolving Credit Facility  627 (a)April 2011
Total  3,581   
Cash and Cash Equivalents  877   
Total Liquidity Sources  4,458   
Less: AEP Commercial Paper Outstanding  347   
Letters of Credit Issued  470   
       
Net Available Liquidity $3,641   

(a)Net of contractually terminated Lehman Brothers Bank’s commitment amount of $69 million.
  Amount Maturity
  (in millions)  
Commercial Paper Backup:    
Revolving Credit Facility $1,500 March 2011
Revolving Credit Facility  1,454 April 2012
Revolving Credit Facility  627 April 2011
Total  3,581  
Cash and Cash Equivalents  818  
Total Liquidity Sources  4,399  
Less:  AEP Commercial Paper Outstanding  399  
          Letters of Credit Issued  652  
      
Net Available Liquidity $3,348  

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

It is our intent to renew the March 2011 facility.  We are currently reviewing our options related to the April 2011 facility.

We use our commercial paper program to meet the short-term borrowing needs of our subsidiaries.  The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility subsidiaries.  In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons.  In 2009, we repaid the $2 billion borrowed under the credit facilities during 2008 primarily with proceeds from our equity offering.  The maximum amount of commercial paper outstanding during 2009the first quarter of 2010 was $614$429 million.  The weighted-average interest rate for our commercial paper during 20092010 was 0.63%0.32%.

Sales of Receivables

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

Our revolving credit agreements contain certain covenants and require us to maintain our percentage of debt to total capitalization at a level that does not exceed 67.5%.  The method for calculating our outstanding debt and other capital is contractually defined.defined in our revolving credit agreements.  At September 30, 2009,March 31, 2010, this contractually-defined percentage was 53.4%54.5%.  Nonperformance underof these covenants could result in an event of default under these credit agreements.  At September 30, 2009,March 31, 2010, we complied with all of the covenants contained in these credit agreements.  In addition, the acceleration of our payment obligations or the obligations of certain of our major subsidiaries prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million would cause an event of default under these credit agreements and in a majority of our non-exchange traded commodity contracts, which would permit the lenders and counterparties to declare the outstanding amounts payable.  However, a default under our non-exchange traded commodity contracts does not cause an event of default under our revolving credit agreements.

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

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders.  At September 30, 2009,March 31, 2010, we had not exceeded those authorized limits.

Dividend Policy and Restrictions

We have declared common stock dividends payable in cash in each quarter since July 1910, representing 398400 consecutive quarters.  The Board of Directors declared a quarterly dividend of $0.41$0.42 per share in October 2009.April 2010.  Future dividends may vary depending upon our profit levels, operating cash flow levelsflows and capital requirements, as well as financial and other business conditions existing at the time.  We have the option to defer interest payments on the AEP Junior Subordinated Debentures issued in March 2008 for one or more periods of up to 10 consecutive years per period.  During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, our common stock.  We believe that these restrictions will not have a material effect on our cashc ash flows, or financial condition or limit any dividend payments in the foreseeable future.

Credit Ratings

Our credit ratings as of September 30, 2009March 31, 2010 were as follows:

 Moody’s  S&P  Fitch
        
AEP Short-termShort Term DebtP-2  A-2  F-2
AEP Senior Unsecured DebtBaa2  BBB  BBB

In 2009,2010, Moody’s:

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

In 2009, Fitch:

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

If we receive a downgradeIn 2010, Fitch:

·Changed its rating outlook for TCC to stable from negative.

Downgrades in our credit ratings by anyone of the rating agencies listed above could increase our borrowing costs could increase and access to borrowed funds could be negatively affected.costs.

Cash FlowCASH FLOW

Managing our cash flows is a major factor in maintaining our liquidity strength.
Nine Months Ended Three Months Ended 
September 30, March 31, 
2009 2008 2010 2009 
(in millions) (in millions) 
Cash and Cash Equivalents at Beginning of Period $411  $178  $490  $411 
Net Cash Flows from Operating Activities  1,871   2,059   2   317 
Net Cash Flows Used for Investing Activities  (2,097)  (3,061)  (430)  (727)
Net Cash Flows from Financing Activities  692   1,162   756   709 
Net Increase in Cash and Cash Equivalents  466   160   328   299 
Cash and Cash Equivalents at End of Period $877  $338  $818  $710 

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

Operating Activities

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

Net Cash Flows from Operating Activities decreased in 2009 primarily due to a decline in net income and an increase in fuel inventory which should be recoverable through future fuel rates as the inventory is consumed.
 Three Months Ended 
 March 31, 
 2010 2009 
 (in millions) 
Net Income $346  $363 
Depreciation and Amortization  408   382 
Other  (752)  (428)
Net Cash Flows from Operating Activities $2  $317 

Net Cash Flows from Operating Activities were $1.9 billion$2 million in 2010 consisting primarily of Net Income of $346 million, $408 million of noncash Depreciation and Amortization offset by $752 million in Other.  Other includes a $656 million increase in securitized receivables under the application of new accounting guidance for “Transfers and Servicing” related to our sale of receivables agreement.  Other changes 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.  Significant changes in other items include an increase in under-recovered fuel primarily in Ohio and West Virginia and the favorable impact of decreases in fuel inventor y and tax receivables.  Deferred Income Taxes increased primarily due to the American Recovery and Reinvestment Act of 2009 extending bonus depreciation provisions, a change in tax accounting method and an increase in tax versus book temporary differences from operations.

Net Cash Flows from Operating Activities were $317 million in 2009 consisting primarily of Net Income of $1.1 billion$363 million and $1.2 billion$382 million of noncash depreciationDepreciation and amortization.Amortization.  Other representschanges 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.  Significant changes in other items include the negative impact on cash of an increase in coal inventory reflecting decreased customer demand for electricity as the result of the economic slowdown and unfavorable weather conditions and an increase in under-recovered fuel primarily in Ohio and West Virginia.
Net Cash Flows from Operating Activities were $2.1 billion in 2008 consisting primarily of Income Before Discontinued Operations of $1.2 billion and $1.1 billion of noncash depreciation and amortization.  Other represents items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  Significant changes in other items include an increase in under-recovered fuel reflecting higher coal and natural gas prices.

Investing Activities
Nine Months Ended Three Months Ended 
September 30, March 31, 
2009 2008 2010 2009 
(in millions) (in millions) 
Construction Expenditures $(2,123) $(2,576) $(609) $(897)
Purchases/Sales of Investment Securities, Net  (49)  (474)
Acquisitions of Nuclear Fuel  (153)  (99)
Acquisitions of Assets  (70)  (97)
Proceeds from Sales of Assets  258   83   139   172 
Other  40   102   40   (2)
Net Cash Flows Used for Investing Activities $(2,097) $(3,061) $(430) $(727)

Net Cash Flows Used for Investing Activities were $2.1 billion$430 million in 2010 primarily due to Construction Expenditures for new generation investment, environmental and distribution.  Proceeds from Sales of Assets in 2010 includes $135 million for sales of Texas transmission assets to ETT.

Net Cash Flows Used for Investing Activities were $727 million in 2009 and $3.1 billion in 2008 and primarily relatedue to Construction Expenditures for our new generation, environmental and distribution investment plan.  Proceeds from Sales of Assets in 2009 includes $104 million relating to the sale of a portion of Turk Plant to joint owners as planned and $95 million for sales of transmission assets in Texas to ETT based upon the original partner agreement.

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

Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather, legal reviews and the ability to access capital.  These construction expenditures will be funded through net income and financing activities.planned.

Financing Activities
Nine Months Ended Three Months Ended 
September 30, March 31, 
2009 2008 2010 2009 
(in millions) (in millions) 
Issuance of Common Stock, Net $1,706  $106  $26  $48 
Issuance/Retirement of Debt, Net  (371)  1,621   952   854 
Dividends Paid on Common Stock  (564)  (500)  (197)  (169)
Other  (79)  (65)  (25)  (24)
Net Cash Flows from Financing Activities $692  $1,162  $756  $709 

Net Cash Flows from Financing Activities were $756 million in 2010.  Our net debt issuances were $296 million. The net issuances included issuances of $500 million of senior unsecured notes and $158 million of pollution control bonds, a $280 million increase in commercial paper outstanding and retirements of $490 million of senior unsecured notes, $86 million of securitization bonds and $54 million of pollution control bonds.  Our short-term debt securitized by receivables increased $656 million under the application of new accounting guidance for “Transfers and Servicing” related to our sale of receivables agreement.  We paid common stock dividends of $197 million.

Net Cash Flows from Financing Activities in 2009 were $692$709 million.  Issuance of Common Stock, Net of $1.7 billion is comprised of our issuance of 69 million shares of common stock with net proceeds of $1.64 billion and additional shares through our dividend reinvestment, employee savings and incentive programs.  Our net debt retirements were $371 million. These retirements included a repayment of $2 billion outstanding under our credit facilities primarily from the proceeds of our common stock issuance and issuances of $1.6 billion of senior unsecured and debt notes and $327 million of pollution control bonds.  See Note 11 – Financing Activities for a complete discussion of long-term debt issuances and retirements.

Net Cash Flows from Financing Activities in 2008 were $1.2 billion.  Our net debt issuances were $1.6 billion.  These$854 million. The net issuances included net increasesissuances of $1.3 billion in$825 million of senior unsecured notes $642 million of short-term debt and $315 million of junior subordinated debentures.  These net increases in outstanding debt were partially offset by a net reacquisition of $370$134 million of pollution control bonds and retirements of $53 million of mortgage notes and $125$84 million of securitization bonds.  We paid common stock dividends of $169 million.

Off-balance Sheet ArrangementsThe following financing activities occurred or are expected to occur during 2010:

Under
·In April 2010, OPCo retired $400 million of its outstanding Senior Unsecured Notes.
·We will refinance an additional $700 million of the remaining long-term debt that will mature in 2010.

OFF-BALANCE SHEET ARRANGEMENTS

In prior periods, under a limited set of circumstances, we enterentered into off-balance sheet arrangements to acceleratefor various reasons including accelerating cash collections, reducereducing operational expenses and spreadspreading risk of loss to third parties.  Our current guidelines restrict the use of off-balance sheet financing entities or structures to traditional operating lease arrangements and salestransfers of customer accounts receivable that we enter in the normal course of business.  OurThe following identifies significant off-balance sheet arrangements  are as follows:arrangements:
September 30, December 31, 
2009 2008 
March 31,
2010
 
December 31,
2009
 
(in millions) (in millions)
AEP Credit Accounts Receivable Purchase Commitments $530  $650  $-  $631 
Rockport Plant Unit 2 Future Minimum Lease Payments  1,996   2,070   1,920   1,920 
Railcars Maximum Potential Loss From Lease Agreement  25   25   25   25 

Effective January 1, 2010, we record the receivables and debt related to AEP Credit on our Condensed Consolidated Balance Sheet.  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 20082009 Annual Report.

Summary Obligation InformationSUMMARY OBLIGATION INFORMATION

A summary of our contractual obligations is included in our 20082009 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in “Cash Flow” above and the drawdowns and standby letters of credit discussed in “Liquidity” above.

SIGNIFICANT FACTORS

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

Ohio Electric Security Plan Filings

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

The order provides a FAC for the three-year period of the ESP.  The FAC increase will be phased in to avoid having the resultant rate increases exceed the ordered annual caps described above.  The FAC increase before phase-in will be subject to quarterly true-ups to actual recoverable FAC costs and to annual accounting audits and prudency reviews.  The order allows CSPCo and OPCo to defer unrecovered FAC costs resulting from the annual caps/phase-in plan and to accrue carrying charges on such deferralsSeveral notices of appeal are outstanding at CSPCo’s and OPCo’s weighted average cost of capital.  The deferred FAC balance at the end of the three-year ESP period will be recovered through a non-bypassable surcharge over the period 2012 through 2018.  The FAC deferrals at September 30, 2009 were $36 million and $238 million for CSPCo and OPCo, respectively, inclusive of carrying charges at the weighted average cost of capital.

In August 2009, an intervenor filed for rehearing requesting, among other things, that the PUCO order CSPCo and OPCo to cease and desist from charging ESP rates, to revert to the rate stabilization plan rates and to compel a refund, including interest, of the amounts collected by CSPCo and OPCo.  CSPCo and OPCo filed a response stating the rates being charged by CSPCo and OPCo have been authorized by the PUCO and there was no basis for precluding CSPCo and OPCo from continuing to charge those rates.  In September 2009, certain intervenors filed appeals of the March 2009 order and the July 2009 rehearing entry with the Supreme Court of Ohio.  One of the intervenors, the Ohio Consumers’ Counsel, has asked the court to stay, pending the outcome of its appeal, a portion of the authorized ESP rates which the Ohio Consumers’ Counsel characterizes as being retroactive.  In October 2009, the Supreme Court of Ohio denied the Ohio Consumers' Counsel's request for a stay and granted motions to dismiss both appeals.
In September 2009, CSPCo and OPCo filed their initial quarterly FAC filing with the PUCO.  An order approving the FAC 2009 filings will not be issued until a financial audit and prudency review is performed by independent third parties and reviewed by the PUCO.

In October 2009, the PUCO convened a workshop to begin to determine the methodology for the Significantly Excessive Earnings Test (SEET).  The SEET requires the PUCO to determine, following the end of each year of the ESP, if rate adjustments included in the ESP resulted in significantly excessive earnings.  This will be determined by measuring whether the utility’s earned return on common equity is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, which have comparable business and financial risk.  In the March 2009 ESP order, the PUCO determined that off-system sales margins and FAC deferral phase-in credits should be excluded from the SEET methodology.  However, the July 2009 PUCO rehearing entry deferred those issues to the SEET workshop.  If the rate adjustments, in the aggregate, result in significantly excessive earnings, the excess amount would be returned to customers.  The PUCO’s decision on the SEET review of CSPCo’s and OPCo’s 2009 earnings is not expected to be finalized until the workshop is completed, the PUCO issues SEET guidelines, a SEET filing is made by CSPCo and OPCo in 2010 and the PUCO issues an order thereon. The SEET workshop will also determine whether CSPCo’s and OPCo’s earnings will be measured on an individual company basis or on a combined CSPCo/OPCo basis.

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

Management is unable to predict the outcome of the various ongoing proceedings and litigation discussed above including the SEET, the FAC filing review and the various appeals to the Supreme Court of Ohio relating to significant issues in the determination of the approved ESP order.  If these proceedings result in adverse rulings, it could haverates.  In addition, an adverse effect on future net income and cash flows.order is expected from the PUCO related to the SEET methodology.  See “Ohio Electric Security Plan Filings” section of Note 3.

Cook Plant Unit 1 Fire and Shutdown

In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in a fire on the electric generator.  This equipment, located in the turbine building, is separate and isolated from the nuclear reactor.  The turbine rotors that caused the vibration were installed in 2006 and are within the vendor’s warranty period.  The warranty provides for the repair or replacement of the turbine rotors if the damage was caused by a defect in materials or workmanship.  I&M is working with its insurance company, Nuclear Electric Insurance Limited (NEIL), and its turbine vendor, Siemens, to evaluate the extent of the damage resulting from the incident and facilitate repairs to return the unit to service.  Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $330$395 million.  Management believes that I&M should recover a significant portion of theserepair and replacement costs through the turbine vendor’s warranty, insurance and the regulatory process.  I&M is repairingrepaired Unit 1 to resumeand it resumed operations as early as the fourth quarter ofin December 2009 at slightly reduced power.  Should post-repair operations prove unsuccessful,The Unit 1 rotors were repaired and reinstalled due to the extensive lead time required to manufacture and install new turbine rotors.  As a result, the replacement of parts will extend the outage into 2011.

I&M maintains property insurance through NEIL with a $1 million deductible.  As of September 30, 2009, we recorded $122 million in Prepaymentsrepaired turbine rotors and Other Current Assets on our Condensed Consolidated Balance Sheets representing recoverable amounts under the property insurance policy.  Through September 30, 2009, I&M received partial payments of $72 million from NEILother equipme nt is scheduled for the cost incurred to date to repairUnit 1 planned outage in the property damage.

I&M also maintains a separate accidental outage policy with NEIL whereby, after a 12-week deductible period, I&M is entitled to weekly paymentsfall of $3.5 million for the first 52 weeks following the deductible period.  After the initial 52 weeks of indemnity, the policy pays $2.8 million per week for up to an additional 110 weeks.  I&M began receiving payments under the accidental outage policy in December 2008.  In 2009, I&M recorded $145 million in revenues and applied $59 million of the accidental outage insurance proceeds to reduce customer bills.
NEIL is reviewing claims made under the insurance policies to ensure that claims associated with the outage are covered by the policies.  The treatment of property damage costs, replacement power costs and insurance proceeds will be the subject of future regulatory proceedings in Indiana and Michigan.2011.  If the ultimate costs of the incident are not covered by warranty, insurance or through the related regulatory process or if the unit is not returned to service in a reasonable period of time or if any future regulatory proceedings are adverse, it could have an adverse impact on net income, cash flows and financial condition.  See “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.

Texas Restructuring Appeals

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

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

TCC,TCC. After a ruling from the PUCT and intervenors appealed theTexas District Court decision toand the Texas Court of Appeals.  In May 2008, the Texas Court of Appeals, affirmed the District Court decision in all but two major respects.  It reversed the District Court’s unfavorable decision which found that the PUCT erred by applying an invalid rule to determine the carrying cost rate.  It also determined that the PUCT erred by not reducing stranded costs by the “excess earnings” that had already been refunded to affiliated REPs.  Management does not believe that TCC will be adversely affected by the Court of Appeals ruling on excess earnings.  The favorable commercial unreasonableness judgment entered by the District Court was not reversed.  In June 2008, the Texas Court of Appeals denied intervenors’ motions for rehearing.  In August 2008, TCC, the PUCT and intervenors filed petitions for review with the Texas Supreme Court.  Review is discretionary and the Texas Supreme Court has not yet determined if it will grant a review.  In January 2009, the Texas Supreme Court requested full briefingSee “Texas Restructuring Appeals” section of the proceedings which concluded in June 2009.Note 3.

TNC received its final true-up order in May 2005 that resulted in refunds via a CTC which have been completed.  TNC appealed its final true-up order, which remains pending in state court.Mountaineer Carbon Capture and Storage Project

ManagementAPCo and ALSTOM Power, Inc. (Alstom), an unrelated third party, jointly constructed a CO2 capture validation facility, which was placed into service in September 2009.  APCo also constructed and owns the necessary facilities to store the CO2.  In APCo’s July 2009 Virginia base rate filing, APCo requested recovery of and a return on its estimated increased Virginia jurisdictional share of its project costs and recovery of the related asset retirement obligation regulatory asset amortization and accretion.  The Virginia Attorney General and the Virginia SCC staff have recommended in the pending Virginia base rate case that no recovery be allowed for the pro ject.  APCo plans to seek recovery of the West Virginia jurisdictional costs in its next West Virginia base rate filing which is expected to be filed in the second quarter of 2010.  If APCo cannot predictrecover all of its investments in and expenses related to the outcome of these court proceedingsMountaineer Carbon Capture and PUCT remand decisions.  If TCC and/or TNC ultimately succeed in their appeals,Storage project, it could have a material favorable effect onwould reduce future net income and cash flows and possiblyimpact financial condition.  If municipal customersSee “Mountaineer Carbon Capture and other intervenors succeed in their appeals, it could have a material adverse effect on future net income, cash flows and possibly financial condition.

New Generation/Purchase Power Agreement

AEP is in various stagesStorage Project” section of construction of the following generation facilities:
                 Commercial
      Total        Nominal Operation
Operating Project   Projected        MW Date
Company Name Location Cost (a) CWIP (b) Fuel Type Plant Type Capacity (Projected)
      (in millions) (in millions)        
AEGCo Dresden(c)Ohio $321(d)$199(d)Gas Combined-cycle 580 2013
SWEPCo Stall Louisiana  386  364 Gas Combined-cycle 500 2010
SWEPCo Turk(e)Arkansas  1,633(e) 622(f)Coal Ultra-supercritical 600(e)2012
APCo Mountaineer(g)West Virginia   (g)   Coal IGCC 629  (g)
CSPCo/OPCo Great Bend(g)Ohio   (g)   Coal IGCC 629  (g)

(a)Amount excludes AFUDC.
(b)Amount includes AFUDC.
(c)In September 2007, AEGCo purchased the partially completed Dresden plant from Dresden Energy LLC, a subsidiary of Dominion Resources, Inc., for $85 million, which is included in the “Total Projected Cost” section above.
(d)During 2009, AEGCo suspended construction of the Dresden Plant.  As a result, AEGCo has stopped recording AFUDC and will resume recording AFUDC once construction is resumed.
(e)SWEPCo owns approximately 73%, or 440 MW, totaling $1.2 billion in capital investment.  See “Turk Plant” section below.
(f)Amount represents SWEPCo’s CWIP balance only.
(g)Construction of IGCC plants is subject to regulatory approvals.
Note 3.

Turk Plant

In November 2007, the APSC granted approval for SWEPCo to buildis currently constructing the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, by issuing a Certificatewhich is expected to be in-service in 2012.  SWEPCo owns 73% of Environmental Compatibilitythe Turk Plant and Public Need (CECPN).  Certain intervenors appealedwill operate the APSC’s decisioncompleted facility.  The Turk Plant is currently estimated to grant the CECPNcost $1.7 billion, excluding AFUDC, with SWEPCo’s share estimated to the Arkansas Courtcost $1.3 billion, excluding AFUDC.  Notices of Appeals.  In January 2009, the APSC granted additional CECPNs allowing SWEPCo to construct Turk-related transmission facilities.  Intervenors also appealed these CECPN orders to the Arkansas Court of Appeals.

In June 2009, the Arkansas Court of Appeals issued a unanimous decision that, if upheld byappeal are outstanding at the Arkansas Supreme Court would reverseand the APSC’s grant of the CECPN permitting construction of the Turk Plant to serve Arkansas retail customers.  The decision was based upon the ArkansasCircuit Court of Appeals’ interpretation ofHempstead County, Arkansas.  Complaints are also outstanding at the statute that governsLPSC, the certification process and its conclusion that the APSC did not fully comply with that process.  The ArkansasTexas Court of Appeals concluded that SWEPCo’s need for base load capacity, the construction and financing of the Turk generating plant and the proposed transmission facilities’ construction and location should all have been considered byFederal District Court for the APSC in a single docket insteadWestern District of separate dockets.  In October 2009, the Arkansas Supreme Court granted the petitions filed by SWEPCo and the APSC to review the Arkansas CourtArkansas.  See “Turk Plant” section of Appeals’ decision.  While the appeal is pending, SWEPCo is continuing construction of the Turk Plant.Note 3.

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

In March 2008,April 2010, we began initiatives to decrease both labor and non-labor expenditures with a goal of achieving significant reductions in operation and maintenance expenses.  One initiative is to offer a one-time voluntary severance program.  Participating employees will receive two weeks of base pay for every year of service.  It is anticipated that more than 2,000 employees will accept voluntary severances and terminate employment no later than May 2010.  The second simultaneous initiative will involve all business units and departments to identify process improvements, streamlined organizational designs and other efficiencies that can deliver additional lasting savings.  There is the LPSC approvedpotential that actions taken as a result of this effort could lead to some involuntary separations. 60; Affected employees would receive the applicationsame severance package as those who volunteered.

We expect to constructrecord a charge to expense in the Turk Plant.  In August 2008, the PUCT issued an order approving the Turk Plant with the following four conditions: (a) the cappingsecond quarter of capital costs for the Turk Plant at the previously estimated $1.522 billion projected construction cost, excluding AFUDC and related transmission costs, (b) capping CO2 emission costs at $28 per ton through the year 2030, (c) holding Texas ratepayers financially harmless from any adverse impact2010 related to these initiatives.   At this time, we are unable to predict the Turk Plant not being fully subscribed to by other utilities or wholesale customers and (d) providing the PUCT all updates, studies, reviews, reports and analyses as previously required under the Louisiana and Arkansas orders.  In October 2008, SWEPCo appealed the PUCT’s order regarding the two cost cap restrictions as being unlawful.  In October 2008, an intervenor filed an appeal contending that the PUCT’s grantimpact of a conditional Certificate of Public Convenience and Necessity for the Turk Plant was not necessary to serve retail customers. If the cost cap restrictions are upheld and construction or CO2 emission costs exceed the restrictions or if the intervenor appeal is successful, it could have an adverse effectthese initiatives on net income, cash flows and possibly financial condition.
A request to stop pre-construction activities at the site was filed in Federal District Court by certain Arkansas landowners.  In July 2008, the federal court denied the request and the Arkansas landowners appealed the denial to the U.S. Court of Appeals.  In January 2009, SWEPCo filed a motion to dismiss the appeal, which was granted in March 2009.

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

SWEPCo is also working with the U.S. Army Corps of Engineers for the approval of a wetlands and stream impact permit.  In March 2009, SWEPCo reported to the U.S. Army Corps of Engineers an inadvertent impact on approximately 2.5 acres of wetlands at the Turk Plant construction site prior to the receipt of the permit.  The U.S. Army Corps of Engineers directed SWEPCo to cease further work impacting the wetland areas.  Construction has continued on other areas outside of the proposed Army Corps of Engineers permitted areas of the Turk Plant pending the Army Corps of Engineers’ review.  SWEPCo has entered into a Consent Agreement and Final Order with the Federal EPA to resolve liability for the inadvertent impact and agreed to pay a civil penalty of approximately $29 thousand.

The Arkansas Governor’s Commission on Global Warming issued its final report to the governor in October 2008.  The Commission was established to set a global warming pollution reduction goal together with a strategic plan for implementation in Arkansas.  The Commission’s final report included a recommendation that the Turk Plant employ post combustion carbon capture and storage measures as soon as it starts operating.  To date, the report’s effect is only advisory, but if legislation is passed as a result of the findings in the Commission’s report, it could impact SWEPCo’s ability to complete construction on schedule in 2012 and on budget.

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

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

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

The American Recovery and Reinvestment Act of 2009

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

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

Company
Proposed Project
Federal Stimulus
Funds Requested
(in millions)
APCoCarbon Capture and Sequestration Demonstration Project at the Mountaineer Plant$334 
APCoHydro Generation Modernization Project in London, W.V.2   
CSPCogridSMART75   
TCCgridSMART123   (a)
TNCgridSMART32   (a)
ETTgridSMART12   

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

LitigationLITIGATION

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcomeresolution will be or what the timing of theand amount of any loss, fine or penalty may be.  Management assessespenalty.  We assess the probability of loss for each contingency and accruesaccrue a liability for cases that have a probable likelihood of loss if the loss amount can be estimated.  For details on our regulatory proceedings and pending litigation see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies and the “Litigation” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 20082009 Annual Report.  Additionally, see Note 3 –R 11; Rate Matters and Note 4 – Commitments, Guarantees and Contingencies included herein.  Adverse results in these proceedings have the potential to materially affect our net income and cash flows.

Environmental Mattersincome.

ENVIRONMENTAL ISSUES

We are implementing a substantial capital investment program and incurring additional operational costs to comply with new environmental control requirements.  The sourcesmost significant source is the CAA’s requirements to reduce emissions of these requirements include:

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

In addition, weWe are engaged in litigation with respect to certainabout environmental matters,issues, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of spent nuclear fuelSNF and future decommissioning of our nuclear units.  We are also involvedengaged in the development of possible future requirements to reduce CO2and other GHG emissions to address concerns about global climate change.  AllSee a complete discussion of these matters are discussed in the “Environmental Matters” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 20082009 Annual Report.

Clean Water Act RegulationsGlobal Warming

In 2004,While comprehensive economy-wide regulation of CO2 emissions might be achieved through new legislation, the Federal EPA continues to take action to regulate CO2 emissions under the existing requirements of the CAA.  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 entrainedendangerment finding for CO2 emissions from new motor vehicles in the cooling water.December 2009 and final rules approved in April 2010 for new motor vehicles are awaiting publication.  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 coulddetermined that CO2 emissions from stationary sources will be $193 million for our plants.  We undertook site-specific studies and have been evaluating site-specific compliance or mitigation measures that could significantly change these cost estimates.

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

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

Potential Regulation of CO2 and Other GHG Emissions

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

In April 2009, the Federal EPA issued a proposed endangerment findingregulation under the CAA regarding GHG emissions from motor vehicles.  The proposed endangerment findingb eginning in January 2011 at the earliest, and is subjectexpected to public comment.  This finding could lead to regulation of CO2 and other gases under existing laws.  In September 2009, the Federal EPA issued a final mandatory GHG reporting rule covering a broad range of facilities emitting in excess of 25,000 tons of GHG emissions per year.  The Federal EPA has also issued proposed light duty vehicle GHG emissions standards for model years 2012-2016, and afinalize its proposed scheme to streamline and phase inphase-in regulation of stationary source GHG CO2 emissions through the NSR’sNSR prevention of significant deterioration and CAA’s Title V permitting programs.operating permit programs in 2010.  The Federal EPA stated its intent to finalize the vehicle standards and permitting rule in conjunction with or following a final endangerment finding, and is reconsidering whether to include GHGCO2 emissions in a number of stationary source standards, including standards that apply to new and modified electric utility units.  Some of the policy approaches being discussed by the Federal EPA would have significant and widespread negative consequences for the national economy and major U.S. industrial enterprises, including us.  Because of these adverse consequences, management believes that these more extreme policies will not ultimately be adopted and that reasonable and comprehensive legislative action is preferable.  Even if reasonableIf substantial CO2 and other GHG emission standardsreductions are imposed, the standards could requirerequired, there will be significant increases in capital expenditures and operating costs which would impact the ultimate retirement of older, less-efficient, coal-fired units.  Management believes that costs of complying with newTo the extent we install additional controls on our generating plants to limit CO2 emissions and other GHG emission standards will be treated like all other reasonable costs of serving customers and should be recoverable from customers as costs of doing business, includingreceive regulatory approvals to increase our rates, cost recovery could have a positive effect on future earnings.  Prudently incurred capital investments made by our subsidiaries in rate-regulated jurisdictions to comply with legal requirements and benefit customers are generally included in rate base for recovery and earn a return on investment.  We would expect these principles to apply to investments made to address new environmental requirements.  However, requests for rate increases reflecting these costs can affect us adversely because our regulators could limit the amount or timing of increased costs that we would recover through higher rates.  In addition, to the extent our costs are relatively higher than our competitors’ costs, such as operators of nuclear generation, it could reduce our off-system sales or cause us to lose customers in jurisdictions that permit customers to choo se their supplier of generation service.

Proposed Health Care LegislationSeveral states have adopted programs that directly regulate CO2 emissions from power plants, but none of these programs are currently in effect in states where we have generating facilities.  Certain of our states have passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements (including Ohio, Michigan, Texas and Virginia).  We are taking steps to comply with these requirements.

The U.S. Congress, supported by President Obama,Certain groups have filed lawsuits alleging that emissions of CO2 are a “public nuisance” and seeking injunctive relief and/or damages from small groups of coal-fired electricity generators, petroleum refiners and marketers, coal companies and others.  We have been named in pending lawsuits, which we are vigorously defending.  It is debating health care reformnot possible to predict the outcome of these lawsuits or their impact on our operations or financial condition.  See “Carbon Dioxide Public Nuisance Claims” and “Alaskan Villages’ Claims” sections of Note 4.

Future federal and state legislation or regulations that mandate limits on the emission of CO2 would result in significant increases in capital expenditures and operating costs, which in turn, could lead to increased liquidity needs and higher financing costs.  Excessive costs to comply with future legislation or regulations might force our utility subsidiaries to close some coal-fired facilities and could lead to possible impairment of assets.  As a result, mandatory limits could have a significantmaterial adverse impact on our benefitsnet income, cash flows and costs.  The discussion centers around universal coverage, revenue sources to keep it deficit neutral and changes to Medicare that could significantly impact our employees and retireesfinancial condition.

For detailed information on global warming and the benefitsactions we are taking to address potential impacts, see Part I of the 2009 Form 10-K under the headings entitled “Business – General – Environmental and costsOther Matters – Global Warming” and “Management’s Financial Discussion and Analysis of our benefit plans.  Until legislation is final, the impact is impossible to predict.Results of Operations.”

Critical Accounting EstimatesCRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

See the “Critical Accounting Policies and Estimates” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 20082009 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

New Accounting Pronouncements

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

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

The FASB issued SFAS 161 “Disclosures about Derivative Instruments and Hedging Activities” (SFAS 161), enhancing disclosure requirements for derivative instruments and hedging activities.  The standard requires that objectives for using derivative instruments be disclosed in termsFirst Quarter of underlying risk and accounting designation.  This standard increased our disclosure requirements related to derivative instruments and hedging activities.  We adopted SFAS 161 effective January 1, 2009.  SFAS 161 is included in the “Derivatives and Hedging” accounting guidance.
The FASB issued SFAS 165 “Subsequent Events” (SFAS 165), incorporating guidance on subsequent events into authoritative accounting literature and clarifying the time following the balance sheet date which management reviewed for events and transactions that may require disclosure in the financial statements.  We adopted this standard effective second quarter of 2009.  The standard increased our disclosure by requiring disclosure of the date through which subsequent events have been reviewed.  The standard did not change our procedures for reviewing subsequent events.  SFAS 165 is included in the “Subsequent Events” accounting guidance.

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

The FASB ratified EITF Issue No. 08-5 “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement” (EITF 08-5), a consensus on liabilities with third-party credit enhancements when the liability is measured and disclosed at fair value.  The consensus treats the liability and the credit enhancement as two units of accounting.  We adopted EITF 08-5 effective January 1, 2009.  With the adoption of FSP SFAS 107-1 and APB 28-1, it is applied to the fair value of long-term debt.  The application of this standard had an immaterial effect on the fair value of debt outstanding.  EITF 08-5 is included in the “Fair Value Measurements and Disclosures” accounting guidance.

The FASB ratified EITF Issue No. 08-6 “Equity Method Investment Accounting Considerations” (EITF 08-6), a consensus on equity method investment accounting including initial and allocated carrying values and subsequent measurements.  We prospectively adopted EITF 08-6 effective January 1, 2009 with no impact on our financial statements.  EITF 08-6 is included in the “Investments – Equity Method and Joint Ventures” accounting guidance.2010

We adopted FSP EITF 03-6-1 “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (EITF 03-6-1),ASU 2009-16 “Transfers and Servicing” effective January 1, 2009.  The rule addressed whether instruments granted in share-based payment transactions are participating securities prior to vesting and determined that the instruments need to be included in earnings allocation in computing EPS under the two-class method.2010.  The adoption of this standard had an immaterial impactresulted in AEP Credit’s transfers of receivables being accounted for as financings with the receivables and short-term debt recorded on our financial statements.  EITF 03-6-1 is included in the “Earnings Per Share” accounting guidance.balance sheet.

The FASB issued FSP SFAS 107-1 and APB 28-1 requiring disclosure about the fair value of financial instruments in all interim reporting periods.  The standard requires disclosure of the method and significant assumptions used to determine the fair value of financial instruments.  We adopted the standard effective second quarterprospective provisions of 2009.  This standard increased the disclosure requirements related to financial instruments.  FSP SFAS 107-1 and APB 28-1 is included in the “Financial Instruments” accounting guidance.

The FASB issued FSP SFAS 115-2 and SFAS 124-2 “Recognition and Presentation of Other-Than-Temporary Impairments”, amending the other-than-temporary impairment (OTTI) recognition and measurement guidance for debt securities.  For both debt and equity securities, the standard requires disclosure for each interim reporting period of information by security class similar to previous annual disclosure requirements.  We adopted the standard effective second quarter of 2009 with no impact on our financial statements and increased disclosure requirements related to financial instruments.  FSP SFAS 115-2 and SFAS 124-2 is included in the “Investments – Debt and Equity Securities” accounting guidance.

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

The FASB issued SFAS 157-2 “Effective Date of FASB Statement No. 157” (SFAS 157-2), which delays the effective date of SFAS 157 to fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually).  As defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.  The fair value hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority to unobservable inputs.  In the absence of quoted prices for identical or similar assets or investments in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.  We adopted SFAS 157-2 effective January 1, 2009.  We will apply these requirements to applicable fair value measurements which include new asset retirement obligations and impairment analysis related to long-lived assets, equity investments, goodwill and intangibles.  We did not record any fair value measurements for nonrecurring nonfinancial assets and liabilities in 2009.  SFAS 157-2 is included in the “Fair Value Measurements and Disclosures” accounting guidance.

The FASB issued FSP SFAS 157-4 “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (FSP SFAS 157-4), providing additional guidance on estimating fair value when the volume and level of activity for an asset or liability has significantly decreased, including guidance on identifying circumstances indicating when a transaction is not orderly.  Fair value measurements shall be based on the price that would be received to sell an asset or paid to transfer a liability in an orderly (not a distressed sale or forced liquidation) transaction between market participants at the measurement date under current market conditions.  The standard also requires disclosures of the inputs and valuation techniques used to measure fair value and a discussion of changes in valuation techniques and related inputs, if any, for both interim and annual periods.  We adopted the standard effective second quarter of 2009.  This standard had no impact on our financial statements but increased our disclosure requirements.  FSP SFAS 157-4 is included in the “Fair Value Measurements and Disclosures” accounting guidance.

Pronouncements Effective in the Future

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

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

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

The FASB issued SFAS 166 “Accounting for Transfers of Financial Assets” (SFAS 166) clarifying when a transfer of a financial asset should be recorded as a sale.  The standard defines participating interest to establish specific conditions for a sale of a portion of a financial asset.  This standard must be applied to all transfers after the effective date.  SFAS 166 is effective for interim and annual reporting in fiscal years beginning after November 15, 2009.  Early adoption is prohibited.  We continue to review the impact of this standard.  We will adopt SFAS 1662009-17 “Consolidations” effective January 1, 2010.  SFAS 166 is included inWe no longer consolidate DHLC effective with the “Transfers and Servicing”adoption of this standard.

See Note 2 for further discussion of accounting guidance.pronouncements.

Future Accounting Changes

The FASBFASB’s standard-setting process is ongoing and until new standards have been finalized and issued, SFAS 167 “Amendments to FASB Interpretation No. 46(R)” (SFAS 167) amendingwe cannot determine the analysis an entity must perform to determine if it has a controlling interest in a variable interest entity (VIE).  This new guidance provides that the primary beneficiary of a VIE must have both:

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

The standard also requires separate presentation on the facereporting of the statement ofour operations and financial position for assets which can only be usedthat may result from any such future changes.  The FASB is currently working on several projects including revenue recognition, contingencies, financial instruments, emission allowances, fair value measurements, leases, insurance, hedge accounting, consolidation policy and discontinued operations.  We also expect to settle obligationssee more FASB projects as a result of a consolidated VIEits desire to converge International Accounting Standards with GAAP.  The ultimate pronouncements resulting from these and liabilities for which creditors do notfuture projects could have recourse to the general credit of the primary beneficiary.  SFAS 167 is effective for interim and annual reporting in fiscal years beginning after November 15, 2009.  Early adoption is prohibited.  We continue to review thean impact of the changes in the consolidation guidance on our future net income and financial statements.  This standard will increase our disclosure requirements related to transactions with VIEs and may change the presentation of consolidated VIE’s assets and liabilities on our Condensed Consolidated Balance Sheets.  We will adopt SFAS 167 effective January 1, 2010.  SFAS 167 is included in the “Consolidation” accounting guidance.position.

The FASB issued FSP SFAS 132R-1 “Employers’ Disclosures about Postretirement Benefit Plan Assets” (FSP SFAS 132R-1) providing additional disclosure guidance for pension and OPEB plan assets.  The standard adds disclosure requirements including hierarchical classes for fair value and concentration of risk.  This standard is effective for fiscal years ending after December 15, 2009.  We expect this standard to increase the disclosure requirements related to our benefit plans.  We will adopt the standard effective for the 2009 Annual Report.  FSP SFAS 132R-1 is included in the “Compensation – Retirement Benefits” accounting guidance.

 
 
 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

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

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

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

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

The following tables provide information on our risk management activities.

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

The following two tables summarize the various mark-to-market (MTM) positions included on our balance sheet as of September 30, 2009 andtable summarizes the reasons for changes in our total MTMmark-to-market (MTM) value included on our balance sheet as compared to December 31, 2008.2009:

Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
September 30, 2009
(in millions)

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

MTM Risk Management Contract Net Assets (Liabilities)
NineThree Months Ended September 30, 2009March 31, 2010
(in millions)
  Utility Operations  
Generation
and
Marketing
  All Other  Total 
Total MTM Risk Management Contract Net Assets (Liabilities) at December 31, 2008 $175  $104  $(7) $272 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period  (77)  (5)  4   (78)
Fair Value of New Contracts at Inception When Entered During the Period (a)  14   61   -   75 
Net Option Premiums Paid (Received) for Unexercised or Unexpired Option Contracts Entered During the Period  -   -   -   - 
Changes in Fair Value Due to Valuation Methodology Changes on Forward Contracts  -   -   -   - 
Changes in Fair Value Due to Market Fluctuations During the Period (b)  9   (16)  -   (7)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)  71   -   -   71 
Total MTM Risk Management Contract Net Assets (Liabilities) at September 30, 2009 $192  $144  $(3)  333 
Cash Flow Hedge Contracts
              (11)
Collateral Deposits              71 
Total MTM Derivative Contract Net Assets at September 30, 2009             $393 
 Utility Operations 
Generation
and
Marketing
 All Other Total
Total MTM Risk Management Contract Net Assets (Liabilities) at December 31, 2009$134  $147  $(3) $278 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period (24)  (6)  2   (28)
Fair Value of New Contracts at Inception When Entered During the Period (a) 6   7   -   13 
Changes in Fair Value Due to Valuation Methodology Changes on Forward Contracts (b) (2)  (2)  -   (4)
Changes in Fair Value Due to Market Fluctuations During the Period (c) 8   6   -   14 
Changes in Fair Value Allocated to Regulated Jurisdictions (d) 25   -   -   25 
Total MTM Risk Management Contract Net Assets (Liabilities) at March 31, 2010$147  $152 $(1)  298 
Cash Flow Hedge Contracts
          (4)
Collateral Deposits          134 
Total MTM Derivative Contract Net Assets at March 31, 2010         $428 

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

MaturitySee Note 8 – Derivatives and Source ofHedging and Note 9 – Fair Value of MTM Risk Management Contract Net Assets (Liabilities)Measurements for additional information related to our risk management contracts.  The following tables and discussion provide information on our credit risk and market volatility risk.

The following table presents the maturity, by year, of our net assets/liabilities, to give an indication of when these MTM amounts will settle and generate or (require) cash:
Maturity and Source of Fair Value of MTM
Credit Risk Management Contract Net Assets (Liabilities)
September 30, 2009
(in millions)

 
Remainder
2009
 2010 2011 2012 2013 
After
2013 (f)
 Total
Utility Operations                    
Level 1 (a)$(1) $-  $-  $-  $-  $-  $(1)
Level 2 (b) 24   43   18   3   8   1   97 
Level 3 (c) 19   39   6   3   -   -   67 
Total 42   82   24   6   8   1   163 
                     
Generation and Marketing                    
Level 1 (a) (2)  1   -   -   -   -   (1)
Level 2 (b) 1   14   17   16   19   41   108 
Level 3 (c) -   1   1   2   3   30   37 
Total (1)  16   18   18   22   71   144 
                     
All Other                    
Level 1 (a) -   -   -   -   -   -   - 
Level 2 (b) (1)  (4)  2   -   -   -   (3)
Level 3 (c) -   -   -   -   -   -   - 
Total (1)  (4)  2   -   -   -   (3)
                     
Total                    
Level 1 (a) (3)  1   -   -   -   -   (2)
Level 2 (b) 24   53   37   19   27   42   202 
Level 3 (c) (d) 19   40   7   5   3   30   104 
Total 40   94   44   24   30   72   304 
Dedesignated Risk Management Contracts (e) 4   14   6   5   -   -   29 
Total MTM Risk Management Contract Net Assets$44  $108  $50  $29  $30  $72  
 
$
333 
(a)Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.  Level 1 inputs primarily consist of exchange traded contracts that exhibit sufficient frequency and volume to provide pricing information on an ongoing basis.
(b)Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.  If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, exchange traded contracts where there was not sufficient market activity to warrant inclusion in Level 1 and OTC broker quotes that are corroborated by the same or similar transactions that have occurred in the market.
(c)Level 3 inputs are unobservable inputs for the asset or liability.  Unobservable inputs shall be used to measure fair value to the extent that the observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.  Level 3 inputs primarily consist of unobservable market data or are valued based on models and/or assumptions.
(d)A significant portion of the total volumetric position within the consolidated Level 3 balance has been economically hedged.
(e)Dedesignated Risk Management Contracts are contracts that were originally MTM but were subsequently elected normal under the accounting guidance for “Derivatives and Hedging.”  At the time of the normal election, the MTM value was frozen and no longer fair valued.  This will be amortized within Utility Operations Revenues over the remaining life of the contracts.
(f)There is mark-to-market value of $72 million in individual periods beyond 2013.  $51 million of this mark-to-market value is in periods 2014-2018, $14 million is in periods 2019-2023 and $7 million is in periods 2024-2028.

Credit RiskWe 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 on an ongoing basis.  We use Moody’s Investors Service, Standard & Poor’s and current market-based qualitative and quantitative data to assess the financial health of counterparties on an ongoing basis.  If an external rating is not available, an internal rating is generated utilizing a quantitative tool developed by Moody’s to estimate probability of default that corresponds to an implied external agency credit rating.

We have risk management contracts with numerous counterparties.  Since open risk management contracts are valued based on changes in market prices of the related commodities, our exposures change daily.  At September 30, 2009,As of March 31, 2010, our credit exposure net of collateral to sub investment grade counterparties was approximately 11.5%9.4%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss).  As of September 30, 2009,March 31, 2010, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:

Counterparty Credit Quality Exposure Before Credit Collateral  Credit Collateral  Net Exposure  
Number of Counterparties >10% of
Net Exposure
  
Net Exposure
of Counterparties >10%
 
 Exposure Before Credit Collateral  Credit Collateral  Net Exposure  
Number of Counterparties >10% of
Net Exposure
  
Net Exposure
of Counterparties >10%
  (in millions, except number of counterparties) 
Counterparty Credit Quality (in millions, except number of counterparties) 
Investment Grade $775  $69  $706   2  $228  $858  $76  $782   2  $227 
Split Rating  7   -   7   2   7   5   -   5   1   5 
Noninvestment Grade  4   2   2   2   1   1   -   1   2   1 
No External Ratings:                                        
Internal Investment Grade  75   4   71   4   56   127   1   126   3   77 
Internal Noninvestment Grade  112   12   100   3   86   105   12   93   3   78 
Total as of September 30, 2009 $973  $87  $886   13  $378 
Total as of March 31, 2010 $1,096  $89  $1,007   11  $388 
                                        
Total as of December 31, 2008 $793  $29  $764   9  $284 
Total as of December 31, 2009 $846  $58  $788   12  $317 

See Note 8 for further information regarding MTM risk management contracts, cash flow hedging, accumulated other comprehensive income, credit risk and collateral triggering events.

VaRValue at Risk (VaR) Associated with Risk Management Contracts

We use a risk measurement model, which calculates Value at Risk (VaR)VaR to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period.  Based on this VaR analysis, at September 30, 2009as of March 31, 2010, a near term typical change in commodity prices is not expected to have a material effect on our net income, cash flows or financial condition.

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

VaR Model

Nine Months Ended  Twelve Months Ended 
September 30, 2009  December 31, 2008 
(in millions)  (in millions) 
End  High  Average  Low  End  High  Average  Low 
$1  $2  $1  $-  $-  $3  $1  $- 
Three Months Ended    Twelve Months Ended
March 31, 2010    December 31, 2009
(in millions)    (in millions)
End High Average Low    End High Average Low
$1 $2 $1 $-    $1 $2 $1 $-

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

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

Interest Rate Risk

We utilize an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which AEP’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  As calculated on debt outstanding as of September 30,for both March 31, 2010 and December 31, 2009, the estimated EaR on our debt portfolio for the following twelve months was $12$4 million.

 
 
 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30,March 31, 2010 and 2009 and 2008
 (in(in millions, except per-share and share amounts)
(Unaudited)
 Three Months Ended  Nine Months Ended 
REVENUES 2009  2008  2009  2008  2010  2009 
Utility Operations $3,364  $4,108  $9,666  $10,318  $3,406  $3,267 
Other Revenues  183   83   541   886   163   191 
TOTAL REVENUES  3,547   4,191   10,207   11,204   3,569   3,458 
EXPENSES                        
Fuel and Other Consumables Used for Electric Generation  931   1,480   2,624   3,513   1,014   929 
Purchased Electricity for Resale  247   394   800   1,023   238   295 
Other Operation and Maintenance  899   1,010   2,724   2,870 
Gain on Sales of Assets, Net  (2)  (6)  (13)  (14)
Asset Impairments and Other Related Charges  -   -   -   (255)
Other Operation  673   610 
Maintenance  271   295 
Depreciation and Amortization  421   387   1,200   1,123   408   382 
Taxes Other Than Income Taxes  193   189   582   578   207   197 
TOTAL EXPENSES  2,689   3,454   7,917   8,838   2,811   2,708 
                        
OPERATING INCOME  858   737   2,290   2,366   758   750 
                        
Other Income (Expense):                        
Interest and Investment Income  5   14   5   45   3   5 
Carrying Costs Income  12   21   33   64   14   9 
Allowance for Equity Funds Used During Construction  23   11   59   32   24   16 
Interest Expense  (248)  (216)  (726)  (669)  (250)  (238)
                        
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS  650   567   1,661   1,838   549   542 
                        
Income Tax Expense  208   192   535   608   207   179 
Equity Earnings of Unconsolidated Subsidiaries  4   1   5   3   4   - 
                        
INCOME BEFORE DISCONTINUED OPERATIONS AND EXTRAORDINARY LOSS  446   376   1,131   1,233 
                
DISCONTINUED OPERATIONS, NET OF TAX  -   -   -   1 
                
INCOME BEFORE EXTRAORDINARY LOSS  446   376   1,131   1,234 
                
EXTRAORDINARY LOSS, NET OF TAX  -   -   (5)  - 
                
NET INCOME  446   376   1,126   1,234   346   363 
                        
Less: Net Income Attributable to Noncontrolling Interests  2   1   5   4   1   2 
                        
NET INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS  444   375   1,121   1,230   345   361 
                        
Less: Preferred Stock Dividend Requirements of Subsidiaries  1   1   2   2   1   1 
                        
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $443  $374  $1,119  $1,228  $344  $360 
                        
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING  476,948,143   402,286,779   452,255,119   401,535,661   478,429,535   406,826,606 
                        
BASIC EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS                
Income Before Discontinued Operations and Extraordinary Loss $0.93  $0.93  $2.48  $3.06 
Discontinued Operations, Net of Tax  -   -   -   - 
Income Before Extraordinary Loss  0.93   0.93   2.48   3.06 
Extraordinary Loss, Net of Tax  -   -   (0.01)  - 
                
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $0.93  $0.93  $2.47  $3.06  $0.72  $0.89 
                        
                
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING  477,111,144   403,910,309   452,495,494   402,925,534   478,844,632   407,381,954 
                
DILUTED EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS                
Income Before Discontinued Operations and Extraordinary Loss $0.93  $0.93  $2.48  $3.05 
Discontinued Operations, Net of Tax  -   -   -   - 
Income Before Extraordinary Loss  0.93   0.93   2.48   3.05 
Extraordinary Loss, Net of Tax  -   -   (0.01)  - 
                        
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $0.93  $0.93  $2.47  $3.05  $0.72  $0.89 
                        
CASH DIVIDENDS PAID PER SHARE $0.41  $0.41  $1.23  $1.23  $0.41  $0.41 
                
See Condensed Notes to Condensed consolidated Financial Statements                

See Condensed Notes to Condensed Consolidated Financial Statements.

 
 
 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETSSTATEMENTS OF CHANGES IN EQUITY AND
ASSETSCOMPREHENSIVE INCOME (LOSS)
September 30,For the Three Months Ended March 31, 2010 and 2009 and December 31, 2008
(in millions)
(Unaudited)

  2009  2008 
CURRENT ASSETS      
Cash and Cash Equivalents $877  $411 
Other Temporary Investments  259   327 
Accounts Receivable:        
Customers  600   569 
Accrued Unbilled Revenues  402   449 
Miscellaneous  63   90 
Allowance for Uncollectible Accounts  (36)  (42)
Total Accounts Receivable  1,029   1,066 
Fuel  998   634 
Materials and Supplies  569   539 
Risk Management Assets  300   256 
Regulatory Asset for Under-Recovered Fuel Costs  103   284 
Margin Deposits  101   86 
Prepayments and Other Current Assets  243   172 
TOTAL CURRENT ASSETS  4,479   3,775 
         
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
Production  22,552   21,242 
Transmission  8,198   7,938 
Distribution  13,336   12,816 
Other Property, Plant and Equipment (including coal mining and nuclear fuel)  3,821   3,741 
Construction Work in Progress  3,251   3,973 
Total Property, Plant and Equipment  51,158   49,710 
Accumulated Depreciation and Amortization  17,337   16,723 
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET  33,821   32,987 
         
OTHER NONCURRENT ASSETS        
Regulatory Assets  4,360   3,783 
Securitized Transition Assets  1,940   2,040 
Spent Nuclear Fuel and Decommissioning Trusts  1,364   1,260 
Goodwill  76   76 
Long-term Risk Management Assets  379   355 
Deferred Charges and Other Noncurrent Assets  774   879 
TOTAL OTHER NONCURRENT ASSETS  8,893   8,393 
         
TOTAL ASSETS $47,193  $45,155 
 AEP Common Shareholders    
 Common Stock     Accumulated    
         Other    
     Paid-in Retained Comprehensive Noncontrolling  
 Shares Amount Capital Earnings Income (Loss) Interests Total
TOTAL EQUITY – DECEMBER 31, 2008 426  $2,771  $4,527  $3,847  $(452) $17  $10,710 
                     
Issuance of Common Stock 2   11   37            48 
Common Stock Dividends          (167)     (2)  (169)
Preferred Stock Dividend Requirements of Subsidiaries          (1)        (1)
Other Changes in Equity                1   1 
SUBTOTAL – EQUITY                   10,589 
                     
COMPREHENSIVE INCOME                    
Other Comprehensive Income (Loss), Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $1             3      3 
Securities Available for Sale, Net of Tax of $1             (2)     (2)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $3             5      5 
NET INCOME          361      2   363 
TOTAL COMPREHENSIVE INCOME                   369 
                     
TOTAL EQUITY – MARCH 31, 2009 428  $2,782  $4,564  $4,040  $(446) $18  $10,958 
                     
TOTAL EQUITY – DECEMBER 31, 2009 498  $3,239  $5,824  $4,451  $(374) $-  $13,140 
                     
Issuance of Common Stock 1   5   21           26 
Common Stock Dividends          (196)     (1)  (197)
Preferred Stock Dividend Requirements of Subsidiaries          (1)        (1)
Other Changes in Equity       2   (2)        - 
SUBTOTAL – EQUITY                   12,968 
                     
COMPREHENSIVE INCOME                    
Other Comprehensive Income, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $2             4      4 
Securities Available for Sale, Net of Tax of $-             1      1 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $3             5      5 
NET INCOME          345      1   346 
TOTAL COMPREHENSIVE INCOME                   356 
                     
TOTAL EQUITY – MARCH 31, 2010 499  $3,244  $5,847  $4,597  $(364) $-  $13,324 

See Condensed Notes to Condensed Consolidated Financial Statements.



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2010 and December 31, 2009
(in millions)
(Unaudited)

  2010  2009 
CURRENT ASSETS      
Cash and Cash Equivalents $818  $490 
Other Temporary Investments  238   363 
Accounts Receivable:        
Customers  613   492 
Accrued Unbilled Revenues  116   503 
Pledged Accounts Receivable – AEP Credit  867   - 
Miscellaneous  98   92 
Allowance for Uncollectible Accounts  (38)  (37)
Total Accounts Receivable  1,656   1,050 
Fuel  984   1,075 
Materials and Supplies  582   586 
Risk Management Assets  323   260 
Accrued Tax Benefits  460   547 
Regulatory Asset for Under-Recovered Fuel Costs  107   85 
Margin Deposits  109   89 
Prepayments and Other Current Assets  239   211 
TOTAL CURRENT ASSETS  5,516   4,756 
         
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
Production  23,417   23,045 
Transmission  8,313   8,315 
Distribution  13,685   13,549 
Other Property, Plant and Equipment (including coal mining and nuclear fuel)  3,833   3,744 
Construction Work in Progress  2,765   3,031 
Total Property, Plant and Equipment  52,013   51,684 
Accumulated Depreciation and Amortization  17,487   17,340 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET  34,526   34,344 
         
OTHER NONCURRENT ASSETS        
Regulatory Assets  4,683   4,595 
Securitized Transition Assets  1,865   1,896 
Spent Nuclear Fuel and Decommissioning Trusts  1,433   1,392 
Goodwill  76   76 
Long-term Risk Management Assets  449   343 
Deferred Charges and Other Noncurrent Assets  1,077   946 
TOTAL OTHER NONCURRENT ASSETS  9,583   9,248 
         
TOTAL ASSETS $49,625  $48,348 

See Condensed Notes to Condensed Consolidated Financial Statements.
 
 
 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 2009March 31, 2010 and December 31, 20082009
(Unaudited)

         2009 2008  2010 2009
CURRENT LIABILITIESCURRENT LIABILITIES (in millions)CURRENT LIABILITIES (in millions)
Accounts PayableAccounts Payable $1,004  $1,297 Accounts Payable $954  $1,158 
Short-term Debt 352   1,976 
Short-term Debt:Short-term Debt:     
GeneralGeneral 412   126 
Securitized Debt for Receivables – AEP CreditSecuritized Debt for Receivables – AEP Credit  651   - 
Total Short-term DebtTotal Short-term Debt  1,063   126 
Long-term Debt Due Within One YearLong-term Debt Due Within One Year 1,540   447 Long-term Debt Due Within One Year 1,253   1,741 
Risk Management LiabilitiesRisk Management Liabilities 136   134 Risk Management Liabilities 151   120 
Customer DepositsCustomer Deposits 265   254 Customer Deposits 261   256 
Accrued TaxesAccrued Taxes 470   634 Accrued Taxes 621   632 
Accrued InterestAccrued Interest 232   270 Accrued Interest 254   287 
Regulatory Liability for Over-Recovered Fuel CostsRegulatory Liability for Over-Recovered Fuel Costs 107   66 Regulatory Liability for Over-Recovered Fuel Costs 38   76 
Other Current LiabilitiesOther Current Liabilities  881   1,219 Other Current Liabilities  920   931 
TOTAL CURRENT LIABILITIESTOTAL CURRENT LIABILITIES  4,987   6,297 TOTAL CURRENT LIABILITIES  5,515   5,327 
           
NONCURRENT LIABILITIESNONCURRENT LIABILITIES     NONCURRENT LIABILITIES     
Long-term DebtLong-term Debt 15,713   15,536 Long-term Debt 16,281   15,757 
Long-term Risk Management LiabilitiesLong-term Risk Management Liabilities 150   170 Long-term Risk Management Liabilities 193   128 
Deferred Income TaxesDeferred Income Taxes 5,824   5,128 Deferred Income Taxes 6,587   6,420 
Regulatory Liabilities and Deferred Investment Tax CreditsRegulatory Liabilities and Deferred Investment Tax Credits 2,901   2,789 Regulatory Liabilities and Deferred Investment Tax Credits 3,005   2,909 
Asset Retirement ObligationsAsset Retirement Obligations 1,197   1,154 Asset Retirement Obligations 1,264   1,254 
Employee Benefits and Pension ObligationsEmployee Benefits and Pension Obligations 2,168   2,184 Employee Benefits and Pension Obligations 2,153   2,189 
Deferred Credits and Other Noncurrent LiabilitiesDeferred Credits and Other Noncurrent Liabilities  1,128   1,126 Deferred Credits and Other Noncurrent Liabilities  1,242   1,163 
TOTAL NONCURRENT LIABILITIESTOTAL NONCURRENT LIABILITIES  29,081   28,087 TOTAL NONCURRENT LIABILITIES  30,725   29,820 
           
TOTAL LIABILITIESTOTAL LIABILITIES  34,068   34,384 TOTAL LIABILITIES  36,240   35,147 
           
Cumulative Preferred Stock Not Subject to Mandatory RedemptionCumulative Preferred Stock Not Subject to Mandatory Redemption  61   61 Cumulative Preferred Stock Not Subject to Mandatory Redemption  61   61 
           
Rate Matters (Note 3)Rate Matters (Note 3)     
Commitments and Contingencies (Note 4)Commitments and Contingencies (Note 4)     Commitments and Contingencies (Note 4)     
           
EQUITYEQUITY     EQUITY     
Common Stock – Par Value – $6.50 Per Share:Common Stock – Par Value – $6.50 Per Share:     Common Stock – Par Value – $6.50 Per Share:     
2009 2008      2010 2009      
Shares AuthorizedShares Authorized600,000,000 600,000,000      600,000,000 600,000,000      
Shares IssuedShares Issued497,649,344 426,321,248      499,133,697 498,333,265      
(20,249,992 shares were held in treasury at September 30, 2009 and December 31, 2008) 3,235   2,771 
(20,278,858 shares were held in treasury at March 31, 2010 and December 31, 2009)(20,278,858 shares were held in treasury at March 31, 2010 and December 31, 2009) 3,244   3,239 
Paid-in CapitalPaid-in Capital 5,826   4,527 Paid-in Capital 5,847   5,824 
Retained EarningsRetained Earnings 4,407   3,847 Retained Earnings 4,597   4,451 
Accumulated Other Comprehensive Income (Loss)Accumulated Other Comprehensive Income (Loss)  (404)  (452)Accumulated Other Comprehensive Income (Loss)  (364)  (374)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITYTOTAL AEP COMMON SHAREHOLDERS’ EQUITY  13,064   10,693 TOTAL AEP COMMON SHAREHOLDERS’ EQUITY  13,324   13,140 
           
Noncontrolling InterestsNoncontrolling Interests  -   17 Noncontrolling Interests  -   - 
           
TOTAL EQUITYTOTAL EQUITY  13,064   10,710 TOTAL EQUITY  13,324   13,140 
           
TOTAL LIABILITIES AND EQUITYTOTAL LIABILITIES AND EQUITY $47,193  $45,155 TOTAL LIABILITIES AND EQUITY $49,625  $48,348 

See Condensed Notes to Condensed Consolidated Financial Statements.


 
 
 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the NineThree Months Ended September 30,March 31, 2010 and 2009 and 2008
(in millions)
(Unaudited)

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

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY AND
COMPREHENSIVE INCOME (LOSS)
For the Nine Months Ended September 30, 2009 and 2008
(in millions)
(Unaudited)

 AEP Common Shareholders    
 Common Stock     Accumulated    
         Other    
     Paid-in Retained Comprehensive Noncontrolling  
 Shares Amount Capital Earnings Income (Loss) Interests Total
TOTAL EQUITY – DECEMBER 31, 2007 422  $2,743  $4,352  $3,138  $(154) $18   $10,097 
                     
EITF 06-10 Adoption, Net of Tax of $6          (10)        (10)
SFAS 157 Adoption, Net of Tax of $0          (1)        (1)
Issuance of Common Stock 3   17   89            106 
Common Stock Dividends          (494)     (6)  (500)
Preferred Stock Dividends          (2)        (2)
Other Changes in Equity       3         1   4 
SUBTOTAL – EQUITY                   9,694 
                     
COMPREHENSIVE INCOME                    
Other Comprehensive Income (Loss), Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $4             7      7 
Securities Available for Sale, Net of Tax of $5             (10)     (10)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $5             9      9 
NET INCOME          1,230      4   1,234 
TOTAL COMPREHENSIVE INCOME                   1,240 
                     
TOTAL EQUITY – SEPTEMBER 30, 2008 425  $2,760  $4,444  $3,861  $(148) $17   $10,934 
                     
TOTAL EQUITY – DECEMBER 31, 2008 426  $2,771  $4,527  $3,847  $(452) $17   $10,710 
                     
Issuance of Common Stock 71   464   1,294            1,758 
Common Stock Dividends          (559)     (5)  (564)
Preferred Stock Dividends          (2)        (2)
Purchase of JMG       55         (18)  37 
Other Changes in Equity       (50)        1   (49)
SUBTOTAL – EQUITY                   11,890 
                     
COMPREHENSIVE INCOME                    
Other Comprehensive Income, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $3             5      5 
Securities Available for Sale, Net of Tax of $5             10      10 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $18             33      33 
NET INCOME          1,121      5   1,126 
TOTAL COMPREHENSIVE INCOME                   1,174 
                     
TOTAL EQUITY – SEPTEMBER 30, 2009 497  $3,235  $5,826  $4,407  $(404) $-  $13,064 

See Condensed Notes to Condensed Consolidated Financial Statements.

  2010  2009 
OPERATING ACTIVITIES      
Net Income $346  $363 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:        
Depreciation and Amortization  408   382 
Deferred Income Taxes  121   217 
Carrying Costs Income  (14)  (9)
Allowance for Equity Funds Used During Construction  (24)  (16)
Mark-to-Market of Risk Management Contracts  (69)  (46)
Amortization of Nuclear Fuel  30   13 
Property Taxes  (53)  (64)
Fuel Over/Under-Recovery, Net  (97)  (95)
Change in Other Noncurrent Assets  (28)  23 
Change in Other Noncurrent Liabilities  37   18 
Changes in Certain Components of Working Capital:        
Accounts Receivable, Net  (617)  102 
Fuel, Materials and Supplies  83   (118)
Margin Deposits  (20)  (39)
Accounts Payable  (83)  3 
Customer Deposits  5   12 
Accrued Taxes, Net  80   (57)
Accrued Interest  (34)  (44)
Other Current Assets  (14)  (7)
Other Current Liabilities  (55)  (321)
Net Cash Flows from Operating Activities  2   317 
         
INVESTING ACTIVITIES        
Construction Expenditures  (609)  (897)
Change in Other Temporary Investments, Net  82   111 
Purchases of Investment Securities  (445)  (179)
Sales of Investment Securities  473   158 
Acquisitions of Nuclear Fuel  (38)  (76)
Proceeds from Sales of Assets  139   172 
Other Investing Activities  (32)  (16)
Net Cash Flows Used for Investing Activities  (430)  (727)
         
FINANCING ACTIVITIES        
Issuance of Common Stock  26   48 
Issuance of Long-term Debt  652   947 
Borrowings from Revolving Credit Facilities  24   28 
Change in Short-term Debt, Net  931   - 
Retirement of Long-term Debt  (638)  (93)
Repayments to Revolving Credit Facilities  (17)  (28)
Principal Payments for Capital Lease Obligations  (24)  (23)
Dividends Paid on Common Stock  (197)  (169)
Dividends Paid on Cumulative Preferred Stock  (1)  (1)
Net Cash Flows from Financing Activities  756   709 
         
Net Increase in Cash and Cash Equivalents  328   299 
Cash and Cash Equivalents at Beginning of Period  490   411 
Cash and Cash Equivalents at End of Period $818  $710 
         
SUPPLEMENTARY INFORMATION        
Cash Paid for Interest, Net of Capitalized Amounts $271  $314 
Net Cash Paid (Received) for Income Taxes  (2)  2 
Noncash Acquisitions under Capital Leases  148   6 
Construction Expenditures Included in Accounts Payable at March 31,  216   294 
Acquisition of Nuclear Fuel Included in Accounts Payable at March 31,  3   17 
         
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 Matters
2.New Accounting Pronouncements and Extraordinary Item
3.Rate Matters
4.Commitments, Guarantees and Contingencies
5.Acquisitions and Discontinued OperationsDispositions
6.Benefit Plans
7.Business Segments
8.Derivatives and Hedging
9.Fair Value Measurements
10.Income Taxes
11.Financing Activities
12.Company-wide Staffing and Budget Review

 
 
 

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

1.SIGNIFICANT ACCOUNTING MATTERS

General

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

In the opinion of management, the unaudited condensed consolidated interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of our net income, financial position and cash flows for the interim periods.  Net income for the three and nine months ended September 30, 2009March 31, 2010 is not necessarily indicative of results that may be expected for the year ending December 31, 2009.  We reviewed subsequent events through our Form 10-Q issuance date of October 30, 2009.2010.  The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 20082009 consolidated financial statements and notes thereto, which are included in our Current Report on Form 8-K10-K as filed with the SEC on May 1, 2009.

Earnings Per Share (EPS)

The following table presents our basic and diluted EPS calculations included on our Condensed Consolidated Statements of Income:
  Three Months Ended September 30, 
  2009  2008 
  (in millions, except per share data) 
     $/share     $/share 
Earnings Applicable to AEP Common Shareholders $443     $374    
               
Weighted Average Number of Basic Shares Outstanding  476.9  $0.93   402.3  $0.93 
Weighted Average Dilutive Effect of:                
Performance Share Units  0.1   -   1.3   - 
Stock Options  -   -   0.1   - 
Restricted Stock Units  0.1   -   0.1   - 
Restricted Shares  -   -   0.1   - 
Weighted Average Number of Diluted Shares Outstanding  477.1  $0.93   403.9  $0.93 

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

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

Options to purchase 612,916 and 146,900 shares of common stock were outstanding at September 30, 2009 and 2008, respectively, but were not included in the computation of diluted earnings per share because the options’ exercise prices were greater than the average quarter market price of the common shares and, therefore, the effect would be antidilutive.February 26, 2010.

Variable Interest Entities

The accounting guidance for “Variable Interest Entities” is a consolidation model that considers risk absorptionif a company has a controlling financial interest in a VIE.  A controlling financial interest will have both (a) the power to direct the activities of a variable interest entity (VIE), also referredVIE that most significantly impact the VIE’s economic performance and (b) the obligation to as variability.absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.  Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.”  In determining whether we are the primary beneficiary of a VIE, we consider factors such as equity at risk, the amount of the VIE’s variability we absorb, guarantees of indebtedness, voting rights including kick-out rights, power to direct the VIE and other factors.  We believe that significant assumptions and judgments were applied consistently.  Also, see “ASU 2009-17 ‘Consolidations’ ” section of Note 2 for a discussion of the impact of new accounting guidance effective January 1, 2010.

We are currently the primary beneficiary of Sabine, DHLC, JMG, DCC Fuel LLC (DCC Fuel), AEP Credit and a protected cell of EIS.  As of January 1, 2010, we are no longer the primary beneficiary of DHLC as defined by new accounting guidance for “Variable Interest Entities.”  In addition, we have not provided material financial or other support to Sabine, DCC Fuel, our protected cell of EIS and AEP Credit that was not previously contractually required.  We hold a significant variable interest in Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series).  In addition, we have not provided material financial or other support to Sabine, DHLC, DCC Fuel or EIS that was not previously contractually required.  Refer to the discussion of JMG below for details regarding payments that were not contractually required. and DHLC.

Sabine is a mining operator providing mining services to SWEPCo.  SWEPCo has no equity investment in Sabine but is Sabine’s only customer.  SWEPCo guarantees the debt obligations and lease obligations of Sabine.  Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo.  The creditors of Sabine have no recourse to any AEP entity other than SWEPCo.  Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee.  In addition, SWEPCo determines how much coal will be mined for each year.  Based on these facts, management has concluded that SWEPCo is the primary beneficiarybeneficia ry and is required to consolidate Sabine.  SWEPCo’s total billings from Sabine for the three months ended September 30,March 31, 2010 and 2009 and 2008 were $34$43 million and $31 million, respectively, and for the nine months ended September 30, 2009 and 2008 were $95 million and $79$35 million, respectively.  See the tables below for the classification of Sabine’s assets and liabilities on our Condensed Consolidated Balance Sheets.

DHLC is a wholly-owned subsidiary of SWEPCo.  DHLC is a mining operator who sells 50% of the lignite produced to SWEPCo and 50% to Cleco Corporation, a nonaffiliated company.  SWEPCo and Cleco Corporation share half of the executive board seats, with equal voting rights and each entity guarantees a 50% share of DHLC’s debt.  SWEPCo and Cleco Corporation equally approve DHLC’s annual budget.  The creditors of DHLC have no recourse to any AEP entity other than SWEPCo.  As SWEPCo is the sole equity owner of DHLC it receives 100% of the management fee.  Based on the structure and equity ownership, managementEIS has concluded that SWEPCo is the primary beneficiary and is required to consolidate DHLC.  SWEPCo’s total billings from DHLC for the three months ended September 30, 2009 and 2008 were $12 million and $11 million, respectively, and for the nine months ended September 30, 2009 and 2008 were $31 million and $32 million, respectively.  See the tables below for the classification of DHLC assets and liabilities on our Condensed Consolidated Balance Sheets.

OPCo has a lease agreement with JMG to finance OPCo’s Flue Gas Desulfurization (FGD) system installed on OPCo’s Gavin Plant.  The PUCO approved the original lease agreement between OPCo and JMG.  JMG owns and leases the FGD to OPCo.  JMG is considered a single-lessee leasing arrangement with only one asset.  OPCo’s lease payments are the only form of repayment associated with JMG’s debt obligations even though OPCo does not guarantee JMG’s debt.  The creditors of JMG have no recourse to any AEP entity other than OPCo for the lease payment.  Based on the structure of the entity, management has concluded OPCo is the primary beneficiary and is required to consolidate JMG.  In April 2009, OPCo paid JMG $58 million which was used to retire certain long-term debt of JMG.  While this payment was not contractually required, OPCo made this payment in anticipation of purchasing the outstanding equity of JMG.  In July 2009, OPCo purchased all of the outstanding equity ownership of JMG for $28 million resulting in an elimination of OPCo’s Noncontrolling Interest related to JMG and an increase in Common Shareholder’s Equity of $54 million.  In August and September 2009, JMG reacquired $218 million of auction rate debt, funded by OPCo capital contributions to JMG.  These reacquisitions were not contractually required.  JMG is a wholly-owned subsidiary of OPCo with a capital structure of 85% equity, 15% debt.

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

EIS is a captive insurance company with multiple protected cells in which ourcells.  Our subsidiaries participate in one protected cell for approximately ten lines of insurance.  Neither AEP nor its subsidiaries have an equity investment inof EIS.  The AEP system is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance.  Our subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims.  Based on our control and the structure of the protected cell and EIS, management has concluded that we are the primary beneficiary of the protected cell and we are required to consolidate the protected cell.its assets and liabilities.  Our insurance premium payments to EISthe protected cell for the three months ended September 30,March 31, 2010 and 2009 and 2008 were $13$18 million and $11 million, respectively, and for the nine months ended September 30, 2009 and 2008 were $30 million and $28 million,$17 m illion, respectively.  See the tables below for the classification of EIS’sthe protected cell’s assets and liabilities on our Condensed Consolidated Balance Sheets.  The amount reported as equity is the protected cell’s policy holders’ surplus.

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

AEP Credit is a wholly-owned subsidiary of AEP.  AEP Credit purchases, without recourse, accounts receivable from certain utility subsidiaries of AEP to reduce working capital requirements.  AEP provides up to 20% of AEP Credit short-term borrowing needs in excess of third party financings.  Any third party financing of AEP Credit only has recourse to the receivables sold for such financing.  Based on our control of AEP Credit, management has concluded that we are the primary beneficiary and are required to consolidate its assets and liabilities.  See the tables below for the classification of AEP Credit’s assets and liabilities on our Condensed Consolidated Balance Sheets.  See “ASU 2009-17 ‘Consolidation’ ” section of Note 2 for discussion of im pact of new accounting guidance effective January 1, 2010.  Also see “Sale of Receivables – AEP Credit” section of Note 14 in the 2009 Annual Report for further information.

DHLC is a wholly-owned subsidiary of SWEPCo.  DHLC is a mining operator that sells 50% of the lignite produced to SWEPCo and 50% to CLECO.  SWEPCo and CLECO share the executive board seats and its voting rights equally.  Each entity guarantees a 50% share of DHLC’s debt.  SWEPCo and CLECO equally approve DHLC’s annual budget.  The creditors of DHLC have no recourse to any AEP entity other than SWEPCo.  As SWEPCo is the sole equity owner of DHLC it receives 100% of the management fee.  Based on the shared control of DHLC’s operations, management concluded as of January 1, 2010 that SWEPCo is no longer the primary beneficiary and is no longer required to consolidate DHLC.  SWEPCo’s total billings from DHLC for the three months ended Ma rch 31, 2010 and March 31, 2009 were $13 million and $11 million, respectively.  See the tables below for the classification of DHLC assets and liabilities on our Condensed Consolidated Balance Sheet at December 31, 2009 as well as our investment and maximum exposure as of March 31, 2010.  As of March 31, 2010, DHLC is reported as an equity investment in Deferred Charges and Other Noncurrent Assets on our Condensed Consolidated Balance Sheet.  Also, see “ASU 2009-17 ‘Consolidations’ ” section of Note 2 for discussion of impact of new accounting guidance effective January 1, 2010.

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

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
September 30, 2009March 31, 2010
(in millions)

 
SWEPCo
Sabine
  
SWEPCo
DHLC
  
OPCo
JMG
  
I&M
DCC Fuel
  EIS  
SWEPCo
Sabine
  
I&M
DCC Fuel
  
Protected Cell
of EIS
  AEP Credit 
ASSETS                           
Current Assets $38  $19  $18  $38  $125  $51  $56  $145  $844 
Net Property, Plant and Equipment  133   29   407   101   -   146   77   -   - 
Other Noncurrent Assets  30   10   -   65   2   34   49   2   8 
Total Assets $201  $58  $425  $204  $127  $231  $182  $147  $852 
                                    
LIABILITIES AND EQUITY                                    
Current Liabilities $27  $15  $20  $38  $38  $35  $41  $42  $808 
Noncurrent Liabilities  174   40   46   166   75   196   141   82   - 
Equity  -   3   359   -   14   -   -   23   44 
Total Liabilities and Equity $201  $58  $425  $204  $127  $231  $182  $147  $852 


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
December 31, 20082009
(in millions)

 
SWEPCo
Sabine
  
SWEPCo
DHLC
  
OPCo
JMG
  
I&M
DCC Fuel
  EIS  
SWEPCo
Sabine
  
SWEPCo
DHLC
  
I&M
DCC Fuel
  
Protected Cell
of EIS
 
ASSETS                           
Current Assets $33  $22  $11  $-  $107  $51  $8  $47  $130 
Net Property, Plant and Equipment  117   33   423   -   -   149   44   89   - 
Other Noncurrent Assets  24   11   1   -   2   35   11   57   2 
Total Assets $174  $66  $435  $-  $109  $235  $63  $193  $132 
                                    
LIABILITIES AND EQUITY                                    
Current Liabilities $32  $18  $161  $-  $30  $36  $17  $39  $36 
Noncurrent Liabilities  142   44   257   -   60   199   38   154   74 
Equity  -   4   17   -   19   -   8   -   22 
Total Liabilities and Equity $174  $66  $435  $-  $109  $235  $63  $193  $132 

Our investment in DHLC was:

 March 31, 2010 
 As Reported on   
 the Consolidated Maximum 
 Balance Sheet Exposure 
 (in millions) 
Capital Contribution from Parent $7  $7 
Retained Earnings  1   1 
SWEPCo’s Guarantee of Debt  -   44 
         
Total Investment in DHLC $8  $52 

In September 2007, we and Allegheny Energy Inc. (AYE) formed a joint venture by creating Potomac-Appalachian Transmission Highline, LLC (PATH).  PATH is a series limited liability company and was created to construct a high-voltage transmission line project in the PJM region.  PATH consists of the “Ohio Series,” the “West Virginia Series (PATH-WV),” both owned equally by AYE and AEP and the “Allegheny Series” which is 100% owned by AYE.  Provisions exist within the PATH-WV agreement that make it a VIE.  The “Ohio Series” does not include the same provisions that make PATH-WV a VIE.  Neither the “Ohio Series” or “Allegheny Series” are considered VIEs.  The other series is not considered a VIE.  We are not required to consolidate PATH-WV as we are notno t the primary beneficiary, although we hold a significant variable interest in PATH-WV.  Our equity investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on our Condensed Consolidated Balance Sheets.  We and AYE share the returns and losses equally in PATH-WV.  Our subsidiaries and AYE’s subsidiaries provide services to the PATH companies through service agreements. At the current time, PATH-WV has no debt outstanding.  However, when debt is issued, the debt to equity ratio in each series shouldis expected to be consistent with other regulated utilities.  The entities recover costs through regulated rates.

Given the structure of the entity, we may be required to provide future financial support to PATH-WV in the form of a capital call.  This would be considered an increase to our investment in the entity.  Our maximum exposure to loss is to the extent of our investment.  The likelihood of such a loss is remote since the FERC approved PATH-WV’s request for regulatory recovery of cost and a return on the equity invested.

Our investment in PATH-WV was:

  September 30, 2009 December 31, 2008 
  
As Reported on the Consolidated
Balance Sheet
 
Maximum
Exposure
 
As Reported on the Consolidated
Balance Sheet
  
Maximum
Exposure
 
    (in millions)    
Capital Contribution from AEP $11  $11  $4  $4 
Retained Earnings  2   2   2   2 
                 
Total Investment in PATH-WV $13  $13  $6  $6 

Revenue Recognition – Traditional Electricity Supply and Demand
 March 31, 2010 December 31, 2009 
 As Reported on   As Reported on   
 the Consolidated Maximum the Consolidated Maximum 
 Balance Sheet Exposure Balance Sheet Exposure 
 (in millions) 
Capital Contribution from Parent $14  $14  $13  $13 
Retained Earnings  3   3   3   3 
                 
Total Investment in PATH-WV $17  $17  $16  $16 

Revenues are recognized from retailEarnings Per Share (EPS)

Basic earnings per common share is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period.  Diluted earnings per common share is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and wholesale electricity salesawards.

The following table presents our basic and electricity transmission and distribution delivery services.  We recognize the revenuesdiluted EPS calculations included on our Condensed Consolidated Statements of Income upon delivery of the energy to the customer and include unbilled as well as billed amounts.Income:

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

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

CSPCo and OPCo Revised Depreciation Rates

Effective January 1, 2009, we revised book depreciation rates for CSPCo and OPCo generating plants consistent with a recently completed depreciation study.  OPCo’s overall higher depreciation rates primarily related to shortened depreciable lives for certain OPCo generating facilities.  In comparing 2009 and 2008, the change in depreciation rates resulted in a net increase (decrease) in depreciation expense of:

 Total Depreciation Expense Variance 
 Three Months Ended Nine Months Ended 
 September 30, 2009/2008 September 30, 2009/2008 
 (in millions) 
CSPCo $(4) $(13)
OPCo  18   52 
  Three Months Ended March 31, 
  2010  2009 
  (in millions, except per share data) 
    $/share    $/share 
Earnings Attributable to AEP Common Shareholders $344     $360    
               
Weighted Average Number of Basic Shares Outstanding  478.4  $0.72   406.8  $0.89 
Weighted Average Dilutive Effect of:                
Performance Share Units  0.3   -   0.5   - 
Restricted Stock Units  0.1   -   0.1   - 
Weighted Average Number of Diluted Shares Outstanding  478.8  $0.72   407.4  $0.89 

The assumed conversion of stock options does not affect net changeearnings for purposes of calculating diluted earnings per share.

Options to purchase 437,866 and 618,916 shares of common stock were outstanding at March 31, 2010 and 2009, respectively, but were not included in depreciation rates resulted in decreases to our net-of-tax, basicthe computation of diluted earnings per share attributable to AEP common shareholders.  Since the options’ exercise prices were greater than the quarter-end market price of $0.02 and $0.06 for the three months ended September 30, 2009 and nine months ended September 30, 2009, respectively.common shares, the effect would have been antidilutive.

Supplementary Information
 
Three Months Ended
September 30,
  
Nine Months Ended
September 30,
  Three Months Ended March 31, 
 2009  2008  2009  2008  2010  2009 
Related Party Transactions (in millions)  (in millions) 
AEP Consolidated Revenues – Utility Operations:                  
Power Pool Purchases – Ohio Valley Electric Corporation (43.47% owned) (a) $-  $(14) $-  $(40)
AEP Consolidated Revenues – Other:                
Ohio Valley Electric Corporation (43.47%) (a) $(9) $- 
AEP Consolidated Revenues – Other Revenues:        
Ohio Valley Electric Corporation – Barging and Other Transportation Services (43.47% Owned)  7   7   22   21   8   9 
AEP Consolidated Expenses – Purchased Energy for Resale:                
AEP Consolidated Expenses – Purchased Electricity for Resale:        
Ohio Valley Electric Corporation (43.47% Owned)(b)  71   70   213   194   77   70 

(a)In 2006,January 2010, the AEP Power Pool began purchasing power from OVEC as part of risk management activities.to serve off-system sales through June 2010.
(b)In January 2010, the AEP Power Pool began purchasing power from OVEC to serve retail sales through June 2010.  The agreement expiredtotal amount reported in May 2008 and subsequently ended in December 2008.2010 includes $6 million related to the new agreement.

Shown below are income statement amounts attributableAdjustments to AEP common shareholders:Reported Cash Flows

 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
 2009 2008 2009 2008 
Amounts Attributable To AEP Common Shareholders(in millions) 
Income Before Discontinued Operations and Extraordinary Loss $443  $374  $1,124  $1,227 
Discontinued Operations, Net of Tax  -   -   -   1 
Extraordinary Loss, Net of Tax  -   -   (5)  - 
Net Income $443  $374  $1,119  $1,228 
In the Financing Activities section of our Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2009, we corrected the presentation of borrowings on our lines of credit of $28 million from Change in Short-term Debt, Net to Borrowings from Revolving Credit Facilities.  We also corrected the presentation of repayments on our lines of credit of $28 million for the three months ended March 31, 2009 to Repayments to Revolving Credit Facilities from Change in Short-term Debt, Net.  The correction to present borrowings and repayments on our lines of credit on a gross basis was not material to our financial statements and had no impact on our previously reported net income, changes in shareholders' equity, financial position or net cash flows from financing activities.

2.NEW ACCOUNTING PRONOUNCEMENTS AND EXTRAORDINARY ITEM

NEW ACCOUNTING PRONOUNCEMENTS

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

Pronouncements Adopted During 2009The First Quarter of 2010

The following standards wereare effective during the first nine monthsquarter of 2009.2010.  Consequently, their impact is reflected in the financial statements and footnotes reflectstatements.  The following paragraphs discuss their impact.

SFAS 141 (revised 2007) “Business Combinations” (SFAS 141R)ASU 2009-16 “Transfers and Servicing” (ASU 2009-16)

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

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

We adopted SFAS 141R, including the FSP, effective January 1, 2009.  It is effective prospectively for business combinations with an acquisition date on or after January 1, 2009.  We had no business combinations in 2009.  We will apply it to any future business combinations.  SFAS 141R is included in the “Business Combinations” accounting guidance.

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

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

We adopted SFAS 160 effective January 1, 2009 and retrospectively applied the standard to prior periods.  SFAS 160 is included in the “Consolidation” accounting guidance.  The retrospective application of this standard:

·Reclassifies Minority Interest Expense of $1 million and $3 million and Interest Expense of $0 million and $1 million for the three and nine months ended September 30, 2008, respectively, as Net Income Attributable to Noncontrolling Interest below Net Income in the presentation of Earnings Attributable to AEP Common Shareholders in our Condensed Consolidated Statements of Income.
·Repositions Preferred Stock Dividend Requirements of Subsidiaries of $1 million and $2 million for the three and nine months ended September 30, 2008, respectively, below Net Income in the presentation of Earnings Attributable to AEP Common Shareholders in our Condensed Consolidated Statements of Income.
·Reclassifies minority interest of $17 million as of December 31, 2008 previously included in Deferred Credits and Other Noncurrent Liabilities and Total Liabilities as Noncontrolling Interests in Total Equity on our Condensed Consolidated Balance Sheets.
·Separately reflects changes in Noncontrolling Interests on the Condensed Consolidated Statements of Changes in Equity and Comprehensive Income (Loss).
·Reclassifies dividends paid to noncontrolling interests of $6 million for the nine months ended September 30, 2008 from Operating Activities to Financing Activities in our Condensed Consolidated Statements of Cash Flows.

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

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

We adopted SFAS 161 effective January 1, 2009.  This standard increased our disclosures related to derivative instruments and hedging activities.  See Note 8.  SFAS 161 is included in the “Derivatives and Hedging” accounting guidance.

SFAS 165 “Subsequent Events” (SFAS 165)

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

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

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

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

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

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

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

We adopted EITF 08-5 effective January 1, 2009.  With the adoption of FSP SFAS 107-1 and APB 28-1, it is applied to the fair value of long-term debt.  The application of this standard had an immaterial effect on the fair value of debt outstanding.  EITF 08-5 is included in the “Fair Value Measurements and Disclosures” accounting guidance.

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

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

We adopted EITF 08-6 effective January 1, 2009 with no impact on our financial statements.  It was applied prospectively.  EITF 08-6 is included in the “Investments – Equity Method and Joint Ventures” accounting guidance.

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

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

We adopted EITF 03-6-1 effective January 1, 2009.  The adoption of this standard had an immaterial impact on our financial statements.  EITF 03-6-1 is included in the “Earnings Per Share” accounting guidance.

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

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

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

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

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

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

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

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

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

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

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

We adopted SFAS 157-2 effective January 1, 2009.  We will apply these requirements to applicable fair value measurements which include new asset retirement obligations and impairment analyses related to long-lived assets, equity investments, goodwill and intangibles.  We did not record any fair value measurements for nonrecurring nonfinancial assets and liabilities in the first nine months of 2009.  SFAS 157-2 is included in the “Fair Value Measurements and Disclosures” accounting guidance.
FSP SFAS 157-4 “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (FSP SFAS 157-4
In April 2009, the FASB issued FSP SFAS 157-4 providing additional guidance on estimating fair value when the volume and level of activity for an asset or liability has significantly decreased, including guidance on identifying circumstances indicating when a transaction is not orderly.  Fair value measurements shall be based on the price that would be received to sell an asset or paid to transfer a liability in an orderly (not a distressed sale or forced liquidation) transaction between market participants at the measurement date under current market conditions.  The standard also requires disclosures of the inputs and valuation techniques used to measure fair value and a discussion of changes in valuation techniques and related inputs, if any, for both interim and annual periods.

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

Pronouncements Effective in the Future

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

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

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

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

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

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

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

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

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

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

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

In June 2009, the FASB issued SFAS 1662009-16 clarifying when a transfer of a financial asset should be recorded as a sale.  The standard defines participating interest to establish specific conditions for a sale of a portion of a financial asset.  This standard must be applied to all transfers after the effective date.

SFAS 166 is effective for interim and annual reporting in fiscal years beginning after November 15, 2009.  Early adoption is prohibited.  We continue to review the impact of this standard.  We will adopt SFAS 166adopted ASU 2009-16 effective January 1, 2010.  SFAS 166 is includedAEP Credit transfers an interest in receivables it acquires from certain of its affiliates to bank conduits and receives cash.  As of December 31, 2009, AEP Credit owed $656 million to bank conduits related to receivable sales outstanding.  Upon adoption of ASU 2009-16, future transactions do not constitute a sale of receivables and are accounted for as financings.  Effective January 2010, we record the “Transfersreceivables and Servicing” accounting guidance.related debt on our Condensed Consolidated Balance Sheet.

SFAS 167 “Amendments to FASB Interpretation No. 46(R)” (SFAS 167)ASU 2009-17 “Consolidations” (ASU 2009-17)

In June 2009, the FASB issued SFAS 167ASU 2009-17 amending the analysis an entity must perform to determine if it has a controlling financial interest in a variable interest entity (VIE).  This newVIE.  In addition to presentation and disclosure guidance, ASU 2009-17 provides that the primary beneficiary of a VIE must have both:

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

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

SFAS 167 is effective for interim and annual reporting in fiscal years beginning after November 15, 2009.  Early adoption is prohibited.  We continue to review the impact of the changes in the consolidation guidance on our financial statements.  This standard will increase our disclosure requirements related to transactions with VIEs and may change the presentation of consolidated VIE’s assets and liabilities on our Condensed Consolidated Balance Sheets.  We will adopt SFAS 167ASU 2009-17 effective January 1, 2010.  SFAS 167 is included in2010 and deconsolidated DHLC.  DHLC was deconsolidated due to the “Consolidation” accounting guidance.

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

In December 2008,shared control between SWEPCo and CLECO.  After January 1, 2010, we report DHLC using the FASB issued FSP SFAS 132R-1 providing additional disclosure guidance for pension and OPEB plan assets.  The rule requires disclosureequity method of investment policies including target allocations by investment class, investment goals, risk management policies and permitted or prohibited investments.  It specifies a minimum of investment classes by further dividing equity and debt securities by issuer grouping.  The standard adds disclosure requirements including hierarchical classes for fair value and concentration of risk.accounting.

This standard is effective for fiscal years ending after December 15, 2009.  Management expects this standard to increase theincreased our disclosure requirements related to our benefit plans.  We will adopt the standard effective for the 2009 Annual Report.  FSP SFAS 132R-1 is included in the “Compensation – Retirement Benefits” accounting guidance.

Future Accounting Changes

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

EXTRAORDINARY ITEM

SWEPCo Texas Restructuring

In August 2006, the PUCT adopted a rule extending the delay in implementation of customer choice in SWEPCo’s SPP area of Texas until no sooner than JanuaryNote 1 2011.  In May 2009, the governor of Texas signed a bill related to SWEPCo’s SPP area of Texas that requires continued cost of service regulation until certain stages have been completed and approved by the PUCT such that fair competition is available to all Texas retail customer classes.  Based upon the signing of the bill, SWEPCo re-applied “Regulated Operations” accounting guidance for the generation portion of SWEPCo’s Texas retail jurisdiction effective second quarter of 2009.  Management believes that a switch to competition in the SPP area of Texas will not occur.  The reapplication of “Regulated Operations” accounting guidance resulted in an $8 million ($5 million, net of tax) extraordinary loss.further discussion.

3.RATE MATTERS

As discussed in the 20082009 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions.  The Rate Matters note within our 20082009 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 20092010 and updates the 20082009 Annual Report.

OhioRegulatory Assets Not Yet Being Recovered
  March 31,  December 31, 
  2010  2009 
  (in millions) 
       
Noncurrent Regulatory Assets (excluding fuel)      
Regulatory assets not yet being recovered pending future proceedings to determine the recovery method and timing:      
       
Regulatory Assets Currently Earning a Return      
Customer Choice Deferrals – CSPCo, OPCo $57  $57 
Storm Related Costs – CSPCo, OPCo, TCC  48   49 
Line Extension Carrying Costs – CSPCo, OPCo  46   43 
Acquisition of Monongahela Power – CSPCo  11   10 
Regulatory Assets Currently Not Earning a Return        
Mountaineer Carbon Capture and Storage Project – APCo  111   111 
Environmental Rate Adjustment Clause – APCo  27   25 
Storm Related Costs – KPCo  24   24 
Transmission Rate Adjustment Clause – APCo  21   26 
Peak Demand Reduction/Energy Efficiency – CSPCo, OPCo  12   8 
Special Rate Mechanism for Century Aluminum – APCo  12   12 
Storm Related Costs – PSO  11   - 
Deferred Wind Power Costs – APCo  11   5 
Total Regulatory Assets Not Yet Being Recovered $391  $370 

CSPCo and OPCo Rate Matters

Ohio Electric Security Plan Filings

In March 2009, theThe PUCO issued an order which was amended by a rehearing entry in JulyMarch 2009 that modified and approved CSPCo’s and OPCo’s ESPs thatwhich established standard service offer rates.rates at the start of the April 2009 billing cycle.  The ESPs will beare in effect through 2011.  The ESP order authorized revenue increases during the ESP period and capped the overall revenuealso limits annual rate increases for CSPCo to 7% in 2009, 6% in 2010 and 6% in 2011 and for OPCo to 8% in 2009, 7% in 2010 and 8% in 2011.  Some rate components and increases are exempt from these limitations.  CSPCo and OPCo implemented rates for the April 2009 billing cycle.  In its July 2009 rehearing entry, the PUCO required CSPCo and OPCo to reduce rates implemented in April 2009 by $22 million and $27 million, respectively, on an annualized basis.  CSPCo and OPCo are collectingcollected the 2009 annualized revenue increase over the last nine months of 2009.

The order provides a FAC for the three-year period of the ESP.  The FAC increase will be phased in to avoid having the resultant rate increases exceed the ordered annual caps described above.  The FAC increase before phase-in will beis subject to quarterly true-ups, to actual recoverable FAC costs and to annual accounting audits and prudency reviews.  The order allows CSPCo and OPCo to defer any unrecovered FAC costs resulting from the annual caps/phase-in plancaps and to accrue associated carrying charges on such deferrals at CSPCo’s and OPCo’s weighted average cost of capital.  TheAny deferred FAC regulatory asset balance at the end of the three-year ESP period will be recovered through a non-bypassable surcharge over the period 2012 through 2018.

  Management expects to recover the CSPCo FAC deferral during 2010.  That recovery will include deferrals associated with the Ormet interim arrangement and is subject to the PUCO’s ultimate decision regarding the Ormet interim arrangement deferrals plus related carrying charges.  See the “Ormet Interim Arrangement” section below.  The FAC deferrals at September 30, 2009as of March 31, 2010 were $36$10 million and $238$345 million for CSPCo and OPCo, respectively, inclusiveexcluding $1 million and $13 million, respectively, of unrecognized equity carrying charges atcosts.

Discussed below are the weighted average cost of capital.  Inoutstanding uncertainties related to the July 2009 rehearing order, the PUCO once again rejected a proposal by several intervenors to offset the FAC costs with a credit for off-system sales margins.  As a result, CSPCo and OPCo will retain the benefit of their share of the AEP System’s off-system sales.ESP order:

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

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

·  CSPCo should attempt to mitigate the costs of its gridSMART advanced metering proposal that will affect portions of its service territory by seeking funds under the American Recovery and Reinvestment Act of 2009.  As a result, a rider was established to recover $32 million related to gridSMART during the three-year ESP period.  In August 2009, CSPCo filed for $75 million in federal grant funding under the American Recovery and Reinvestment Act of 2009.
·  CSPCo and OPCo can recover their incremental carrying costs related to environmental investments made from 2001 through 2008 that are not reflected in existing rates.  Future recovery during the ESP period of incremental carrying charges on environmental expenditures incurred beginning in 2009 may be requested in annual filings.

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

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

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

In August 2009, an intervenor filed for rehearing requesting, among other things, that the PUCO order CSPCo and OPCo to cease and desist from charging ESP rates, to revert to the rate stabilization plan rates and to compel a refund, including interest, of the amounts collected by CSPCo and OPCo.  CSPCo and OPCo filed a response stating the rates being charged by CSPCo and OPCo have been authorized by the PUCO and there was no basis for precluding CSPCo and OPCo from continuing to charge those rates.  In September 2009, certain intervenors filed appeals of the March 2009 order and the July 2009 rehearing entryappeal with the Supreme Court of Ohio.  OneOhio raising several issues including alleged retroactive ratemaking, recovery of carrying charges on certain environmental investments, Provider of Last Resort (POLR) charges and the intervenors, the Ohio Consumers’ Counsel, has asked the courtdecision not to stay, pending the outcome of its appeal, a portion of the authorized ESPoffset rates which the Ohio Consumers’ Counsel characterizes as being retroactive.  In October 2009,by off-system sales margins.  A decision from the Supreme Court of Ohio deniedis pending.

In November 2009, the Industrial Energy Users-Ohio group filed a notice of appeal with the Supreme Court of Ohio Consumers' Counsel's requestchallenging components of the ESP order including the POLR charge, the distribution riders for gridSMARTSM and enhanced reliability, the PUCO’s conclusion and supporting evaluation that the modified ESPs are more favorable than the expected results of a staymarket rate offer, the unbundling of the fuel and granted motions to dismiss both appeals.
non-fuel generation rate components, the scope and design of the fuel adjustment clause and the approval of the plan after the 150-day statutory deadline.  A decision from the Supreme Court of Ohio is pending.

In September 2009, CSPCo and OPCoApril 2010, the Industrial Energy Users-Ohio group filed their initial quarterly FAC filinganother notice of appeal with the PUCO.  An order approvingSupreme Court of Ohio challenging alleged retroactive ratemaking, CSPCo's and OPCo's abilities to collect through the FAC 2009 filings will not be issued until a financial auditamounts deferred under the Ormet interim arrangement and prudency reviewthe approval of the plan after the 150-day statutory deadline.  A decision from the Supreme Court of Ohio is performed by independent third parties and reviewed by the PUCO.pending.

In October 2009, the PUCO convened a workshop to begin to determine the methodology for the Significantly Excessive Earnings Test (SEET).  The SEET requires that the PUCO to determine, following the end of each year of the ESP, if rate adjustments included in the ESP resulted in significantly excessive earnings.  This will be determined by measuring whether the utility’s earned return on common equity is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, which have comparable business and financial risk.  In the March 2009 ESP order, the PUCO determined that off-system sales margins and FAC deferral phase-in credits should be excluded from the SEET methodology.  However, the July 2009 PUCO rehearing entry deferred those issues to the SEET workshop.  If the rate adjustments, in the aggregate, result in significantly excessive earnings, the excess amount would be returned to customers.  The PUCO staff recommended that the SEET be calculated on an individual company basis and not on a combined CSPCo/OPCo basis and that off-system sales margins be included in the earnings test.  It is unclear at this time whether the FAC phase-in deferral credits will be included in the earnings test.  Management believes that CSPCo and OPCo should not be required to refund unrecovered FAC regulatory assets until they are collected, assuming there are excessiv e earnings in that year.  In April 2010, the PUCO heard arguments related to various SEET issues including the treatment of the FAC deferrals.  The PUCO’s decision on the SEET review of CSPCo’s and OPCo’s 2009 earningsmethodology is not expected to be finalized until the workshop is completed, the PUCO issues SEET guidelines, a SEET filing is made by CSPCo and OPCo in 2010related to 2009 earnings and the PUCO issues an order thereon.  The SEET workshop will also determine whether CSPCo’s and OPCo’s earnings will be measured on an individual company basis or on a combined CSPCo/OPCo basis.

In October 2009, an intervenor filed a complaint for writ of prohibition with the Supreme Court of Ohio requesting the Court to prohibitApril 2010, CSPCo and OPCo from billing and collecting any ESP rate increases thatfiled a request with the PUCO authorized as the intervenor believes the PUCO's statutory jurisdiction over CSPCo's and OPCo's ESP application ended on December 28, 2008, which was 150 days after theto delay their SEET filing of the ESP applications.until July 2010.  As a result, CSPCo and OPCo plan on filing a response in oppositionare unable to the complaint for writdetermine whether they will be required to return any of prohibition.their ESP revenues to customers.

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

CSPCo, OPCo and Ormet, a large aluminum company, filed an application with the PUCO for approval of an interim arrangement governing the provision of generation service to Ormet.  This interim arrangement was effective from January 2009 through September 2009.  In January 2009, the PUCO approved the application.  In March 2009, the PUCO approved a FAC in the ESP filings.  The approval of the FAC, together with the PUCO approval of the interim arrangement, provided the basis to record regulatory assets for the difference between the approved market price and the rate paid by Ormet.  Through September 2009, the last month of the interim arrangement, CSPCo and OPCo had $30 million and $34 million, respectively, of deferred FAC related to the interim arrangement including recognized carryin g charges but excluding $1 million and $1 million, respectively, of unrecognized equity carrying costs.  In November 2009, CSPCo and OPCo requested that the PUCO approve recovery of the deferrals under the interim agreement, plus a weighted average cost of capital carrying charge.  The interim arrangement deferrals are included in CSPCo’s and OPCo’s FAC phase-in deferral balance.  See “Ohio Electric Security Plan Filings” section above.  In the ESP proceeding, intervenors requested that CSPCo and OPCo be required to refund the Ormet-related regulatory assets and requested that the PUCO prevent CSPCo and OPCo from collecting the Ormet-related revenues in the future.  The PUCO did not take any action on this request in the ESP proceeding.  The intervenors raised the issue again in response to CSPCo’s and OPCo’s November 2009 filing to approve recovery of the deferrals under the interim agreement.  If CSPCo and OPCo are not ultimately permitted to fully recover their requested deferrals under the interim arrangement, it would reduce future net income and cash flows and impact financial condition.

Economic Development Rider

In April 2010, the Industrial Energy Users-Ohio filed a notice of appeal of the PUCO-approved Economic Development Rider (EDR) with the Supreme Court of Ohio.  The Industrial Energy Users-Ohio raised several issues including (a) the PUCO lost jurisdiction over CSPCo’s and OPCo’s ESP proceedings and related proceedings when the PUCO failed to issue ESP orders within the 150 days statutory deadline, (b) the EDR should not be exempt from the ESP annual rate limitations and (c) CSPCo and OPCo should not be allowed to apply a weighted average long-term debt carrying cost on deferred EDR regulatory assets.

As of March 31, 2010, CSPCo and OPCo have incurred $21 million and $12 million, respectively, in EDR costs.  Of these costs, CSPCo and OPCo have collected $8 million and $6 million, respectively, through the EDR, which CSPCo and OPCo began collecting in January 2010.  The remaining $13 million and $6 million for CSPCo and OPCo, respectively, are recorded as EDR regulatory assets.  Management cannot predict the amounts CSPCo and OPCo will defer for future recovery through the EDR.  If CSPCo and OPCo are not ultimately permitted to recover their deferrals or are required to refund revenue collected, it would reduce future net income and cash flows and impact financial condition.

Environmental Investment Carrying Cost Rider

In February 2010, CSPCo and OPCo filed an application with the PUCO to establish an Environmental Investment Carrying Cost Rider to recover carrying costs related to environmental investments in 2009.  CSPCo’s and OPCo’s proposed initial rider would recover $29 million and $37 million, respectively, from July 2010 through December 2011 for carrying costs for 2009 through 2011.  If approved, the implementation of the rider will likely not impact cash flows, but will impact the ESP phase-in plan deferrals associated with the FAC since this rider is within the rate increase caps authorized by the PUCO in the ESP proceedings.

Ohio IGCC Plant

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

The June 2006 order also provided that if CSPCo and OPCo have not commenced a continuous course of construction of the proposed IGCC plant within five years of thebefore June 2006 PUCO order,2011, all pre-construction cost recoveries associated with itemscosts that may be utilized in projects at other jurisdictionssites must be refunded to Ohio ratepayers with interest.

In September 2008, the Ohio Consumers’ Counsel  Intervenors have filed a motionmotions with the PUCO requesting all pre-construction costs be refunded to Ohio ratepayersratepay ers with interest.  In October 2008, CSPCo and OPCo filed a response with the PUCO that argued the Ohio Consumers’ Counsel’s motion was without legal merit and contrary to past precedent.  In January 2009, a PUCO Attorney Examiner issued an order that required CSPCo and OPCo to file a detailed statement outlining the status of the construction of the IGCC plant, including whether CSPCo and OPCo are engaged in a continuous course of construction on the IGCC plant.  In February 2009, CSPCo and OPCo filed a statement that CSPCo and OPCo have not commenced construction of the IGCC plant and CSPCo and OPCo believe there exist real statutory barriers to the construction of any new base load generation in Ohio, including the IGCC plant.  The statement also indicated that while construction on the IGCC plant might not begin by June 2011, changes in circumstances could result in the commencement of construction on a continuous course by that time.

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

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

OrmetSWEPCo Rate Matters

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which is expected to be in service in 2012.  SWEPCo owns 73% of the Turk Plant and will operate the completed facility.  The Turk Plant is currently estimated to cost $1.7 billion, excluding AFUDC, with SWEPCo’s share estimated to cost $1.3 billion, excluding AFUDC.  As of March 31, 2010, excluding costs attributable to its joint owners, SWEPCo has capitalized approximately $777 million of expenditures (including AFUDC and capitalized interest, and related transmission costs of $35 million).  As of March 31, 2010, the joint owners and SWEPCo have contractual construction commitments of approximately $459 million (including related transmission costs of $7 million).  SWEPCo’s share of the contractual construction commitments is $337 million.  If the plant is cancelled, the joint owners and SWEPCo would incur contractual construction cancellation fees, based on construction status as of March 31, 2010, of approximately $121 million (including related transmission cancellation fees of $1 million).  SWEPCo’s share of the contractual construction cancellation fees would be approximately $89 million.

Discussed below are the outstanding uncertainties related to the Turk Plant:

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN).  Following an appeal by certain intervenors, the Arkansas Court of Appeals issued a unanimous decision that, if upheld by the Arkansas Supreme Court, would reverse the APSC’s grant of the CECPN.  The Arkansas Court of Appeals concluded that SWEPCo’s need for base load capacity, the construction and financing of the Turk Plant and the proposed transmission facilities’ construction and location should have been considered by the APSC in a single docket instead of separate dockets.  The Arkansas Supreme Court granted petitions filed by SWEPCo and the APSC to review the Arkansas Court of Appeals’ decision.  The Court heard oral argument s in April 2010.  A decision from the Arkansas Supreme Court is pending.

The PUCT issued an order approving a Certificate of Convenience and Necessity (CCN) for the Turk Plant with the following conditions: (a) a cap on the recovery of jurisdictional capital costs for the Turk Plant based on the previously estimated $1.522 billion projected construction cost, excluding AFUDC and related transmission costs, (b) a cap on recovery of annual CO2 emission costs at $28 per ton through the year 2030 and (c) a requirement to hold Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers.  SWEPCo appealed the PUCT’s order contending the two cost cap restrictions are unlawful.  The Texas Industrial Energy Consumers fi led an appeal contending that the PUCT’s grant of a conditional CCN for the Turk Plant was unnecessary to serve retail customers.  In February 2010, the Texas District Court affirmed the PUCT in all respects.  In March 2010, SWEPCo and the Texas Industrial Energy Consumers appealed the Texas District Court decision.

The LPSC approved SWEPCo’s application to construct the Turk Plant.  The Sierra Club petitioned the LPSC to begin an investigation into the construction of the Turk Plant which was rejected by the LPSC in November 2009.  In December 2009, the Sierra Club refiled its petition as a stand alone complaint proceeding.  In February 2010, SWEPCo filed a motion to dismiss and denied the allegations in the complaint.

In DecemberNovember 2008, CSPCo, OPCoSWEPCo received its required air permit approval from the Arkansas Department of Environmental Quality (ADEQ) and Ormet,commenced construction at the site.  In January 2010, the Arkansas Pollution Control and Ecology Commission (APCEC) upheld the air permit.  In February 2010, the parties who unsuccessfully appealed the air permit to the APCEC filed a large aluminum company currently operating at a reduced loadnotice of approximately 330 MW (Ormet operated at an approximate 500 MW load in 2008), filed an applicationappeal of the APCEC’s decision with the PUCOCircuit Court of Hempstead County, Arkansas.

The wetlands permit was issued by the U.S. Army Corps of Engineers in December 2009.  In February 2010, the Sierra Club, the Audubon Society and others filed a complaint in the Federal District Court for approvalthe Western District of an interim arrangement governingArkansas against the provisionU.S. Army Corps of generation service to Ormet.  The interim arrangement was effective January 1, 2009 and expired in September 2009 uponEngineers challenging the filing of a new PUCO-approved long-term power contract between Ormet and CSPCo/OPCo that was effective prospectively through 2018.  Under the interim arrangement, Ormet would pay the then-current applicable generation tariff rates and riders and CSPCo and OPCo would defer as a regulatory asset, beginning in 2009, the difference between the PUCO-approved 2008 market price of $53.03 per MWHprocess used and the applicable generation tariff rates and riders.  CSPCo and OPCo proposed to recover the deferral through the new FAC phased-in mechanism that they proposed in the ESP proceeding.  In January 2009, the PUCO approved the application as an interim arrangement.  In February 2009, an intervenor filed an application for rehearingterms of the PUCO’s interim arrangement approval.  In March 2009, the PUCO grantedpermit issued to SWEPCo authorizing certain wetland and stream impacts.

Management believes that application for further considerationSWEPCo’s planning, certification and construction of the matters specifiedTurk Plant has been in the rehearing application.  In the PUCO’s July 2009 order discussed below, CSPComaterial compliance with all applicable laws and OPCo were directedregulations.  Further, management expects that SWEPCo will ultimately be able to file an application to recover the appropriate amountscomplete construction of the deferrals underTurk Plant and related transmission facilities and place those facilities in service.  However, if SWEPCo is unable to complete the interim agreementTurk Plant construction and forplace the remainderTurk Plant in service or if SWEPCo cannot recover all of 2009.

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

In March 2009, the PUCO issued an order in the ESP filings which included approval of a FAC for the ESP period.  The approval of an ESP FAC, together with the January 2009 PUCO approval of the Ormet interim arrangement, provided the basis to record regulatory assets for the differential in the approved market price of $53.03 versus the rate paid by Ormet until the effective date of the 2009-2018 power contract.

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

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

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

Hurricane IkeStall Unit

In September 2008,SWEPCo is constructing the Stall Unit, an intermediate load 500 MW natural gas-fired combustion turbine combined cycle generating unit, at its existing Arsenal Hill Plant located in Shreveport, Louisiana.  The Stall Unit is currently estimated to cost $431 million, including $51 million of AFUDC, and is expected to be in service territoriesin mid-2010.  The LPSC and the APSC issued orders capping SWEPCo’s Stall Unit construction costs at $445 million including AFUDC and excluding related transmission costs.

As of CSPCoMarch 31, 2010, SWEPCo has capitalized construction costs of $402 million, including AFUDC, and OPCo were impacted by strong winds fromhas contractual construction commitments of an additional $17 million.  If the remnants of Hurricane Ike.  Under the RSP, which was effective in 2008, CSPCo and OPCo could seek a distribution rate adjustment to recover incremental distribution expenses related to major storm service restoration efforts.  In September 2008, CSPCo and OPCo established regulatory assets of $17 million and $10 million, respectively, for the expected recoveryfinal cost of the storm restoration costs.  In December 2008,Stall Unit were to exceed the PUCO approved these regulatory assets along with a long-term debt only carrying$445 million cost on these regulatory assets.  In its order approvingcap, the deferrals,APSC or LPSC could disallow their jurisdictional allocation of construction costs in excess of the PUCO stated that the mechanism for recovery would be determined in CSPCo’scaps and OPCo’s next distribution rate filings.  At September 30, 2009, CSPCo and OPCo have accrued for future recovery regulatory assets of $18 million and $10 million, respectively, including the approved long-term debt only carrying costs.  If CSPCo and OPCo are not ultimately permitted to recover their storm damage deferrals, it would have an adverse effect onthereby reduce future net income and cash flows.flows and impact financial condition.

2009 Texas Base Rate Filing

In August 2009, SWEPCo filed a rate case with the PUCT to increase its base rates by approximately $75 million annually including a return on equity of 11.5%.  The filing included requests for financing cost riders of $32 million related to construction of the Stall Unit and Turk Plant, a vegetation management rider of $16 million and other requested increases of $27 million.  In April 2010, a settlement agreement was approved by the PUCT to increase SWEPCo’s base rates by approximately $15 million annually, effective May 2010, including a return on equity of 10.33%, which consists of $5 million related to construction of the Stall Unit and $10 million in other increases.  In addition, the settlement agreement will decrease annual depreciation expense by $17 million and allows SWEPCo a $10 million on e-year surcharge rider to recover additional vegetation management costs that SWEPCo must spend within two years.

TCC and TNC Rate Matters

TEXAS RESTRUCTURING

Texas Restructuring Appeals

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

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

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

TCC, the PUCT and intervenors appealed the District Court decision to the Texas Court of Appeals.  In May 2008, the Texas Court of Appeals, affirmed the District Court decision in all but two major respects.  It reversed the District Court’s unfavorable decision which found that the PUCT erred by applying an invalid rule to determine the carrying cost rate.  It also determined that the PUCT erred by not reducing stranded costs by the “excess earnings” that had already been refunded to affiliated REPs.  Management does not believe that TCC will be adversely affected by the Court of Appeals ruling on excess earnings based upon the reasons discussed in the “TCC Excess Earnings” section below.  The favorable commercial unreasonableness judgment entered by the District Court was not reversed.  In June 2008, the Texas Court of Appeals denied intervenors’ motions for rehearing.  In August 2008, TCC, the PUCT and intervenors filed petitions for review with the Texas Supreme Court.  Review is discretionary and the Texas Supreme Court has not yet determined if it will grant review.  In January 2009, theThe Texas Supreme Court requested a full briefing of the proceedings which concluded in June 2009.  A decision is not expected fromhas co ncluded.  The following represent issues where either the Texas SupremeDistrict Court until 2010.or the Texas Court of Appeals recommended the PUCT decision be modified:

TNC received its final true-up order in May 2005 that resulted in refunds via a CTC which have been completed.  TNC appealed its final true-up order, which remains pending in state court.
·  The Texas District Court judge determined that the PUCT erred by applying an invalid rule to determine the carrying cost rate for the true-up of stranded costs.  The Texas Court of Appeals reversed the District Court’s unfavorable decision.

·  The Texas District Court judge determined that the PUCT improperly reduced TCC’s net stranded plant costs for commercial unreasonableness. This favorable decision was affirmed by the Texas Court of Appeals.

·  The Texas Court of Appeals determined that the PUCT erred by not reducing stranded costs by the “excess earnings” that had already been refunded to affiliated REPs.  This decision could be unfavorable unless the PUCT allows TCC to recover the refunds previously made to the REPs.  See the “TCC Excess Earnings” section below.

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

TCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes

TCC’s appeal remains outstandingIn 2006, the PUCT reduced recovery of the amount securitized by $103 million of tax benefits and associated carrying costs related to TCC’s generation assets.  In 2006, TCC obtained a private letter ruling from the stranded costs true-up and related orders regarding whetherIRS which confirmed that such reduction was an IRS normalization violation.  In order to avoid a normalization violation, the PUCT may require TCCagreed to refund certain Accumulated Deferred Investment Tax Credit (ADITC) and Excess Deferred Federal Income Tax (EDFIT) tax benefits to customers.  Subsequent to the PUCT’s ordered reduction to TCC’s securitized stranded costs for certain tax benefits, the PUCT, reacting to possible IRS normalization violations, allowedallow TCC to defer refunding the tax benefits of $103 million of ordered CTC refunds for other true-up items to negate the securitization reduction.  Of the $103 million, $61 million relates to the present value of certain tax benefits applied to reduce the securitization stranded generating assets and $42 million was for subsequent carrying costs.  The deferral of the CTC refunds is pending resolution on whether the PUCT’s securitization refund is an IRS normalization violation.

Since the deferralplus interest through the CTC refund period pending resolution of the normalization issue.  In 2008, the IRS issued a favorable final regulation in March 2008 addressing the normalization requirements for the treatment of ADITC and EDFIT in a stranded cost determination.  Consistent with a Private Letter Ruling TCC received in 2006, the final regulations, clearly state that TCC will sustainwhich supported the IRS’ private letter ruling which would make the refunding of or the reduction of the amount securitized by such tax benefits a normalization violation ifviolation.  After the PUCT orders TCC in aIRS issued its final order after all appeals to flow these tax benefits to customers as partregulations, at the request of the stranded cost true-up.  TCC notified the PUCT that the final regulations were issued.  The PUCT made a request toPUC T, the Texas Court of Appeals forremanded the matter to be remanded backtax normalization issue to the PUCT for further action.  In May 2008, as requested by the PUCT, the Texas Court of Appeals ordered a remand of the tax normalization issue for the consideration of this favorable additional evidence.

evidence including the IRS regulations.  TCC expectsis not accruing interest on the $103 million because it is not probable that the PUCT will alloworder TCC to retainviolate the deferred amounts.  This will have a favorable effect on future net income as TCC will be able to amortizenormalization provision of the deferred ADITC and EDFIT tax benefits to income over the remaining securitization period.  Since management expects that the PUCT will allow TCC to retain the deferred CTC refund amounts in order to avoid an IRS normalization violation, no relatedInternal Revenue Code.  If interest expense has been accrued related to refunds of these amounts.  Ifwere accrued, management estimates interest expense would have been approximately $11$15 million higher for the period July 2008 through September 2009 based on a CTC interest rate of 7.5% with $4 million relating to 2008.March 2010.

IfManagement believes that the PUCT will ultimately allow TCC to retain the deferred amounts, which would have a favorable effect on future net income and cash flows.  Although unexpected, if the PUCT fails to issue a favorable order and orders TCC to return the tax benefits to customers, thereby causing a violation of the IRSresulting normalization regulations, the violation could result in TCC’s repayment to the IRS under the normalization rules, of ADITCAccumulated Deferred Investment Tax Credits (ADITC) on all property, including transmission and distribution property.  This amount approximates $102 million as of September 30, 2009.March 31, 2010.  It could also lead to a loss of TCC’s right to claim accelerated tax depreciation in future tax returns.  If TCC is required to repay its ADITC to the IRS its ADITC and is also required to refund ADITC plus unaccrued interest to customers, it would have an unfavorable effect onred uce future net income and cash flows.  Tax counsel advised management that a normalization violation should not occur until all remedies under law have been exhaustedflows and the tax benefits are actually returned to ratepayers under a nonappealable final order.  Management intends to continue to work with the PUCT to favorably resolve this issue and avoid the adverse effects of a normalization violation on future net income, cash flows andimpact financial condition.

TCC Excess Earnings

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

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

Texas Restructuring – SPP

In August 2006, the PUCT adopted a rule extending the delay in implementation of customer choice in SWEPCo’s SPP area of Texas until no sooner than January 1, 2011.  In May 2009, the governor of Texas signed a bill related to SWEPCo’s SPP area of Texas that requires continued cost of service regulation until certain stages have been completed and approved by the PUCT such that fair competition is available to all Texas retail customer classes.  Based upon the signing of the bill, SWEPCo re-applied “Regulated Operations” accounting guidance for the generation portion of SWEPCo’s Texas retail jurisdiction in the second quarter of 2009.  Management believes that a switch to competition in the SPP area of Texas will not occur.  The reapplication of “Regulated Operations” accounting guidance resulted in an $8 million ($5 million, net of tax) extraordinary loss.

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

OTHER TEXAS RATE MATTERS

Hurricanes Dolly and Ike

In July and September 2008, TCC’s service territory in south Texas was hit by Hurricanes Dolly and Ike, respectively.  TCC incurred $23 million and $2 million in incremental maintenance costs related to service restoration efforts for Hurricanes Dolly and Ike, respectively.  TCC has a PUCT-approved catastrophe reserve which permits TCC to collect $1.3 million annually until the catastrophe reserve reaches $13 million.  Any incremental storm-related maintenance costs can be charged against the catastrophe reserve if the total incremental maintenance costs for a storm exceed $500 thousand.  In June 2008, prior to these hurricanes, TCC had a $2 million balance in its catastrophe reserve account.  Therefore, TCC established a net regulatory asset for $23 million.  The balance in the net catastrophe reserve regulatory asset account as of September 30, 2009 is approximately $22 million.

Under Texas law and as previously approved by the PUCT in prior base rate cases, the regulatory asset will be included in rate base in the next base rate filing.  In connection with the filing of the next base rate case, TCC will evaluate the existing catastrophe reserve ratepayer funding and review potential future events to determine the appropriate increase in the funding level to request both recovery of the then existing regulatory asset balance and to adequately fund a reserve for future storms in a reasonable time period.

2008 Interim Transmission Rates

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

2009 Interim Transmission Rates

In February 2009, TCC and TNC filed applications with the PUCT for an annual interim update of wholesale-transmission rates.  The proposed new interim transmission rates are estimated to increase annual transmission revenues by $8 million and $9 million for TCC and TNC, respectively.  In May 2009, the PUCT and the FERC approved the new interim transmission rates as filed.  TCC and TNC implemented the new rates effective May 2009, subject to review during the next TCC and TNC base rate case.  This review could result in a refund if the PUCT finds that TCC and TNC have not prudently incurred the requested transmission investment.  TCC and TNC have not recorded any provision for refund regarding the interim transmission rates because management believes these new rates are reasonable and necessary to recover costs associated with prudently incurred new transmission investment.  A refund of the interim transmission rates would have an adverse impact on net income and cash flows.

2007 Texas Base Rate Increase Appeal

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

TCC implemented the rate change in June 2007, subject to refund.  In March 2008, therates.  The PUCT issued an order approving ain 2007 which increased TCC’s base rates by $20 million, base rate increase based oneliminated a return on common equitymerger credit rider of 9.96% and an additional $20 million increase in revenues related to the expiration of TCC’s merger credits.  In addition,and reduced depreciation expense was decreasedrates by $7 million and discretionary fee revenues were increased by $3 million.  The order increased TCC’s annual pretax incomePUCT decision was appealed by approximately $50 million.  Various parties appealed the PUCT decision.

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

2009 Texas Base Rate Filing

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

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

ETT 2007 Formation Appeal

In December 2007, TCC contributed $70 million of transmission facilities to ETT an AEPis a joint venture accounted for using the equity method.between AEP Utilities, Inc. and MidAmerican Energy Holdings Company Texas Transco, LLC.  TCC and TNC have sold transmission assets both in service and under construction to ETT.  The PUCT approved ETT's initial rates, a request for a transfer of facilitiesin-service assets and CWIP and a certificate of convenience and necessity (CCN) to operate as a stand alone transmission utility in the ERCOT region.ERCOT.  ETT was allowed a 9.96% after tax return on equity rate in those approvals.  In 2008, intervenors filed a notice of appealequity.  Intervenors appealed the PUCT’s decision to the Travis County District Court.  In October 2008, theThe court ruled that the PUCT exceeded its authority by approving ETT’s application as a stand alone transmission utility without a service area under the wrong section of the statute.  Management believes that ruling is incorrect.  Moreover, ETT provided evidence in its application that ETT complied with what the court determined was the proper section of the statute.

In January 2009, ETT and the PUCT filed appeals to the Texas Court of Appeals.&# 160; In June 2009,March 2010, the Texas Court of Appeals reversed the Travis County District Court and affirmed the PUCT's decision in all material respects.

In a separate development, the Texas governor signed a new law that clarifies the PUCT’s authority to grant CCNs to transmission-onlytransmission only utilities such as ETT.  In September 2009,  ETT filed an application with the PUCT for a CCN under the new law for the purpose of confirming its authority to operate as a transmission-onlytransmission only utility regardless of the outcome of the pending litigation.  The parties toIn March 2010, the litigation pendingPUCT approved the application for a CCN under the new law.  In April 2010, intervenors filed a joint motion for rehearing at the Texas Court of Appeals have stipulated agreement or indicated they are not opposed to ETT’s request.Appeals.

During 2009, TCC and TNC sold $93 million and $1 million, respectively, of additional transmission facilities to ETT.  As of September 30, 2009, AEP’s netMarch 31, 2010, ETT’s investment in ETTproperty, plant and equipment was $47 million.$441 million, of which $39 million was under construction.  Depending upon the result of ETT’s filingCCN rehearing under the new law, the ultimate outcome of the appeals and any resulting remands, TCC and TNC may be required to reacquire transferred assets and projects under construction previously transferred to ETT by ETT if ETT cannot obtainTCC and TNC.  TCC and TNC would not be required to acquire the appropriate approvals.  As of September 30, 2009, ETT’s net investment in property, plant and equipment was $236 million, of which $100 million was under construction.

In September 2008, ETT and a group of other Texas transmission providers filed a comprehensive plan with the PUCT for completion of the Competitive Renewable Energy Zone (CREZ) initiative.  The CREZ initiative is the development of 2,400 miles of new transmission lines to transport electricity from 18,000 MWs of planned wind farm capacity in west Texas to rapidly growing cities in eastern Texas.  In March 2009, the PUCT issued an order pursuant to a January 2009 decision that authorized ETT to pursue the construction of $841 million of new CREZ transmission assets and also initiated a proceeding to develop a sequence of regulatory filings for routing the CREZ transmission lines.  In June 2009, ETT and other parties entered into a settlement agreement establishing dates for these filings.  Pursuant to the settlement agreement, which is pending PUCT approval, ETT would make regulatory filings in 2010 and initiate construction upon receipt of PUCT approval.

ETT,competitive renewable-energy zones projects.  If TCC and TNC are involved in transactions relatingrequired to the transfer to ETT of other transmission assets, which are in various stages of review and approval.  In October 2009, ETT, TCC and TNC filed joint applications with the PUCT for approval to transfer from TCC and TNC to ETT approximately $69 million and $72 million, respectively, of transmissionreacquire these assets and CWIP.  The transfers are planned to be completed by the end of the first quarter of 2010.  A decision from the PUCT is pending.projects, it could impact cash flows and financial condition.

Stall Unit

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

Turk Plant

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

VirginiaAPCo and WPCo Rate Matters

2009 Virginia E&R Costs Recovery FilingBase Rate Case

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

The Virginia E&R cost recovery mechanism under Virginia law ceased effective with costs incurred through December 2008.  However, the 2007 amendments to Virginia’s electric utility restructuring law provide for a rate adjustment clause to be requested in 2009 to recover incremental E&R costs incurred through December 2008.  Under this amendment, APCo filed an application, in May 2009, to recover $102 million of unrecovered 2008 incremental deferred E&R costs plus its 2008 equity costs based on a 12.5% return on equity on its E&R capital investments. However, APCo deferredgeneration and recognized income under the E&R legislation based on a return on equity of 10.1%, which was the Virginia SCC staff’s recommendation in the prior E&R case.  In October 2009, a stipulation agreement was reached between the parties and fileddistribution base rate increase with the Virginia SCC addressing all matters other than rate design and customer class allocation issues.  The stipulation agreement allows APCo to recover Virginia incremental E&R costs of $90$154 million representing costs deferred during 2008 plus unrecognized 2008 equity costs, usingannually based on a 10.6%13.35% return on equity forcommon equity.  The Virginia SCC staff and intervenors have recommended revenue increases ranging from $33 million to $94 million.  Interim rates, subject to refund, became effective in December 2009 but were discontinued in February 2010 when Virginia newly enacted legislation suspended the collection in 2010.  This will result in an immaterial adjustment which will be recorded in the fourth quarter of 2009.interim rates.  The Virginia SCC is expectedrequired to approveissue a final order no later than July 2010 with new rates effective August 2010.  The enacted legislation also stated that depending on the stipulation agreement in the fourth quarterrevenue awarded, a refund of 2009.

As of September 30, 2009, APCo had $88 million of deferred Virginia incremental E&R costs excluding $17 million of unrecognized equity carrying costs.  The $88 million consists of $6 million of over-recovered costs collected under the 2008 surcharge, $14 million approved by the Virginia SCC related to the 2009 surchargeinterim rates may not be necessary.  If a refund is required, it would reduce future net income and $80 million, representing costs deferred during 2008, which were included in the May 2009 E&R filing for collection in 2010.cash flows and impact f inancial condition.

Mountaineer Carbon Capture and Storage Project

In January 2008, APCo and ALSTOM Power, Inc. (Alstom), an unrelated third party, entered into an agreement to jointly constructconstructed a CO2 capture demonstration facility.validation facility, which was placed into service in September 2009.  APCo also constructed and Alstom will each own part of the CO2 capture facility.  APCo will also construct and ownowns the necessary facilities to store the CO2.  RWE AG, a German electric power and natural gas public utility, and the Electric Power Research Institute are participating in the project and providing some funding to offset APCo's costs.  APCo’s estimated cost for its share of the constructed facilities is $74 million.  In May 2009, the West Virginia Department of Environmental Protection issued a permit to inject CO2 that requires, among other items, that APCo monitor the wells for at least 20 years following the cessation of CO2 injection.  In September 2009, the capture portion of the project was placed into service and in October 2009, APCo started injecting CO2 ininto the underground storage.storage facilities.  The injection of CO2 required the recordationrecording of an asset retirement obligation and an offsetting regulatory asset.  Through March 31, 2010, APCo has recorded a noncurrent regulatory asset at its estimated net present value of $36$111 million consisting of $72 million in October 2009.  Through September 30, 2009, APCo incurred $71project costs and $39 million in capitalized project costs which are included in Regulatory Assets.asset retirement costs.

APCo currently earns a return on the Virginia portion of the capitalized project costs incurred through June 30, 2008, as a result of a base rate case settlement approved by the Virginia SCC in November 2008.  In APCo’s July 2009 Virginia base rate filing, APCo requested recovery of and a return on theits estimated increased Virginia jurisdictional share of its CO2 capture and storage project costs includingand recovery of the related asset retirement obligation expenses.  Seeregulatory asset amortization and accretion.  The Virginia Attorney General and the “Virginia Base Rate Filing” section below.  Based onVirginia SCC staff have recommended in the favorable treatment related to the CO2 capture demonstration facility in APCo’s lastpending Virginia base rate case APCo is deferring its carbon capture expense as a regulatory assetthat no recovery be allowed for future recovery.the project.  APCo plans to seek recovery of the West Virginia jurisdictional costs in its next West Virginia base rate filing which is expected to be filed in the firstsecond quarter of 2010.  If APCo cannot recover all of its investment in and expenses related to the deferredMountaineer Carbon Capture and Storage project, costs are disallowed in future Virginia or West Virginia rate proceedings, it could have an adverse effect onwould reduce future net income and cash flows.

Virginia Base Rate Filing

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

Rate Adjustment Clauses

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

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

Virginia Fuel Factor Proceeding

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

APCo’s Filings for an IGCC Plant

See “APCo’s FilingsAPCo filed a petition with the WVPSC requesting approval of a Certificate of Public Convenience and Necessity (CPCN) to construct a 629 MW IGCC power plant in Mason County, West Virginia.  APCo also requested the Virginia SCC and the WVPSC to approve a surcharge rate mechanism to provide for the timely recovery of pre-construction costs and the ongoing financing 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.  The WVPSC granted APCo the CPCN and approved the requested cost recovery.  Various intervenors filed petitions with the WVPSC to reconsider the order.

In 2008, the Virginia SCC issued an order denying APCo’s request for a surcharge rate mechanism based upon its finding that the estimated cost of the plant was uncertain and may escalate.  The Virginia SCC also expressed concerns that the estimated costs did not include a retrofitting of carbon capture and sequestration facilities.  During 2009, based on an unfavorable order received in Virginia, the WVPSC removed the IGCC Plant” section within “West Virginia Rate Matters”case as an active case from its docket and indicated that the conditional CPCN granted in 2008 must be reconsidered if and when APCo proceeds forward with the IGCC plant.

Through March 31, 2010, APCo deferred for disclosure.

future recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia Rate Mattersjurisdiction, approximately $2 million applicable to its FERC jurisdiction and approximately $9 million applicable to its Virginia jurisdiction.

APCo will not start construction of the IGCC plant until sufficient assurance of full cost recovery exists in Virginia and in West Virginia.  If the plant is cancelled, APCo plans to seek recovery of its prudently incurred deferred pre-construction costs which, if not recoverable, would reduce future net income and cash flows and impact financial condition.

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

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

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

In September 2009, the WVPSC issued an order grantingapproving APCo’s and WPCo’s March 2009 ENEC request.  The approved order provided for recovery of an under-recovered balance plus a projected increase in ENEC costs over a four-year phase-in period with an overall increase of $355 million increase to be phased in over the next four years withand a first-year increase of $124 million.  As of September 30, 2009, APCo’s ENEC under-recovery balance was $255 million, which is included in Regulatory Assets.effective October 2009.  The WVPSC also approved a fixed annual carrying cost rate of 4%, effective October 1, 2009, to be applied to the incremental deferred regulatory asset balance that will result from the phase-in plan.  In March 2010, APCo and WPCo filed its second-year request with the WVPSC to increase rates in July 2010 by $96 million.  As of March 31, 2010, APCo’s ENEC under-recovery balance was $318 million which is included in noncurrent regulatory assets.

The order disallowed an immaterial amount of deferred ENEC costs which was recognized in September 2009.  It2009 order also lowered annual coal cost projections by $27 million and deferred recovery of unrecovered ENEC deferrals related to price increases on certain renegotiated coal contracts.  The WVPSC indicated that it would review the prudency of these additional costs in the next ENEC proceeding.  As of September 30, 2009,March 31, 2010, APCo has deferred $13$23 million of unrecovered coal costs on the renegotiated coal contracts which is included in APCo’s $255$318 million ENEC under-recovery regulatory asset and has recorded an additional $5 million in purchased fuel costs oninventory related to the renegotiated coal contracts, which is recorded in Fuel on the Condensed Consolidated Balance Sheets.balance sheets.  Although management believes the portion of its deferred ENEC under-recovery balance attributable to renegotiated coal contracts is probable of recovery, if the WVPSC werewe re to disallow a portion of APCo’s and WPCo’s deferred ENEC costs including any costs incurred in the future related to the renegotiated coal contracts, it could have an adverse effect onreduce future net income and cash flows.
APCo’s Filings for an IGCC Plantflows and impact financial condition.

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

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

In July 2007, APCo filed a request with the Virginia SCC for a rate adjustment clause to recover initial costs associated with the proposed IGCC plant.  The filing requested recovery of an estimated $45 million over twelve months beginning January 1, 2009.  The $45 million included a return on projected CWIP2006 and development, designPrior Fuel and planning pre-construction costs incurred from July 1, 2007 through December 31, 2009.  APCo also requested authorization to defer a carrying cost on deferred pre-construction costs incurred beginning July 1, 2007 until such costs are recovered.Purchased Power

The Virginia SCCOCC filed a complaint with the FERC related to the allocation of off-system sales margins (OSS) among the AEP operating companies in accordance with a FERC-approved allocation agreement.  The FERC issued an orderadverse ruling in April 2008 denying APCo’s requests, in part, upon its finding that the estimated cost of the plant was uncertain and may escalate.  The Virginia SCC also expressed concern that the $2.2 billion estimated cost did not include2008.  As a retrofitting of carbon capture and sequestration facilities.  In July 2008, based on the unfavorable order received in Virginia, the WVPSC issuedresult, PSO recorded a notice seeking comments from parties on how the WVPSC should proceed.  Various parties, including APCo, filed comments with the WVPSC.  In September 2009, the WVPSC removed the IGCC case as an active case from its docket and indicated that the conditional CPCN grantedregulatory liability in 2008 must be reconsidered if and when APCo proceeds forward withto return reallocated OSS to customers.  Starting in March 2009, PSO refunded the IGCC plant.

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

Through September 30, 2009, APCo deferredA reallocation of purchased power costs among AEP West companies for future recovery pre-construction IGCC costsperiods prior to 2002 resulted in an under-recovery of approximately $9$42 million applicableof PSO fuel costs.  PSO recovered the $42 million by offsetting it against an existing fuel over-recovery during the period June 2007 through May 2008.  The Oklahoma Industrial Energy Consumers (OIEC) has contended that PSO should not have collected the $42 million without specific OCC approval.  As such, the OIEC contends that the OCC should require PSO to refund the $42 million it collected through its fuel clause.  The OCC has heard the OIEC appeal and a decision is pending.  In March 2010, PSO filed motions to advance this proceeding since the FERC has ruled on the allocation of off-system sales margins proceeding and PSO has refunded the additional margins to its West Virginia jurisdiction, approximately $2 million applicableretail customers.  If the OCC were to its FERC jurisdiction and approximately $9 million applicableorder PSO to its Virginia jurisdiction.

Although management continues to pursue considerationrefund all or a part of the construction of the IGCC plant, APCo will not start construction of the IGCC plant until sufficient assurance of cost recovery exists.  If the plant is cancelled, APCo plans to seek recovery of its prudently incurred deferred pre-construction costs, which if not recoverable,$42 million, it would have an adverse effect onreduce future net income and cash flows.flows and impact financial condition.

Mountaineer Carbon Capture2008 Fuel and Storage ProjectPurchased Power

See “Mountaineer Carbon CaptureIn July 2009, the OCC initiated a proceeding to review PSO’s fuel and Storage Project” section within “Virginia Rate Matters”purchased power adjustment clause for disclosure.the calendar year 2008 and also initiated a prudency review of the related costs.  In March 2010, the Oklahoma Attorney General and the OIEC recommended the fuel clause adjustment rider be amended so that the shareholder’s portion of off-system sales margins sharing decrease from 25% to 10%.  The OIEC also recommended that the OCC conduct a comprehensive review of all affiliate transactions during 2007 and 2008.  If the OCC were to issue an unfavorable decision, it would reduce future net income and cash flows and impact financial condition.

2008 Oklahoma Base Rate Appeal

In January 2009, the OCC issued a final order approving an $81 million increase in PSO’s non-fuel base revenues based on a 10.5% return on equity.  The new rates reflecting the final order were implemented with the first billing cycle of February 2009.  PSO and intervenors filed appeals with the Oklahoma Supreme Court raising various issues.  The Oklahoma Supreme Court assigned the case to the Court of Civil Appeals.  If the intervenors’ appeals are successful, it could reduce future net income and cash flows and impact financial condition.

I&M Rate Matters

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

I&M filed applications with the IURC to increase its fuel adjustment charge by approximately $53 million for the period of April 2009 through September 2009.  The filings sought increases for previously under-recovered fuel clause expenses.

As fully discussed in the “Cook Plant Unit 1 Fire and Shutdown” section of Note 4, Cook Unit 1 was shut down in September 2008 due to significant turbine damage and a small fire on the electric generator.  Unit 1 was placed back into service in December 2009 at slightly reduce power.  The unit outage resulted in increased replacement power fuel costs.  The filing only requested the cost of replacement power through mid-December 2008, the date when I&M began receiving accidental outage insurance proceeds.  I&M committed to absorb the costs of replacement power through the date the unit returned to service, which occurred in December 2009.

I&M reached an agreement with intervenors, which was approved by the IURC in March 2009, to collect its existing prior period under-recovery regulatory asset deferral balance over twelve months instead of over six months as initially proposed.  Under the agreement, the fuel factors were placed into effect, subject to refund, and a subdocket was established to consider issues relating to the Unit 1 shutdown including the treatment of the accidental outage insurance proceeds.  A procedural schedule has been established for the subdocket with hearings expected to be held in November 2010.

Management believes that I&M is entitled to retain the accidental outage insurance proceeds since it made customers whole regarding the replacement power costs.  If any fuel clause revenues or accidental outage insurance proceeds have to be refunded, it would reduce future net income and cash flows and impact financial condition.

2009 Power Supply Cost Recovery (PSCR) Reconciliation (Cook Plant Unit 1 Fire and Shutdown)

In March 2010, I&M filed its 2009 PSCR reconciliation with the MPSC.  The filing included an adjustment to exclude from the PSCR the incremental fuel cost of replacement power due to the Cook Plant Unit 1 outage from mid-December 2008 through December 2009, the period during which I&M received and recognized the accidental outage insurance proceeds.  Management believes that I&M is entitled to retain the accidental outage insurance proceeds since it made customers whole regarding the replacement power costs.  If any fuel clause revenues or accidental outage insurance proceeds have to be refunded, it would reduce future net income and cash flows and impact financial condition.  See the “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.

Michigan Base Rate Filing

In January 2010, I&M filed for a $63 million increase in annual base rates based on an 11.75% return on common equity.  I&M can request interim rates, subject to refund, after six months.  The MPSC must issue a final order within one year.

Kentucky Rate Matters

Kentucky Storm Restoration Expenses

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

Indiana Rate Matters

Indiana Base Rate Filing

In December 2009, KPCo filed a January 2008 filingbase rate case with the IURC, updated inKPSC to increase base revenues by $124 million annually based on an 11.75% return on common equity.  The base rate case also requested recovery of $24 million of deferred storm restoration expenses as of March 31, 2010 over a three-year period.  In April 2010, the second quarterKentucky Industrial Utility Customers filed testimony with the KPSC which recommends an annual base revenue increase of 2008, I&M requested an increase in its Indiana base rates of $80no more than $41 million based on a 10.1% return on equity of 11.5%.  The base rate increase included a $69 million annual reduction incommon equity.  New rates dueare expected to an approved reduction in depreciation expense previously approved by the IURC and implemented for accounting purposesbecome effective June 2007.  In addition, I&M proposed to share with customers, through a proposed tracker, 50% of its off-system sales margins initially estimated to be $96 million annually with a guaranteed credit to customers of $20 million.

In December 2008, I&M and all of the intervenors jointly filed a settlement agreement with the IURC proposing to resolve all of the issues in the case.  The settlement agreement incorporated the $69 million annual reduction in revenues from the depreciation rate reduction in the development of an agreed to revenue increase of $44 million, which included a $22 million increase in base rates based on an authorized return on equity of 10.5% and a $22 million initial increase in tracker rates for incremental PJM, net emission allowance and demand side management (DSM) costs.  The agreement also establishes an off-system sales sharing mechanism and other provisions which include continued funding for the eventual decommissioning of the Cook Plant.

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

Rockport and Tanners Creek Plants Environmental Facilities

In January 2009, I&M filed a petition with the IURC requesting approval of a Certificate of Public Convenience and Necessity (CPCN) to use advanced coal technology which would allow I&M to reduce airborne emissions of NOx and mercury from its existing coal-fired steam electric generating units at the Rockport and Tanners Creek Plants.  In addition, the petition requested approval to construct and recover the costs of selective non-catalytic reduction (SNCR) systems at the Tanners Creek Plant and to recover the costs of activated carbon injection (ACI) systems on both generating units at the Rockport Plant.  The petition requested to depreciate the ACI systems over an accelerated 10-year period and the SNCR systems over the 11-year remaining useful life of the Tanners Creek generating units.

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

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

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

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

Consistent with the March 2009 IURC order, I&M made its semi-annual fuel filing in July 2009 requesting an increase of approximately $4 million for2010.  If the period October 2009 through March 2010.  The projected fuel costs for the period included the second half of the under-recovered deferral balance approved in the March 2009 order plus recovery of an additional $12 million under-recovered deferral balance from the reconciliation period of December 2008 through May 2009.

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

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

Michigan Rate Matters

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

In March 2009, I&M filed with the Michigan Public Service Commission (MPSC) its 2008 PSCR reconciliation.  The filing also included an adjustment to reduce the incremental fuel cost of replacement power due to the Cook Plant Unit 1 outage with a portion of the accidental insurance proceeds from the Cook Plant Unit 1 outage policy, which began in mid-December 2008.  See “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.  In May 2009, the MPSC set a procedural schedule for testimony and hearings to be held in the fourth quarter of 2009.  A final order is anticipated in the first quarter of 2010.  Management is unable to predict the outcome of this proceeding and whether it will have an adverse effect on future net income and cash flows.  

Oklahoma Rate Matters

PSO Fuel and Purchased Power

2006 and Prior Fuel and Purchased Power

Proceedings addressing PSO’s historic fuel costs from 2001 through 2006 remain open at the OCC due to two issues.  The first issue relates to the allocation of off-system sales margins (OSS) among the AEP operating companies in accordance with a FERC-approved allocation agreement.  In June 2008, the Oklahoma Industrial Energy Consumers (OIEC) appealed the ALJ recommendations that concluded the FERC and not the OCC had jurisdiction over this matter.  In August 2008, the OCC filed a complaint with the FERC concerning this allocation of OSS issue.  In December 2008, under an adverse FERC ruling, PSO recorded a regulatory liability to return the reallocated OSS to customers.  Effective with the March 2009 billing cycle, PSO began refunding the additional reallocated OSS to its customers.  See “Allocation of Off-system Sales Margins” section within “FERC Rate Matters.”

The second issue concerns a 2002 under-recovery of $42 million of PSO fuel costs resulting from a reallocation among AEP West companies of purchased power costs for periods prior to 2002.  PSO recovered the $42 million by offsetting it against an existing fuel over-recovery during the period June 2007 through May 2008.  In the June 2008 appeal by the OIEC of the ALJ recommendations, the OIEC contended that PSO should not have collected the $42 million without specific OCC approval nor collected the $42 million before the OSS allocation issue was resolved.  As such, the OIEC contends that the OCC could and should require PSO to refund the $42 million it collected through its fuel clause.  In August 2008, the OCC heard the OIEC appeal and a decision is pending.  Although the OSS allocation issue has been resolved at the FERC, if the OCC were to order PSO to make an additional refund for all or a part of the $42 million, it would have an adverse effect on future net income and cash flows.

2007 Fuel and Purchased Power

In September 2008, the OCC initiated a review of PSO’s generation, purchased power and fuel procurement processes and costs for 2007.  In August 2009, a joint stipulation and settlement agreement (settlement) was filed with the OCC requesting the OCC to issue an order accepting the fuel adjustment clause for 2007 and find that PSO’s fuel procurement practices, policies and decisions were prudent.  In September 2009, the OCC issued a final order approving the settlement.

2008 Oklahoma Base Rate Filing Appeal

In July 2008, PSO filed an application with the OCC to increase its base rates by $133 million (later adjusted to $127 million) on an annual basis.  At the time of the filing, PSO was recovering $16 million a year for costs related to new peaking units recently placed into service through a Generation Cost Recovery Rider (GCRR).  Subsequent to implementation of the new base rates, the GCRR terminates and PSO recovers these costs through the new base rates.  Therefore, PSO’s net annual requested increase in total revenues was actually $117 million (later adjusted to $111 million).  The proposed revenue requirement reflected a return on equity of 11.25%.

In January 2009, the OCC issued a final order approving an $81 million increase in PSO’s non-fuel base revenues based on a 10.5% return on equity.  The rate increase includes a $59 million increase in base rates and a $22 million increase for costs to be recovered through riders outside of base rates.  The $22 million increase includes $14 million for purchase power capacity costs and $8 million for the recovery of carrying costs associated with PSO’s program to convert overhead distribution lines to underground service.  The $8 million recovery of carrying costs associated with the overhead to underground conversion program will occur only if PSO makes the required capital expenditures.  The final order approved lower depreciation rates and also provided for the deferral of $6 million of generation maintenance expenses to be recovered over a six-year period.  The deferral was recorded in the first quarter of 2009.  PSO was given authority to record additional under/over recovery deferrals for future distribution storm costs above or below the amount included in base rates and for certain transmission reliability expenses.  The new rates reflecting the final order were implemented with the first billing cycle of February 2009.  During 2009, PSO accrued a regulatory liability of approximately $1 million related to a delay in installing gridSMART technologies as the OCC final order had included $2 million of additional revenues for this purpose.

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

Oklahoma Capital Reliability Rider Filing

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

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

PSO Purchase Power Agreement

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

Louisiana Rate Matters

2008 Formula Rate Filing

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

2009 Formula Rate Filing

In April 2009, SWEPCo filed the second FRP which would increase its annual Louisiana retail rates by an additional $4 million effective in August 2009 pursuant to the approved FRP.  SWEPCo implemented the FRP rate increase as filed in August 2009, subject to refund.  In October 2009, consultants for the LPSC objected to certain components of SWEPCo’s FRP calculation.  The consultants also recommended refunding the SIA through SWEPCo’s FRP.  See “Allocation of Off-system Sales Margins” section within “FERC Rate Matters.”  SWEPCo will continue to work with the LPSC regarding the issues raised in their objection.  SWEPCo believes the rates as filed are in compliance with the FRP methodology previously approved by the LPSC.  If the LPSC disagrees with SWEPCo, it could result in material refunds.

Stall Unit

In May 2006, SWEPCo announced plans to build an intermediate load, 500 MW, natural gas-fired, combustion turbine, combined cycle generating unit at its existing Arsenal Hill Plant location in Shreveport, Louisiana to be named the Stall Unit.  SWEPCo submitted the appropriate filings to the LPSC, the PUCT, the APSC and the Louisiana Department of Environmental Quality to seek approvals to construct the Stall Unit.  The Stall Unit is currently estimated to cost $435 million, including $49 million of AFUDC, and is expected to be in service in mid-2010.

The Louisiana Department of Environmental Quality issued an air permit for the Stall Unit in March 2008.  In July 2008, a Louisiana ALJ issued a recommendation that SWEPCo be authorized to construct, own and operate the Stall Unit and recommended that costs be capped at $445 million including AFUDC and excluding related transmission costs.  In October 2008, the LPSC issued a final order effectively approving the ALJ recommendation.  In March 2007, the PUCT approved SWEPCo’s request for a certificate of necessity for the facility based on a prior cost estimate.  In December 2008, SWEPCo submitted an amended filing seeking approval from the APSC to construct the unit.  The APSC staff filed testimony in March 2009 supporting the approval of the plant.  In June 2009, the APSC approved the construction of the unit with a series of conditions consistent with those designated by the LPSC, including a requirement for an independent monitor and a $445 million cost cap including AFUDC and excluding related transmission costs.

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

Temporary Funding of Financing Costs during Construction

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

Turk Plant

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

Arkansas Rate Matters

Turk Plant

In August 2006, SWEPCo announced plans to build the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas.  SWEPCo submitted filings with the APSC, the PUCT and the LPSC seeking certification of the plant.  In 2007, the Oklahoma Municipal Power Authority (OMPA) acquired an approximate 7% ownership interest in the Turk Plant, paid SWEPCo $13.5 million for its share of the accrued construction costs and began paying its proportional share of ongoing costs. During the first quarter of 2009, the Arkansas Electric Cooperative Corporation (AECC) and the East Texas Electric Cooperative (ETEC) acquired ownership interests in the Turk Plant representing approximately 12% and 8%, respectively, paid SWEPCo $104 million in the aggregate for their shares of accrued construction costs and began paying their proportional shares of ongoing construction costs.  The joint owners are billed monthly for their share of the on-going construction costs exclusive of AFUDC.  Through September 30, 2009, the joint owners paid SWEPCo $196 million for their share of the Turk Plant construction expenditures.  SWEPCo owns 73% of the Turk Plant and will operate the completed facility.  The Turk Plant is currently estimated to cost $1.6 billion, excluding AFUDC, with SWEPCo’s share estimated to cost $1.2 billion, excluding AFUDC.  In addition, SWEPCo will own 100% of the related transmission facilities which are currently estimated to cost $131 million, excluding AFUDC.

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

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

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

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

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

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

SWEPCo is also working with the U.S. Army Corps of Engineers for the approval of a wetlands and stream impact permit.  In March 2009, SWEPCo reported to the U.S. Army Corps of Engineers an inadvertent impact on approximately 2.5 acres of wetlands at the Turk Plant construction site prior to the receipt of the permit.  The U.S. Army Corps of Engineers directed SWEPCo to cease further work impacting the wetland areas.  Construction has continued on other areas outside of the proposed Army Corps of Engineers permitted areas of the Turk Plant pending the Army Corps of Engineers review.  SWEPCo has entered into a Consent Agreement and Final Order with the Federal EPA to resolve liability for the inadvertent impact and agreed to pay a civil penalty of approximately $29 thousand.

The Arkansas Governor’s Commission on Global Warming issued its final report to the governor in October 2008.  The Commission was established to set a global warming pollution reduction goal together with a strategic plan for implementation in Arkansas.  The Commission’s final report included a recommendation that the Turk Plant employ post combustion carbon capture and storage measures as soon as it starts operating.  To date, the report’s effect is only advisory, but if legislation is passed as a result of the findings in the Commission’s report, it could impact SWEPCo’s ability to complete construction on schedule in 2012 and on budget.

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

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

Arkansas Base Rate Filing

In February 2009, SWEPCo filed an application with the APSC for a base rate increase of $25 million based on a requested return on equity of 11.5%.  SWEPCo also requested a separate rider to recover financing costs related to the construction of the Stall Unit and Turk Plant.

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

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

Stall Unit

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

FERC Rate Matters

Regional Transmission Rate Proceedings at the FERC

SECASeams Elimination Cost Allocation (SECA) Revenue Subject to Refund

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

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

In September 2006, AEP filed briefs jointly with other affected companies noting exceptions to the ALJ’s initial decision and asking the FERC to reverse the decision in large part.decision.  Management believes based on advice of legal counsel, that the FERC should reject the ALJ’s initial decision because it contradicts prior related FERC decisions, which are presently subject to rehearing.  Furthermore, management believes the ALJ’s findings on key issues are largely without merit.  AEP and SECA ratepayers arehave been engaged in settlement discussions in an effort to settle the SECA issue.  However, if the ALJ’s initial decision is upheld in its entirety, it could result in a refund of a portion or all of the unsettled SECA revenues.  In December 2009, several parties filed a motion with the U.S. Court of Appeals to force the FERC to res olve the SECA issue.

Based on anticipated settlements, theThe AEP East companies provided reserves for net refunds for current and future SECA settlements totaling $39 million and $5 million in 2006 and 2007, respectively, applicable to a total ofthe $220 million of SECA revenues.  In February 2009, a settlement agreement was approved by the FERC resulting in the completion of a $1 million settlement applicable to $20 million of SECA revenue.  Including this most recent settlement, AEP has completed settlements totaling $10 million applicable to $112 million of SECA revenues.  The balance in the reserve for future settlements as of September 30, 2009 was $34 million.revenues collected.  As of September 30, 2009,March 31, 2010, there were no in-process settlements.

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

The FERC PJM Regional Transmission Rate Proceeding

With the elimination of T&O rates, the expiration of SECA rates and after considerable administrative litigation at the FERC in which AEP sought to mitigate the effect of the T&O rate elimination, the FERC failed to implement a regional rate in PJM.  As a result, the AEP East companies’ retail customers incur the bulk of the cost of the existing AEP east transmission zone facilities even though other non-affiliated entities transmit power over AEP’s lines.  However, the FERC ruled that the cost of any new 500 kV and higher voltage transmission facilities built in PJM would be shared by all customers in the region.  It is expected that most of the new 500 kV and higher voltage transmission facilities will be built in other zones of PJM, not AEP’s zone.  The AEP East companies will need to obtain state regulatory approvals for recovery of any costs of new facilities that are assigned to them by PJM.  In February 2008, AEP filed a Petition for Review of the FERC orders in this case in the United States Court of Appeals.  In August 2009, the United States Court of Appeals issued an opinion affirming FERC’s refusal to implement a regional rate design in PJM.

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

The FERC PJM and MISO Regional Transmission Rate Proceeding

In the SECA proceedings, the FERC ordered the RTOs and transmission owners in the PJM/MISO region (the Super Region) to file, by August 1, 2007, a proposal to establish a permanent transmission rate design for the Super Region to be effective February 1, 2008.  All of the transmission owners in PJM and MISO, with the exception of AEP and one MISO transmission owner, elected to support continuation of zonal rates in both RTOs.  In September 2007, AEP filed a formal complaint proposing a highway/byway rate design be implemented for the Super Region where users pay based on their use of the transmission system.  AEP argued the use of other PJM and MISO facilities by AEP is not as large as the use of the AEP East companies’ transmission by others in PJM and MISO and as a result the use of zonal rates would be unfair and discriminatory to AEP’s East zone retail customers.  Therefore, a regional rate design change is required to recognize that the provision and use of transmission service in the Super Region is not sufficiently uniform between transmission owners and users to justify zonal rates.  In January 2008, the FERC denied AEP’s complaint.  AEP filed a rehearing request with the FERC in March 2008.  In December 2008, the FERC denied AEP’s request for rehearing.  In February 2009, AEP filed an appeal in the U.S. Court of Appeals.  If the court appeal is successful, earnings could benefit for a certain period of time due to regulatory lag until the AEP East companies reduce future retail revenues in their next fuel or base rate proceedings to reflect the resultant additional wholesale transmission T&O revenues reduction of transmission cost to retail customers.  This case is pending before the U.S. Court of Appeals which in August 2009 ruled against AEP in a similar case.  See “The FERC PJM Regional Transmission Rate Proceeding” section above.

Allocation of Off-system Sales Margins

In August 2008, the OCC filed a complaint at the FERC alleging that AEP inappropriately allocated off-system sales margins between the AEP East companies and the AEP West companies and did not properly allocate off-system sales margins within the AEP West companies.  The PUCT, the APSC and the Oklahoma Industrial Energy Consumers intervened in this filing.

In November 2008, the FERC issued a final order concluding that AEP inappropriately deviated from off-system sales margin allocation methods in the SIA and the CSW Operating Agreement for the period June 2000 through March 2006.  The FERC ordered AEP to recalculate and reallocate the off-system sales margins in compliance with the SIA and to have the AEP East companies issue refunds to the AEP West companies.  Although the FERC determined that AEP deviated from the CSW Operating Agreement, the FERC determined the allocation methodology was reasonable.  The FERC ordered AEP to submit a revised CSW Operating Agreement for the period June 2000 to March 2006.  In December 2008, AEP filed a motion for rehearing and a revised CSW Operating Agreement for the period June 2000 to March 2006.  The motion for rehearing is still pending.

In January 2009, AEP filed a compliance filing with the FERC and refunded approximately $250 million from the AEP East companies to the AEP West companies.  Following authorized regulatory treatment, the AEP West companies shared a portion of SIA margins with their customers during the period June 2000 to March 2006.  In December 2008, the AEP West companies recorded a provision for refund reflecting the sharing.  In January 2009, SWEPCo refunded approximately $13 million to FERC wholesale customers.  In February 2009, SWEPCo filed a settlement agreement with the PUCT that provides for the Texas retail jurisdiction amount to be included in the March 2009 fuel cost report submitted to the PUCT.  PSO began refunding approximately $54 million plus accrued interest to Oklahoma retail customers through the fuel adjustment clause over a 12-month period beginning with the March 2009 billing cycle.

In April 2009, TCC and TNC filed their Advanced Metering System (AMS) with the PUCT proposing to invest in AMS to be recovered through customer surcharges beginning in October 2009.  In the filing, TCC and TNC proposed to apply the SIA recorded customer refunds including interest to reduce the AMS investment and the resultant associated customer surcharge.  In July 2009, consultants for the LPSC issued an audit report of SWEPCo’s Louisiana retail fuel adjustment clause.  Within this report, the consultants for the LPSC recommended that SWEPCo refund the SIA, including interest, through the fuel adjustment clause.  In October 2009, other consultants for the LPSC recommended refunding the SIA through SWEPCo’s formula rate plan.  See “2009 Formula Rate Filing” section within “Louisiana Rate Matters.”  SWEPCo is working with the APSC and the LPSC to determine the effect the FERC order will have on retail rates.  Management cannot predict the outcome of the requested FERC rehearing proceeding or any future state regulatory proceedings but believes the AEP West companies’ provision for refund regarding related future state regulatory proceedings is adequate.impact financial condition.

Modification of the Transmission Agreement (TA)

APCo, CSPCo, I&M, KPCo and OPCo are parties to the TA entered into in 1984, as amended, that provides for a sharing of the cost of transmission lines operated at 138-kV and above and transmission stations operated at 345kV and above.containing extra-high voltage facilities.  In June 2009,  AEPSC, on behalf of the parties to the TA, filed with the FERC a request to modify the TA.  Under the proposed amendments, WPCoKGPCo and KGPCoWPCo will be added as parties to the TA.  In addition, the amendments would provide for the allocation of PJM transmission costs on the basis of the TA parties’ 12-month coincident peak and reimburse the majority of PJM transmission revenues based on individual cost of service instead of the MLR method used in the present TA.  AEPSC requested the effective date to be the first day of the month following a final non-appealable FERC order. 0; The delayed effective date was approved by the FERC in August 2009 when the FERC accepted the new TA for filing.  Settlement discussions are in process.  Managementprogress.  Once approved by the FERC, management is unable to predict whether the effect, if any, itparties to the TA will haveexperience regulatory lag and its effect on future net income and cash flows due to timing of the implementation of the modified TA by various state regulatorsregulators.

PJM/MISO Market Flow Calculation Errors

During 2009, an analysis conducted by MISO and PJM discovered several instances of unaccounted for power flows on numerous coordinated flowgates.  These flows affected the settlement data for congestion revenues and expenses and date back to the start of the FERC’s new approved TA.MISO market in 2005.  PJM has provided MISO an initial analysis of amounts they believe they owe MISO.  MISO disputes PJM’s methodology.

Settlement discussions between MISO and PJM have been unsuccessful, and as a result, in March 2010, MISO filed two related complaints against PJM at the FERC related to the above claim.  MISO seeks to recover a total of approximately $145 million from PJM.  Given that PJM passes its costs on to its members, if PJM is held liable for these damages, PJM members, including the AEP East companies, may be held responsible for a share of the refunds or payments PJM is directed to make to MISO.  AEP has intervened and filed a protest to one complaint.  Management believes that MISO's claims filed at the FERC are without merit and that PJM's right to recover from AEP and other members any damages awarded to MISO is limited.  If the FERC orders a settlement above the AEP East companies’ re serve related to their estimated portion of PJM additional costs, it could reduce future net income and cash flows and impact financial condition.

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 20082009 Annual Report should be read in conjunction with this report.

GUARANTEES

We record certain immaterial liabilities for guarantees in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees in excess of our ownership percentages.  In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

Letters Ofof Credit

We enter into standby letters of credit (LOCs) with third parties.  These LOCs cover items such as gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.  As the Parent, we issued all of these LOCs in our ordinary course of business on behalf of our subsidiaries.  At September 30, 2009,As of March 31, 2010, the maximum future payments for all the LOCs issued under the two $1.5 billion 5-year credit facilities are approximately $98$175 million with maturities ranging from October 2009May 2010 to July 2010.June 2011.

We have a $627 million 3-year credit agreement.  As of September 30, 2009, $372March 31, 2010, $477 million of letters of creditLOCs with maturities ranging from May 2010 to JuneNovember 2010 were issued by subsidiaries under the $627 million 3-year credit agreement to support variable rate Pollution Control Bonds.  We had a $350 million 364-day credit agreement that expired in April 2009.

Guarantees Ofof Third-Party Obligations

SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation in the amount of approximately $65 million.  Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine Mining Company (Sabine), a consolidated variable interest entity.  This guarantee ends upon depletion of reserves and completion of final reclamation.  Based on the latest study, we estimate the reserves will be depleted in 2029 with final reclamation completed by 2036.  A new study is in process to include new, expanded areas of the mine.  As of September 30, 2009,March 31, 2010, SWEPCo has collected approximately $42$45 million through a rider forf or final mine closure and reclamation costs, of which $2 million is recorded in Other Current Liabilities, $23$21 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $17$22 million is recorded in Asset Retirement Obligations on our Condensed Consolidated Balance Sheets.

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

Indemnifications Andand 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 salesales agreements is discussed in the 20082009 Annual Report, “Dispositions” section of Note 7.  These sale agreements include indemnifications with a maximum exposure related to the collective purchase price, which is approximately $1.1 billion.  Approximately $1 billion of the maximum exposure relates to the Bank of America (BOA) litigation (see “Enron Bankruptcy” section of this note), of which the probable payment/performance risk is $439$443 million and is recorded in Deferred Credits and Other Noncurrent Liabilities on our Condensed Consolidated Balance Sheets as of September 30, 2009.March 31, 2010.  The remaining exposure is remote.  There are no material liabilities recorded for any indemnifications other than amounts recorded related to the BOA litigation.

Master Lease Agreements

We lease certain equipment under master lease agreements. GE Capital Commercial Inc. (GE) notified us in November 2008 that they elected to terminate our Master Leasing Agreements in accordance with the termination rights specified within the contract.  In 2010 and 2011, we will be required to purchase all equipment under the lease and pay GE an amount equal to the unamortized value of all equipment then leased.  In December 2008 and 2009, we signed new master lease agreements with one-year commitment periods that include lease terms of up to 10 years.  We expect to enter into additional replacement leasing arrangements for the equipment affected by this notification prior to the termination dates of 2010 and 2011.

For equipment under the GE master lease agreements that expire prior toin 2011, the lessor is guaranteed receipt of up to 87% of the unamortized balance of the equipment at the end of the lease term.  If the fair market value of the leased equipment is below the unamortized balance at the end of the lease term, we are committed to pay the difference between the fair market value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance.  Under the new master lease agreements, the lessor is guaranteed receipt ofa residual value up to 68%a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term.  If the actual fair market value of the leased equipment is below the unamortized balanceguaranteed residual value at the end of the lease term, we are committed to pay the difference betweenbetwe en the actual fair market value and unamortized balance, with the total guarantee not to exceed 68% of the unamortized balance.residual value guarantee.  At September 30, 2009,March 31, 2010, the maximum potential loss for these lease agreements was approximately $8$3 million assuming the fair market value of the equipment is zero at the end of the lease term.  Historically, at the end of the lease term the fair market value has been in excess of the unamortized balance.

Railcar Lease

In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars.  The lease is accounted for as an operating lease.  In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars).  The assignment is accounted for as operating leases for I&M and SWEPCo.  The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years.  I&M and SWEPCo intend to renew these leases for the full lease term of twenty years, via the renewal options.  The future minimum lease obligations are $19$18 million forfo r I&M and $22$21 million for SWEPCo for the remaining railcars as of September 30, 2009.March 31, 2010.

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

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

ENVIRONMENTAL CONTINGENCIES

Federal EPA Complaint and Notice of Violation

The Federal EPA, certain special interest groups and a number of states alleged that a unit jointly owned byAPCo, CSPCo, Dayton PowerI&M and Light Company and Duke Energy Ohio, Inc.OPCo modified certain units at the Beckjord Station was modifiedtheir coal-fired generating plants in violation of the NSR requirements of the CAA.

  Cases with similar allegations against CSPCo, Dayton Power and Light Company (DP&L) and Duke Energy Ohio, Inc. were also filed related to their jointly-owned units.  The cases were settled with the exception of a case involving a jointly-owned Beckjord caseunit which had a liability trial in 2008.trial.  Following the trial, the jury found no liability for claims made against the jointly-owned Beckjord unit.  In December 2008, however, the court ordered a new trial in the Beckjord case.  Following a second liability trial in 2009, the jury again found no liability at the jointly-owned Beckjord unit.  In 2009, theThe defendants and the plaintiffs filed appeals.appealed to the Seventh Circuit Court of Appeals.  Beckjord is operated by Duke Energy Ohio, Inc.

SWEPCo Notice of Enforcement and Notice of Citizen Suit

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

In February 2008, theThe Federal EPA issued a Notice of Violation (NOV) based on alleged violations of a percent sulfur in fuel limitation and the heat input values listed in thea previous state permit.  The NOV also alleges that a permit alteration issued by the Texas Commission on Environmental Quality in 2007 was improper.  In March 2008, SWEPCo met with the Federal EPA to discuss the alleged violations in March 2008.violations.  The Federal EPA did not object to the settlement of similar alleged violations in the federal citizen suit.  We are unable to predict the timing of any future action by the Federal EPA or the effect of such actionsaction on our net income, cash flows or financial condition.

Carbon Dioxide (CO2) Public Nuisance Claims

In 2004, eight states and the City of New York filed an action in Federal District Court for the Southern District of New York against AEP, AEPSC, Cinergy Corp, Xcel Energy, Southern Company and Tennessee Valley Authority.  The Natural Resources Defense Council, on behalf of three special interest groups, filed a similar complaint against the same defendants.  The actions allege that CO2 emissions from the defendants’ power plants constitute a public nuisance under federal common law due to impacts of global warming and sought injunctive relief in the form of specific emission reduction commitments from the defendants.  The dismissal of this lawsuit was appealed totrial court dismissed the Second Circuit Court of Appeals.  In April 2007, the U.S. Supreme Court issued a decision holding that the Federal EPA has authority to regulate emissions of CO2 and other GHG under the CAA.  The Second Circuit requested supplemental briefs addressing the impact of the U.S. Supreme Court’s decision on this case.lawsuits.

In September 2009, the Second Circuit Court of Appeals issued a ruling vacating the dismissal andon appeal remanding the casecases to the Federal District Court for the Southern District of New York.  The Second Circuit held that the issues of climate change and global warming do not raise political questions and that Congress’ refusal to regulate GHGCO2 emissions does not mean that plaintiffs must wait for an initial policy determination by Congress or the President’s administration to secure the relief sought in their complaints.  The court stated that Congress could enact comprehensive legislation to regulate CO2 emissions or that the Federal EPA could regulate CO2 emissions under existing CAA authorities and that either of these actions could override any decision made by the district court under federal common law.  The Second Circuit did not rule on whether the plaintiffs could proceed with their state common law nuisance claims.  We believe the actions are without merit and intend to continue to defend against the claims including seeking further review by the Second Circuit and, if necessary, the United States Supreme Court.The defendants’ petition for rehearing was denied.

In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that GHGCO2 emissions exacerbated the effects of Hurricane Katrina.  The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs’ complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims.  The court granted petitions for rehearing and scheduled oral argument for May 24, 2010.  We were initially dismissed from this case without prejudice, but are named as a defendant in a pending fourth amended complaint.

We believe the actions are without merit and intend to continue to defend against the claims.

Alaskan Villages’ Claims

In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company and other electric generating companies.  The complaint alleges that the defendants' emissions of CO2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together.  The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance.  The plaintiffs also allege that the effects of global warming willwil l require the relocation of the village at an alleged cost of $95 million to $400 million.  In October 2009, the judge dismissed plaintiffs’ federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs’ lack of standing to bring the claim.  The judge also dismissed plaintiffs’ state law claims without prejudice to refiling in state court.  The plaintiffs appealed the decision.  We believe the action is without merit and intend to defend against the claims.

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

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

Superfund addresses clean-up of hazardous substances that have been released to the environment.  The Federal EPA administers the clean-up programs.  Several states have enacted similar laws.  In March 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M to take voluntary action necessary to prevent and/or mitigate public harm.  I&M requested  remediation proposals from environmental consulting firms.  In May 2008, I&M issued a contract to one of the consulting firms and started remediation work in accordance with a plan approved by MDEQ.  I&M recorded approximately $4$11 million of expense during 2008.  Based upon updated information,prior to January 1, 2010, $3 million of which I&M recorded additional expense of $7 million in March 2009.  As the remediation work is completed, I&M’s cost may continue to increase.  I&M cannot predict the amount of additional cost, if any.

Amos Plant – Request to Show Cause

In March 2010, we received a request to show cause from the Federal EPA alleging that certain reporting requirements under Superfund and the Emergency Planning and Community Right-to-Know Act had been violated and inviting us to engage in settlement negotiations.  The request includes a proposed civil penalty of approximately $300 thousand.  We indicated our willingness to engage in good faith negotiations and meet with representatives of the Federal EPA.  We have not admitted that any violations occurred or that the amount of the proposed penalty is reasonable.

Defective Environmental Equipment

As part of our continuing environmental investment program, we chose to retrofit wet flue gas desulfurization systems on several of our units utilizing the jet bubbling reactor (JBR) technology.  The following plants have been scheduled for the installation of the JBR technology.  technology or are currently utilizing JBR retrofits:

JBRs
Installed/
Scheduled for
Plant NamePlant OwnersInstallation
CardinalOPCo/ Buckeye Power, Inc.3
Conesville
CSPCo/Dayton Power and Light Company/
Duke Energy Ohio, Inc.
1
Clifty CreekIndiana-Kentucky Electric Corporation2
Kyger CreekOhio Valley Electric Corporation2
Muskingum River (a)OPCo1
Big Sandy (a)KPCo1

(a)Contracts for the Muskingum River and Big Sandy projects have been temporarily suspended during the early development stages of the projects.

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

NUCLEAR CONTINGENCIES

I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC).  We have a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant.  The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037.  The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements.  By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generating units, for a nuclear power plant incident at any nuclear plant in the U.S.  Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.

Cook Plant Unit 1 Fire and Shutdown

In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in significant turbine damage and a small fire on the electric generator.  This equipment, located in the turbine building, is separate and isolated from the nuclear reactor.  The turbine rotors that caused the vibration were installed in 2006 and are within the vendor’s warranty period.  The warranty provides for the repair or replacement of the turbine rotors if the damage was caused by a defect in materials or workmanship.  I&M is working with its insurance company, Nuclear Electric Insurance Limited (NEIL), and its turbine vendor, Siemens, to evaluate the extent of the damage resulting from the incident and facilitate repairs to return the unit to service.  Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $330$395 million.  Management believes that I&M should recover a significant portion of these costs through theth e turbine vendor’s warranty, insurance and the regulatory process.  I&M is repairingrepaired Unit 1 to resumeand it resumed operations as early as the fourth quarter ofin December 2009 at slightly reduced power.  Should post-repair operations prove unsuccessful,The Unit 1 rotors were repaired and reinstalled due to the extensive lead time required to manufacture and install new turbine rotors.  As a result, the replacement of parts will extend the outage into 2011.

The refueling outagerepaired turbine rotors and other equipment is scheduled for the Unit 1 planned outage in the fall of 2009 for Unit 1 was rescheduled to the spring of 2010.  Management anticipates that the loss of capacity from Unit 1 will not affect I&M’s ability to serve customers due to the existence of sufficient generating capacity in the AEP Power Pool.2011.

I&M maintains property insurance through NEIL with a $1 million deductible.  As of September 30, 2009,March 31, 2010, we recorded $122$143 million in Prepayments and Other Current Assets on our Condensed Consolidated Balance SheetsSheet representing recoverable amounts under the property insurance policy.  Through September 30, 2009,March 31, 2010, I&M received partial payments of $72$118 million from NEIL for the cost incurred to date to repair the property damage.  In April 2010, I&M received a $45 million payment from NEIL.

I&M also maintainsmaintained a separate accidental outage insurance policy with NEIL whereby, after a 12-week deductible period, I&M is entitled to weekly payments of $3.5 million for the first 52 weeks following the deductible period.  After the initial 52 weeks of indemnity, the policy pays $2.8 million per week for up to an additional 110 weeks.  I&M began receiving payments under the accidental outage policy in December 2008.NEIL.  In 2009, I&M recorded $145$185 million in revenue under this policy and applied $59 millionreduced the cost of the accidental outage insurance proceeds to reduce customer bills.replacement power in customers’ bills by $78 million.

NEIL is reviewing claims made under the insurance policies to ensure that claims associated with the outage are covered by the policies.  The treatment of property damage costs, replacement power costs and insurance proceeds will be the subject of future regulatory proceedings in Indiana and Michigan.  If the ultimate costs of the incident are not covered by warranty, insurance or through the regulatory process or if the unit is not returned to service in a reasonable period of time or if any future regulatory proceedings are adverse, it could have an adverse impact on net income, cash flows and financial condition.

OPERATIONAL CONTINGENCIES

Fort Wayne Lease

Since 1975, I&M has leased certain energy delivery assets from the City of Fort Wayne, Indiana under a long-term lease that expiresexpired on February 28, 2010.  I&M has been negotiating with Fort Wayne to purchase the assets at the end of the lease, but no agreement has been reached.  Recent mediation with Fort Wayne was also unsuccessful.  Fort Wayne issued a technical notice of default under the lease to I&M in August 2009.  I&M responded to Fort Wayne in October 2009 that it did not agree there was a default under the lease.  In October 2009, I&M filed for declaratory and injunctive relief in Indiana state court.  The parties agreed to submit this matter to mediation.  In February 2010, the court issued a stay to continue mediation.  I&M is making monthly payments to an escrow account in lieu of rent.& #160; I&M will seek recovery in rates for any amount it may pay related to this dispute.  At this time, management cannot predict the outcome of this dispute or its potential impact on net income or cash flows.

TEM Litigation

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

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

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

Enron Bankruptcy

In 2001, we purchased Houston Pipeline Company (HPL) from Enron.  Various HPL-related contingencies and indemnities from Enron remained unsettled at the date of Enron’s bankruptcy.  In connection with our acquisition of HPL, we entered into an agreement with BAM Lease Company, which granted HPL the exclusive right to use approximately 55 billion cubic feet (BCF) of cushion gas required for the normal operation of the Bammel gas storage facility.  At the time of our acquisition of HPL, BOA and certain other banks (the BOA Syndicate) and Enron entered into an agreement granting HPL the exclusive use of the cushion gas.  Also at the time of our acquisition, Enron and the BOA Syndicate released HPL from all prior and future liabilities and obligations in connection with the financing arrangement.arrangemen t.  After the Enron bankruptcy, the BOA Syndicate informed HPL of a purported default by Enron under the terms of the financing arrangement.  This dispute is being litigated in the Enron bankruptcy proceedings and in federal courts in Texas and New York.

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

In 2003, AEP filed a lawsuit against BOA in the United States District Court for the Southern District of Texas.  BOA led the lending syndicate involving the monetization of the cushion gas to Enron and its subsidiaries.  The lawsuit asserts that BOA made misrepresentationsrepresentations and engaged in fraud to induce and promote the stock sale of HPL, that BOA directly benefited from the sale of HPL and that AEP undertook the stock purchase and entered into the cushion gas arrangement with Enron and BOA based on misrepresentations that BOA made about Enron’s financial condition that BOA knew or should have known were false.  In April 2005, the Judge entered an order severing and transferring the declaratory judgment claims involving the right to use and cushion gas consent agreements to the Southern District of New York anda nd retaining in the Southern District of Texas the four counts alleging breach of contract, fraud and negligent misrepresentation.  HPL and BOA filed motions for summary judgment in the case pending in the Southern District of New York.  Trial in federal court in Texas was continued pending a decision on the motions for summary judgment in the New York case.

In August 2007, the judge in the New York action issued a decision on all claims, including those that were pending trial in Texas, granting BOA summary judgment and dismissing our claims.  In December 2007, the judge held that BOA is entitled to recover damages of approximately $347 million plus interest.  In August 2008, the court entered a final judgment of $346 million (the original judgment less $1 million BOA would have incurred to remove 55 BCF of natural gas from the Bammel storage facility) and clarified the interest calculation method.million.  We appealed and posted a bond covering the amount of the judgment entered against us.  In May 2009, the judge awarded $20 million of attorneys’ fees to BOA.  We appealed this award and posted bond covering that amount.  In September 2009, the United States Court of Appeals for the Second Circuit heard oral argument on our appeal of the lower court’s decision.appeal.

In 2005, we sold our interest in HPL.  We indemnified the buyer of HPL against any damages resulting from the BOA litigation up to the purchase price.  After recalculation for the final judgment, theThe liability for the BOA litigation was $439$443 million and $433$441 million including interest at September 30, 2009March 31, 2010 and December 31, 2008,2009, respectively.  These liabilities are included in Deferred Credits and Other Noncurrent Liabilities on our Condensed Consolidated Balance Sheets.

Shareholder Lawsuits

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

Natural Gas Markets Lawsuits

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

Rail Transportation Litigation
5.ACQUISITIONS AND DISPOSITIONS

In October 2008, the Oklahoma Municipal Power Authority and the Public Utilities Board of the City of Brownsville, Texas, as co-owners of Oklaunion Plant, filed a lawsuit in United States District Court, Western District of Oklahoma against AEP alleging breach of contract and breach of fiduciary duties related to negotiations for rail transportation services for the plant.  The plaintiffs allege that AEP assumed the duties of the project manager, PSO, and operated the plant for the project manager and is therefore responsible for the alleged breaches.  Trial is scheduled for December 2009.  We intend to vigorously defend against these allegations.  We believe a provision recorded in 2008 should be sufficient.

FERC Long-term Contracts

In 2002, the FERC held a hearing related to a complaint filed by Nevada Power Company and Sierra Pacific Power Company (the Nevada utilities).  The complaint sought to break long-term contracts entered during the 2000 and 2001 California energy price spike which the customers alleged were “high-priced.”  The complaint alleged that we sold power at unjust and unreasonable prices because the market for power was allegedly dysfunctional at the time such contracts were executed.  In 2003, the FERC rejected the complaint.  In 2006, the U.S. Court of Appeals for the Ninth Circuit reversed the FERC order and remanded the case to the FERC for further proceedings.  That decision was appealed to the U.S. Supreme Court.  In June 2008, the U.S. Supreme Court affirmed the validity of contractually-agreed rates except in cases of serious harm to the public.  The U.S. Supreme Court affirmed the Ninth Circuit’s remand on two issues, market manipulation and excessive burden on consumers.  The FERC initiated remand procedures and gave the parties time to attempt to settle the issues.  In September 2009, the parties reached a settlement.  We reversed a portion of a provision recorded in 2008.

5.       ACQUISITIONS AND DISCONTINUED OPERATIONS

ACQUISITIONS

20092010

Oxbow Mine LigniteValley Electric Membership Corporation (Utility Operations segment)

In AprilNovember 2009, SWEPCo agreedsigned a letter of intent to purchase 50%the transmission and distribution assets of Valley Electric Membership Corporation (VEMCO).  The current estimate of the Oxbow Mine lignite reserves for $13purchase is $99 million, and DHLC agreedplus the assumption of certain liabilities, subject to purchase 100% of all associated mining equipment and assets for $16 million from the North American Coal Corporation and its affiliates, Red River Mining Company and Oxbow Property Company, LLC.  Cleco Power LLC (Cleco) will acquire the remaining 50% interest in the lignite reserves for $13 million.  SWEPCo expects to complete the transaction in the fourth quarter of 2009.adjustments at closing.  Consummation of the transaction is subject to regulatory approval by the LPSC, the APSC, the Rural Utilities Service and the APSCNational Rural Utilities Cooperative Finance Corporation.  In January 2010, the VEMCO members approved the transaction.  In April 2010, a joint application between SWEPCo and VEMCO was filed with the transferLPSC.  SWEPCo will seek recovery from Louisiana customers for all costs related to this acquisition.  VEMCO services approximately 30,000 customers in Louisiana. & #160;SWEPCo expects to complete the transaction in the third quarter of 2010 upon receipt of regulatory and other regulatory instruments.  If approved, DHLC will acquire and own the Oxbow Mine mining equipment and related assets and it will operate the Oxbow Mine.  The Oxbow Mine is located near Coushatta, Louisiana and will be used as one of the fuel sources for SWEPCo’s and Cleco’s jointly-owned Dolet Hills Generating Station.approvals.

20082009

Erlbacher companies (AEP RiverNone

DISPOSITIONS

2010

Electric Transmission Texas LLC (ETT) (Utility Operations segment)

In June 2008, AEP River Operations purchased certain barging assets from Missouri Barge Line Company, Missouri Dry Dock2010, TCC and Repair CompanyTNC sold $64 million and Cape Girardeau Fleeting, Inc. (collectively known as Erlbacher companies) for $35 million.  These assets were incorporated into AEP River’s operations diversifying its customer base.

DISCONTINUED OPERATIONS

We determined that certain$71 million, respectively, of our operations were discontinued operations and classified them as such for all periods presented.  We recorded the following amounts in 2009 and 2008 relatedtransmission facilities to discontinued operations:

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

U.K. Generation (a)
Nine Months Ended September 30,(in millions)
2009 Revenue$- 
2009 Pretax Income- 
2009 Earnings, Net of Tax- 
2008 Revenue$- 
2008 Pretax Income2 
2008 Earnings, Net of Tax1 

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

ETT.  There were no cash flows used forgains or provided by operating, investinglosses recorded on these transactions.

2009

Electric Transmission Texas LLC (ETT) (Utility Operations segment)

In January 2009, TCC sold $60 million of transmission facilities to ETT.  There were no gains or financing activities related to our discontinued operations for the nine months ended September 30, 2009 and 2008.losses recorded on these transactions.

6.      BENEFIT PLANS

Components of Net Periodic Benefit Cost

The following tables providetable provides the components of our net periodic benefit cost for the plans for the three and nine months ended September 30, 2009March 31, 2010 and 2008:2009:
 
  Other 
  Other Postretirement   Postretirement 
Pension Plans Benefit Plans Pension Plans Benefit Plans 
Three Months Ended September 30, Three Months Ended September 30, Three Months Ended March 31, Three Months Ended March 31, 
2009 2008 2009 2008 2010 2009 2010 2009 
(in millions) (in millions) 
Service Cost $26  $25  $11  $10  $28  $26  $12  $10 
Interest Cost  64   62   27   28   63   63   28   27 
Expected Return on Plan Assets  (80)  (84)  (21)  (27)  (78)  (80)  (26)  (20)
Amortization of Transition Obligation  -   -   7   7   -   -   7   7 
Amortization of Net Actuarial Loss  14   10   11   3   22   15   7   11 
Net Periodic Benefit Cost $24  $13  $35  $21  $35  $24  $28  $35 

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

7.       BUSINESS SEGMENTS
 7.BUSINESS SEGMENTS

As outlined in our 20082009 Annual Report, our primary business is our electric utility operations.  Within our Utility Operations segment, we centrally dispatch generation assets and manage our overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight.  While our Utility Operations segment remains our primary business segment, other segments include our AEP River Operations segment with significant barging activities and our Generation and Marketing segment, which includes our nonregulated generating, marketing and risk management activities primarily in the ERCOT market area.  Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

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

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

AEP River Operations
·Commercial barging operations that annually transport approximately 33 million tons of coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers.

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

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

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

The tables below present our reportable segment information for the three and nine months ended September 30,March 31, 2010 and 2009 and 2008 and balance sheet information as of September 30, 2009March 31, 2010 and December 31, 2008.2009.  These amounts include certain estimates and allocations where necessary.

    Nonutility Operations       
  Utility Operations 
AEP River
Operations
 
Generation
and
Marketing
 All Other (a) Reconciling Adjustments Consolidated 
  (in millions)
Three Months Ended September 30, 2009                   
Revenues from:                   
External Customers $3,364 (d)$113  $68  $2  $-  $3,547  
Other Operating Segments  25 (d) 4   -   1   (30)  -  
Total Revenues $3,389  $117  $68  $3  $(30) $3,547  
                    
Income (Loss) Before Discontinued Operations and Extraordinary Loss $448  $10  $5  $(17) $-  $446  
Extraordinary Loss, Net of Tax  -   -   -   -   -   -  
Net Income (Loss)  448   10   5   (17)  -   446  
Less: Net Income Attributable to Noncontrolling Interests  2   -   -   -   -   2  
Net Income (Loss) Attributable to AEP Shareholders  446   10   5   (17)  -   444  
Less: Preferred Stock Dividend Requirements of Subsidiaries  1   -   -   -   -   1 
Earnings (Loss) Attributable to AEP Common Shareholders $445  $10  $5  $(17) $-  $443  
    Nonutility Operations      
Three Months Ended March 31, 2010 Utility Operations 
AEP River
Operations
 
Generation
and
Marketing
 All Other (a) Reconciling Adjustments Consolidated
  (in millions)
Revenues from:                  
External Customers $3,406  $121  $47  $(5) $-  $3,569 
Other Operating Segments  20   5   -   8   (33)  - 
Total Revenues $3,426  $126  $47  $3  $(33) $3,569 
                   
Net Income (Loss) $344  $3  $10  $(11) $-  $346 

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


    Nonutility Operations       
  Utility Operations 
AEP River
Operations
 
Generation
and
Marketing
 All Other (a) Reconciling Adjustments Consolidated 
  (in millions)
Nine Months Ended September 30, 2009                   
Revenues from:                   
External Customers $9,666 (d)$341  $213  $(13) $-  $10,207  
Other Operating Segments  46 (d) 13   6   28   (93)  -   
Total Revenues $9,712  $354  $219  $15  $(93) $10,207  
                    
Income (Loss) Before Discontinued Operations and Extraordinary Loss $1,121  $22  $33  $(45) $-  $1,131  
Extraordinary Loss, Net of Tax  (5)  -   -   -   -   (5) 
Net Income (Loss)  1,116   22   33   (45)  -   1,126  
Less: Net Income Attributable to Noncontrolling Interests  5   -   -   -   -   5  
Net Income (Loss) Attributable to AEP Shareholders  1,111   22   33   (45)  -   1,121  
Less: Preferred Stock Dividend Requirements of Subsidiaries  2   -   -   -   -   2  
Earnings (Loss) Attributable to AEP Common Shareholders $1,109  $22  $33  $(45) $-  $1,119  
    Nonutility Operations      
  Utility Operations 
AEP River
Operations
 
Generation
and
Marketing
 
All Other
(a)
 Reconciling Adjustments Consolidated
  (in millions)
Three Months Ended March 31, 2009                  
Revenues from:                  
External Customers $3,267 (d)$123  $87  $(19) $-  $3,458 
Other Operating Segments  - (d) 6   5   22   (33)  - 
Total Revenues $3,267  $129  $92  $3  $(33) $3,458 
                   
Net Income (Loss) $346  $11  $24  $(18) $-  $363 

    Nonutility Operations       
  Utility Operations 
AEP River
Operations
 
Generation
and
Marketing
 All Other (a) Reconciling Adjustments Consolidated 
  (in millions) 
Nine Months Ended September 30, 2008                   
Revenues from:                   
External Customers $10,318 (d)$442  $409  $35  $-  $11,204  
Other Operating Segments  257 (d) 18   (143)  (17)  (115)  -  
Total Revenues $10,575  $460  $266  $18  $(115) $11,204  
                    
Income Before Discontinued Operations and Extraordinary Loss $1,036  $21  $43  $133  $-  $1,233  
Discontinued Operations, Net of Tax  -   -   -   1   -   1  
Net Income  1,036   21   43   134   -   1,234  
Less: Net Income Attributable to Noncontrolling Interests  4   -   -   -   -   4  
Net Income Attributable to AEP Shareholders  1,032   21   43   134   -   1,230  
Less: Preferred Stock Dividend Requirements of Subsidiaries  2   -   -   -   -   2  
Earnings Attributable to AEP Common Shareholders $1,030  $21  $43  $134  $-  $1,228  
   Nonutility Operations          Nonutility Operations      
March 31, 2010 Utility Operations 
AEP River
Operations
 
Generation
and
Marketing
 
All Other
(a)
 
Reconciling Adjustments
(b)
 Consolidated
 Utility Operations 
AEP River
Operations
 
Generation
and
Marketing
 All Other (a) 
Reconciling Adjustments
(c)
 Consolidated  (in millions)
 (in millions) 
September 30, 2009               
Total Property, Plant and Equipment $50,392  $423  $570  $10  $(237) $51,158   $51,168  $502  $584  $10  $(251) $52,013 
Accumulated Depreciation and Amortization  17,114   84   161   8   (30)  17,337    17,247   92   176   9   (37)  17,487 
Total Property, Plant and Equipment – Net $33,278  $339  $409  $2  $(207) $33,821   $33,921  $410  $408  $1  $(214) $34,526 
                              
Total Assets $45,776  $467  $791  $15,436  $(15,277)(b)$47,193   $48,066  $551  $832  $14,996  $(14,820)(c)$49,625 

   Nonutility Operations          Nonutility Operations      
December 31, 2009 Utility Operations 
AEP River
Operations
 
Generation
and
Marketing
 
All Other
(a)
 
Reconciling Adjustments
(b)
 Consolidated
 Utility Operations 
AEP River
Operations
 
Generation
and
Marketing
 All Other (a) Reconciling Adjustment (c) Consolidated  (in millions)
December 31, 2008 (in millions) 
Total Property, Plant and Equipment $48,997  $371  $565  $10  $(233) $49,710   $50,905  $436  $571  $10  $(238) $51,684 
Accumulated Depreciation and Amortization  16,525   73   140   8   (23)  16,723    17,110   88   168   8   (34)  17,340 
Total Property, Plant and Equipment – Net $32,472  $298  $425  $2  $(210) $32,987   $33,795  $348  $403  $2  $(204) $34,344 
                              
Total Assets $43,773  $439  $737  $14,501  $(14,295)(b)$45,155   $46,930  $495  $779  $15,094  $(14,950)(c)$48,348 

(a)All Other includes:
 ·Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense, and other nonallocated costs.
 ·Forward natural gas contracts that were not sold with our natural gas pipeline and storage operations in 2004 and 2005.  These contracts are financial derivatives which will gradually liquidatesettle and completely expire in 2011.
(b)·The first quarter 2008 cash settlement of a purchase power and sale agreement with TEM relatedIncludes eliminations due to the Plaquemine Cogeneration Facility which was sold in 2006.  The cash settlement of $255 million ($164 million, net of tax) is included in Net Income.an intercompany capital lease.
·Revenue sharing related to the Plaquemine Cogeneration Facility.
(b)(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.
(c)Includes eliminations due to an intercompany capital lease.
(d)PSO and SWEPCo transferred certain existing ERCOT energy marketing contracts to AEP Energy Partners, Inc. (AEPEP) (Generation and Marketing segment) and entered into intercompany financial and physical purchase and sales agreements with AEPEP.  As a result, we reported third-party net purchases or sales activity for these energy marketing contracts as Revenues from External Customers for the Utility Operations segment.  This is offset by the Utility Operations segment’s related net sales (purchases) for these contracts with AEPEP in Revenues from Other Operating Segments of $(113) thousand and $(95)$(5) million for the three months ended September 30, 2009 and 2008, respectively, and $(6) million and $143 million for the nine months ended September 30, 2009 and 2008, respectively.March 31, 2009.  The Generation and Marketing segment also reports these purchasepurchases or sales contracts with Utility Operations as Revenues from Other Operating Segments.  These affiliatedaffi liated contracts between PSO and SWEPCo with AEPEP will endended in December 2009.

8.       DERIVATIVES AND HEDGING
8.DERIVATIVES AND HEDGING

Objectives for Utilization of Derivative InstrumentsOBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

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

Strategies for Utilization of Derivative Instruments to Achieve ObjectivesSTRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

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

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

The following table represents the gross notional volume of our outstanding derivative contracts as of September 30,March 31, 2010 and December 31, 2009:
 
Notional Volume of Derivative Instruments
September 30, 2009
Unit of
Primary Risk ExposureVolumeMeasure
(in millions)
Commodity:
Power544   MWHs
Coal61   Tons
Natural Gas153   MMBtu
Heating Oil and Gasoline8   Gallons
Interest Rate$216 USD
Interest Rate and Foreign Currency$89   USD
Notional Volume of Derivative Instruments
    
 Volume  
 March 31, December 31, Unit of
 2010 2009 Measure
 (in millions)  
Commodity:       
Power  523   589 MWHs
Coal  72   60 Tons
Natural Gas  137   127 MMBtus
Heating Oil and Gasoline  7   6 Gallons
Interest Rate $194  $216 USD
          
Interest Rate and Foreign Currency $329  $83 USD

Fair Value Hedging Strategies

At certain times, weWe enter into interest rate derivative transactions in orderas part of an overall strategy to manage existing fixed interest rate risk exposure.  Thesethe mix of fixed-rate and floating-rate debt.  Certain interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our fixed-rate debt to a floating rate.  Currently, this strategy is not actively employed.Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges.

Cash Flow Hedging Strategies

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

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

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

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

Accounting for Derivative Instruments and the Impact on Our Financial Statements
ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON OUR FINANCIAL STATEMENTS

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

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

According to the accounting guidance for “Derivatives and Hedging,” we reflect the fair values of our derivative instruments subject to netting agreements with the same counterparty net of related cash collateral.  For certain risk management contracts, we are required to post or receive cash collateral based on third party contractual agreements and risk profiles.  For the September 30, 2009March 31, 2010 and December 31, 20082009 balance sheets, we netted $29$36 million and $11$12 million, respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $100$170 million and $43$98 million, respectively, of cash collateral paid to third parties against short-term and long-term risk management liabilities.

The following table representstables represent the gross fair value impact of our derivative activity on our Condensed Consolidated Balance Sheet as of September 30,March 31, 2010 and December 31, 2009:

Fair Value of Derivative Instruments
September 30, 2009
 
Fair Value of Derivative Instruments
March 31, 2010
Fair Value of Derivative Instruments
March 31, 2010
 
           
 Risk Management          Risk Management         
 Contracts Hedging Contracts      Contracts Hedging Contracts     
     Interest Rate          Interest Rate     
     and Foreign Other        and Foreign Other   
Balance Sheet Location Commodity (a) Commodity (a) Currency (a) (a) (b) Total  Commodity (a) Commodity (a) Currency (a) (a) (b) Total 
 (in millions)  (in millions) 
Current Risk Management Assets  $1,518  $24  $-  $(1,242) $300   $1,614  $25  $-  $(1,316) $323 
Long-term Risk Management Assets   828   4   -   (453)  379    933   6   -   (490)  449 
Total Assets   2,346   28   -   (1,695)  679    2,547   31   -   (1,806)  772 
                                          
Current Risk Management Liabilities   1,399   24   3   (1,290)  136    1,522   25   4   (1,400)  151 
Long-term Risk Management Liabilities   643   10   2   (505)  150    792   4   2   (605)  193 
Total Liabilities   2,042   34   5   (1,795)  286    2,314   29   6   (2,005)  344 
                                          
Total MTM Derivative Contract Net Assets (Liabilities)  $304  $(6) $(5) $100  $393   $233  $2  $(6) $199  $428 

Fair Value of Derivative Instruments
December 31, 2009
 
  Risk Management         
  Contracts Hedging Contracts     
      Interest Rate     
      and Foreign Other   
Balance Sheet Location Commodity (a) Commodity (a) Currency (a) (a) (b) Total 
  (in millions) 
Current Risk Management Assets  $1,078  $13  $-  $(831) $260 
Long-term Risk Management Assets   614   -   -   (271)  343 
Total Assets   1,692   13   -   (1,102)  603 
                      
Current Risk Management Liabilities   997   17   3   (897)  120 
Long-term Risk Management Liabilities   442   -   2   (316)  128 
Total Liabilities   1,439   17   5   (1,213)  248 
                      
Total MTM Derivative Contract Net Assets (Liabilities)  $253  $(4) $(5) $111  $355 

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

The table below presents our activity of derivative risk management contracts for the three and nine months ended September 30,March 31, 2010 and 2009:
 
Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended March 31, 2010 and 2009

 Three Months Ended Nine Months Ended 
 September 30, 2009 September 30, 2009  2010  2009 
Location of Gain (Loss) (in millions)  (in millions) 
Utility Operations Revenue  $25  $124  $38  $65 
Other Revenue   1   19   1   13 
Regulatory Assets   (1)   (2)
Regulatory Liabilities   49   130 
Regulatory Assets (a)  -   (1)
Regulatory Liabilities (a)  42   34 
Total Gain on Risk Management Contracts  $74  $271  $81  $111 

 (a)Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or non-current within the balance sheet.

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

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

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

Accounting for Fair Value Hedging Strategies

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

We record realized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged, in Interest Expense on our Condensed Consolidated Statements of Income.  During the three and nine months ended September 30,March 31, 2010, we designated interest rate derivatives as fair value hedges.  During the three months ended March 31, 2010, no hedge ineffectiveness was recognized.  During the three months ended March 31, 2009, we did not employ any fair value hedging strategies.  During the three and nine months ended September 30, 2008, we designated interest rate derivatives as fair value hedges and did not recognize any hedge ineffectiveness related to these derivative transactions.

Accounting for Cash Flow Hedging Strategies

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

Realized gains and losses on derivative contracts for the purchase and sale of electricity, coal, heating oil and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on our Condensed Consolidated Statements of Income, or in Regulatory Assets or Regulatory Liabilities on our Condensed Consolidated Balance Sheet,Sheets, depending on the specific nature of the risk being hedged.  We do not hedge all variable price risk exposure related to commodities.  During the three and nine months ended September 30,March 31, 2010 and 2009, and 2008, we recognized immaterial amounts related to hedge ineffectiveness.designated commodity derivatives as cash flow hedges.

Beginning in 2009, we executed financial heating oil and gasoline derivative contracts to hedge the price risk of our diesel fuel and gasoline purchases.  We reclassify gains and losses on financial fuel derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on our Condensed Consolidated Balance Sheets into Other Operation andexpense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on our Condensed Consolidated Statements of Income.  We do not hedge all fuel price risk exposure.  During the three and nine months ended September 30,March 31, 2010 and 2009, we recognized no hedge ineffectiveness related to this hedge strategy.designated heating oil and gasoline derivatives as cash flow hedges.

We reclassify gains and losses on interest rate derivative hedges related to our debt financings from Accumulated Other Comprehensive Income (Loss) into Interest Expense in those periods in which hedged interest payments occur.  During the three and nine months ended September 30,March 31, 2010 and 2009, we recognized a $1 million loss and a $6 million gain, respectively, in Interest Expense related to hedge ineffectiveness ondesignated interest rate derivatives designated as cash flow hedges.  During the three and nine months ended September 30, 2008, we recognized immaterial amounts in Interest Expense related to hedge ineffectiveness.

The accumulated gains or losses related to our foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on our Condensed Consolidated Balance Sheets into Depreciation and Amortization expense on our Condensed Consolidated Statements of Income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships.  We do not hedge all foreign currency exposure.  During the three and nine months ended September 30,March 31, 2010 and 2009, we designated foreign currency derivatives as cash flow hedges.

During the three months ended March 31, 2010 and 2008, we recognized no2009, hedge ineffectiveness related to thiswas immaterial or nonexistent for all of the hedge strategy.strategies disclosed above.

The following tables provide details on designated, effective cash flow hedges included in AOCI on our Condensed Consolidated Balance Sheets and the reasons for changes in cash flow hedges for the three and nine months ended September 30,March 31, 2010 and 2009.  All amounts in the following table are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow HedgesTotal Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges 
For the Three Months Ended September 30, 2009 
For the Three Months Ended March 31, 2010For the Three Months Ended March 31, 2010 
 Commodity  Interest Rate and Foreign Currency  Total  Commodity  Interest Rate and Foreign Currency  Total 
 (in millions)  (in millions) 
Beginning Balance in AOCI as of July 1, 2009 $6  $(11) $(5)
Balance in AOCI as of January 1, 2010 $(2) $(13) $(15)
Changes in Fair Value Recognized in AOCI  (6)  (4)  (10)  3   (1)  2 
Amount of (Gain) or Loss Reclassified from AOCI to Income Statement/within Balance Sheet            
Amount of (Gain) or Loss Reclassified from AOCI to Income Statement/within Balance Sheet:            
Utility Operations Revenue  (7)  -   (7)  -   -   - 
Other Revenue  (5)  -   (5)  (1)  -   (1)
Purchased Electricity for Resale  10   -   10   1   -   1 
Interest Expense  -   1   1   -   1   1 
Regulatory Assets(a)  2   -   2   1   -   1 
Regulatory Liabilities(a)  (3)  -   (3)  -   -   - 
Ending Balance in AOCI as of September 30, 2009 $(3) $(14) $(17)
Balance in AOCI as of March 31, 2010 $2  $(13) $(11)
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges 
For the Three Months Ended March 31, 2009 
  Commodity  Interest Rate and Foreign Currency  Total 
  (in millions) 
Balance in AOCI as of January 1, 2009 $7  $(29) $(22)
Changes in Fair Value Recognized in AOCI  (3)  -   (3)
Amount of (Gain) or Loss Reclassified from AOCI  to Income Statement/within Balance Sheet:            
Utility Operations Revenue  (2)  -   (2)
Other Revenue  (2)  -   (2)
Purchased Electricity for Resale  8   -   8 
Interest Expense  -   1   1 
Regulatory Assets (a)  2   -   2 
Regulatory Liabilities (a)  (1)  -   (1)
Balance in AOCI as of March 31, 2009 $9  $(28) $(19)

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges 
For the Nine Months Ended September 30, 2009 
  Commodity  Interest Rate and Foreign Currency  Total 
  (in millions) 
Beginning Balance in AOCI as of January 1, 2009 $7  $(29) $(22)
Changes in Fair Value Recognized in AOCI  (9)  11   2 
Amount of (Gain) or Loss Reclassified from AOCI  to Income Statement/within Balance Sheet            
Utility Operations Revenue  (13)  -   (13)
Other Revenue  (11)  -   (11)
Purchased Electricity for Resale  24   -   24 
Interest Expense  -   4   4 
Regulatory Assets  5   -   5 
Regulatory Liabilities  (6)  -   (6)
Ending Balance in AOCI as of September 30, 2009 $(3) $(14) $(17)
(a)Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or non-current within the balance sheet.

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on our Condensed Consolidated Balance Sheet at September 30,March 31, 2010 and December 31, 2009 were:

Impact of Cash Flow Hedges on our Condensed Consolidated Balance Sheet
September 30, 2009
 
Impact of Cash Flow Hedges
Condensed Consolidated Balance Sheet
March 31, 2010
Impact of Cash Flow Hedges
Condensed Consolidated Balance Sheet
March 31, 2010
 
Commodity Interest Rate and Foreign Currency Total Commodity Interest Rate and Foreign Currency Total 
(in millions) (in millions) 
Hedging Assets (a) $17  $-  $17  $16  $-  $16 
Hedging Liabilities (a)  (23)  (5)  (28)  (14)  (6)  (20)
AOCI Gain (Loss) Net of Tax  (3)  (14)  (17)
AOCI Loss Net of Tax  2   (13)  (11)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months  1   (4)  (3)  -   (4)  (4)

Impact of Cash Flow Hedges
Condensed Consolidated Balance Sheet
December 31, 2009
 
 Commodity Interest Rate and Foreign Currency Total 
 (in millions) 
Hedging Assets (a) $8  $-  $8 
Hedging Liabilities (a)  (12)  (5)  (17)
AOCI Loss Net of Tax  (2)  (13)  (15)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months  (2)  (4)  (6)

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


The actual amounts that we reclassify from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.  As of September 30, 2009,March 31, 2010, the maximum length of time that we are hedging (with contracts subject to the accounting guidance for “Derivatives and Hedging”) our exposure to variability in future cash flows related to forecasted transactions is 3845 months.

Credit Risk

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

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

Collateral Triggering Events

Under a limited number of derivative and non-derivative counterparty contracts primarily related to our pre-2002 risk management activities and under the tariffs of the RTOs and Independent System Operators (ISOs), we are obligated to post an amount of collateral if our credit ratings decline below investment grade.  The amount of collateral required fluctuates based on market prices and our total exposure.  On an ongoing basis, our risk management organization assesses the appropriateness of these collateral triggering items in contracts.  We believe that a downgrade below investment grade is unlikely. As of September 30, 2009, theThe following table represents our aggregate fair value of such derivative contracts, was $36 million andthe amount of collateral we were not required to post any collateral.  We would have been required to post $36 million of collateral at September 30, 2009for all derivative and non-derivative contracts if ourthe credit ratings had declined below investment grade of which $30 millionand how much was attributable to our RTO and ISO activities.activities as of March 31, 2010 and December 31, 2009:

 Aggregate Amount of Collateral the Amount 
 Fair Value of Registrant Subsidiaries Attributable to 
 Derivative Would Have Been RTO and ISO 
 Contracts Required to Post Activities 
 (in millions) 
March 31, 2010$9 $34 $32 
December 31, 2009 10  34  29 

In addition, a majority of our non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable.  These cross-default provisions could be triggered if there was a non-performance event under borrowed debt in excess of $50 million.  On an ongoing basis, our risk management organization assesses the appropriateness of these cross-default provisions in our contracts.  As of September 30, 2009, the fair value of derivative liabilities subject to cross-default provisions totaled $852 million prior to consideration of contractual netting arrangements.  This exposure has been reduced by cash collateral posted of $14 million.  We believe that a non-performance event under these provisions is unlikely.  IfThe following table represents the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, the amount this exposure has been reduced by cash collateral we have posted and if a cross-default provision would have been triggered, athe settlement of up to $240 millionamount that would be required after considering our contractual netting arrangements.arrangements as of March 31, 2010 and December 31, 2009:
 Liabilities of   Additional 
 Contracts with Cross   Settlement Liability 
 Default Provisions   if Cross Default 
 Prior to Contractual Amount of Cash Provision is 
 Netting Arrangements Collateral Posted Triggered 
 (in millions) 
March 31, 2010$794 $48 $287 
December 31, 2009 567  15  199 

9.      FAIR VALUE MEASUREMENTS

With the adoption of newFair Value Hierarchy and Valuation Techniques

The accounting guidance we are required to provide certainfor “Fair Value Measurements and Disclosures” establishes a fair value disclosureshierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.  When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value.  Valuation models utilize various inputs such as commodity, interest rate and, to a lesser de gree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.

For our commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1.  We verify our price curves using these broker quotes and classify these fair values within Level 2 when substantially all of the fair value can be corroborated.  We typically obtain multiple broker quotes, which are non-binding in nature, but are based on recent trades in the marketplace.  When multiple broker quotes are obtained, we previously were only requiredaverage the quoted bid and ask prices.  In certain circumstances, we may discard a broker quote if it is a clear outlier.  We use a historical correlation analysis between the broker quoted location and the illiquid locations and if the points are highly correlated we include these locations within Level 2 as well.  Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information.  Long-dated and illiquid complex or structured transactions and FTRs can introduce the need for internally developed modeling inputs based upon extrapolations and assumptions of observable market data to provideestimate fair value.  When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3.

We utilize our trustee’s external pricing service in our annual report.estimate of the fair value of the underlying investments held in the nuclear trusts.  Our investment managers review and validate the prices utilized by the trustee to determine fair value.  We perform our own valuation testing to verify the fair values of the securities.  We receive audit reports of our trustee’s operating controls and valuation processes.  The new accounting guidance didtrustee uses multiple pricing vendors for the assets held in the trusts.  Equities are classified as Level 1 holdings if they are actively traded on exchanges.  Fixed income securities do not change the method totrade on an exchange and do not have an official closing price.  Pricing vendors calculate the amountsbond valuations using financial models and matrices. &# 160;Fixed income securities are typically classified as Level 2 holdings because their valuation inputs are based on observable market data.  Observable inputs used for valuing fixed income securities are benchmark yields, reported trades, broker/dealer quotes, issuer spreads, two-sided markets, benchmark securities, bids, offers, reference data, and economic events.  Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments.  Investments with unobservable valuation inputs are classified as Level 3 investments.

Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equities.  They are valued based on the Condensed Consolidated Balance Sheets.observable inputs primarily unadjusted quoted prices in active markets  for identical assets.

Items classified as Level 2 are primarily investments in individual fixed income securities.  These fixed income securities are valued using models with input data as follows:

Type of Fixed Income Security
United StatesState and Local
Type of InputGovernmentCorporate DebtGovernment
Benchmark YieldsXXX
Broker QuotesXXX
Discount MarginsXX
Treasury Market UpdateX
Base SpreadXXX
Corporate ActionsX
Ratings Agency UpdatesX
Prepayment Schedule and HistoryX
Yield AdjustmentsX

Fair Value Measurements of Long-term Debt

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

The book values and fair values of Long-term Debt at September 30, 2009as of March 31, 2010 and December 31, 20082009 are summarized in the following table:
    
  September 30, 2009  December 31, 2008 
  Book Value  Fair Value  Book Value  Fair Value 
  (in millions) 
Long-term Debt $17,253  $18,251  $15,983  $15,113 
  March 31, 2010  December 31, 2009
  Book Value Fair Value  Book Value Fair Value
  (in millions)
Long-term Debt $17,534  $18,647   $17,498  $18,479 

Fair Value Measurements of Other Temporary Investments

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

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

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

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

The following is a summary of Other Temporary Investments:

  September 30, 2009 December 31, 2008
  Cost Gross Unrealized Gains Gross Unrealized Losses 
Estimated
Fair
Value
 Cost Gross Unrealized Gains Gross Unrealized Losses 
Estimated
Fair
Value
Other Temporary Investments (in millions)
Cash (a) $167  $-  $-  $167  $243  $-  $-  $243 
Debt Securities  57   -   -   57   56   -   -   56 
Equity Securities  18   17   -   35   27   11   10   28 
Total Other Temporary Investments $242  $17  $-  $259  $326  $11  $10  $327 
  March 31, 2010 
Other Temporary Investments Cost  Gross Unrealized Gains  Gross Unrealized Losses  
Estimated
Fair Value
 
  (in millions) 
Restricted Cash (a) $141  $-  $-  $141 
Fixed Income Securities – Mutual Funds  58   -   -   58 
Equity Securities:                
Domestic  1   15   -   16 
Mutual Funds  18   5   -   23 
Total Other Temporary Investments $218  $20  $-  $238 

  December 31, 2009 
 
 
Other Temporary Investments
 Cost Gross Unrealized Gains Gross Unrealized Losses 
Estimated
Fair Value
 
  (in millions) 
Cash and Cash Equivalents (a)  $223  $-  $-  $223 
Debt Securities   102   -   -   102 
Equity Securities   19   19   -   38 
Total Other Temporary Investments  $344  $19  $-  $363 

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

The following table provides the activity for our debt and equity securities within Other Temporary Investments for the three and nine months ended September 30,March 31, 2010 and 2009:
Gross Realized
Proceeds FromPurchasesGross Realized GainsLosses on
Investment Salesof Investmentson Investment SalesInvestment Sales
(in millions)
Three Months Ended$-   $1 $- $- 
Nine Months Ended- 2 - - 

In June 2009, we recorded $9 million ($6 million, net of tax) of other-than-temporary impairments of Other Temporary Investments for equity investments of our protected cell captive insurance company.  
      Gross Realized Gross Realized
Three Months Ended Proceeds From Purchases Gains on Losses on
March 31, Investment Sales of Investments Investment Sales Investment Sales
  (in millions)
2010 $241  $197  $-  $- 
2009  -   -   -   - 

At September 30, 2009,March 31, 2010, we had no Other Temporary Investments with an unrealized loss position.  At DecemberMarch 31, 2008, the fair value of corporate equity securities with an unrealized loss position was $17 million and we had no investments in a continuous unrealized loss position for more than twelve months.  At September 30, 2009, the fair value of2010, debt securities are primarily include debt based mutual funds with short and intermediate maturities.maturities and variable rate demand notes.

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow us to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities.  By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines.  In general, limitations include:

·Acceptable investments (rated investment grade or above when purchased).
·Maximum percentage invested in a specific type of investment.
·Prohibition of investment in obligations of AEP or its affiliates.
·Withdrawals permitted only for payment of decommissioning costs and trust expenses.
·Target asset allocation is 50% fixed income and 50% equity securities.

We maintain trust records for each regulatory jurisdiction.  These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities.  The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.

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

The following is a summary of nuclear trust fund investments at September 30, 2009March 31, 2010 and December 31, 2008:2009:

 September 30, 2009 December 31, 2008 
 
Estimated
Fair
Value
 
Gross
Unrealized
Gains
 
Other-Than-
Temporary
Impairments
 
Estimated
Fair
Value
 
Gross
Unrealized
Gains
 
Other-Than-
Temporary
Impairments
 
 (in millions) 
Cash $19  $-  $-  $18  $-  $- 
Debt Securities  780   35   (2)  773   52   (3)
Equity Securities  565   223   (135)  469   89   (82)
Spent Nuclear Fuel and Decommissioning Trusts $1,364  $258  $(137) $1,260  $141  $(85)
  March 31, 2010  December 31, 2009 
  
Estimated
Fair
Value
  
Gross
Unrealized
Gains
  
Other-Than-
Temporary
Impairments
  
Estimated
Fair
Value
  
Gross
Unrealized
Gains
  
Other-Than-
Temporary
Impairments
 
  (in millions) 
Cash and Cash Equivalents $16  $-  $-  $14  $-  $- 
Fixed Income Securities:                        
United States Government  451   15   (2)  401   13   (4)
Corporate Debt  59   5   (2)  57   5   (2)
State and Local Government  326   3   -   369   8   1 
Subtotal Fixed Income Securities  836   23   (4)  827   26   (5)
Equity Securities – Domestic  581   261   (118)  551   234   (119)
Spent Nuclear Fuel and Decommissioning Trusts $1,433  $284  $(122) $1,392  $260  $(124)

The following table provides the securities activity within the decommissioning and SNF trusts for the three and nine months ended September 30,March 31, 2010 and 2009:
 
      Gross Realized 
Proceeds From Purchases Gross Realized Gains Losses on 
Investment Sales of Investments on Investment Sales Investment Sales 
(in millions)        Gross Realized
Three Months Ended $113  $129  $1  $-  Proceeds From Purchases Gross Realized Gains Losses on
Nine months Ended  524   571   10   (1)
March 31, Investment Sales of Investments on Investment Sales Investment Sales
 (in millions)
2010 $232  $248  $5  $- 
2009  158   178   3  - 

The adjusted cost of debt securities was $745$813 million and $721$801 million as of September 30, 2009March 31, 2010 and December 31, 2008,2009, respectively.

The fair value of debt securities held in the nuclear trust funds, summarized by contractual maturities, at September 30, 2009March 31, 2010 was as follows:
 
Fair Value
of Debt
Securities
  
Fair Value
of Debt
Securities
 
 (in millions)  (in millions) 
Within 1 year $27  $15 
1 year – 5 years  217   309 
5 years – 10 years  241   256 
After 10 years  295   256 
Total $780  $836 

Fair Value Measurements of Financial Assets and Liabilities

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

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

The following tables set forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2009March 31, 2010 and December 31, 2008.2009.  As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  There have not been any significant changes in AEP’s valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis as of September 30, 2009
Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31, 2010
Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31, 2010
                  
Level 1 Level 2 Level 3 Other TotalLevel 1 Level 2 Level 3 Other Total
Assets:(in millions)(in millions)
                          
Cash and Cash Equivalents (a)$799  $-  $-  $78  $877 $733  $-   $-  $85  $818 
                          
Other Temporary Investments  
Cash and Cash Equivalents (a) 142  -   -   25   167 
Debt Securities (c) 57  -   -   -   57 
Equity Securities (d) 35   -   -   -   35 
Restricted Cash (a) 106  -   -   35   141 
Fixed Income Securities – Mutual Funds 58  -   -   -   58 
Equity Securities (c):             
Domestic 16  -   -   -   16 
Mutual Funds  23   -   -   -   23 
Total Other Temporary Investments 234   -   -   25   259  203   -   -   35   238 
                          
Risk Management Assets                          
Risk Management Contracts (e) 21  2,195   116   (1,699)  633 
Cash Flow Hedges (e) 3  24   -   (10)  17 
Dedesignated Risk Management Contracts (f) -   -   -   29   29 
Risk Management Commodity Contracts (d) (g) 22  2,360   148   (1,839)  691 
Cash Flow Hedges:             
Commodity Hedges (d) 11  20   -   (15)  16 
Dedesignated Risk Management Contracts (e) -   -   -   65   65 
Total Risk Management Assets 24   2,219   116   (1,680)  679  33   2,380   148   (1,789)  772 
                          
Spent Nuclear Fuel and Decommissioning Trusts                          
Cash and Cash Equivalents (g) -  10   -   9   19 
Debt Securities (h) -  780   -   -   780 
Equity Securities (d) 565   -   -   -   565 
Cash and Cash Equivalents (f) -  6   -   10   16 
Fixed Income Securities:             
United States Government -  451   -   -   451 
Corporate Debt -  59   -   -   59 
State and Local Government -   326   -   -   326 
Subtotal Fixed Income Securities -  836   -   -   836 
Equity Securities – Domestic (c) 581   -   -  -  581 
Total Spent Nuclear Fuel and Decommissioning Trusts 565   790   -   9   1,364  581   842   -   10   1,433 
                          
Total Assets$1,622  $3,009  $116  $(1,568) $3,179 $1,550  $3,222  $148  $(1,659) $3,261 
                          
Liabilities:                          
                          
Risk Management Liabilities                          
Risk Management Contracts (e)$23  $1,993  $12  $(1,770) $258 
Cash Flow Hedges (e) 5   33   -   (10)  28 
Risk Management Commodity Contracts (d) (g)$27  $2,238  $32  $(1,973) $324 
Cash Flow Hedges:             
Commodity Hedges (d) 2  27   -   (15)  14 
Interest Rate/Foreign Currency Hedges -   6   -   -   6 
Total Risk Management Liabilities$28  $2,026  $12  $(1,780) $286 $29  $2,271  $32  $(1,988) $344 


Assets and Liabilities Measured at Fair Value on a Recurring Basis as of December 31, 2008
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2009
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2009
         
Level 1 Level 2 Level 3 Other TotalLevel 1 Level 2 Level 3 Other Total
Assets:(in millions)(in millions)
                          
Cash and Cash Equivalents             
Cash and Cash Equivalents (a)$304  $-  $-  $60  $364 $427  $-  $-  $63  $490 
Debt Securities (b) -   47   -   -   47 
Total Cash and Cash Equivalents 304   47   -   60   411 
                          
Other Temporary Investments  
Cash and Cash Equivalents (a) 217  -   -   26   243  198  -   -   25   223 
Debt Securities (c) 56  -   -   -   56 
Equity Securities (d) 28   -   -   -   28 
Debt Securities (b) 57  45   -   -   102 
Equity Securities (c) 38   -   -   -   38 
Total Other Temporary Investments 301   -   -   26   327  293   45   -   25   363 
                          
Risk Management Assets                          
Risk Management Contracts (e) 61  2,413   86   (2,022)  538 
Cash Flow Hedges (e) 6  32   -   (4)  34 
Dedesignated Risk Management Contracts (f) -   -   -   39   39 
Risk Management Contracts (d) (h) 8  1,609   72   (1,119)  570 
Cash Flow Hedges (d) 1  11   -   (4)  8 
Dedesignated Risk Management Contracts (e) -   -   -   25   25 
Total Risk Management Assets 67   2,445   86   (1,987)  611  9   1,620   72   (1,098)  603 
                          
Spent Nuclear Fuel and Decommissioning Trusts                          
Cash and Cash Equivalents (g) -  6   -   12   18 
Debt Securities (h) -  773   -   -   773 
Equity Securities (d) 469   -   -   -   469 
Cash and Cash Equivalents (f) -  3   -   11   14 
Fixed Income Securities:             
United States Government -  401   -   -   401 
Corporate Debt -  57   -   -   57 
State and Local Government -   369   -   -   369 
Subtotal Fixed Income Securities -  827   -   -   827 
Equity Securities (c) 551   -   -   -   551 
Total Spent Nuclear Fuel and Decommissioning Trusts 469   779   -   12   1,260  551   830   -   11   1,392 
                          
Total Assets$1,141  $3,271  $86  $(1,889) $2,609 $1,280  $2,495  $72  $(999) $2,848 
                          
Liabilities:                          
                          
Risk Management Liabilities                          
Risk Management Contracts (e)$77  $2,213  $37  $(2,054) $273 
Cash Flow Hedges (e) 1   34   -   (4)  31 
Risk Management Contracts (d) (h)$11  $1,415  $10  $(1,205) $231 
Cash Flow Hedges (d) -   21   -   (4)  17 
Total Risk Management Liabilities$78  $2,247  $37  $(2,058) $304 $11  $1,436  $10  $(1,209) $248 

(a)Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions or with third parties.  Level 1 amounts primarily represent investments in money market funds.
(b)Amount represents commercial paper investments with maturities of less than ninety days.
(c)Amounts represent debt-based mutual funds.
(d)(c)Amount representsAmounts represent publicly traded equity securities and equity-based mutual funds.
(e)(d)Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.”
(f)(e)“Dedesignated Risk Management Contracts” areRepresents contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for “Derivatives and Hedging.”  At the time of the normal election, the MTM value was frozen and no longer fair valued.  This MTM value will be amortized into Utility Operations Revenuesrevenues over the remaining life of the contracts.
(g)(f)Amounts in “Other” column primarily represent accrued interest receivables from financial institutions.  Level 2 amounts primarily represent investments in money market funds.
(g)The March 31, 2010 maturity of the net fair value of risk management commodity contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures ($1) million in 2010, ($2) million in periods 2011-2013 and ($2) million in periods 2014-2015;  Level 2 matures $44 million in 2010, $57 million in periods 2011-2013, $0 million in periods 2014-2015 and $21 million in periods 2016-2028;  Level 3 matures $28 million in 2010, $35 million in periods 2011-2013, $29 million in periods 2014-2015 and $24 million in periods 2016-2028.  Risk management commodity contracts are substantially comprised of power contracts.
(h)Amounts represent corporate, municipalThe December 31, 2009 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures ($1) million in 2010, ($1) million in periods 2011-2013 and treasury bonds.($1) million in periods 2014-2015;  Level 2 matures $65 million in 2010, $84 million in periods 2011-2013, $22 million in periods 2014-2015 and $23 million in periods 2016-2028;  Level 3 matures $17 million in 2010, $16 million in periods 2011-2013, $8 million in periods 2014-2015 and $21 million in periods 2016-2028.

There have been no transfers between Level 1 and Level 2 during the three months ended March 31, 2010.

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

Three Months Ended September 30, 2009Net Risk Management Assets (Liabilities)Other Temporary InvestmentsInvestments in Debt Securities
(in millions)
Balance as of July 1, 2009$67 $- $- 
Realized (Gain) Loss Included in Net Income (or Changes in Net Assets) (a)(8)- - 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)10 - - 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income- - - 
Purchases, Issuances and Settlements (b)- - - 
Transfers in and/or out of Level 3 (c)7 - - 
Changes in Fair Value Allocated to Regulated Jurisdictions (d)28 - - 
Balance as of September 30, 2009$104 $- $- 
Three Months Ended March 31, 2010 Net Risk Management Assets (Liabilities) 
  (in millions) 
Balance as of January 1, 2010 $62 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)  27 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)  24 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income  - 
Purchases, Issuances and Settlements (c)  (31)
Transfers into Level 3 (d) (h)  15 
Transfers out of Level 3 (e) (h)  1 
Changes in Fair Value Allocated to Regulated Jurisdictions (g)  18 
Balance as of March 31, 2010 $116 


Nine Months Ended September 30, 2009Net Risk Management Assets (Liabilities)Other Temporary InvestmentsInvestments in Debt Securities
(in millions)
Balance as of January 1, 2009$49 $- $- 
Realized (Gain) Loss Included in Net Income (or Changes in Net Assets) (a)(21)- - 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)51 - - 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income- - - 
Purchases, Issuances and Settlements (b)- - - 
Transfers in and/or out of Level 3 (c)(26)- - 
Changes in Fair Value Allocated to Regulated Jurisdictions (d)51 - - 
Balance as of September 30, 2009$104 $- $- 

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


Nine Months Ended September 30, 2008 Net Risk Management Assets (Liabilities) Other Temporary Investments Investments in Debt Securities
Three Months Ended March 31, 2009 Net Risk Management Assets (Liabilities) 
 (in millions) (in millions) 
Balance as of January 1, 2008 $49  $-  $- 
Balance as of January 1, 2009 $49 
Realized (Gain) Loss Included in Net Income (or Changes in Net Assets) (a) -  -  -   (12)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 4  -  -   59 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income -  -  -   - 
Purchases, Issuances and Settlements (b) -  (118) (17)  - 
Transfers in and/or out of Level 3 (c)(f) (35) 118  17   (25)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)(g)  (11)  -   -   15 
Balance as of September 30, 2008 $7  $-  $- 
Balance as of March 31, 2009 $86 

(a)Included in revenues on our Condensed Consolidated Statements of Income.
(b)Includes principal amountRepresents the change in fair value between the beginning of securities settled during the period.reporting period and the settlement of the risk management commodity contract.
(c)“Transfers in and/Represents the settlement of risk management commodity contracts for the reporting period.
(d)Represents existing assets or out ofliabilities that were previously categorized as Level 3” represent2.
(e)Represents existing assets or liabilities that were previously categorized as Level 3.
(f)Represents existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period.
(d)(g)“Changes in Fair Value Allocated to Regulated Jurisdictions” relatesRelates to the net gains (losses) of those contracts that are not reflected on theour Condensed Consolidated Statements of Income.  These net gains (losses) are recorded as regulatory liabilities/assets.
(h)Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.

10.    INCOME TAXES

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

We are no longer subject to U.S. federal examination for years before 2000.2001.  We have completed the exam for the years 2001 through 2006 and have issues that we are pursuing at the appeals level.  The years 2007 and 2008 are currently under examination.  Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for income taxes have been made for potential liabilities resulting from such matters.  In addition, we accrue interest on these uncertain tax positions.  We are not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on net income.

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

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

Federal Tax Legislation

The American RecoveryPatient Protection and ReinvestmentAffordable Care Act and the related Health Care and Education Reconciliation Act (Health Care Acts) were enacted in March 2010.  The Health Care Acts amend tax rules so that the portion of 2009 was signed into lawemployer health care costs that are reimbursed by the President in February 2009.  It providedMedicare Part D prescription drug subsidy will no longer be deductible by the employer for several new grant programs and expandedfederal income tax credits and an extensionpurposes effective for years beginning after December 31, 2012.  Because of the 50% bonus depreciation provision enactedloss of the future tax deduction, a reduction in the Economic Stimulus Act of 2008.  The enacted provisions aredeferred tax asset related to the nondeductible OPEB liabilities accrued to date was recorded in March 2010.  This reduction did not expected to have a material impact on net incomematerially affect our cash flows or financial condition.  However, we forecastFor the bonus depreciation provision could providethree months ended March 31, 2010, deferred tax assets decreased $56 million, partially offset by recording net tax regulatory assets of $35 million in our jurisdictions with regulated operations, resulting in a significant favorable cash flow benefitdecrease in 2009.

 11.   FINANCING ACTIVITIES
net income of $21 million.

Common Stock

In April 2009, we issued 69 million shares of common stock at $24.50 per share for net proceeds of $1.64 billion, which were primarily used to repay cash drawn under our credit facilities in the second quarter of 2009.
11.FINANCING ACTIVITIES

Long-term Debt
 September 30,  December 31,  March 31,  December 31, 
Type of Debt 2009  2008  2010  2009 
 (in millions)  (in millions) 
Senior Unsecured Notes $12,316  $11,069  $12,423  $12,416 
Pollution Control Bonds  2,055   1,946   2,263   2,159 
Notes Payable  288   233   316   326 
Securitization Bonds  1,995   2,132   1,909   1,995 
Junior Subordinated Debentures  315   315   315   315 
Spent Nuclear Fuel Obligation (a)  264   264   265   265 
Other Long-term Debt  87   88   88   88 
Unamortized Discount (net)  (67)  (64)  (45)  (66)
Total Long-term Debt Outstanding  17,253   15,983   17,534   17,498 
Less Portion Due Within One Year  1,540   447   1,253   1,741 
Long-term Portion $15,713  $15,536  $16,281  $15,757 

(a)Pursuant to the Nuclear Waste Policy Act of 1982, I&M (a nuclear licensee) has an obligation to the United States Department of Energy for spent nuclear fuel disposal.  The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983.  Trust fund assets related to this obligation of $306 million and $301 million at September 30, 2009March 31, 2010 and December 31, 2008, respectively,2009 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 ninethree months of 20092010 are shown in the tables below.
 
Company Type of Debt Principal Amount Interest Rate Due Date
    (in millions) (%)  
Issuances:        
APCo Senior Unsecured Notes $350  7.95 2020
CSPCo Pollution Control Bonds  60  3.875 2038
CSPCo Pollution Control Bonds  32  5.80 2038
I&M Senior Unsecured Notes  475  7.00 2019
I&M Notes Payable  102  5.44 2013
I&M Pollution Control Bonds  50  6.25 2025
I&M Pollution Control Bonds  50  6.25 2025
OPCo Senior Unsecured Notes  500  5.375 2021
PSO Pollution Control Bonds  34  5.25 2014
          
Non-Registrant:         
AEP River Operations Notes Payable  49  7.59 2026
KPCo Senior Unsecured Notes  40  7.25 2021
KPCo Senior Unsecured Notes  30  8.03 2029
KPCo Senior Unsecured Notes  60  8.13 2039
TCC Pollution Control Bonds  101  6.30 2029
Total Issuances   $1,933 (a)   
Company Type of Debt Principal Amount Interest Rate Due Date
    (in millions) (%)  
Issuances:        
APCo Pollution Control Bonds $18  4.625 2021
CSPCo Floating Rate Notes  150  Variable 2012
OPCo Pollution Control Bonds  86  3.125 2043
SWEPCo Senior Unsecured Notes  350  6.20 2040
SWEPCo  Pollution Control Bonds   54   3.25 2015
Total Issuances   $658 (a)   

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

(a)Amount indicated on the statement of cash flows of $1,912$652 million is net of issuance costs and premium or discount.
 
Company
 Type of Debt Principal Amount Paid Interest Rate Due Date
    (in millions) (%)  
Retirements and Principal Payments:        
APCo Senior Unsecured Notes $150  6.60 2009
OPCo Pollution Control Bonds  218  Variable 2028-2029
OPCo Notes Payable  1  6.27 2009
OPCo Notes Payable  7  7.21 2009
OPCo Notes Payable  70  7.49 2009
PSO Senior Unsecured Notes  50  4.70 2009
SWEPCo Notes Payable  3  4.47 2011
          
Non-Registrant:         
AEP Subsidiaries Notes Payable  11  Variable 2017
AEP Subsidiaries Notes Payable  4  5.88 2011
AEGCo Senior Unsecured Notes  7  6.33 2037
TCC Securitization Bonds  54  5.56 2010
TCC Securitization Bonds  84  4.98 2010
Total Retirements and Principal Payments   $659     

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

During 2008, we chose to begin eliminating our auction-rate debt position due to market conditions.  As of September 30, 2009, $54 million of our auction-rate tax-exempt long-term debt remained outstanding at a rate of 0.862% that resets every 35 days.  The instruments under which the bonds are issued allow us to convert to other short-term variable-rate structures, term-put structures and fixed-rate structures.  In the third quarter of 2009, we reacquired $218 million of auction-rate debt related to JMG with interest rates at the contractual maximum rate of 13%.  We were unable to refinance the debt without JMG’s consent.  We sought approval from the PUCO to terminate the JMG relationship and received the approval in June 2009.  In July 2009, we purchased the outstanding equity ownership of JMG for $28 million which enabled us to reacquire this debt.
 
Company
 Type of Debt Principal Amount Paid Interest Rate Due Date
    (in millions) (%)  
Retirements and Principal Payments:        
AEP Senior Unsecured Notes $490  5.375 2010
SWEPCo  Pollution Control Bonds   54   Variable  2019
          
Non-Registrant:         
AEP Subsidiaries Notes Payable  4  Variable 2017
AEGCo Senior Unsecured Notes  4  6.33 2037
TCC Securitization Bonds  32  5.56 2010
TCC Securitization Bonds  54  4.98 2010
Total Retirements and  Principal Payments   $638     

As of September 30, 2009,March 31, 2010, trustees held, on our behalf, $321$303 million of our reacquired auction-rate tax-exempt long-term debt, which includes the $218debt.

In April 2010, OPCo retired $400 million related to JMG.  We plan to reissue the debt.of variable rate Senior Unsecured Notes due in 2010 and I&M issued $85 million of 4.00% Notes Payable due in 2014.

Dividend Restrictions

The holders of our common stock are entitled to receive the dividends declared by our Board of Directors provided funds are legally available for such dividends.  Our income derives from our common stock equity in the earnings of our utility subsidiaries.  Various financing arrangements, charter provisions and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends.

The Federal Power Act prohibits the utility subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.”  The term “capital account” is not defined in the Federal Power Act or its regulations.  Management understands “capital account” to mean the par value of the common stock multiplied by the number of shares outstanding.  This restriction does not limit the ability of the utility subsidiaries to pay dividends out of retained earnings.

We have issued $315 million of Junior Subordinated Debentures.  The debentures will mature on March 1, 2063, subject to extensions to no later than March 1, 2068.  We have the option to defer interest payments on the AEP Junior Subordinated Debentures issued in March 2008debentures for one or more periods of up to 10 consecutive years per period.  During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire our common stock.  We believe that these restrictions willdo not have a material effect on our net income, cash flows, financial condition or limitanticipate any dividenddeferral of those interest payments in the foreseeable future.

Pursuant to the leverage restrictions in our credit agreements, as of March 31, 2010, none of our retained earnings were restricted for the purpose of the payment of dividends.

Short-term Debt

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

  March 31, 2010 December 31, 2009
  Outstanding Interest Outstanding Interest
Type of Debt Amount Rate (a) Amount Rate (a)
  (in millions)   (in millions)  
Securitized Debt for Receivables (b) $651  0.24% $-  - 
Commercial Paper  399  0.35%  119  0.26%
Line of Credit – Sabine Mining Company (c)  13  2.12%  7  2.06%
Total $1,063    $126   

(a)Weighted average rate.
(b)Paid primarily with proceeds fromAmount of securitized debt for receivables as accounted for under the April 2009 equity issuance.“Transfers and Servicing” accounting guidance.  See “ASU 2009-16 ‘Transfers and Servicing’ ” section of Note 2.
(c)Rate based on LIBOR.
(d)Sabine Mining Company is a consolidated variable interest entity.  This line of credit does not reduce available liquidity under AEP’s credit facilities.

Credit Facilities

As of September 30, 2009, weWe have credit facilities totaling $3 billion to support our commercial paper program.  The facilities are structured as two $1.5 billion credit facilities, of which $750 million may be issued under each credit facility as letters of credit.  As of March 31, 2010, the maximum future payments for letters of credit issued under the two $1.5 billion credit facilities were $175 million.

We have a $627 million 3-year credit agreement.  Under the facility, we may issue letters of credit.  As of September 30, 2009, $372March 31, 2010, $477 million of letters of credit were issued by subsidiaries under the $627 million 3-year credit agreement to support variable rate Pollution Control Bonds.  We had a $350 million 364-day credit agreement that expired in April 2009.

Sales of Receivables
Securitized Accounts Receivable – AEP Credit

AEP Credit has a sale of receivables agreement with banks and commercial paperbank conduits.  Under the sale of receivables agreement, AEP Credit sells an interest in the receivables it acquires from affiliated utility subsidiaries to the commercial paperbank conduits and banksreceives cash.  Prior to January 1, 2010, this transaction constituted a sale of receivables in accordance with the accounting guidance for “Transfers and receives cash.Servicing,” allowing the receivables to be removed from our Condensed Consolidated Balance Sheet.  See “ASU 2009-16 ‘Transfers and Servicing’ ” section of Note 2 for discussion of impact of new accounting guidance effective January 1, 2010 whereby such future transactions do not constitute a sale of receivables and will be accounted for as financing.  AEP Credit continues to service the receivables.  We entered into these securitized transactions to allow AEP Credit to repay its outstanding debt obligations, continue to purchase our operating companies’ receivables and accelerate AEP Credit’s cash collections.

Accounts receivable information for AEP Credit is as follows:

  Three Months 
  Ended 
  March 31, 2010 
  (in millions) 
Credit Losses Related to Securitized Accounts Receivable $4 


 March 31, December 31, 
 2010 2009 
 (in millions) 
Total Principal Outstanding $651  $656 
Derecognized Accounts Receivable  -   631 
Delinquent Securitized Accounts Receivable  37   29 

As of March 31, 2010, AEP Credit's bad debt reserves related to the securitized accounts receivable was $24 million.  Customer accounts receivable retained and securitized for the electric operating companies are managed by AEP Credit.  AEP Credit’s delinquent customer accounts receivable represents accounts greater than 30 days past due.

12.COMPANY-WIDE STAFFING AND BUDGET REVIEW

In July 2009,April 2010, we renewedbegan initiatives to decrease both labor and increased our salenon-labor expenses with a goal of receivables agreement.  The saleachieving significant reductions in operation and maintenance expenses.  One initiative is to offer a one-time voluntary severance program.  Participating employees will receive two weeks of receivables agreement provides a commitmentbase pay for every year of $750 million from bank conduits to purchase receivables.  This agreementservice.  It is anticipated that more than 2,000 employees will expire in Julyaccept voluntary severances and terminate employment no later than May 2010.  The previous salesecond simultaneous initiative will involve all business units and departments seeking to identify process improvements, streamlined organizational designs and other efficiencies that can deliver additional lasting savings.  There is the potential that actions taken as a result of receivables agreement providedthis effort could lead to some involuntary separations .  Affected employees would receive the same severance package as those who volunteered.

We expect to record a commitmentcharge to expense in the second quarter of $700 million.
2010 related to these initiatives.   At this time, we are unable to predict the impact of these initiatives on net income, cash flows and financial condition.














APPALACHIAN POWER COMPANY
AND SUBSIDIARIES


 
 
 

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations
RESULTS OF OPERATIONS

Third
First Quarter of 20092010 Compared to ThirdFirst Quarter of 20082009

Reconciliation of ThirdFirst Quarter of 20082009 to ThirdFirst Quarter of 20092010
Net Income
(in millions)

Third Quarter of 2008    $39 
        
Changes in Gross Margin:       
Retail Margins  77     
Off-system Sales  (65)    
Total Change in Gross Margin      12 
         
Total Expenses and Other:        
Other Operation and Maintenance  (4)    
Depreciation and Amortization  (7)    
Carrying Costs Income  (5)    
Other Income  (3)    
Interest Expense  (5)    
Total Expenses and Other      (24)
         
Third Quarter of 2009     $27 
First Quarter of 2009$74 
Changes in Gross Margin:
Retail Margins42 
Off-system Sales3 
Transmission Revenues1 
Other(1)
Total Change in Gross Margin45 
Total Expenses and Other:
Other Operation and Maintenance(32)
Depreciation and Amortization(7)
Taxes Other Than Income Taxes(2)
Other Income(2)
Carrying Costs Income2 
Interest Expense(2)
Total Expenses and Other(43)
Income Tax Expense(6)
First Quarter of 2010$70 

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·Retail Margins increased $77$42 million primarily due to the following:
 ·A $54 million increase due to a decrease in off-system sales margins shared with customers in Virginia and West Virginia.
·A $37$52 million increase in rate relief primarily due to the impact of the Virginia baseinterim rate order issued in October 2008, an increase in the recovery of E&R costs in Virginia and an increase in the recovery of construction financing costs in West Virginia.
These increases were partially offset by:
·A $9 million decrease due to higher capacity settlement expenses under the Interconnection Agreement net of recovery in West Virginia and environmental deferrals in Virginia.
·A $5 million decrease in industrial sales primarily due to suspended operations by APCo’s largest customer, Century Aluminum.
·Margins from Off-system Sales decreased $65 million primarily due to lower physical sales volumes and lower margins as a result of lower market prices, partially offset by higher trading and marketing margins.

Total Expenses and Other changed between years as follows:

·Other Operation and Maintenance expenses increased $4 million primarily due to the following:
·A $9 million increase related to the establishment of a regulatory asset in the third quarter of 2008 for Virginia’s share of previously expended NSR settlement costs.  See “Virginia Rate Matters – Virginia E&R Costs Recovery Filing” section of Note 3.
·A $2 million increase related to generation plant maintenance.
These increases were partially offset by:
·An $8 million decrease related to the establishment of a regulatory asset for the deferral of transmission costs.  See “Virginia Rate Matters – Rate Adjustment Clauses” section of Note 3.
·Depreciation and Amortization expenses increased $7 million primarily due to increased assets to depreciate reflecting environmental upgrades at the Amos and Clinch River Plants.
·Carrying Costs Income decreased $5 million due to completion of reliability deferrals in Virginiaimplemented in December 2008 and a decrease of environmental deferrals in Virginia in 2009.
·Interest Expense increased $5 million primarily due2009, subject to an increase in long-term borrowings.

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

Reconciliation of Nine Months Ended September 30, 2008 to Nine Months Ended September 30, 2009
Net Income
(in millions)

Nine Months Ended September 30, 2008    $121 
        
Changes in Gross Margin:       
Retail Margins  230     
Off-system Sales  (159)    
Total Change in Gross Margin      71 
         
Total Expenses and Other:        
Other Operation and Maintenance  16     
Depreciation and Amortization  (17)    
Carrying Costs Income  (23)    
Other Income  (7)    
Interest Expense  (15)    
Total Expenses and Other      (46)
         
Income Tax Expense      (15)
         
Nine Months Ended September 30, 2009     $131 

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·Retail Margins increased $230 million primarily due to the following:
·A $128 million increase in rate relief primarily due to the impact of the Virginia base rate order issued in October 2008,refund, an increase in the recovery of E&R costs in Virginia and an increase in the recovery of construction financing costs in West Virginia.
 ·A $124$20 million increase in residential usage primarily due to a decrease17% increase in off-system sales margins shared with customers in Virginia and West Virginia.
·A $19 million increase due to new rates effective January 2009 for a power supply contract with KGPCo.heating degree days.
 These increases were partially offset by:
 ·A $37$19 million decrease due to higher capacity settlement expenses under the Interconnection Agreement net of recovery in West Virginia and environmental deferrals in Virginia.
 ·A $15An $11 million decrease in industrial sales primarily due to suspended operations by APCo’s largest customer, Century Aluminum.
·Margins from Off-system Sales decreased $159increased $3 million primarily due to lowerhigher physical sales volumes and lower margins as a result of lower market prices,reflecting favorable generation availability, partially offset by higherlower trading and marketing margins.

Total Expenses and Other and Income Tax Expense changed between years as follows:

·Other Operation and Maintenance expenses decreased $16increased $32 million primarily due to the following:
 ·A $14$13 million decrease related to the establishment of a regulatory asset in 2009 for the deferral of transmission costs.  See “Virginia Rate Matters – Rate Adjustment Clauses” section of Note 3.
·A $6 million decreaseincrease in employee benefit expenses.
 ·A $2An $8 million decrease in generation plant maintenance.
These decreases were partially offset by:increase related to the reduction of a 2009 regulatory asset for the over-recovery of  transmission costs.
 ·A $9$7 million increase related toin maintenance expenses resulting primarily from a planned outage at the establishment of a regulatory asset in the third quarter of 2008 for Virginia’s share of previously expended NSR settlement costs.  See “Virginia Rate Matters – Virginia E&R Costs Recovery Filing” section of Note 3.Amos Plant and snow storm damage restoration.
·Depreciation and Amortization expenses increased $17$7 million primarily due to increased assets to depreciate reflectinga greater depreciation base resulting from environmental upgrades at the Amos and Clinch RiverMountaineer Plants and the amortization of carrying charges and depreciation expenses that are being collected through the Virginia E&R surcharges.
·Carrying Costs Income decreased $23 million due to completion of reliability deferrals in Virginia in December 2008 and a decrease of environmental deferrals in Virginia in 2009.
·InterestTax Expense increased $15$6 million primarily due to an increase in long-term borrowings.
·Other Income decreased $7 million primarily due to higher interestthe regulatory accounting treatment of state income that was recorded in 2008 related to a tax refundtaxes and other tax adjustments.
·Income Tax Expense increased $15 million primarily due to an increase in pretax book income and changes in certain book/tax differences which are accounted for on a flow-through basis.

Financial ConditionFINANCIAL CONDITION

LIQUIDITY

APCo participates in the Utility Money Pool, which provides access to AEP’s liquidity.  APCo has $150 million of Senior Unsecured Notes and $50 million of Pollution Control Bonds that will mature in 2010.  APCo relies upon ready access to capital markets, cash flows from operations and access to the Utility Money Pool to fund its maturities, current operations and capital expenditures.  See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of liquidity.

Credit Ratings

APCo’s credit ratings as of September 30, 2009March 31, 2010 were as follows:

 Moody’s S&P Fitch
      
Senior Unsecured DebtBaa2 BBB BBB

Moody’s, S&P hasand Fitch have APCo on stable outlook.  In February 2009, Moody’s changed its rating outlook for APCo from negative to stable.  In September 2009, Fitch changed its rating outlook for APCo from negative to stable.  If APCo receives a downgradeDowngrades from any of the rating agencies its borrowing costs could increase and access to borrowed funds could be negatively affected.APCo’s borrowing costs.

Cash FlowCASH FLOW

Cash flows for the ninethree months ended September 30,March 31, 2010 and 2009 and 2008 were as follows:
   
  2010 2009
  (in thousands)
Cash and Cash Equivalents at Beginning of Period $2,006  $1,996 
Cash Flows from (Used for):      
Operating Activities  178,522   (29,207)
Investing Activities  (167,978)  (220,590)
Financing Activities  (10,308)  250,355 
Net Increase in Cash and Cash Equivalents  236   558 
Cash and Cash Equivalents at End of Period $2,242  $2,554 

  2009 2008
  (in thousands)
Cash and Cash Equivalents at Beginning of Period $1,996  $2,195 
Cash Flows from (Used for):      
Operating Activities  (53,712)  208,445 
Investing Activities  (406,707)  (472,029)
Financing Activities  460,237   263,376 
Net Decrease in Cash and Cash Equivalents  (182)  (208)
Cash and Cash Equivalents at End of Period $1,814  $1,987 

Operating Activities

Net Cash Flows Used forfrom Operating Activities were $54$179 million in 2009.2010.  APCo produced Net Income of $131$70 million during the period and hada noncash expense itemsitem of $229 million for Deferred Income Taxes and $204$77 million for Depreciation and Amortization.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The current period activity in working capital relates to a number of items.  The $160 million outflow from Fuel, Materials and Supplies was primarily due to an increase in coal inventory.  The $132$98 million outflow from Accounts Payable was primarily due to APCo’s provision for revenue refundthe placement of $77 million which was paid inFGD equipment into service at the first quarterAmos Plant and decreased purchases of 2009 toenergy from the AEP West companies as part of a FERC order on the SIA.system pool.  The $52$81 million inflow from Accounts Receivable, Net was primarily due to a decrease in accrued revenues due to usual seasonal fluctuations and timing of settlements of receivables from affiliated companies.  The $181$41 million changeinflow from Fuel, Materials and Supplies was primarily due to a reduction in Fuel Over/Under-Recovery, Net resulted fromfuel inventory and a net under-recovery of fueldecrease in the average cost in both Virginia and West Virginia.per ton.

Net Cash Flows fromUsed for Operating Activities were $208$29 million in 2008.2009.  APCo produced Net Income of $121$74 million during the period and had noncash expense items of $187 million for Depreciation and Amortization and $111$80 million for Deferred Income Taxes partially offset by $39and $70 million in Carrying Costs Income.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 $42number of items.  The $116 million inflowcash outflow from Accounts Payable was primarily due to an increaseAPCo’s provision for revenue refund of $77 million which was paid in fuel costs.the first quarter 2009 to the AEP West companies as part of the FERC 217;s recent order on the SIA.  The $114$71 million change in Fuel Over/Under-Recovery, Net resulted from higherin a net under-recovery of fuel costscost in both Virginia and the 2009 approval of a four-year phase-in plan for ENEC recovery in West Virginia.

Investing Activities

Net Cash Flows Used for Investing Activities during 2010 and 2009 and 2008 were $407$168 million and $472$221 million, respectively.  Construction Expenditures were $420expenditures of $167 million and $488$221 million in 2010 and 2009, and 2008, respectively, were primarily relatedfor projects to improve service reliability for transmission and distribution, service reliability projects, as well as environmental upgrades for both periods.upgrades.  Environmental upgrades primarily include the installation of selective catalytic reductionFGD equipment on APCo’s plants and flue gas desulfurization projects at the Amos and Mountaineer Plants.

Financing Activities

Net Cash Flows fromUsed for Financing Activities were $460$10 million in 2009.  APCo issued $350 million of Senior Unsecured Notes in March 2009 and retired $150 million of Senior Unsecured Notes in May 2009.  APCo received capital contributions from the Parent of $250 million in the second quarter of 2009.2010.  APCo had a net increase of $37$118 million in borrowings from the Utility Money Pool.  APCo retired $100 million of Notes Payable - Affiliated and issued $17.5 million of Pollution Control Bonds in 2010.  In addition, APCo paid $20$44 million in dividends on common stock.

Net Cash Flows from Financing Activities were $263$250 million in 2008.2009.  APCo issued $500$350 million of Senior Unsecured Notes in March 2008, $125 million of Pollution Control Bonds in June 2008 and $70 million of Pollution Control Bonds in September 2008.  APCo retired $213 million of Pollution Control Bonds and $200 million of Senior Unsecured Notes in the second quarter of 2008.2009.  APCo had a net decrease of $182$74 million in borrowings from the Utility Money Pool.  In addition, APCo received capital contributions from the Parent of $175 million.

Financing Activity

Long-term debt issuances, retirements and principal payments made during the first ninethree months of 20092010 were:

Issuances
 
Principal
Amount
 Interest Due 
Principal
Amount
 Interest Due
Type of Debt Rate Date Rate Date
 (in thousands) (%)   (in thousands) (%)  
Senior Unsecured Notes $350,000  7.95 2020
Pollution Control Bonds $17,500  4.625 2021


Retirements and Principal Payments
 
Principal
Amount Paid
 Interest Due 
Principal
Amount Paid
 Interest Due
Type of Debt Rate Date Rate Date
 (in thousands) (%)   (in thousands) (%)  
Senior Unsecured Notes $150,000  6.60 2009
Notes Payable – Affiliated $100,000   4.708 2010
Land Note 12  13.718 2026 4  13.718 2026

Liquidity

Although the financial markets were volatile at both a global and domestic level, APCo issued $350 million of Senior Unsecured Notes during the first nine months of 2009.  The credit situation appears to have improved but could impact APCo’s future operations and ability to issue debt at reasonable interest rates.

APCo participates in the Utility Money Pool, which provides access to AEP’s liquidity.  APCo relies upon cash flows from operations and access to the Utility Money Pool to fund current operations and capital expenditures.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of liquidity.

Summary Obligation InformationSUMMARY OBLIGATION INFORMATION

A summary of contractual obligations is included in the 20082009 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 FactorsREGULATORY ACTIVITY

LitigationVirginia Regulatory Activity

In July 2009, APCo filed a generation and distribution base rate increase with the Virginia SCC of $154 million annually based on a 13.35% return on common equity.  The Virginia SCC staff and intervenors have recommended revenue increases ranging from $33 million to $94 million.  The new interim rates, subject to refund, became effective in December 2009 but were discontinued in February 2010 when Virginia newly enacted legislation suspended the collection of interim rates.  The Virginia SCC is required to issue a final order no later than July 2010 with new rates effective August 2010.

West Virginia Regulatory Activity

APCo provided notice to the WVPSC that it intends to file a base rate case during 2010.

In a 2009 proceeding established by the WVPSC to explore options to meet WPCo's future power supply requirements, the WVPSC issued an order approving a joint stipulation among APCo, WPCo, the WVPSC staff and the Consumer Advocate Division.  The order approved the recommendation of the signatories to the stipulation that WPCo merge into APCo and be supplied from APCo's existing power resources.  The order also indicated that it is in the best interests of West Virginia customers that the merger occurs as quickly as possible.  Merger approvals from the WVPSC, Virginia SCC and the FERC are required.  No merger approval filings have been made.

SIGNIFICANT FACTORS

REGULATORY ISSUES

Mountaineer Carbon Capture and Storage Project

APCo and ALSTOM Power, Inc. (Alstom), an unrelated third party, jointly constructed a CO2 capture validation facility, which was placed into service in September 2009.  APCo also constructed and owns the necessary facilities to store the CO2.  In APCo’s July 2009 Virginia base rate filing, APCo requested recovery of and a return on its estimated increased Virginia jurisdictional share of its project costs and recovery of the related asset retirement obligation regulatory asset amortization and accretion.  The Virginia Attorney General and the Virginia SCC staff have recommended in the pending Virginia base rate case that no recovery be allowed for the pro ject.  APCo plans to seek recovery of the West Virginia jurisdictional costs in its next West Virginia base rate filing which is expected to be filed in the second quarter of 2010.  If APCo cannot recover all of its investments in and expenses related to the Mountaineer Carbon Capture and Storage project, it would reduce future net income and cash flows and impact financial condition.  See “Mountaineer Carbon Capture and Storage Project” section of Note 3.

LITIGATION AND ENVIRONMENTAL ISSUES

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 theand amount of any loss, fine or penalty may be.penalty.  Management does, however, assessassesses the probability of loss for such contingencieseach contingency and accrues a liability for cases which have a probable likelihood of loss andif the loss amount can be estimated.  For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 20082009 Annual Report.  Also,Additionally, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the “Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries” section.Contingencies.  Adverse results in thesethe se proceedings have the potential to materially affect APCo’s net income, financial condition and cash flows.

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

Critical Accounting EstimatesCRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 20082009 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncementsbenefits.

See the “New Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of the adoption and impact 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 andAnd Qualitative Disclosures About Risk Management Activities” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for disclosures abouta discussion of risk management activities.  The following tables provide information about AEP’s risk management activities’ effect on APCo.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in APCo’s Condensed Consolidated Balance Sheet as of September 30, 2009 and the reasons for changes in total MTM value as compared to December 31, 2008.

Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
September 30, 2009
(in thousands)

  MTM Risk  Cash Flow  DETM       
  Management  Hedge  Assignment  Collateral    
  Contracts  Contracts  (a)  Deposits  Total 
Current Assets $85,559  $2,818  $-  $(4,942) $83,435 
Noncurrent Assets  61,936   553   -   (4,737)  57,752 
Total MTM Derivative Contract Assets  147,495   3,371   -   (9,679)  141,187 
                     
Current Liabilities  42,005   2,397   2,767   (16,167)  31,002 
Noncurrent Liabilities  38,585   996   697   (16,624)  23,654 
Total MTM Derivative Contract Liabilities  80,590   3,393   3,464   (32,791)  54,656 
                     
Total MTM Derivative Contract Net Assets (Liabilities) $66,905  $(22) $(3,464) $23,112  $86,531 

(a)See “Natural Gas Contracts with DETM” section of Note 15 of the 2008 Annual Report.
MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2009
(in thousands)



Total MTM Risk Management Contract Net Assets at December 31, 2008 $56,936 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period  (24,390)
Fair Value of New Contracts at Inception When Entered During the Period (a)  - 
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period  (185)
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts  - 
Changes in Fair Value Due to Market Fluctuations During the Period (b)  (530)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)  35,074 
Total MTM Risk Management Contract Net Assets  66,905 
Cash Flow Hedge Contracts  (22)
DETM Assignment (d)  (3,464)
Collateral Deposits  23,112 
Total MTM Derivative Contract Net Assets at September 30, 2009 $86,531 

(a)Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices.  The contract prices are valued against market curves associated with the delivery location and delivery term.  A significant portion of the total volumetric position has been economically hedged.
(b)Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(c)“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected on the Condensed Consolidated Statements of Income.  These net gains (losses) are recorded as regulatory liabilities/assets.
(d)See “Natural Gas Contracts with DETM” section of Note 15 of the 2008 Annual Report.

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

The following table presents the maturity, by year, of net assets/liabilities to give an indication of when these MTM amounts will settle and generate or (require) cash:

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets (Liabilities)
September 30, 2009
(in thousands)

  Remainder              After    
  2009  2010  2011  2012  2013  2013  Total 
Level 1 (a) $(444) $(48) $1  $-  $-  $-  $(491)
Level 2 (b)  8,411   14,350   6,979   983   2,758   220   33,701 
Level 3 (c)  6,659   13,812   2,118   1,085   (26)  -   23,648 
Total  14,626   28,114   9,098   2,068   2,732   220   56,858 
Dedesignated Risk Management Contracts (d)  1,444   4,951   1,928   1,724   -   -   10,047 
Total MTM Risk Management Contract Net Assets $16,070  $33,065  $11,026  $3,792  $2,732  $220  $66,905 

(a)Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.  Level 1 inputs primarily consist of exchange traded contracts that exhibit sufficient frequency and volume to provide pricing information on an ongoing basis.
(b)Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.  If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, exchange traded contracts where there was not sufficient market activity to warrant inclusion in Level 1 and OTC broker quotes that are corroborated by the same or similar transactions that have occurred in the market.
(c)Level 3 inputs are unobservable inputs for the asset or liability.  Unobservable inputs shall be used to measure fair value to the extent that the observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.  Level 3 inputs primarily consist of unobservable market data or are valued based on models and/or assumptions.
(d)Dedesignated Risk Management Contracts are contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for “Derivatives and Hedging.”  At the time of the normal election, the MTM value was frozen and no longer fair valued.  This will be amortized into Revenues over the remaining life of the contracts.

Credit Risk

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

See Note 8 for further information regarding MTM risk management contracts, cash flow hedging, accumulated other comprehensive income, credit risk and collateral triggering events.

VaR Associated with Risk Management Contracts

Management uses a risk measurement model, which calculates Value at Risk (VaR) to measure commodity price risk in the risk management portfolio.  The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period.  Based on this VaR analysis, at September 30, 2009, a near term typical change in commodity prices is not expected to have a material effect on net income, cash flows or financial condition.

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

Nine Months Ended    Twelve Months Ended
September 30, 2009    December 31, 2008
(in thousands)    (in thousands)
End High Average Low    End High Average Low
$258 $699 $353 $151    $176 $1,096 $396 $161

Management back-tests its VaR results against performance due to actual price moves.  Based on the assumed 95% confidence interval, the performance due to actual price moves would be expected to exceed the VaR at least once every 20 trading days.  Management’s back-testing results show that its actual performance exceeded VaR far fewer than once every 20 trading days.  As a result, management believes APCo’s VaR calculation is conservative.

As APCo’s VaR calculation captures recent price moves, management also performs regular stress testing of the portfolio to understand APCo’s exposure to extreme price moves.  Management employs a historical-based method whereby the current portfolio is subjected to actual, observed price moves from the last four years in order to ascertain which historical price moves translated into the largest potential MTM loss.  Management then researches the underlying positions, price moves and market events that created the most significant exposure.

Interest Rate Risk

Management utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which APCo’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  As calculated on APCo’s debt outstanding as of September 30, 2009, the estimated EaR on APCo’s debt portfolio for the following twelve months was $3.5 million.


 
 
 


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30,March 31, 2010 and 2009 and 2008
(in thousands)
(Unaudited)

  2010 2009
REVENUES    
Electric Generation, Transmission and Distribution $845,990  $727,959 
Sales to AEP Affiliates  78,771   56,231 
Other Revenues  1,862   1,839 
TOTAL REVENUES  926,623   786,029 
       
EXPENSES      
Fuel and Other Consumables Used for Electric Generation  180,640   143,681 
Purchased Electricity for Resale  63,683   75,816 
Purchased Electricity from AEP Affiliates  267,502   197,124 
Other Operation  90,040   65,502 
Maintenance  63,110   55,910 
Depreciation and Amortization  77,430   69,995 
Taxes Other Than Income Taxes  26,280   24,103 
TOTAL EXPENSES  768,685   632,131 
       
OPERATING INCOME  157,938   153,898 
       
Other Income (Expense):      
Interest Income  291   382 
Carrying Costs Income  5,764   4,083 
Allowance for Equity Funds Used During Construction  1,163   2,653 
Interest Expense  (51,727)  (49,705)
       
INCOME BEFORE INCOME TAX EXPENSE  113,429   111,311 
       
Income Tax Expense  43,147   36,904 
       
NET INCOME  70,282   74,407 
       
Preferred Stock Dividend Requirements Including Capital Stock Expense  225   225 
       
EARNINGS ATTRIBUTABLE TO COMMON STOCK $70,057  $74,182

  Three Months Ended  Nine Months Ended 
  2009  2008  2009  2008 
REVENUES            
Electric Generation, Transmission and Distribution $629,566  $719,295  $1,929,552  $1,926,841 
Sales to AEP Affiliates  63,645   74,632   181,914   262,230 
Other Revenues  2,462   4,906   6,348   12,186 
TOTAL REVENUES  695,673   798,833   2,117,814   2,201,257 
                 
EXPENSES                
Fuel and Other Consumables Used for Electric Generation  140,321   220,955   402,893   554,022 
Purchased Electricity for Resale  54,087   71,075   189,534   167,205 
Purchased Electricity from AEP Affiliates  202,043   219,595   570,231   595,433 
Other Operation  68,402   66,316   197,441   210,262 
Maintenance  53,164   51,292   158,552   161,371 
Depreciation and Amortization  69,701   62,364   203,844   186,528 
Taxes Other Than Income Taxes  24,257   24,319   72,156   72,414 
TOTAL EXPENSES  611,975   715,916   1,794,651   1,947,235 
                 
OPERATING INCOME  83,698   82,917   323,163   254,022 
                 
Other Income (Expense):                
Interest Income  301   1,945   1,078   7,541 
Carrying Costs Income  6,467   11,924   16,341   38,921 
Allowance for Equity Funds Used During Construction  1,897   2,130   5,734   6,278 
Interest Expense  (51,982)  (47,385)  (153,144)  (138,644)
                 
INCOME BEFORE INCOME TAX EXPENSE  40,381   51,531   193,172   168,118 
                 
Income Tax Expense  13,011   12,516   62,225   47,508 
                 
NET INCOME  27,370   39,015   130,947   120,610 
                 
Preferred Stock Dividend Requirements Including Capital Stock Expense
  225   238   675   714 
                 
EARNINGS ATTRIBUTABLE TO COMMON STOCK $27,145  $38,777  $130,272  $119,896 
The common stock of APCo is wholly-owned by AEP.

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 NineThree Months Ended September 30,March 31, 2010 and 2009 and 2008
(in thousands)
(Unaudited)

 Common Stock  Paid-in Capital  Retained Earnings  Accumulated Other Comprehensive Income (Loss)  Total  Common Stock Paid-in Capital Retained Earnings 
Accumulated
Other
Comprehensive
Income (Loss)
 Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2007
 $260,458  $1,025,149  $831,612  $(35,187) $2,082,032 
                                  
EITF 06-10 Adoption, Net of Tax of $1,175          (2,181)      (2,181)
SFAS 157 Adoption, Net of Tax of $154          (286)      (286)
Capital Contribution from Parent      175,000           175,000 
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2008 $260,458  $1,225,292  $951,066  $(60,225) $2,376,591 
              
Common Stock Dividends        (20,000)    (20,000)
Preferred Stock Dividends          (599)      (599)        (200)    (200)
Capital Stock Expense      115   (115)      -      26   (25)    1 
SUBTOTAL – COMMON SHAREHOLDER’S EQUITY                  2,253,966              2,356,392 
                                  
COMPREHENSIVE INCOME                                  
Other Comprehensive Income (Loss), Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $677
              (1,258)  (1,258)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $1,346              2,499   2,499 
Other Comprehensive Income, Net of Taxes:              
Cash Flow Hedges, Net of Tax of $945
          1,756   1,756 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $661          1,226   1,226 
NET INCOME          120,610       120,610         74,407     74,407 
TOTAL COMPREHENSIVE INCOME                  121,851               77,389 
                                  
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2008
 $260,458  $1,200,264  $949,041  $(33,946) $2,375,817 
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2009 $260,458  $1,225,318  $1,005,248  $(57,243) $2,433,781 
                                  
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2008
 $260,458  $1,225,292  $951,066  $(60,225) $2,376,591 
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2009 $260,458  $1,475,393  $1,085,980  $(50,254) $2,771,577 
                                  
Capital Contribution from Parent      250,000           250,000 
Common Stock Dividends          (20,000)      (20,000)        (44,000)    (44,000)
Preferred Stock Dividends          (599)      (599)        (200)    (200)
Capital Stock Expense      76   (76)      -      27   (25)    2 
SUBTOTAL – COMMON SHAREHOLDER’S EQUITY                  2,605,992              2,727,379 
                                  
COMPREHENSIVE INCOME                                  
Other Comprehensive Income (Loss), Net of Taxes:                                  
Cash Flow Hedges, Net of Tax of $545
              (1,013)  (1,013)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $1,982              3,680   3,680 
Cash Flow Hedges, Net of Tax of $940          (1,746)  (1,746)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $562          1,043   1,043 
NET INCOME          130,947       130,947         70,282     70,282 
TOTAL COMPREHENSIVE INCOME                  133,614               69,579 
                                  
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2009
 $260,458  $1,475,368  $1,061,338  $(57,558) $2,739,606 
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2010 $260,458  $1,475,420  $1,112,037  $(50,957) $2,796,958 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2009 and December 31, 2008
(in thousands)
(Unaudited)


  2009  2008 
CURRENT ASSETS      
Cash and Cash Equivalents $1,814  $1,996 
Accounts Receivable:        
Customers  126,428   175,709 
Affiliated Companies  121,925   110,982 
Accrued Unbilled Revenues  47,736   55,733 
Miscellaneous  768   498 
Allowance for Uncollectible Accounts  (5,426)  (6,176)
Total Accounts Receivable  291,431   336,746 
Fuel  282,835   131,239 
Materials and Supplies  84,568   76,260 
Risk Management Assets  83,435   65,140 
Accrued Tax Benefits  88,542   15,599 
Regulatory Asset for Under-Recovered Fuel Costs  92,629   165,906 
Prepayments and Other Current Assets  46,879   45,657 
TOTAL CURRENT ASSETS  972,133   838,543 
         
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
Production  4,214,909   3,708,850 
Transmission  1,797,755   1,754,192 
Distribution  2,606,423   2,499,974 
Other Property, Plant and Equipment  358,696   358,873 
Construction Work in Progress  661,531   1,106,032 
Total Property, Plant and Equipment  9,639,314   9,427,921 
Accumulated Depreciation and Amortization  2,752,839   2,675,784 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
  6,886,475   6,752,137 
         
OTHER NONCURRENT ASSETS        
Regulatory Assets  1,329,527   999,061 
Long-term Risk Management Assets  57,752   51,095 
Deferred Charges and Other Noncurrent Assets  96,180   121,828 
TOTAL OTHER NONCURRENT ASSETS  1,483,459   1,171,984 
         
TOTAL ASSETS $9,342,067  $8,762,664 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



 
 
 

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITYASSETS
September 30, 2009March 31, 2010 and December 31, 20082009
(in thousands)
(Unaudited)

  2009  2008 
CURRENT LIABILITIES (in thousands) 
Advances from Affiliates $231,788  $194,888 
Accounts Payable:        
General  195,277   358,081 
Affiliated Companies  111,723   206,813 
Long-term Debt Due Within One Year – Nonaffiliated  200,018   150,017 
Long-term Debt Due Within One Year – Affiliated  100,000   - 
Risk Management Liabilities  31,002   30,620 
Customer Deposits  57,804   54,086 
Deferred Income Taxes  74,192   - 
Accrued Taxes  42,531   65,550 
Accrued Interest  69,748   47,804 
Other Current Liabilities  70,346   113,655 
TOTAL CURRENT LIABILITIES  1,184,429   1,221,514 
         
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated  3,072,342   2,924,495 
Long-term Debt – Affiliated  -   100,000 
Long-term Risk Management Liabilities  23,654   26,388 
Deferred Income Taxes  1,316,661   1,131,164 
Regulatory Liabilities and Deferred Investment Tax Credits  547,099   521,508 
Employee Benefits and Pension Obligations  323,237   331,000 
Deferred Credits and Other Noncurrent Liabilities  117,287   112,252 
TOTAL NONCURRENT LIABILITIES  5,400,280   5,146,807 
         
TOTAL LIABILITIES  6,584,709   6,368,321 
         
Cumulative Preferred Stock Not Subject to Mandatory Redemption  17,752   17,752 
         
Commitments and Contingencies (Note 4)        
         
COMMON SHAREHOLDER’S EQUITY        
Common Stock – No Par Value:        
Authorized – 30,000,000 Shares        
Outstanding – 13,499,500 Shares  260,458   260,458 
Paid-in Capital  1,475,368   1,225,292 
Retained Earnings  1,061,338   951,066 
Accumulated Other Comprehensive Income (Loss)  (57,558)  (60,225)
TOTAL COMMON SHAREHOLDER’S EQUITY  2,739,606   2,376,591 
         
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $9,342,067  $8,762,664 
  2010 2009
CURRENT ASSETS      
Cash and Cash Equivalents $2,242  $2,006 
Accounts Receivable:      
Customers  150,827   150,285 
Affiliated Companies  68,831   135,686 
Accrued Unbilled Revenues  56,777   68,971 
Miscellaneous  4,447   6,690 
Allowance for Uncollectible Accounts  (5,471)  (5,408)
Total Accounts Receivable  275,411   356,224 
Fuel  303,191   343,261 
Materials and Supplies  87,591   88,575 
Risk Management Assets  78,529   67,956 
Accrued Tax Benefits  156,821   180,708 
Regulatory Asset for Under-Recovered Fuel Costs  54,829   78,685 
Prepayments and Other Current Assets  42,336   36,293 
TOTAL CURRENT ASSETS  1,000,950   1,153,708 
       
PROPERTY, PLANT AND EQUIPMENT      
Electric:      
Production  4,603,157   4,284,361 
Transmission  1,821,829   1,813,777 
Distribution  2,671,245   2,642,479 
Other Property, Plant and Equipment  353,552   329,497 
Construction Work in Progress  437,070   730,099 
Total Property, Plant and Equipment  9,886,853   9,800,213 
Accumulated Depreciation and Amortization  2,777,628   2,751,443 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET  7,109,225   7,048,770 
       
OTHER NONCURRENT ASSETS      
Regulatory Assets  1,457,796   1,433,791 
Long-term Risk Management Assets  65,847   47,141 
Deferred Charges and Other Noncurrent Assets  130,954   113,003 
TOTAL OTHER NONCURRENT ASSETS  1,654,597   1,593,935 
       
TOTAL ASSETS $9,764,772  $9,796,413 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


 
 
 

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
March 31, 2010 and December 31, 2009
(Unaudited)

   2010 2009
CURRENT LIABILITIES  (in thousands)
Advances from Affiliates  $347,425  $229,546 
Accounts Payable:       
General   185,339   291,240 
Affiliated Companies   100,994   157,640 
Long-term Debt Due Within One Year – Nonaffiliated   200,020   200,019 
Long-term Debt Due Within One Year – Affiliated   -   100,000 
Risk Management Liabilities   35,161   25,792 
Customer Deposits   59,202   57,578 
Deferred Income Taxes   66,669   68,706 
Accrued Taxes   65,810   65,241 
Accrued Interest   69,667   58,962 
Other Current Liabilities   80,507   95,292 
TOTAL CURRENT LIABILITIES   1,210,794   1,350,016 
        
NONCURRENT LIABILITIES       
Long-term Debt – Nonaffiliated   3,211,224   3,177,287 
Long-term Risk Management Liabilities   30,388   20,364 
Deferred Income Taxes   1,478,387   1,439,884 
Regulatory Liabilities and Deferred Investment Tax Credits   534,661   526,546 
Employee Benefits and Pension Obligations   310,417   312,873 
Deferred Credits and Other Noncurrent Liabilities   174,196   180,114 
TOTAL NONCURRENT LIABILITIES   5,739,273   5,657,068 
        
TOTAL LIABILITIES   6,950,067   7,007,084 
        
Cumulative Preferred Stock Not Subject to Mandatory Redemption   17,747   17,752 
        
Rate Matters (Note 3)       
Commitments and Contingencies (Note 4)       
        
COMMON SHAREHOLDER’S EQUITY       
Common Stock – No Par Value:       
Authorized – 30,000,000 Shares       
Outstanding – 13,499,500 Shares   260,458   260,458 
Paid-in Capital   1,475,420   1,475,393 
Retained Earnings   1,112,037   1,085,980 
Accumulated Other Comprehensive Income (Loss)   (50,957)  (50,254)
TOTAL COMMON SHAREHOLDER’S EQUITY   2,796,958   2,771,577 
        
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY  $9,764,772  $9,796,413 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.




APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the NineThree Months Ended September 30,March 31, 2010 and 2009 and 2008
(in thousands)
(Unaudited)

 2009  2008  2010 2009
OPERATING ACTIVITIES          
Net Income $130,947  $120,610  $70,282  $74,407 
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:            
Depreciation and Amortization  203,844   186,528  77,430  69,995 
Deferred Income Taxes  229,246   111,297  19,121  80,375 
Carrying Costs Income  (16,341)  (38,921) (5,764) (4,083)
Allowance for Equity Funds Used During Construction  (5,734)  (6,278) (1,163) (2,653)
Mark-to-Market of Risk Management Contracts  (31,415)  7,450  (12,977) (9,433)
Fuel Over/Under-Recovery, Net  (181,241)  (113,748) (11,804) (70,837)
Change in Other Noncurrent Assets  (38,470)  (24,670) 11,082  (7,737)
Change in Other Noncurrent Liabilities  22,595   (12,565) (2,568) 3,098 
Changes in Certain Components of Working Capital:            
Accounts Receivable, Net  51,667   (12,313) 80,813  64,045 
Fuel, Materials and Supplies  (159,904)  3,483  41,054  (39,266)
Accounts Payable  (131,914)  41,869  (97,732) (115,697)
Accrued Taxes, Net  (95,962)  (51,208) 24,150  (41,201)
Other Current Assets  (14,172)  (17,202) (4,250) (16,033)
Other Current Liabilities  (16,858)  14,113   (9,152)  (14,187)
Net Cash Flows from (Used for) Operating Activities  (53,712)  208,445   178,522   (29,207)
            
INVESTING ACTIVITIES            
Construction Expenditures  (420,075)  (487,797) (167,412) (221,053)
Change in Other Cash Deposits  235   (18)
Acquisitions of Assets  (1,024)  - 
Proceeds from Sales of Assets  14,157   15,786 
Other Investing Activities  (566)  463 
Net Cash Flows Used for Investing Activities  (406,707)  (472,029)  (167,978)  (220,590)
            
FINANCING ACTIVITIES            
Capital Contribution from Parent  250,000   175,000 
Issuance of Long-term Debt – Nonaffiliated  345,658   686,512  17,376  345,814 
Change in Advances from Affiliates, Net  36,900   (181,699) 117,879  (74,407)
Retirement of Long-term Debt – Nonaffiliated  (150,012)  (412,786) (5) (4)
Retirement of Long-term Debt – Affiliated (100,000) - 
Retirement of Cumulative Preferred Stock (4) - 
Principal Payments for Capital Lease Obligations  (2,582)  (3,052) (1,790) (848)
Dividends Paid on Common Stock  (20,000)  -  (44,000) (20,000)
Dividends Paid on Cumulative Preferred Stock  (599)  (599) (200) (200)
Other Financing Activities  872   -   436   - 
Net Cash Flows from Financing Activities  460,237   263,376 
Net Cash Flows from (Used for) Financing Activities  (10,308)  250,355 
            
Net Decrease in Cash and Cash Equivalents  (182)  (208)
Net Increase in Cash and Cash Equivalents 236  558 
Cash and Cash Equivalents at Beginning of Period  1,996   2,195   2,006   1,996 
Cash and Cash Equivalents at End of Period $1,814  $1,987  $2,242  $2,554 
            
SUPPLEMENTARY INFORMATION            
Cash Paid for Interest, Net of Capitalized Amounts $148,745  $110,349  $38,971  $49,390 
Net Cash Received for Income Taxes  (14,679)  (26,330)
Net Cash Paid (Received) for Income Taxes -  (2,683)
Noncash Acquisitions Under Capital Leases  884   1,246  20,369  151 
Construction Expenditures Included in Accounts Payable at September 30,  56,989   112,376 
Construction Expenditures Included in Accounts Payable at March 31, 43,262  88,405 

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 MattersNote 1
New Accounting Pronouncements and Extraordinary Item
Note 2
Rate MattersNote 3
Commitments, Guarantees and ContingenciesNote 4
Benefit Plans
Note 6
Business SegmentsNote 7
Derivatives and HedgingNote 8
Fair Value Measurements
Note 9
Income TaxesNote 10
Financing Activities
Note 11
Company-wide Staffing and Budget ReviewNote 12



 
 
 






COLUMBUS SOUTHERN POWER COMPANY
AND SUBSIDIARIES


 
 
 

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

RESULTS OF OPERATIONS

Results of Operations
ThirdFirst Quarter of 20092010 Compared to ThirdFirst Quarter of 20082009

Reconciliation of ThirdFirst Quarter of 20082009 to ThirdFirst Quarter of 20092010
Net Income
(in millions)

Third Quarter of 2008    $82 
        
Changes in Gross Margin:       
Retail Margins  33     
Off-system Sales  (41)    
Total Change in Gross Margin      (8)
         
Total Expenses and Other:        
Other Operation and Maintenance  18     
Depreciation and Amortization  14     
Other Income  (1)    
Interest Expense  (1)    
Total Expenses and Other      30 
         
Income Tax Expense      (6)
         
Third Quarter of 2009     $98 
First Quarter of 2009$49 
Changes in Gross Margin:
Retail Margins3 
Off-system Sales4 
Total Change in Gross Margin7 
Total Expenses and Other:
Other Operation and Maintenance6 
Depreciation and Amortization(3)
Taxes Other Than Income Taxes(2)
Interest Expense(1)
Total Expenses and Other- 
Income Tax Expense(4)
First Quarter of 2010$52 

The major components of the decreaseincrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·Retail Margins increased $33$3 million primarily due to:
 ·A $37$22 million increase related to the implementation of higher rates set by the Ohio ESP.
 ·A $35$5 million increase in fuel margins due to the deferral of fuel costs in 2009.  The PUCO’s March 2009 approval of CSPCo’s ESP allows for the recovery of fuel and related costs incurred since January 1, 2009.  See “Ohio Electric Security Plan Filings” section of Note 3.margins.
 These increases were partially offset by:
 ·A $16$14 million decrease in residential and commercial revenue primarily due toas a 30% decrease in cooling degree days.
·A $13 million decrease in industrial sales primarily due to reduced operating levels by CSPCo’s largest industrial customer, Ormet.
·A $13 million decrease related toresult of the cessationelimination of Restructuring Transition Charge (RTC) revenues with the implementation of rates underCSPCo’s ESP.
·A $4 million decrease as a result of the Ohio ESP.loss of the City of Westerville as a dedicated customer to Off-system Sales.  These sales are shared by the members of the AEP Power Pool.
·A $4 million decrease in commercial and industrial sales primarily due to reduced usage.
·Margins from Off-system Sales decreased $41increased $4 million primarily due to lowerhigher physical sales volumes and lower margins as a result of lower market prices, partially offset by higher trading and marketing margins.

Total Expenses and Other and Income Tax Expense changed between years as follows:

·Other Operation and Maintenance expenses decreased $18 million primarily due to:
·An $8 million decrease in expenses related to CSPCo’s Unit Power Agreement for AEGCo’s Lawrenceburg Plant.  In 2008, these expenses were recorded in Other Operation and Maintenance.  With the March 2009 ESP order, approval was granted to record these costs in purchased power and recover through the FAC.
·A $6 million decrease in recoverable PJM expenses.
·A $2 million decrease in employee benefit expenses.
·Depreciation and Amortization decreased $14 million primarily due to the completed amortization of transition regulatory assets in December 2008.
·Income Tax Expense increased $6 million primarily due to an increase in pretax book income.

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

Reconciliation of Nine Months Ended September 30, 2008 to Nine Months Ended September 30, 2009
Net Income
(in millions)

Nine Months Ended September 30, 2008    $214 
        
Changes in Gross Margin:       
Retail Margins  63     
Off-system Sales  (92)    
Transmission Revenues  (1)    
Other  (1)    
Total Change in Gross Margin      (31)
         
Total Expenses and Other:        
Other Operation and Maintenance  29     
Depreciation and Amortization  41     
Taxes Other Than Income Taxes  (2)    
Other Income  (4)    
Interest Expense  (7)    
Total Expenses and Other      57 
         
Income Tax Expense      (9)
         
Nine Months Ended September 30, 2009     $231 

The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·Retail Margins increased $63 million primarily due to:
·An $80 million increase related to the implementation of higher rates set by the Ohio ESP.
·A $57 million increase in fuel margins due to the deferral of fuel costs in 2009.  The PUCO’s March 2009 approval of CSPCo’s ESP allows for the recovery of fuel and related costs incurred since January 1, 2009.  See “Ohio Electric Security Plan Filings” section of Note 3.
These increases were partially offset by:
·A $39 million decrease as a result of Restructuring Transition Charge (RTC) revenues.  The PUCO allowed CSPCo to continue collecting the RTC pending the implementation of the new ESP tariffs which did not occur until March 30, 2009.  During the first quarter of 2009, these revenues were offset in fuel under-recovery.  In 2008, RTC revenues were recorded but were offset through the amortization of the transition regulatory assets as discussed below.  With the implementation of the Ohio ESP, RTC revenues ended.  See “Ohio Electric Security Plan Filings” section of Note 3.
·A $25 million decrease in industrial sales primarily due to reduced operating levels by CSPCo’s largest industrial customer, Ormet.
·A $10 million decrease in commercial revenue primarily due to reduced usage and an 18% decrease in cooling degree days.
·Margins from Off-system Sales decreased $92 million primarily due to lower physical sales volumes and lower margins as a result of lower market prices, partially offset by higher trading and marketing margins.reflecting favorable generation availability.

Total Expenses and Other and Income Tax Expense changed between years as follows:

·Other Operation and Maintenance expenses decreased $29$6 million primarily due to:
 ·A $25An $8 million decrease in expenses related to CSPCo’s Unit Power Agreement for AEGCo’s Lawrenceburg Plant.  In 2008, these expenses were recorded in Other Operation and Maintenance.  With the Marcha 2009 ESP order, approval was granted to record these costs in purchased power and recover through the FAC.
·A $6 million decrease in employee benefit expenses.
·A $4 million decrease in recoverable PJM expenses.
·A $3 million decrease in net allocated transmission expenses related to the AEP Transmission Equalization Agreement.
·A $2 million decrease in boiler plant maintenance expenses primarily related to work performed at the Conesville Plant in 2008.
·A $2 million decrease in maintenance expenses for overhead transmission lines.
These decreases were partially offset by:
·A $13 million increase in overhead distribution line expenses primarily due to ice and wind storms in the first quarter of 2009 and increased vegetation management activities.
·A $6 million increase related to an obligation to contribute to the “Partnership with Ohio” fund for low income, at-risk customers ordered by the PUCO’s March 2009 approval of CSPCo’s ESP.  See “Ohio Electric Security Plan Filings” section of Note 3.
·A $3 million decrease in overhead distribution line expenses primarily due to ice and wind storms in the first quarter of 2009, partially offset by increased vegetation management activities.
·A $3 million decrease in removal costs primarily related to work performed at the Conesville and Darby Plants.
These decreases were partially offset by:
·A $4 million increase in recoverable customer account expenses due to increased Universal Service Fund surcharge rates for customers who qualify for payment assistance.
·A $3 million increase in employee-related expenses.
·Depreciation and Amortization decreased $41increased $3 million primarily due to projects at the Conesville Plant that were completed amortization of transition regulatory assetsand placed in December 2008.service in November 2009.
·Taxes Other Than Income Taxes increased $2 million primarily due to an increaseincreases in property taxes partially offset by a decrease in state excise taxes.
·Other Income decreased $4 million primarily due to interest income recorded in 2008 on expected federal tax refund related to Simple Service Cost Method.
·Interest Expense increased $7 million primarily due to an increase in long-term borrowings and adjustments recorded in 2008 related to tax reserves, which were partially offset by an increase in the debt component of AFUDC.
·Income Tax Expense increased $9$4 million primarily due to an increase in pretax book income.income, other book/tax differences accounted for on a flow-through basis and the tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits.

Critical Accounting EstimatesSIGNIFICANT FACTORS

REGULATORY ISSUES

Ohio Electric Security Plan Filing

During 2009, the PUCO issued an order that modified and approved CSPCo’s ESP which established rates through 2011.  The order also limits rate increases for CSPCo to 7% in 2009, 6% in 2010 and 6% in 2011.  The order provides a FAC for the three-year period of the ESP.  Several notices of appeal are outstanding at the Supreme Court of Ohio relating to significant issues in the determination of the approved ESP rates.  In addition, an order is expected from the PUCO related to the SEET methodology.  See “Ohio Electric Security Plan Filings” section of Note 3.

LITIGATION AND ENVIRONMENTAL ISSUES

In the ordinary course of business, CSPCo 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 will be or the timing and amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss amount can be estimated.  For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2009 Annual Report.  Additionally, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies.  Adverse results in th ese proceedings have the potential to materially affect CSPCo’s net income, financial condition and cash flows.

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 20082009 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncementsbenefits.

See the “New Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of the adoption and impact 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 andAnd Qualitative Disclosures About Risk Management Activities” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for disclosures abouta discussion of risk management activities.

Interest Rate Risk

Management utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure.  EaR statistically quantifies the extent to which CSPCo’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  As calculated on CSPCo’s debt outstanding as of September 30, 2009, the estimated EaR on CSPCo’s debt portfolio for the following twelve months was $112 thousand.

 
 
 

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30,March 31, 2010 and 2009 and 2008
(in thousands)
(Unaudited)

 Three Months Ended  Nine Months Ended 
 2009  2008  2009  2008  2010 2009
REVENUES                
Electric Generation, Transmission and Distribution $533,306  $633,325  $1,482,421  $1,638,705  $501,019  $460,922 
Sales to AEP Affiliates  22,143   29,032   51,514   111,553  15,832  10,206 
Other Revenues  694   1,426   1,820   4,121   588   608 
TOTAL REVENUES  556,143   663,783   1,535,755   1,754,379   517,439   471,736 
                    
EXPENSES                    
Fuel and Other Consumables Used for Electric Generation  88,523   112,566   222,943   283,946  114,441  70,944 
Purchased Electricity for Resale  21,750   63,441   74,010   150,637  19,645  29,838 
Purchased Electricity from AEP Affiliates  105,120   139,017   294,280   343,699  98,799  93,092 
Other Operation  68,971   87,358   210,614   245,379  77,326  76,088 
Maintenance  23,926   23,039   86,558   80,705  24,283  31,014 
Depreciation and Amortization  36,292   50,373   105,863   146,668  37,487  34,945 
Taxes Other Than Income Taxes  44,149   44,533   132,576   130,078   47,057   45,282 
TOTAL EXPENSES  388,731   520,327   1,126,844   1,381,112   419,038   381,203 
                    
OPERATING INCOME  167,412   143,456   408,911   373,267  98,401  90,533 
                    
Other Income (Expense):                    
Interest Income  144   1,515   618   5,457  142  240 
Carrying Costs Income  1,984   1,566   5,394   4,870  2,221  1,689 
Allowance for Equity Funds Used During Construction  914   745   2,799   2,165  921  1,300 
Interest Expense  (22,487)  (21,127)  (64,356)  (57,612)  (21,784)  (20,793)
                    
INCOME BEFORE INCOME TAX EXPENSE  147,967   126,155   353,366   328,147  79,901  72,969 
                    
Income Tax Expense  50,374   44,493   122,737   113,939   28,251   24,111 
                    
NET INCOME  97,593   81,662   230,629   214,208  51,650  48,858 
                    
Capital Stock Expense  39   39   118   118   39   39 
                    
EARNINGS ATTRIBUTABLE TO COMMON STOCK $97,554  $81,623  $230,511  $214,090  $51,611  $48,819 

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 NineThree Months Ended September 30,March 31, 2010 and 2009 and 2008
(in thousands)
(Unaudited)

 Common Stock  Paid-in Capital  Retained Earnings  
Accumulated
Other
Comprehensive Income (Loss)
  Total  Common Stock Paid-in Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2007
 $41,026  $580,349  $561,696  $(18,794) $1,164,277 
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2008 $41,026  $580,506  $674,758  $(51,025) $1,245,265 
                               
EITF 06-10 Adoption, Net of Tax of $589          (1,095)      (1,095)
SFAS 157 Adoption, Net of Tax of $170          (316)      (316)
Common Stock Dividends          (87,500)      (87,500)      (50,000)   (50,000)
Capital Stock Expense      118   (118)      -     39  (39)    - 
SUBTOTAL – COMMON SHAREHOLDER’S EQUITY                  1,075,366            1,195,265 
                               
COMPREHENSIVE INCOME                               
Other Comprehensive Income, Net of Taxes:                               
Cash Flow Hedges, Net of Tax of $582              1,080   1,080 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $456              846   846 
Cash Flow Hedges, Net of Tax of $340        631  631 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $298        554  554 
NET INCOME          214,208       214,208       48,858     48,858 
TOTAL COMPREHENSIVE INCOME                  216,134               50,043 
                               
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2008
 $41,026  $580,467  $686,875  $(16,868) $1,291,500 
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2009
 $41,026  $580,545  $673,577  $(49,840) $1,245,308 
                               
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2008
 $41,026  $580,506  $674,758  $(51,025) $1,245,265 
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2009
 $41,026  $580,663  $788,139  $(49,993) $1,359,835 
                               
Common Stock Dividends          (150,000)      (150,000)      (31,250)   (31,250)
Capital Stock Expense      118   (118)      -     39  (39)    - 
Noncash Dividend of Property to Parent          (8,123)      (8,123)
SUBTOTAL – COMMON SHAREHOLDER’S EQUITY                  1,087,142            1,328,585 
                               
COMPREHENSIVE INCOME                               
Other Comprehensive Income (Loss), Net of Taxes:                               
Cash Flow Hedges, Net of Tax of $699              (1,299)  (1,299)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $894              1,661   1,661 
Cash Flow Hedges, Net of Tax of $555        (1,031) (1,031)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $333        619  619 
NET INCOME          230,629       230,629       51,650     51,650 
TOTAL COMPREHENSIVE INCOME                  230,991               51,238 
                               
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2009
 $41,026  $580,624  $747,146  $(50,663) $1,318,133 
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2010
 $41,026  $580,702  $808,500  $(50,405) $1,379,823 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.




 
 
 

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2009March 31, 2010 and December 31, 20082009
(in thousands)
(Unaudited)

 2009  2008  2010 2009
CURRENT ASSETS            
Cash and Cash Equivalents $1,204  $1,063  $1,414  $1,096 
Other Cash Deposits  20,077   32,300   5,860   16,150 
Advances to Affiliates  37,818   - 
Accounts Receivable:              
Customers  22,153   56,008   43,051   37,158 
Affiliated Companies  20,176   44,235   14,766   28,555 
Accrued Unbilled Revenues  24,878   18,359   12,078   11,845 
Miscellaneous  2,141   11,546   4,812   4,164 
Allowance for Uncollectible Accounts  (3,565)  (2,895)  (2,019)  (3,481)
Total Accounts Receivable  65,783   127,253   72,688   78,241 
Fuel  72,204   42,075   83,463   74,158 
Materials and Supplies  38,886   33,781   40,142   39,652 
Emission Allowances  13,794   20,211   25,177   26,587 
Risk Management Assets  43,916   35,984   44,362   34,343 
Accrued Tax Benefits  18,023   469   9,517   29,273 
Margin Deposits  17,652   13,613   18,971   14,874 
Prepayments and Other Current Assets  9,616   27,411   14,101   6,349 
TOTAL CURRENT ASSETS  301,155   334,160   353,513   320,723 
              
PROPERTY, PLANT AND EQUIPMENT              
Electric:              
Production  2,372,111   2,326,056   2,648,128   2,641,860 
Transmission  610,824   574,018   635,148   623,680 
Distribution  1,699,698   1,625,000   1,748,245   1,745,559 
Other Property, Plant and Equipment  201,890   211,088   201,250   189,315 
Construction Work in Progress  399,388   394,918   144,328   155,081 
Total Property, Plant and Equipment  5,283,911   5,131,080   5,377,099   5,355,495 
Accumulated Depreciation and Amortization  1,844,261   1,781,866   1,861,973   1,838,840 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET  3,439,650   3,349,214   3,515,126   3,516,655 
              
OTHER NONCURRENT ASSETS              
Regulatory Assets  335,691   298,357   309,995   341,029 
Long-term Risk Management Assets  30,569   28,461   37,264   23,882 
Deferred Charges and Other Noncurrent Assets  72,798   125,814   128,009   147,217 
TOTAL OTHER NONCURRENT ASSETS  439,058   452,632   475,268   512,128 
              
TOTAL ASSETS $4,179,863  $4,136,006  $4,343,907  $4,349,506 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


 
 
 

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDER’S EQUITY
September 30, 2009March 31, 2010 and December 31, 20082009
(Unaudited)

 2009  2008   2010 2009
CURRENT LIABILITIES (in thousands)   (in thousands)
Advances from Affiliates $20,095  $74,865   $-  $24,202 
Accounts Payable:               
General  88,992   131,417    85,166   95,872 
Affiliated Companies  84,743   120,420    52,427   81,338 
Long-term Debt Due Within One Year – Nonaffiliated   150,000   150,000 
Long-term Debt Due Within One Year – Affiliated  100,000   -    -   100,000 
Risk Management Liabilities  16,275   16,490    19,407   13,052 
Customer Deposits  28,067   30,145    29,021   27,911 
Accrued Taxes  100,021   185,293    154,344   199,001 
Accrued Interest  26,776   23,867    27,203   24,669 
Other Current Liabilities  67,275   58,811    70,480   67,053 
TOTAL CURRENT LIABILITIES  532,244   641,308    588,048   783,098 
               
NONCURRENT LIABILITIES               
Long-term Debt – Nonaffiliated  1,436,291   1,343,594    1,438,592   1,286,393 
Long-term Debt – Affiliated  -   100,000 
Long-term Risk Management Liabilities  12,522   14,774    17,200   10,313 
Deferred Income Taxes  511,102   435,773    539,387   535,265 
Regulatory Liabilities and Deferred Investment Tax Credits  179,825   161,102    177,639   174,671 
Employee Benefits and Pension Obligations  142,020   148,123    132,317   133,968 
Deferred Credits and Other Noncurrent Liabilities  47,726   46,067    70,901   65,963 
TOTAL NONCURRENT LIABILITIES  2,329,486   2,249,433    2,376,036   2,206,573 
               
TOTAL LIABILITIES  2,861,730   2,890,741    2,964,084   2,989,671 
               
Rate Matters (Note 3)       
Commitments and Contingencies (Note 4)               
               
COMMON SHAREHOLDER’S EQUITY               
Common Stock – No Par Value:               
Authorized – 24,000,000 Shares               
Outstanding – 16,410,426 Shares  41,026   41,026    41,026   41,026 
Paid-in Capital  580,624   580,506    580,702   580,663 
Retained Earnings  747,146   674,758    808,500   788,139 
Accumulated Other Comprehensive Income (Loss)  (50,663)  (51,025)   (50,405)  (49,993)
TOTAL COMMON SHAREHOLDER’S EQUITY  1,318,133   1,245,265    1,379,823   1,359,835 
               
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY $4,179,863  $4,136,006   $4,343,907  $4,349,506 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.




 
 
 

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the NineThree Months Ended September 30,March 31, 2010 and 2009 and 2008
(in thousands)
(Unaudited)

 2009  2008  2010 2009
OPERATING ACTIVITIES          
Net Income $230,629  $214,208  $51,650  $48,858 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:            
Depreciation and Amortization  105,863   146,668  37,487  34,945 
Deferred Income Taxes  97,279   8,981  8,327  38,945 
Carrying Costs Income  (5,394)  (4,870)
Allowance for Equity Funds Used During Construction  (2,799)  (2,165) (921) (1,300)
Mark-to-Market of Risk Management Contracts  (14,832)  5,326  (11,609) (3,204)
Deferred Property Taxes  67,012   65,763 
Property Taxes 24,131  22,262 
Fuel Over/Under-Recovery, Net  (36,401)  -  26,139  (16,934)
Change in Other Noncurrent Assets  (18,365)  (7,942) (4,994) (8,551)
Change in Other Noncurrent Liabilities  22,644   (4,081) (46) 13,410 
Changes in Certain Components of Working Capital:            
Accounts Receivable, Net  62,244   (13,757) 5,553 43,345 
Fuel, Materials and Supplies  (28,817)  7,415  (9,795) (19,854)
Accounts Payable  (56,723)  (2,650) (22,402) (81,080)
Customer Deposits  (2,078)  (13,100)
Accrued Taxes, Net  (102,827)  (26,358) (24,444) (57,623)
Other Current Assets  8,017   (13,178) (428) 1,157 
Other Current Liabilities  (5,914)  (14,018)  (1,619)  (9,817)
Net Cash Flows from Operating Activities  319,538   346,242   77,029   4,559 
            
INVESTING ACTIVITIES            
Construction Expenditures  (216,737)  (304,175) (42,906) (67,831)
Change in Other Cash Deposits  12,223   21,796  10,290  11,093 
Change in Advances to Affiliates, Net  -   (21,833) (37,818) - 
Acquisitions of Assets  (227)  -  (190) - 
Proceeds from Sales of Assets  721   1,287   789   206 
Net Cash Flows Used for Investing Activities  (204,020)  (302,925)  (69,835)  (56,532)
            
FINANCING ACTIVITIES            
Issuance of Long-term Debt – Nonaffiliated  91,204   346,407  149,625  - 
Change in Advances from Affiliates, Net  (54,770)  (95,199) (24,202) 102,871 
Retirement of Long-term Debt – Nonaffiliated  -   (204,245)
Retirement of Long-term Debt – Affiliated (100,000) - 
Principal Payments for Capital Lease Obligations  (2,017)  (2,213) (1,120) (674)
Dividends Paid on Common Stock  (150,000)  (87,500) (31,250) (50,000)
Other Financing Activities  206   -   71   - 
Net Cash Flows Used for Financing Activities  (115,377)  (42,750)
Net Cash Flows from (Used for) Financing Activities  (6,876)  52,197 
            
Net Increase in Cash and Cash Equivalents  141   567  318  224 
Cash and Cash Equivalents at Beginning of Period  1,063   1,389   1,096   1,063 
Cash and Cash Equivalents at End of Period $1,204  $1,956  $1,414  $1,287 
            
SUPPLEMENTARY INFORMATION            
Cash Paid for Interest, Net of Capitalized Amounts $71,032  $57,004  $18,631  $31,229 
Net Cash Paid for Income Taxes  10,997   53,682  -  387 
Noncash Acquisitions Under Capital Leases  784   1,374  8,353  254 
Construction Expenditures Included in Accounts Payable at September 30,  26,688   51,997 
Noncash Dividend of Property to Parent  8,123   - 
Construction Expenditures Included in Accounts Payable at March 31, 13,891  51,297 

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 MattersNote 1
New Accounting Pronouncements and Extraordinary ItemNote 2
Rate MattersNote 3
Commitments, Guarantees and ContingenciesNote 4
Benefit PlansNote 6
Business SegmentsNote 7
Derivatives and HedgingNote 8
Fair Value Measurements
Note 9
Income TaxesNote 10
Financing ActivitiesNote 11
Company-wide Staffing and Budget ReviewNote 12




 
 
 






INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES



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


Results of Operations

Third Quarter of 2009 Compared to Third Quarter of 2008

Reconciliation of Third Quarter of 2008 to Third Quarter of 2009
Net Income
(in millions)

Third Quarter of 2008    $46 
        
Changes in Gross Margin:       
Retail Margins  (2)    
FERC Municipals and Cooperatives  1     
Off-system Sales  (39)    
Other  38     
Total Change in Gross Margin      (2)
         
Total Expenses and Other:        
Other Operation and Maintenance  17     
Depreciation and Amortization  (2)    
Other Income  4     
Interest Expense  (5)    
Total Expenses and Other      14 
         
Income Tax Expense      (3)
         
Third Quarter of 2009     $55 

The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·Margins from Off-system Sales decreased $39 million primarily due to lower physical sales volumes and lower margins as a result of lower market prices, partially offset by higher trading and marketing margins.
·Other revenues increased $38 million primarily due to Cook Plant accidental outage insurance policy proceeds of $46 million.  Of these insurance proceeds, $19 million were used to reduce customer bills which are primarily included in Retail Margins.  See “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.  A decrease in River Transportation Division (RTD) revenues partially offset the insurance proceeds.  RTD’s related expenses which offset the RTD revenues are included in Other Operation on the Condensed Consolidated Statements of Income.

Total Expenses and Other changed between years as follows:

·Other Operation and Maintenance expenses decreased $17 million primarily due to declines in operation and maintenance expenses of $9 million for nuclear operations and $8 million for RTD caused by decreased barging activity.
·Other Income increased $4 million due to higher equity AFUDC.
·Interest Expense increased $5 million primarily due to increased borrowings.  In January 2009, I&M issued $475 million of 7% Senior Unsecured Notes.
Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008

Reconciliation of Nine Months Ended September 30, 2008 to Nine Months Ended September 30, 2009
Net Income
(in millions)

Nine Months Ended September 30, 2008    $151 
        
Changes in Gross Margin:       
Retail Margins  (26)    
FERC Municipals and Cooperatives  5     
Off-system Sales  (94)    
Transmission Revenues  (1)    
Other  132     
Total Change in Gross Margin      16 
         
Total Expenses and Other:        
Other Operation and Maintenance  43     
Depreciation and Amortization  (5)    
Taxes Other Than Income Taxes  2     
Other Income  8     
Interest Expense  (18)    
Total Expenses and Other      30 
         
Income Tax Expense      (13)
         
Nine Months Ended September 30, 2009     $184 

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power, were as follows:

·Retail Margins decreased $26 million primarily due to the following:
·A $37 million decline due to a 16% decrease in industrial sales resulting from reduced operating levels and suspended operations by certain large industrial customers.
·Lower fuel recoveries reflecting $59 million of Cook Plant accidental outage insurance proceeds allocated to customers under fuel clauses.
These decreases were partially offset by:
·A $29 million increase in capacity revenue reflecting MLR changes.
·A $26 million increase from an Indiana rate settlement.  See “Indiana Base Rate Filing” section of Note 3.
·A $17 million favorable impact for lower PJM charges reflecting a decline in sales volume.
·Margins from Off-system Sales decreased $94 million primarily due to lower physical sales volumes and lower margins as a result of lower market prices, partially offset by higher trading and marketing margins.
·Other revenues increased $132 million primarily due to Cook Plant accidental outage insurance policy proceeds of $145 million.  Of the insurance proceeds, $59 million were used to reduce customer bills which are primarily included in Retail Margins.  See “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.  A decrease in RTD revenues partially offset the insurance proceeds.  RTD’s related expenses which offset the RTD revenues are included in Other Operation on the Condensed Consolidated Statements of Income.

Total Expenses and Other and Income Tax Expense changed between years as follows:

·Other Operation and Maintenance expenses decreased $43 million primarily due to the following:
·A $21 million decline for nuclear and coal-fired generating operation and maintenance expenses reflecting cost containment efforts, deferral of costs during outages and deferral of NSR costs provided in the rate settlement for recovery.  See “Indiana Base Rate Filing” section of Note 3.
·An $11 million decline for RTD caused by decreased barging activity.
·A $7 million decline in accretion expense reflecting a change in the annual decommissioning estimate at Cook Plant for an extension of its life authorized in the rate settlement.
·Other Income increased $8 million due to higher equity AFUDC.
·Interest Expense increased $18 million primarily due to increased borrowings.  In January 2009, I&M issued $475 million of 7% Senior Unsecured Notes.
·Income Tax Expense increased $13 million primarily due to an increase in pretax book income, partially offset by a decrease in state income taxes.

Cook Plant Unit 1 Fire and Shutdown

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

I&M maintains property insurance through NEIL with a $1 million deductible.  As of September 30, 2009, I&M recorded $122 million in Prepayments and Other Current Assets on the Condensed Consolidated Balance Sheets representing recoverable amounts under the property insurance policy.  Through September 30, 2009, I&M received partial payments of $72 million from NEIL for the cost incurred to date to repair the property damage.

I&M also maintains a separate accidental outage policy with NEIL whereby, after a 12-week deductible period, I&M is entitled to weekly payments of $3.5 million for the first 52 weeks following the deductible period.  After the initial 52 weeks of indemnity, the policy pays $2.8 million per week for up to an additional 110 weeks.  I&M began receiving payments under the accidental outage policy in December 2008.  In 2009, I&M recorded $145 million in revenues and applied $59 million of the accidental outage insurance proceeds to reduce customer bills.

NEIL is reviewing claims made under the insurance policies to ensure that claims associated with the outage are covered by the policies.  The treatment of property damage costs, replacement power costs and insurance proceeds will be the subject of future regulatory proceedings in Indiana and Michigan.  If the ultimate costs of the incident are not covered by warranty, insurance or through the regulatory process or if the unit is not returned to service in a reasonable period of time or if any future regulatory proceedings are adverse, it could have an adverse impact on net income, cash flows and financial condition.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2008 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncements

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of adoption of new accounting pronouncements.


QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Risk management assets and liabilities are managed by AEPSC as agent.  The related risk management policies and procedures are instituted and administered by AEPSC.  See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section for disclosures about risk management activities.

Interest Rate Risk

Management utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure.  EaR statistically quantifies the extent to which I&M’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  As calculated on I&M’s debt outstanding as of September 30, 2009, the estimated EaR on I&M’s debt portfolio for the following twelve months was $2.3 million.


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2009 and 2008
(in thousands)
(Unaudited)

  Three Months Ended  Nine Months Ended 
  2009  2008  2009  2008 
REVENUES            
Electric Generation, Transmission and Distribution $435,399  $513,548  $1,257,673  $1,370,158 
Sales to AEP Affiliates  43,796   72,295   161,167   232,734 
Other Revenues – Affiliated  24,958   31,792   80,890   84,268 
Other Revenues – Nonaffiliated  48,114   3,388   149,997   13,659 
TOTAL REVENUES  552,267   621,023   1,649,727   1,700,819 
                 
EXPENSES                
Fuel and Other Consumables Used for Electric Generation  105,287   141,563   316,449   351,300 
Purchased Electricity for Resale  28,203   39,427   97,417   87,351 
Purchased Electricity from AEP Affiliates  93,093   112,060   253,964   296,559 
Other Operation  121,737   136,875   346,421   381,928 
Maintenance  50,650   52,573   148,412   156,402 
Depreciation and Amortization  34,032   31,822   100,406   95,301 
Taxes Other Than Income Taxes  19,122   19,992   58,071   60,236 
TOTAL EXPENSES  452,124   534,312   1,321,140   1,429,077 
                 
OPERATING INCOME  100,143   86,711   328,587   271,742 
                 
Other Income (Expense):                
Other Income  5,024   880   12,879   4,621 
Interest Expense  (25,668)  (20,629)  (75,372)  (56,977)
                 
INCOME BEFORE INCOME TAX EXPENSE  79,499   66,962   266,094   219,386 
                 
Income Tax Expense  24,640   21,326   81,774   68,348 
                 
NET INCOME  54,859   45,636   184,320   151,038 
                 
Preferred Stock Dividend Requirements  85   85   255   255 
                 
EARNINGS ATTRIBUTABLE TO COMMON STOCK $54,774  $45,551  $184,065  $150,783 

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.





 
 
 

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Nine Months Ended September 30, 2009 and 2008
(in thousands)
(Unaudited)

  Common Stock  Paid-in Capital  Retained Earnings  Accumulated Other Comprehensive Income (Loss)  Total 
                
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2007
 $56,584  $861,291  $483,499  $(15,675) $1,385,699 
                     
EITF 06-10 Adoption, Net of Tax of $753          (1,398)      (1,398)
Common Stock Dividends          (56,250)      (56,250)
Preferred Stock Dividends          (255)      (255)
SUBTOTAL – COMMON SHAREHOLDER’S EQUITY                  1,327,796 
                     
COMPREHENSIVE INCOME                    
Other Comprehensive Income, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $967              1,795   1,795 
Amortization of Pension and OPEB Deferred
  Costs, Net of Tax of $178
              331   331 
NET INCOME          151,038       151,038 
TOTAL COMPREHENSIVE INCOME                  153,164 
                     
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2008
 $56,584  $861,291  $576,634  $(13,549) $1,480,960 
                     
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2008
 $56,584  $861,291  $538,637  $(21,694) $1,434,818 
                     
Capital Contribution from Parent      120,000           120,000 
Common Stock Dividends          (73,500)      (73,500)
Preferred Stock Dividends          (255)      (255)
Gain on Reacquired Preferred Stock      1           1 
SUBTOTAL – COMMON SHAREHOLDER’S EQUITY                  1,481,064 
                     
COMPREHENSIVE INCOME                    
Other Comprehensive Income (Loss), Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $265              (492)  (492)
Amortization of Pension and OPEB Deferred
  Costs, Net of Tax of $334
              620   620 
NET INCOME          184,320       184,320 
TOTAL COMPREHENSIVE INCOME                  184,448 
                     
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2009
 $56,584  $981,292  $649,202  $(21,566) $1,665,512 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2009 and December 31, 2008
(in thousands)
(Unaudited)

  2009  2008 
CURRENT ASSETS      
Cash and Cash Equivalents $843  $728 
Advances to Affiliates   160,749   - 
Accounts Receivable:        
Customers  54,690   70,432 
Affiliated Companies  117,941   94,205 
Accrued Unbilled Revenues  11,612   19,260 
Miscellaneous  2,477   1,010 
Allowance for Uncollectible Accounts  (2,113)  (3,310)
Total Accounts Receivable  184,607   181,597 
Fuel  67,795   67,138 
Materials and Supplies  151,578   150,644 
Risk Management Assets  43,120   35,012 
Regulatory Asset for Under-Recovered Fuel Costs  9,965   33,066 
Prepayments and Other Current Assets  166,137   66,733 
TOTAL CURRENT ASSETS  784,794   534,918 
         
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
Production  3,584,836   3,534,188 
Transmission  1,147,401   1,115,762 
Distribution  1,339,065   1,297,482 
Other Property, Plant and Equipment (including nuclear fuel and coal mining)  785,504   703,287 
Construction Work in Progress  308,039   249,020 
Total Property, Plant and Equipment  7,164,845   6,899,739 
Accumulated Depreciation, Depletion and Amortization  3,101,119   3,019,206 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET  4,063,726   3,880,533 
         
OTHER NONCURRENT ASSETS        
Regulatory Assets  495,305   455,132 
Spent Nuclear Fuel and Decommissioning Trusts  1,364,442   1,259,533 
Long-term Risk Management Assets  29,592   27,616 
Deferred Charges and Other Noncurrent Assets  88,894   86,193 
TOTAL OTHER NONCURRENT ASSETS  1,978,233   1,828,474 
         
TOTAL ASSETS $6,826,753  $6,243,925 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
September 30, 2009 and December 31, 2008
(Unaudited)

  2009  2008 
CURRENT LIABILITIES (in thousands) 
Advances from Affiliates $-  $476,036 
Accounts Payable:        
General  144,806   194,211 
Affiliated Companies  73,395   117,589 
Long-term Debt Due Within One Year – Nonaffiliated  37,544   - 
Long-term Debt Due Within One Year – Affiliated  25,000   - 
Risk Management Liabilities  16,011   16,079 
Customer Deposits  27,493   26,809 
Accrued Taxes  54,358   66,363 
Obligations Under Capital Leases  30,347   43,512 
Other Current Liabilities  118,519   141,160 
TOTAL CURRENT LIABILITIES  527,473   1,081,759 
         
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated  2,015,155   1,377,914 
Long-term Risk Management Liabilities  12,121   14,311 
Deferred Income Taxes  583,183   412,264 
Regulatory Liabilities and Deferred Investment Tax Credits  738,889   656,396 
Asset Retirement Obligations  938,504   902,920 
Deferred Credits and Other Noncurrent Liabilities  337,839   355,463 
TOTAL NONCURRENT LIABILITIES  4,625,691   3,719,268 
         
TOTAL LIABILITIES  5,153,164   4,801,027 
         
Cumulative Preferred Stock Not Subject to Mandatory Redemption  8,077   8,080 
         
Commitments and Contingencies (Note 4)        
         
COMMON SHAREHOLDER’S EQUITY        
Common Stock – No Par Value:        
Authorized – 2,500,000 Shares        
Outstanding – 1,400,000 Shares  56,584   56,584 
Paid-in Capital  981,292   861,291 
Retained Earnings  649,202   538,637 
Accumulated Other Comprehensive Income (Loss)  (21,566)  (21,694)
TOTAL COMMON SHAREHOLDER’S EQUITY  1,665,512   1,434,818 
         
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $6,826,753  $6,243,925 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2009 and 2008
(in thousands)
(Unaudited)

  2009  2008 
OPERATING ACTIVITIES      
Net Income $184,320  $151,038 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:        
Depreciation and Amortization  100,406   95,301 
Deferred Income Taxes  133,959   47,565 
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net  (4,563)  834 
Allowance for Equity Funds Used During Construction  (7,830)  (967)
Mark-to-Market of Risk Management Contracts  (14,580)  4,876 
Amortization of Nuclear Fuel  41,198   72,453 
Change in Other Noncurrent Assets  285   5,678 
Change in Other Noncurrent Liabilities  50,932   38,568 
Changes in Certain Components of Working Capital:        
Accounts Receivable, Net  (2,322)  (2,422)
Fuel, Materials and Supplies  (1,591)  12,736 
Accounts Payable  (48,044)  16,549 
Accrued Taxes, Net  (15,005)  2,550 
Other Current Assets  (54,221)  (24,736)
Other Current Liabilities  (20,598)  1,393 
Net Cash Flows from Operating Activities  342,346   421,416 
         
INVESTING ACTIVITIES        
Construction Expenditures  (242,256)  (221,538)
Change in Advances to Affiliates, Net  (160,749)  - 
Purchases of Investment Securities  (571,167)  (413,538)
Sales of Investment Securities  523,927   362,773 
Acquisitions of Nuclear Fuel  (153,172)  (99,110)
Other Investing Activities  18,990   3,376 
Net Cash Flows Used for Investing Activities  (584,427)  (368,037)
         
FINANCING ACTIVITIES        
Capital Contribution from Parent  120,000   - 
Issuance of Long-term Debt – Nonaffiliated  670,060   115,225 
Issuance of Long-term Debt – Affiliated  25,000   - 
Change in Advances from Affiliates, Net  (476,036)  179,007 
Retirement of Long-term Debt – Nonaffiliated  -   (262,000)
Retirement of Cumulative Preferred Stock  (2)  - 
Principal Payments for Capital Lease Obligations  (23,640)  (28,917)
Dividends Paid on Common Stock  (73,500)  (56,250)
Dividends Paid on Cumulative Preferred Stock  (255)  (255)
Other Financing Activities  569   - 
Net Cash Flows from (Used for) Financing Activities  242,196   (53,190)
         
Net Increase in Cash and Cash Equivalents  115   189 
Cash and Cash Equivalents at Beginning of Period  728   1,139 
Cash and Cash Equivalents at End of Period $843  $1,328 
         
SUPPLEMENTARY INFORMATION        
Cash Paid for Interest, Net of Capitalized Amounts $81,833  $57,086 
Net Cash Paid (Received) for Income Taxes  (21,414)  7,482 
Noncash Acquisitions Under Capital Leases  2,344   3,279 
Construction Expenditures Included in Accounts Payable at September 30,  42,576   26,150 
Acquisition of Nuclear Fuel Included in Accounts Payable at September 30,  2   66,127 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


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

The condensed notes to I&M’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries.  Listed below are the notes that apply to I&M.  
Footnote
Reference
Significant Accounting MattersNote 1
New Accounting Pronouncements and Extraordinary ItemNote 2
Rate MattersNote 3
Commitments, Guarantees and ContingenciesNote 4
Benefit PlansNote 6
Business SegmentsNote 7
Derivatives and HedgingNote 8
Fair Value MeasurementsNote 9
Income TaxesNote 10
Financing ActivitiesNote 11









OHIO POWER COMPANY CONSOLIDATED



OHIO POWER COMPANY CONSOLIDATED
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

Results of OperationsRESULTS OF OPERATIONS

ThirdFirst Quarter of 20092010 Compared to ThirdFirst Quarter of 20082009

Reconciliation of ThirdFirst Quarter of 20082009 to ThirdFirst Quarter of 20092010
Net Income
(in millions)
Third Quarter of 2008    $56 
        
Changes in Gross Margin:       
Retail Margins  132     
Off-system Sales  (57)    
Other  (2)    
Total Change in Gross Margin      73 
         
Total Expenses and Other:        
Other Operation and Maintenance  9     
Depreciation and Amortization  (17)    
Taxes Other Than Income Taxes  1     
Carrying Costs Income  (1)    
Other Income  (1)    
Interest Expense  (1)    
Total Expenses and Other      (10)
         
Income Tax Expense      (22)
         
Third Quarter of 2009     $97 

First Quarter of 2009$81 
��
Changes in Gross Margin:
Retail Margins35 
FERC Municipals and Cooperatives(8)
Off-system Sales3 
Transmission Revenues1 
Other(55)
Total Change in Gross Margin(24)
Total Expenses and Other:
Other Operation and Maintenance(24)
Depreciation and Amortization(1)
Other Income1 
Interest Expense(2)
Total Expenses and Other(26)
Income Tax Expense14 
First Quarter of 2010$45 

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·Retail Margins increased $132$35 million primarily due to the following:
 ·An $85A $12 million base rate increase in fuel margins primarily due to the deferral of fuel costs in 2009.  The PUCO’s March 2009 approval of OPCo’s ESP allows for the recovery of fuel and related costs beginning January 1,Indiana base rate filing, effective March 2009.  See “Ohio Electric Security Plan Filings” section of Note 3.
 ·A $50 million increase related to the implementation of higher rates set by the Ohio ESP.
·An $18$10 million increase in capacity settlements under the Interconnection Agreement.
·A $20 million increase in fuel margins due to higher fuel and purchased power costs recorded in 2009 related to the Cook Plant Unit 1 shutdown.  This increase in fuel margins was offset by a corresponding decrease in Other Revenues as discussed below.
·An $8 million increase in margins from industrial sales due to higher industrial usage reflecting an improvement in demand.
 These increases were partially offset by:
 ·A $30$10 million decrease in industrial sales primarilyother fuel margins. 
·A $4 million increase in PJM charges.
·FERC Municipals and Cooperatives margins decreased $8 million due to reduced operating levels and suspended operations by certain large industrial customersa unit power sales agreement ending in OPCo’s service territory.December 2009.
·Margins from Off-system Sales decreased $57increased $3 million primarily due to lowerhigher physical sales volumes and lower margins as a result of lower market prices,reflecting favorable generation availability, partially offset by higherlower trading and marketing margins.
·Other revenues decreased $55 million primarily due to the Cook Plant accidental outage insurance proceeds of $54 million in the first quarter of 2009.  I&M reduced customer bills by approximately $20 million in the first quarter of 2009 for the cost of replacement power during the outage period.  This decrease in revenues was offset by a corresponding increase in Retail Margins as discussed above.

Total Expenses and Other and Income Tax Expense changed between years as follows:

·Other Operation and Maintenance expenses decreased $9increased $24 million primarily due to:to the following:
 ·A $5$13 million decreaseincrease in maintenanceadministrative and removalgeneral expenses from plannedfor increased benefit and forced outages at various plants.insurance costs.
 ·A $2 million decrease in recoverable PJM expenses.
·A $2 million decrease in recoverable customer account expenses due to decreased Universal Service Fund surcharge rates for customers who qualify for payment assistance.
·A $2 million decrease in net allocated transmission expenses related to the AEP Transmission Equalization Agreement.
These decreases were partially offset by:
·A $2$4 million increase in maintenance of overhead linessteam production expense primarily due to increased vegetation management activities slightly offset by reduced wind stormdeferral of NSR costs incurred in 2009 versus 2008.
·Depreciation and Amortization increased $17 million primarily due to:
·A $21 million increase from higher depreciable property balances asincluded in a result of environmental improvements placed in service and various other property additions and higher depreciation rates related to shortened depreciable lives for certain generating facilities.rate settlement.
 ·A $3 million increase as a result ofin transmission expense reflecting lower credits under the completion of the amortization of a regulated liability in December 2008 related to energy sales to Ormet at below-market rates.  See “Ormet” section of Note 3.
The increase was partially offset by:
·A $7 million decrease due to the completion of the amortization of regulatory assets in December 2008.Transmission Agreement.
·Income Tax Expense increased $22decreased $14 million primarily due to an increasea decrease in pretax book income.

NineREGULATORY ACTIVITY

Michigan Regulatory Activity

In January 2010, I&M filed for a $63 million increase in annual Michigan base rates based on an 11.75% return on common equity.  I&M can request interim rates, subject to refund, after six months.  The MPSC must issue a final order within one year.

SIGNIFICANT FACTORS

REGULATORY ISSUES

Cook Plant Unit 1 Fire and Shutdown

In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in a fire on the electric generator.  Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $395 million.  Management believes that I&M should recover a significant portion of repair and replacement costs through the turbine vendor’s warranty, insurance and the regulatory process.  I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power.  The Unit 1 rotors were repaired and reinstalled due to the extensive lead time required to manufacture and install new turbine rotors.  As a result, the replacement of the repaired turbine rotors and other equipme nt is scheduled for the Unit 1 planned outage in the fall of 2011.  If the ultimate costs of the incident are not covered by warranty, insurance or through the related regulatory process or if any future regulatory proceedings are adverse, it could have an adverse impact on net income, cash flows and financial condition.  See “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.

LITIGATION AND ENVIRONMENTAL ISSUES

In the ordinary course of business, I&M 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 will be or the timing and amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss amount can be estimated.  For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2009 Annual Report.  Additionally, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies.  Adverse results in these proceedings have the potential to materially affect I&M’s net income, financial condition and cash flows.

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2009 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “New Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for a discussion of the adoption and impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

See “Quantitative And Qualitative Disclosures About Risk Management Activities” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for a discussion of risk management activities.


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended September 30,March 31, 2010 and 2009
(in thousands)
(Unaudited)

  2010 2009
REVENUES    
Electric Generation, Transmission and Distribution $438,024  $421,927 
Sales to AEP Affiliates  84,217   59,986 
Other Revenues – Affiliated  27,966   30,740 
Other Revenues – Nonaffiliated  2,849   54,391 
TOTAL REVENUES  553,056   567,044 
       
EXPENSES      
Fuel and Other Consumables Used for Electric Generation  119,181   102,960 
Purchased Electricity for Resale  29,767   38,361 
Purchased Electricity from AEP Affiliates  82,250   79,978 
Other Operation  130,681   109,460 
Maintenance  48,444   46,274 
Depreciation and Amortization  33,831   32,745 
Taxes Other Than Income Taxes  21,032   20,696 
TOTAL EXPENSES  465,186   430,474 
       
OPERATING INCOME  87,870   136,570 
       
Other Income (Expense):      
Interest Income  485   2,543 
Allowance for Equity Funds Used During Construction  4,435   1,555 
Interest Expense  (26,101)  (23,531)
       
INCOME BEFORE INCOME TAX EXPENSE  66,689   117,137 
       
Income Tax Expense  21,631   36,185 
       
NET INCOME  45,058   80,952 
       
Preferred Stock Dividend Requirements  85   85 
       
EARNINGS ATTRIBUTABLE TO COMMON STOCK $44,973  $80,867 

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2010 and 2009
(in thousands)
(Unaudited)

  Common Stock Paid-in Capital Retained Earnings 
Accumulated
Other
Comprehensive
Income (Loss)
 Total
                
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2008 $56,584  $861,291  $538,637  $(21,694) $1,434,818 
                
Common Stock Dividends        (24,500)     (24,500)
Preferred Stock Dividends        (85)     (85)
Gain on Reacquired Preferred Stock     1         1 
SUBTOTAL – COMMON SHAREHOLDER’S EQUITY              1,410,234 
                
COMPREHENSIVE INCOME               
Other Comprehensive Income, Net of Taxes:               
Cash Flow Hedges, Net of Tax of $463           859   859 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $111           207   207 
NET INCOME        80,952      80,952 
TOTAL COMPREHENSIVE INCOME              82,018 
                
TOTAL COMMON SHAREHOLDER’S EQUITY – 
 MARCH 31, 2009
 $56,584  $861,292  $595,004  $(20,628) $1,492,252 
                
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2009 $56,584  $981,292  $656,608  $(21,701) $1,672,783 
                
Common Stock Dividends        (25,750)     (25,750)
Preferred Stock Dividends        (85)     (85)
SUBTOTAL – COMMON SHAREHOLDER’S EQUITY              1,646,948 
                
COMPREHENSIVE INCOME               
Other Comprehensive Income (Loss), Net of Taxes:               
Cash Flow Hedges, Net of Tax of $422           (784)  (784)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $117           218   218 
NET INCOME        45,058      45,058 
TOTAL COMPREHENSIVE INCOME              44,492 
                
TOTAL COMMON SHAREHOLDER’S EQUITY – 
 MARCH 31, 2010
 $56,584  $981,292  $675,831  $(22,267) $1,691,440 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.





INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2010 and December 31, 2009
(in thousands)
(Unaudited)

   2010 2009
CURRENT ASSETS       
Cash and Cash Equivalents  $994  $779 
Advances to Affiliates   85,186   114,012 
Accounts Receivable:       
Customers   61,564   71,120 
Affiliated Companies   58,417   83,248 
Accrued Unbilled Revenues   7,395   8,762 
Miscellaneous   16,160   8,638 
Allowance for Uncollectible Accounts   (2,111)  (2,265)
Total Accounts Receivable   141,425   169,503 
Fuel   98,700   79,554 
Materials and Supplies   164,265   164,439 
Risk Management Assets   46,704   34,438 
Accrued Tax Benefits   142,237   144,473 
Deferred Cook Plant Fire Costs   143,071   134,322 
Prepayments and Other Current Assets   30,810   29,395 
TOTAL CURRENT ASSETS   853,392   870,915 
        
PROPERTY, PLANT AND EQUIPMENT       
Electric:       
Production   3,650,607   3,634,215 
Transmission   1,160,617   1,154,026 
Distribution   1,373,381   1,360,553 
Other Property, Plant and Equipment (including nuclear fuel and coal mining)   783,596   755,132 
Construction Work in Progress   297,681   278,278 
Total Property, Plant and Equipment   7,265,882   7,182,204 
Accumulated Depreciation, Depletion and Amortization   3,094,371   3,073,695 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET   4,171,511   4,108,509 
        
OTHER NONCURRENT ASSETS       
Regulatory Assets   525,685   496,464 
Spent Nuclear Fuel and Decommissioning Trusts   1,433,012   1,391,919 
Long-term Risk Management Assets   48,654   29,134 
Deferred Charges and Other Noncurrent Assets   87,677   82,047 
TOTAL OTHER NONCURRENT ASSETS   2,095,028   1,999,564 
        
TOTAL ASSETS  $7,119,931  $6,978,988 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
March 31, 2010 and December 31, 2009
(Unaudited)

  2010 2009
CURRENT LIABILITIES (in thousands)
Accounts Payable:      
General $151,467  $171,192 
Affiliated Companies  52,146   61,315 
Long-term Debt Due Within One Year – Nonaffiliated  37,544   37,544 
Long-term Debt Due Within One Year – Affiliated  -   25,000 
Risk Management Liabilities  19,423   13,436 
Customer Deposits  28,927   27,711 
Accrued Taxes  76,903   56,814 
Obligations Under Capital Leases  27,327   25,065 
Other Current Liabilities  209,788   154,433 
TOTAL CURRENT LIABILITIES  603,525   572,510 
       
NONCURRENT LIABILITIES      
Long-term Debt – Nonaffiliated  2,015,546   2,015,362 
Long-term Risk Management Liabilities  17,306   10,386 
Deferred Income Taxes  720,092   696,163 
Regulatory Liabilities and Deferred Investment Tax Credits  799,892   756,845 
Asset Retirement Obligations  911,918   894,746 
Deferred Credits and Other Noncurrent Liabilities  352,135   352,116 
TOTAL NONCURRENT LIABILITIES  4,816,889   4,725,618 
       
TOTAL LIABILITIES  5,420,414   5,298,128 
       
Cumulative Preferred Stock Not Subject to Mandatory Redemption  8,077   8,077 
       
Rate Matters (Note 3)      
Commitments and Contingencies (Note 4)      
       
COMMON SHAREHOLDER’S EQUITY      
Common Stock – No Par Value:      
Authorized – 2,500,000 Shares      
Outstanding – 1,400,000 Shares  56,584   56,584 
Paid-in Capital  981,292   981,292 
Retained Earnings  675,831   656,608 
Accumulated Other Comprehensive Income (Loss)  (22,267)  (21,701)
TOTAL COMMON SHAREHOLDER’S EQUITY  1,691,440   1,672,783 
       
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $7,119,931  $6,978,988 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2010 and 2009
(in thousands)
(Unaudited)

  2010 2009
OPERATING ACTIVITIES      
Net Income $45,058  $80,952 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:      
Depreciation and Amortization  33,831   32,745 
Deferred Income Taxes  18,442   56,889 
Deferral of Incremental Nuclear Refueling Outage Expenses, Net  (20,025)  (7,851)
Allowance for Equity Funds Used During Construction  (4,435)  (1,555)
Mark-to-Market of Risk Management Contracts  (20,345)  (3,272)
Amortization of Nuclear Fuel  30,090   13,228 
Fuel Over/Under-Recovery, Net  16,439   (5,709)
Change in Other Noncurrent Assets  (11,056)  (12,585)
Change in Other Noncurrent Liabilities  28,926   9,715 
Changes in Certain Components of Working Capital:      
Accounts Receivable, Net  28,078   34,499 
Fuel, Materials and Supplies  (18,972)  (2,036)
Accounts Payable  13,171   (68,603)
Accrued Taxes, Net  23,964   (1,224)
Other Current Assets  (13,044)  (18,527)
Other Current Liabilities  38,068   (26,733)
Net Cash Flows from Operating Activities  188,190   79,933 
       
INVESTING ACTIVITIES      
Construction Expenditures  (104,796)  (92,814)
Change in Advances to Affiliates, Net  28,826   - 
Purchases of Investment Securities  (247,632)  (178,407)
Sales of Investment Securities  232,078   158,086 
Acquisitions of Nuclear Fuel  (37,616)  (75,670)
Other Investing Activities  500   10,757 
Net Cash Flows Used for Investing Activities  (128,640)  (178,048)
       
FINANCING ACTIVITIES      
Issuance of Long-term Debt – Nonaffiliated  -   567,949 
Issuance of Long-term Debt – Affiliated  -   25,000 
Change in Advances from Affiliates, Net  -   (459,615)
Retirement of Long-term Debt – Affiliated  (25,000)  - 
Retirement of Cumulative Preferred Stock  -   (2)
Principal Payments for Capital Lease Obligations  (8,524)  (10,377)
Dividends Paid on Common Stock  (25,750)  (24,500)
Dividends Paid on Cumulative Preferred Stock  (85)  (85)
Other Financing Activities  24   - 
Net Cash Flows from (Used for) Financing Activities  (59,335)  98,370 
       
Net Increase in Cash and Cash Equivalents  215   255 
Cash and Cash Equivalents at Beginning of Period  779   728 
Cash and Cash Equivalents at End of Period $994  $983 
       
SUPPLEMENTARY INFORMATION      
Cash Paid for Interest, Net of Capitalized Amounts $30,056  $35,231 
Net Cash Paid (Received) for Income Taxes  -   (355)
Noncash Acquisitions Under Capital Leases  8,476   705 
Construction Expenditures Included in Accounts Payable at March 31,  29,496   29,910 
Acquisition of Nuclear Fuel Included in Accounts Payable at March 31,  2,705   17,016 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


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

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

Footnote
Reference
Significant Accounting MattersNote 1
New Accounting PronouncementsNote 2
Rate MattersNote 3
Commitments, Guarantees and ContingenciesNote 4
Benefit PlansNote 6
Business SegmentsNote 7
Derivatives and HedgingNote 8
Fair Value MeasurementsNote 9
Income TaxesNote 10
Financing ActivitiesNote 11
Company-wide Staffing and Budget ReviewNote 12










OHIO POWER COMPANY CONSOLIDATED



OHIO POWER COMPANY CONSOLIDATED
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

First Quarter of 2010 Compared to Nine Months Ended September 30, 2008First Quarter of 2009

Reconciliation of Nine Months Ended September 30, 2008First Quarter of 2009 to Nine Months Ended September 30, 2009First Quarter of 2010
Net Income
(in millions)

Nine Months Ended September 30, 2008    $248 
        
Changes in Gross Margin:       
Retail Margins  176     
Off-system Sales  (117)    
Other  4     
Total Change in Gross Margin      63 
         
Total Expenses and Other:        
Other Operation and Maintenance  (15)    
Depreciation and Amortization  (50)    
Carrying Costs Income  (5)    
Other Income  (6)    
Total Expenses and Other      (76)
         
Income Tax Expense      (2)
         
Nine Months Ended September 30, 2009     $233 

First Quarter of 2009$73 
Changes in Gross Margin:
Retail Margins42 
Off-system Sales5 
Other(18)
Total Change in Gross Margin29 
Total Expenses and Other:
Other Operation and Maintenance14 
Depreciation and Amortization(5)
Taxes Other Than Income Taxes(2)
Carrying Costs Income3 
Interest Expense(1)
Total Expenses and Other9 
Income Tax Expense(19)
First Quarter of 2010$92 

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·Retail Margins increased $176$42 million primarily due to the following:
 ·A $107$24 million increase in fuel margins primarily due tocapacity settlements under the deferral of fuel costs in 2009.  The PUCO’s March 2009 approval of OPCo’s ESP allows for the recovery of fuel and related costs beginning January 1, 2009.  See “Ohio Electric Security Plan Filings” section of Note 3.Interconnection Agreement.
 ·A $103$23 million increase primarily due to a $16 million increase related to the implementation of higher rates set by the Ohio ESP.ESP and $6 million of increased demand charges from WPCo effective January 2010.
 ·A $40$12 million increase in capacity settlements under the Interconnection Agreement.fuel margins.
 These increases were partially offset by:
 ·A $59$15 million decrease in industrialretail sales primarily due to reduced operating levelsa decrease in residential and suspended operations by certain large industrial customers in OPCo’s service territory.
·A $29 million decrease related to coal contract amendments recorded in 2008.commercial usage.
·Margins from Off-system Sales decreased $117increased $5 million primarily due to lowerhigher physical sales volumes and lower margins as a resultreflecting favorable generating availability.
·Other revenues decreased $18 million primarily due to reduced gains on the sale of lower market prices, partially offset by higher trading and marketing margins.emission allowances.

Total Expenses and Other and Income Tax Expense changed between years as follows:

·Other Operation and Maintenance expenses increased $15decreased $14 million primarily due to:
 ·A $15An $8 million increase in maintenance of overhead lines primarily duedecrease related to a $13 million increase in vegetation management activities and a $3 million increase in ice and wind storm costs incurred in 2009 versus 2008.
·A $6 million increase related to an obligation to contribute to the “Partnership with Ohio” fund for low income, at-risk customers ordered by the PUCO’s March 2009 approval of OPCo’s ESP.  See “Ohio Electric Security Plan Filings” section
·A $7 million decrease from the reversal of Note 3.an accrual for employee benefit expenses.
·A $4 million decrease in rent expense as a result of the purchase of JMG in December 2009.
 These increasesdecreases were partially offset by:
 ·A $6$3 million decreaseincrease in recoverable customer account expenses due to decreasedincreased Universal Service Fund surcharge rates for customers who qualify for payment assistance.
·A $2 million increase in employee benefit expenses.
·Depreciation and Amortization increased $50$5 million primarily due to:
·A $61to a $6 million increase from higher depreciable property balances as a result of environmental improvements placed in service and various other property additions, and higher depreciation rates relatedpartially offset by a $1 million decrease due to shortened depreciable lives for certain generating facilities.distribution leasehold improvements being fully amortized in the fourth quarter of 2009.
·Interest expense increased $1 million primarily due to:
 ·An $8A $6 million decrease in the debt component of AFUDC primarily due to the Amos Plant FGD and precipitator upgrade going into service in March 2009.
·A $5 million increase as a resultprimarily due to an increase in interest expense from the issuance of the completion of the amortization of a regulated liabilitylong-term debt in December 2008 related to energy sales to Ormet at below market rates.  See “Ormet” section of Note 3.September 2009.
 These increases were partially offset by:
 ·A $21An $8 million decrease duein interest expense related to the completionreacquisition of JMG’s bonds during the amortizationthird quarter of regulatory assets in December 2008.2009.
·Income Tax Expense increased $2$19 million primarily due to changesan increase in certain book/pretax book income and the tax differences accounted for on a flow-through basis.treatment associated with the future reimbursement of Medicare Part D prescription drug benefits.

Financial ConditionFINANCIAL CONDITION

LIQUIDITY

OPCo participates in the Utility Money Pool, which provides access to AEP’s liquidity.  OPCo has $600 million of Senior Unsecured Notes and $79 million of Pollution Control Bonds that will mature in 2010.  OPCo relies upon ready access to capital markets, cash flows from operations and access to the Utility Money Pool to fund its maturities, current operations and capital expenditures.  See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of liquidity.

Credit Ratings

OPCo’s credit ratings as of September 30, 2009March 31, 2010 were as follows:

 Moody’s S&P Fitch
      
Senior Unsecured DebtBaa1 BBB BBB+

Moody’s, S&P and Fitch have OPCo on stable outlook.  In August 2009, Moody’s changed its rating outlook for OPCo from negative to stable.  If OPCo receives a downgradeDowngrades from any of the rating agencies its borrowing costs could increase and access to borrowed funds could be negatively affected.OPCo’s borrowing costs.

Cash FlowCASH FLOW

Cash flows for the ninethree months ended September 30,March 31, 2010 and 2009 and 2008 were as follows:

 2009  2008  2010 2009
 (in thousands)  (in thousands)
Cash and Cash Equivalents at Beginning of Period $12,679  $6,666  $1,984  $12,679 
Cash Flows from (Used for):            
Operating Activities  136,802   435,406  251,324  (22,900)
Investing Activities  (674,647)  (486,678) (258,305) (156,584)
Financing Activities  528,116   53,694   6,150   180,174 
Net Increase (Decrease) in Cash and Cash Equivalents  (9,729)  2,422   (831)  690 
Cash and Cash Equivalents at End of Period $2,950  $9,088  $1,153  $13,369 

Operating Activities

Net Cash Flows from Operating Activities were $137$251 million in 2009.2010.  OPCo produced Net Income of $233$92 million during the period and had noncash expense items of $263$89 million for Depreciation and Amortization, $213$41 million for Deferred Income Taxes and $67 million for Deferred Property Taxes.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The current period activity in working capital relates to a number of items.  Accounts Receivable, Net had a $62 million inflow primarily due to decreased sales to affiliates and settlement of allowance sales to affiliated companies.  Fuel, Materials and Supplies had a $57 million inf low primarily due to a decrease in coal inventory deliveries.  Accrued Taxes, Net had a $30 million outflow due to temporary timing differences of payments for property taxes partially offset by a decrease of federal income tax related accruals.  The $38 million change in Fuel Over/Under-Recovery, Net reflects the deferral of fuel costs as a fuel clause was reactivated in 2009 under OPCo’s ESP.

Net Cash Flows Used for Operating Activities were $23 million in 2009.  OPCo produced Net Income of $73 million during the period and noncash expense items of $84 million for Depreciation and Amortization, $72 million for Deferred Income Taxes.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The activity in working capital primarily relates to a number of items.  Fuel, Materials and Supplies had a $181 million outflow primarily due to an increase in coal inventory reflecting decreased customer demand for electricity as a result of the economic slowdown.  Accounts Payable had a $139$95 million cash outflow primarily due to OPCo’s provision for revenue refund of $62 million which was paid in the first quarter 2009 to the AEP West companies as part of the FERC’s orderor der on the SIA.  Accrued Taxes, Net had a $104$79 million cash outflow due to a decrease of federal income tax related accruals and temporary timing differences of payments for property taxestaxes.  Fuel, Materials and Supplies had a decrease$53 million cash outflow primarily due to an increase in coal inventory.  Accounts Receivable, Net had a $40 million inflow due to timing differences of federal income tax related accruals.payments from customers and the receipt of final payment due to a coal contract amendment.  The $242$65 million change in Fuel Over/Under-Recovery,Under Recovery, Net reflects the deferral of fuel costs as a fuel clause was reactivated in 2009 under OPCo’s ESP.

Net Cash Flows from Operating Activities were $435 million in 2008.  OPCo produced Net Income of $248 million during the period and a noncash expense item of $212 million for Depreciation and Amortization.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital and changes in the future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  Fuel, Materials and Supplies had a $48 million outflow due to price increases.  Accounts Payable had a $45 million inflow primarily due to increases in tonnage and prices per ton related to fuel and consumable purchases.

Investing Activities

Net Cash Flows Used for Investing Activities in 2010 and 2009 were $675$258 million and $487$157 million, respectively.  OPCo had a net increase of $179 million in 2009 and 2008, respectively.loans to the Utility Money Pool in 2010.  Construction Expenditures were $343of $78 million and $453$163 million in 2010 and 2009, and 2008, respectively, were 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 desulfurizationFGD projects at the Cardinal, Amos and Mitchell Plants.  OPCo had a net increase of $368 million in loans to in the Utility Money Pool in 2009.Plant.

Financing Activities

Net Cash Flows from Financing Activities were $528$6 million in 2009 primarily due to a $550during 2010.  OPCo issued $86 million Capital Contribution from Parent as well as a $500 million issuance of Senior Unsecured Notes.  These increases were partially offset by a $218 million reacquisition of Pollution Control Bonds related to JMG and a $78 million retirement of  Notes Payable – Nonaffiliated.in March 2010.  OPCo also had a net decreasepaid $75 million in borrowings of $134 million from the Utility Money Pool.dividends on common stock.

Net Cash Flows from Financing Activities were $54$180 million in 2008.  OPCo issued $165 million of Pollution Control Bonds and $250 million of Senior Unsecured Notes.  These increases were partially offset by the retirement of $250 million of Pollution Control Bonds and $13 million of Notes Payable – Nonaffiliated.  OPCo also had2009 primarily due to a net decreaseincrease of $186 million in borrowings of $102 million from the Utility Money Pool.

Financing Activity

Long-term debt issuances retirements and principal payments made during the first ninethree months of 20092010 were:

Issuances
 
Principal
Amount
 Interest Due 
Principal
Amount
 Interest Due
Type of Debt Rate Date  Rate Date
 (in thousands) (%)    (in thousands) (%)  
Senior Unsecured Notes $500,000   5.375 2021
Pollution Control Bonds $86,000  3.125 2043

Retirements and Principal Payments
  
Principal
Amount Paid
 Interest Due
Type of Debt  Rate Date
  (in thousands) (%)  
Notes Payable – Nonaffiliated $6,500  7.21 2009
Notes Payable – Nonaffiliated  1,000  6.27 2009
Notes Payable – Nonaffiliated  70,000  7.49 2009
Pollution Control Bonds  218,000  Variable 2028-2029

Liquidity

Although the financial markets were volatile at both a global and domestic level, OPCo issued $500 million of Senior Unsecured Notes during the first nine months of 2009.  The credit situation appears to have improved but could impact OPCo’s future operations and ability to issue debt at reasonable interest rates.None

OPCo participates in the Utility Money Pool, which provides access to AEP’s liquidity.  OPCo relies upon cash flows from operations and access to the Utility Money Pool to fund current operations and capital expenditures.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of liquidity.

Summary Obligation InformationSUMMARY OBLIGATION INFORMATION

A summary of contractual obligations is included in the 20082009 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in “Cash Flow” and “Financing Activity” above.

Purchase of JMG Funding EquitySIGNIFICANT FACTORS

REGULATORY ISSUES

Ohio Electric Security Plan Filing

During 2009, the PUCO issued an order that modified and approved OPCo’s ESP which established rates through 2011.  The order also limits rate increases for OPCo hasto 8% in 2009, 7% in 2010 and 8% in 2011.  The order provides a lease agreement with JMG to finance OPCo’s Flue Gas Desulfurization (FGD) system installed on OPCo’s Gavin Plant.  The PUCO approvedFAC for the original lease agreement between OPCo and JMG.  JMG owns and leasesthree-year period of the FGD to OPCo.  In the third quarterESP.  Several notices of 2009, OPCo reacquired $218 million of auction-rate debt related to JMG with interest ratesappeal are outstanding at the contractual maximum rateSupreme Court of 13%.  OPCo was unableOhio relating to refinancesignificant issues in the debt without JMG’s consent.  OPCo sought approvaldetermination of the approved ESP rates.  In addition, an order is expected from the PUCO related to terminate the JMG relationship and received the approval in June 2009.  In July 2009, OPCo purchased the outstanding equity ownershipSEET methodology.  See “Ohio Electric Security Plan Filings” section of JMG for $28 million which enabled OPCo to reacquire this debt.  OPCo plans to reissue the debt.  Management’s intent is to cancel the lease and dissolve JMG in December 2009.  The assets and liabilities of JMG will remain incorporated with OPCo’s business.Note 3.

Significant Factors

Litigation and Regulatory ActivityLITIGATION AND ENVIRONMENTAL ISSUES

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 theand amount of any loss, fine or penalty may be.penalty.  Management does, however, assessassesses the probability of loss for such contingencieseach contingency and accrues a liability for cases which have a probable likelihood of loss andif the loss amount can be estimated.  For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 20082009 Annual Report.  Also,Additionally, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the “Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries” section.Contingencies.  Adverse results in thesethe se proceedings have the potential to materially affect OPCo’s net income, financial condition and cash flows.

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

Critical Accounting EstimatesCRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 20082009 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncementsbenefits.

See the “New Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of the adoption and impact 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 andAnd Qualitative Disclosures About Risk Management Activities” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for disclosures abouta discussion of risk management activities.  The following tables provide information about AEP’s risk management activities’ effect on OPCo.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in OPCo’s Condensed Consolidated Balance Sheet as of September 30, 2009 and the reasons for changes in total MTM value as compared to December 31, 2008.

Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
September 30, 2009
(in thousands)

  MTM Risk Management Contracts  
Cash Flow Hedge
Contracts
  DETM Assignment (a)  
Collateral
Deposits
  Total 
Current Assets $60,270  $1,728  $-  $(3,004) $58,994 
Noncurrent Assets  38,866   338   -   (2,879)  36,325 
Total MTM Derivative Contract Assets  99,136   2,066   -   (5,883)  95,319 
                     
Current Liabilities  34,176   1,457   1,682   (9,871)  27,444 
Noncurrent Liabilities  25,248   605   423   (10,142)  16,134 
Total MTM Derivative Contract Liabilities  59,424   2,062   2,105   (20,013)  43,578 
                     
Total MTM Derivative Contract Net Assets (Liabilities) $39,712  $4  $(2,105) $14,130  $51,741 


(a)See “Natural Gas Contracts with DETM” section of Note 15 of the 2008 Annual Report.


MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2009
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2008 $37,761 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period  (17,126)
Fair Value of New Contracts at Inception When Entered During the Period (a)  7,733 
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period  (136)
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts  - 
Changes in Fair Value Due to Market Fluctuations During the Period (b)  4,862 
Changes in Fair Value Allocated to Regulated Jurisdictions (c)  6,618 
Total MTM Risk Management Contract Net Assets  39,712 
Cash Flow Hedge Contracts  4 
DETM Assignment (d)  (2,105)
Collateral Deposits  14,130 
Total MTM Derivative Contract Net Assets at September 30, 2009 $51,741 

(a)Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices.  The contract prices are valued against market curves associated with the delivery location and delivery term.  A significant portion of the total volumetric position has been economically hedged.
(b)Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(c)“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected on the Condensed Consolidated Statements of Income.  These net gains (losses) are recorded as regulatory liabilities/assets.
(d)See “Natural Gas Contracts with DETM” section of Note 15 of the 2008 Annual Report.

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

The following table presents the maturity, by year, of net assets/liabilities to give an indication of when these MTM amounts will settle and generate or (require) cash:

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets (Liabilities)
September 30, 2009
(in thousands)

  Remainder              After    
  2009  2010  2011  2012  2013  2013  Total 
Level 1 (a) $(270) $(29) $1  $-  $-  $-  $(298)
Level 2 (b)  5,330   8,336   3,404   636   1,676   134   19,516 
Level 3 (c)  4,055   8,399   1,288   660   (16)  -   14,386 
Total  9,115   16,706   4,693   1,296   1,660   134   33,604 
Dedesignated Risk Management Contracts (d)  877   3,010   1,172   1,049   -   -   6,108 
Total MTM Risk Management Contract Net Assets $9,992  $19,716  $5,865  $2,345  $1,660  $134  $39,712 

(a)Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.  Level 1 inputs primarily consist of exchange traded contracts that exhibit sufficient frequency and volume to provide pricing information on an ongoing basis.
(b)Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.  If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, exchange traded contracts where there was not sufficient market activity to warrant inclusion in Level 1 and OTC broker quotes that are corroborated by the same or similar transactions that have occurred in the market.
(c)Level 3 inputs are unobservable inputs for the asset or liability.  Unobservable inputs shall be used to measure fair value to the extent that the observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.  Level 3 inputs primarily consist of unobservable market data or are valued based on models and/or assumptions.
(d)Dedesignated Risk Management Contracts are contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for “Derivatives and Hedging.”  At the time of the normal election, the MTM value was frozen and no longer fair valued.  This will be amortized into Revenues over the remaining life of the contracts.

Credit Risk

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

See Note 8 for further information regarding MTM risk management contracts, cash flow hedging, accumulated other comprehensive income, credit risk and collateral triggering events.

VaR Associated with Risk Management Contracts

Management uses a risk measurement model, which calculates Value at Risk (VaR) to measure commodity price risk in the risk management portfolio.  The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period.  Based on this VaR analysis, at September 30, 2009, a near term typical change in commodity prices is not expected to have a material effect on net income, cash flows or financial condition.

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

Nine Months Ended    Twelve Months Ended
September 30, 2009    December 31, 2008
(in thousands)    (in thousands)
End High Average Low    End High Average Low
$186 $530 $259 $113    $140 $1,284 $411 $131

Management back-tests its VaR results against performance due to actual price moves.  Based on the assumed 95% confidence interval, performance due to actual price moves would be expected to exceed the VaR at least once every 20 trading days.  Management’s back-testing results show that its actual performance exceeded VaR far fewer than once every 20 trading days.  As a result, management believes OPCo’s VaR calculation is conservative.

As OPCo’s VaR calculation captures recent price moves, management also performs regular stress testing of the portfolio to understand OPCo’s exposure to extreme price moves.  Management employs a historical-based method whereby the current portfolio is subjected to actual, observed price moves from the last four years in order to ascertain which historical price moves translated into the largest potential MTM loss.  Management then researches the underlying positions, price moves and market events that created the most significant exposure.

Interest Rate Risk

Management utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure.  EaR statistically quantifies the extent to which OPCo’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  As calculated on OPCo’s debt outstanding as of September 30, 2009, the estimated EaR on OPCo’s debt portfolio for the following twelve months was $2.4 million.

 
 
 


OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30,March 31, 2010 and 2009 and 2008
(in thousands)
(Unaudited)

 Three Months Ended  Nine Months Ended 
 2009  2008  2009  2008  2010 2009
REVENUES                
Electric Generation, Transmission and Distribution $481,049  $600,841  $1,463,200  $1,672,203  $543,700  $524,686 
Sales to AEP Affiliates  276,947   245,830   714,639   739,077  306,768  226,694 
Other Revenues – Affiliated  5,646   5,759   19,415   17,545  6,574  7,488 
Other Revenues – Nonaffiliated  2,329   4,584   9,445   12,738   4,231   3,847 
TOTAL REVENUES  765,971   857,014   2,206,699   2,441,563   861,273   762,715 
                    
EXPENSES                    
Fuel and Other Consumables Used for Electric Generation  238,574   359,341   681,523   928,465  331,017  253,474 
Purchased Electricity for Resale  42,160   56,142   138,398   129,874  38,890  52,269 
Purchased Electricity from AEP Affiliates  19,782   48,867   56,989   116,540  22,191  16,742 
Other Operation  91,162   98,653   287,009   280,494  89,156  99,598 
Maintenance  50,703   51,791   168,893   159,706  56,231  60,040 
Depreciation and Amortization  89,169   72,180   262,576   211,919  89,361  84,023 
Taxes Other Than Income Taxes  48,300   49,019   146,274   146,534   53,084   51,492 
TOTAL EXPENSES  579,850   735,993   1,741,662   1,973,532   679,930   617,638 
                    
OPERATING INCOME  186,121   121,021   465,037   468,031  181,343  145,077 
                    
Other Income (Expense):                    
Interest Income  242   2,252   1,002   6,910  405  244 
Carrying Costs Income  3,143   3,936   7,152   12,159  4,874  1,584 
Allowance for Equity Funds Used During Construction  1,081   555   1,849   1,801  1,031  867 
Interest Expense  (40,614)  (39,731)   (114,536)  (115,088)  (39,975)  (38,681)
                    
INCOME BEFORE INCOME TAX EXPENSE  149,973   88,033   360,504   373,813  147,678  109,091 
                    
Income Tax Expense  53,398   31,601   127,408   125,782   55,775   36,482 
                    
NET INCOME  96,575   56,432   233,096   248,031  91,903  72,609 
                    
Less: Net Income Attributable to Noncontrolling Interest  1,026   233   2,042   1,111   -   463 
                    
NET INCOME ATTRIBUTABLE TO OPCo SHAREHOLDERS  95,549   56,199   231,054   246,920  91,903  72,146 
                    
Less: Preferred Stock Dividend Requirements  183   183   549   549   183   183 
                    
EARNINGS ATTRIBUTABLE TO OPCo COMMON SHAREHOLDER $95,366  $56,016  $230,505  $246,371  $91,720  $71,963 

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



 
 
 

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the NineThree Months Ended September 30,March 31, 2010 and 2009 and 2008
(in thousands)
(Unaudited)

  OPCo Common Shareholder       
  Common Stock  Paid-in Capital  Retained Earnings  
Accumulated
Other
Comprehensive
Income (Loss)
  
Noncontrolling
Interest
  Total 
                   
TOTAL EQUITY – DECEMBER 31, 2007 $321,201  $536,640  $1,469,717  $(36,541) $15,923  $2,306,940 
                         
EITF 06-10 Adoption, Net of Tax of $1,004          (1,864)          (1,864)
SFAS 157 Adoption, Net of Tax of $152          (282)          (282)
Common Stock Dividends – Nonaffiliated                  (1,111)  (1,111)
Preferred Stock Dividends          (549)          (549)
Other Changes in Equity                  1,109   1,109 
SUBTOTAL – EQUITY
                      2,304,243 
                         
COMPREHENSIVE INCOME                        
Other Comprehensive Income, Net of Taxes:                        
Cash Flow Hedges, Net of Tax of $337              625       625 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $1,136              2,110       2,110 
NET INCOME          246,920       1,111   248,031 
TOTAL COMPREHENSIVE INCOME                      250,766 
                         
TOTAL EQUITY – SEPTEMBER 30, 2008
 $321,201  $536,640  $1,713,942  $(33,806) $17,032  $2,555,009 
                         
TOTAL EQUITY – DECEMBER 31, 2008
 $321,201  $536,640  $1,697,962  $(133,858) $16,799  $2,438,744 
                         
Capital Contribution from Parent      550,000               550,000 
Common Stock Dividends – Affiliated          (50,000)          (50,000)
Common Stock Dividends – Nonaffiliated                  (2,042)  (2,042)
Preferred Stock Dividends          (549)          (549)
Purchase of JMG      54,431           (17,910)  36,521 
Other Changes in Equity                  1,111   1,111 
SUBTOTAL – EQUITY
                      2,973,785 
                         
COMPREHENSIVE INCOME                        
Other Comprehensive Income, Net of Taxes:                        
Cash Flow Hedges, Net of Tax of $4,946              9,185       9,185 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $2,566              4,765       4,765 
NET INCOME          231,054       2,042   233,096 
TOTAL COMPREHENSIVE INCOME                      247,046 
                         
TOTAL EQUITY – SEPTEMBER 30, 2009
 $321,201  $1,141,071  $1,878,467  $(119,908) $-  $3,220,831 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2009 and December 31, 2008
(in thousands)
(Unaudited)

  2009  2008 
CURRENT ASSETS      
Cash and Cash Equivalents $2,950  $12,679 
Advances to Affiliates  367,743   - 
Accounts Receivable:        
Customers  46,310   91,235 
Affiliated Companies  167,994   118,721 
Accrued Unbilled Revenues  15,821   18,239 
Miscellaneous  3,535   23,393 
Allowance for Uncollectible Accounts  (2,737)  (3,586)
Total Accounts Receivable  230,923   248,002 
Fuel  364,195   186,904 
Materials and Supplies  110,642   107,419 
Risk Management Assets  58,994   53,292 
Accrued Tax Benefits  30,833   13,568 
Prepayments and Other Current Assets  34,613   42,999 
TOTAL CURRENT ASSETS  1,200,893   664,863 
         
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
Production  6,672,504   6,025,277 
Transmission  1,158,700   1,111,637 
Distribution  1,536,856   1,472,906 
Other Property, Plant and Equipment  373,475   391,862 
Construction Work in Progress  238,525   787,180 
Total Property, Plant and Equipment  9,980,060   9,788,862 
Accumulated Depreciation and Amortization  3,280,362   3,122,989 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET  6,699,698   6,665,873 
         
OTHER NONCURRENT ASSETS        
Regulatory Assets  685,750   449,216 
Long-term Risk Management Assets  36,325   39,097 
Deferred Charges and Other Noncurrent Assets  114,151   184,777 
TOTAL OTHER NONCURRENT ASSETS  836,226   673,090 
         
TOTAL ASSETS $8,736,817  $8,003,826 
 OPCo Common Shareholder      
 Common Stock Paid-in Capital Retained Earnings 
Accumulated
Other
Comprehensive
Income (Loss)
 
Noncontrolling
Interest
 Total
                  
TOTAL EQUITY – DECEMBER 31, 2008$321,201  $536,640  $1,697,962  $(133,858) $16,799  $2,438,744 
                  
Common Stock Dividends – Nonaffiliated             (463)  (463)
Preferred Stock Dividends       (183)        (183)
Other Changes in Equity             1,111   1,111 
SUBTOTAL – EQUITY                2,439,209 
                  
COMPREHENSIVE INCOME                 
Other Comprehensive Income, Net of Taxes:                 
Cash Flow Hedges, Net of Tax of $570          1,058      1,058 
Amortization of Pension and OPEB Deferred Costs, Net of  Tax of $855          1,588      1,588 
NET INCOME       72,146      463   72,609 
TOTAL COMPREHENSIVE INCOME                75,255 
                  
TOTAL EQUITY – MARCH 31, 2009$321,201  $536,640  $1,769,925  $(131,212) $17,910  $2,514,464 
                  
TOTAL COMMON SHAREHOLDER’S EQUITY –DECEMBER 31, 2009$321,201  $1,123,149  $1,908,803 $(118,458) $-  $3,234,695 
                  
Common Stock Dividends       (75,287)        (75,287)
Preferred Stock Dividends       (183)        (183)
SUBTOTAL – COMMON SHAREHOLDER’S EQUITY                3,159,225 
                  
COMPREHENSIVE INCOME                 
Other Comprehensive Income (Loss), Net of Taxes:                 
Cash Flow Hedges, Net of Tax of $817          (1,517)     (1,517)
Amortization of Pension and OPEB Deferred Costs, Net of  Tax of $949          1,762      1,762 
NET INCOME       91,903         91,903 
TOTAL COMPREHENSIVE INCOME                92,148 
                  
TOTAL COMMON SHAREHOLDER’S EQUITY –MARCH 31, 2010$321,201  $1,123,149  $1,925,236  $(118,213) $-  $3,251,373 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



 
 
 

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITYASSETS
September 30, 2009March 31, 2010 and December 31, 20082009
(in thousands)
(Unaudited)

  2009  2008 
CURRENT LIABILITIES (in thousands) 
Advances from Affiliates $-  $133,887 
Accounts Payable:        
General  166,856   193,675 
Affiliated Companies  76,645   206,984 
Long-term Debt Due Within One Year – Nonaffiliated  479,450   77,500 
Risk Management Liabilities  27,444   29,218 
Customer Deposits  23,069   24,333 
Accrued Taxes  100,556   187,256 
Accrued Interest  35,514   44,245 
Other Current Liabilities  114,039   163,702 
TOTAL CURRENT LIABILITIES  1,023,573   1,060,800 
         
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated  2,562,849   2,761,876 
Long-term Debt – Affiliated  200,000   200,000 
Long-term Risk Management Liabilities  16,134   23,817 
Deferred Income Taxes  1,122,531   927,072 
Regulatory Liabilities and Deferred Investment Tax Credits  133,252   127,788 
Employee Benefits and Pension Obligations  278,635   288,106 
Deferred Credits and Other Noncurrent Liabilities  162,385   158,996 
TOTAL NONCURRENT LIABILITIES  4,475,786   4,487,655 
         
TOTAL LIABILITIES  5,499,359   5,548,455 
         
Cumulative Preferred Stock Not Subject to Mandatory Redemption  16,627   16,627 
         
Commitments and Contingencies (Note 4)        
         
EQUITY        
Common Stock – No Par Value:        
Authorized – 40,000,000 Shares        
Outstanding – 27,952,473 Shares  321,201   321,201 
Paid-in Capital  1,141,071   536,640 
Retained Earnings  1,878,467   1,697,962 
Accumulated Other Comprehensive Income (Loss)  (119,908)  (133,858)
TOTAL COMMON SHAREHOLDER’S EQUITY  3,220,831   2,421,945 
         
Noncontrolling Interest  -   16,799 
         
TOTAL EQUITY  3,220,831   2,438,744 
         
TOTAL LIABILITIES AND EQUITY $8,736,817  $8,003,826 
   2010 2009
CURRENT ASSETS       
Cash and Cash Equivalents  $1,153  $1,984 
Advances to Affiliates   617,299   438,352 
Accounts Receivable:       
Customers   64,895   60,711 
Affiliated Companies   129,823   200,579 
Accrued Unbilled Revenues   19,146   15,021 
Miscellaneous   3,076   2,701 
Allowance for Uncollectible Accounts   (2,668)  (2,665)
Total Accounts Receivable   214,272   276,347 
Fuel   280,344   336,866 
Materials and Supplies   114,976   115,486 
Risk Management Assets   59,227   50,048 
Accrued Tax Benefits   128,944   143,473 
Prepayments and Other Current Assets   37,415   26,301 
TOTAL CURRENT ASSETS   1,453,630   1,388,857 
        
PROPERTY, PLANT AND EQUIPMENT       
Electric:       
Production   6,755,219   6,731,469 
Transmission   1,184,514   1,166,557 
Distribution   1,579,150   1,567,871 
Other Property, Plant and Equipment   374,890   348,718 
Construction Work in Progress   204,870   198,843 
Total Property, Plant and Equipment   10,098,643   10,013,458 
Accumulated Depreciation and Amortization   3,395,099   3,318,896 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET   6,703,544   6,694,562 
        
OTHER NONCURRENT ASSETS       
Regulatory Assets   795,135   742,905 
Long-term Risk Management Assets   43,746   28,003 
Deferred Charges and Other Noncurrent Assets   162,378   184,812 
TOTAL OTHER NONCURRENT ASSETS   1,001,259   955,720 
        
TOTAL ASSETS  $9,158,433  $9,039,139 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
March 31, 2010 and December 31, 2009
(Unaudited)

     2010 2009
CURRENT LIABILITIES    (in thousands)
Accounts Payable:         
General    $166,683  $182,848 
Affiliated Companies     81,706   92,766 
Long-term Debt Due Within One Year – Nonaffiliated     679,450   679,450 
Risk Management Liabilities     29,456   24,391 
Customer Deposits     23,238   22,409 
Accrued Taxes     159,132   203,335 
Accrued Interest     48,674   46,431 
Other Current Liabilities     109,626   104,889 
TOTAL CURRENT LIABILITIES     1,297,965   1,356,519 
          
NONCURRENT LIABILITIES         
Long-term Debt – Nonaffiliated     2,449,659   2,363,055 
Long-term Debt – Affiliated     200,000   200,000 
Long-term Risk Management Liabilities     20,353   12,510 
Deferred Income Taxes     1,345,173   1,302,939 
Regulatory Liabilities and Deferred Investment Tax Credits     137,116   128,187 
Employee Benefits and Pension Obligations     259,072   269,485 
Deferred Credits and Other Noncurrent Liabilities     181,095   155,122 
TOTAL NONCURRENT LIABILITIES     4,592,468   4,431,298 
          
TOTAL LIABILITIES     5,890,433   5,787,817 
          
Cumulative Preferred Stock Not Subject to Mandatory Redemption     16,627   16,627 
          
Rate Matters (Note 3)         
Commitments and Contingencies (Note 4)         
          
COMMON SHAREHOLDER’S EQUITY         
Common Stock – No Par Value:         
Authorized – 40,000,000 Shares         
Outstanding – 27,952,473 Shares     321,201   321,201 
Paid-in Capital     1,123,149   1,123,149 
Retained Earnings     1,925,236   1,908,803 
Accumulated Other Comprehensive Income (Loss)     (118,213)  (118,458)
TOTAL COMMON SHAREHOLDER’S EQUITY     3,251,373   3,234,695 
          
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY    $9,158,433  $9,039,139 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



 
 
 

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the NineThree Months Ended September 30,March 31, 2010 and 2009 and 2008
(in thousands)
(Unaudited)
  2009  2008 
OPERATING ACTIVITIES      
Net Income $233,096  $248,031 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:        
Depreciation and Amortization  262,576   211,919 
Deferred Income Taxes  213,458   45,424 
Carrying Costs Income  (7,152)  (12,159)
Allowance for Equity Funds Used During Construction  (1,849)  (1,801)
Mark-to-Market of Risk Management Contracts  (15,226)  (2,028)
Deferred Property Taxes  66,976   63,867 
Fuel Over/Under-Recovery, Net  (242,392)  - 
Change in Other Noncurrent Assets  12,690   (52,788)
Change in Other Noncurrent Liabilities  40,709   9,300 
Changes in Certain Components of Working Capital:        
Accounts Receivable, Net  15,155   16,947 
Fuel, Materials and Supplies  (180,514)  (48,197)
Accounts Payable  (138,828)  45,252 
Accrued Taxes, Net  (103,965)  (56,936)
Other Current Assets  (4,164)  (14,333)
Other Current Liabilities  (13,768)  (17,092)
Net Cash Flows from Operating Activities  136,802   435,406 
         
INVESTING ACTIVITIES        
Construction Expenditures  (342,633)  (453,405)
Change in Advances to Affiliates, Net  (367,743)  (39,758)
Proceeds from Sales of Assets  31,253   6,872 
Other Investing Activities  4,476   (387)
Net Cash Flows Used for Investing Activities  (674,647)  (486,678)
         
FINANCING ACTIVITIES        
Capital Contribution from Parent  550,000   - 
Issuance of Long-term Debt – Nonaffiliated  494,078   412,389 
Change in Short-term Debt, Net – Nonaffiliated  -   (701)
Change in Advances from Affiliates, Net  (133,887)  (101,548)
Retirement of Long-term Debt – Nonaffiliated  (295,500)  (263,463)
Retirement of Cumulative Preferred Stock  (1)  - 
Principal Payments for Capital Lease Obligations  (3,435)  (4,636)
Dividends Paid on Common Stock – Nonaffiliated  (2,042)  (1,111)
Dividends Paid on Common Stock – Affiliated  (50,000)  - 
Dividends Paid on Cumulative Preferred Stock  (549)  (549)
Acquisition of JMG Noncontrolling Interest  (28,221)  - 
Other Financing Activities  (2,327)  13,313 
Net Cash Flows from Financing Activities  528,116   53,694 
         
Net Increase (Decrease) in Cash and Cash Equivalents  (9,729)  2,422 
Cash and Cash Equivalents at Beginning of Period  12,679   6,666 
Cash and Cash Equivalents at End of Period $2,950  $9,088 

 2010 2009
OPERATING ACTIVITIES     
Net Income $91,903  $72,609 
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:     
Depreciation and Amortization  89,361  84,023 
Deferred Income Taxes  41,462  71,740 
Carrying Costs Income  (4,874) (1,584)
Allowance for Equity Funds Used During Construction  (1,031) (867)
Mark-to-Market of Risk Management Contracts  (13,704) (7,117)
Property Taxes  24,242  21,527 
Fuel Over/Under-Recovery, Net  (38,025) (65,192)
Change in Other Noncurrent Assets  (5,008) 1,669 
Change in Other Noncurrent Liabilities  (1,741) 19,318 
Changes in Certain Components of Working Capital:     
Accounts Receivable, Net  62,075  39,518 
Fuel, Materials and Supplies  57,032  (52,588)
Accounts Payable  (10,190) (95,306)
Customer Deposits  829  2,073 
Accrued Taxes, Net  (30,082) (78,533)
Accrued Interest  2,243  (8,311)
Other Current Assets  (8,331) (15,394)
Other Current Liabilities  (4,837)  (10,485)
Net Cash Flows from (Used for) Operating Activities  251,324   (22,900)
     
INVESTING ACTIVITIES     
Construction Expenditures  (78,398) (163,263)
Change in Advances to Affiliates, Net  (178,947) - 
Acquisitions of Assets  (823) - 
Proceeds from Sales of Assets  2,047  2,796 
Other Investing Activities  (2,184)  3,883 
Net Cash Flows Used for Investing Activities  (258,305)  (156,584)
     
FINANCING ACTIVITIES     
Issuance of Long-term Debt – Nonaffiliated  85,487  - 
Change in Advances from Affiliates, Net  -  186,279 
Retirement of Long-term Debt – Nonaffiliated  -  (4,500)
Principal Payments for Capital Lease Obligations  (2,101) (1,316)
Dividends Paid on Common Stock – Nonaffiliated  -  (463)
Dividends Paid on Common Stock – Affiliated  (75,287) - 
Dividends Paid on Cumulative Preferred Stock  (183) (183)
Other Financing Activities  (1,766)  357 
Net Cash Flows from Financing Activities  6,150   180,174 
     
Net Increase (Decrease) in Cash and Cash Equivalents  (831) 690 
Cash and Cash Equivalents at Beginning of Period  1,984   12,679 
Cash and Cash Equivalents at End of Period $1,153  $13,369 
     
SUPPLEMENTARY INFORMATION           
Cash Paid for Interest, Net of Capitalized Amounts $119,763  $112,321  $36,243  $64,554 
Net Cash Paid (Received) for Income Taxes  (23,241)  61,051 
Net Cash Paid for Income Taxes  -  2,337 
Noncash Acquisitions Under Capital Leases  2,022   2,018   22,559  157 
Noncash Acquisition of Coal Land Rights  -   41,600 
Construction Expenditures Included in Accounts Payable at September 30,  15,527   25,839 
Construction Expenditures Included in Accounts Payable at March 31,  12,894  15,767 

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 MattersNote 1
New Accounting Pronouncements and Extraordinary Item
Note 2
Rate Matters
Note 3
Commitments, Guarantees and Contingencies
Note 4
Benefit Plans
Note 6
Business Segments
Note 7
Derivatives and Hedging
Note 8
Fair Value Measurements
Note 9
Income Taxes
Note 10
Financing Activities
Note 11
Company-wide Staffing and Budget ReviewNote 12



 
 
 







PUBLIC SERVICE COMPANY OF OKLAHOMA


 
 
 

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


Results of OperationsRESULTS OF OPERATIONS

ThirdFirst Quarter of 20092010 Compared to ThirdFirst Quarter of 20082009

Reconciliation of ThirdFirst Quarter of 20082009 to ThirdFirst Quarter of 20092010
Net Income
(in millions)

Third Quarter of 2008    $28 
        
Changes in Gross Margin:       
Retail and Off-system Sales Margins (a)  20     
Transmission Revenue  2     
Other  (1)    
Total Change in Gross Margin      21 
         
Total Expenses and Other:        
Other Operation and Maintenance  6     
Taxes Other Than Income Taxes  (2)    
Other Income  (1)    
Total Expenses and Other      3 
         
Income Tax Expense      (8)
         
Third Quarter of 2009     $44 
First Quarter of 2009$6 
Changes in Gross Margin:
Retail Margins (a)11 
Off-system Sales1 
Transmission Revenues2 
Other1 
Total Change in Gross Margin15 
Total Expenses and Other:
Other Operation and Maintenance(16)
Depreciation and Amortization1 
Other Income(1)
Interest Expense(2)
Total Expenses and Other(18)
Income Tax Expense1 
First Quarter of 2010$4 

(a)Includes firm wholesale sales to municipals and cooperatives.

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·Retail and Off-system Sales Margins increased $20$11 million primarily due to an increase in retail sales margins resulting from base rate adjustments.increases.
·Transmission Revenues increased $2 million primarily due to higher rates in the SPP region.

Total Expenses and Other and Income Tax Expense changed between years as follows:

·Other Operation and Maintenance expenses decreased $6increased $16 million primarily due to:to the following:
 ·A $4$7 million decreaseincrease in steam generation expense primarily due to higher planned maintenance in 2008.employee-related expenses.
 ·A $2 million decrease primarily due to a decrease in sale of receivable expense from decreased revenues.
·Taxes Other Than Income Taxes increased $2 million primarily due to an increase in state sales and use tax and an increase in real and personal property tax.
·Income Tax Expense increased $8 million primarily due to an increase in pretax book income.

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

Reconciliation of Nine Months Ended September 30, 2008 to Nine Months Ended September 30, 2009
Net Income
(in millions)

Nine Months Ended September 30, 2008    $69 
        
Changes in Gross Margin:       
Retail and Off-system Sales Margins (a)  70     
Transmission Revenues  3     
Other  (10)    
Total Change in Gross Margin      63 
         
Total Expenses and Other:        
Other Operation and Maintenance  28     
Deferral of Ice Storm Costs  (72)    
Depreciation and Amortization  (6)    
Taxes Other Than Income Taxes  (2)    
Other Income  (4)    
Total Expenses and Other      (56)
         
Income Tax Expense      (2)
         
Nine Months Ended September 30, 2009     $74 

(a)Includes firm wholesale sales to municipals and cooperatives.

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·Retail and Off-system Sales Margins increased $70 million primarily due to an increase in retail sales margins resulting from base rate adjustments including riders of $25 million.  The $25 million increase in riders were offset by a corresponding $14 million increase in Other Operation and Maintenance expenses and a $6 million increase in Depreciation and Amortization expenses as discussed below.
·
Other revenues decreased $10 million primarily due to the sale of SO2 allowances.  The decrease was offset by a corresponding $9 million decrease in Other Operation and Maintenance expenses as discussed below.

Total Expenses and Other and Income Tax Expense changed between years as follows:

·Other Operation and Maintenance expenses decreased $28 million primarily due to:
·The write-off in the first quarter of 2008 of $10 million of unrecoverable pre-construction costs related to the cancelled Red Rock Generating Facility.
·A $10 million decrease due to lower plant maintenance expense primarily due toresulting from the 2009 deferral of generation maintenance expenses as a result of PSO’s base rate filing.  See “2008 Oklahoma Base Rate Filing Appeal” section of Note 3.
·A $9 million decrease in expense due to the amortization of regulatory assets related to the 2007 ice storm expense which is offset by a corresponding decrease in Other revenues as discussed above.
·A $3 million decrease in employee-related expenses.
·A $3 million decrease primarily due to a decrease in sale of receivable expense from decreased revenues.
·A $2 million decrease in expense related to maintenance of overhead transmission lines.
These decreases were partially offset by:
·A $14 million increase in expense from amortization of regulatory assets related to the 2007 ice storm, demand side management and distribution vegetation management directly offset by a corresponding increase in revenue from the riders discussed above.
·Deferral of Ice Storm Costs in 2008 of $72 million results from an OCC order approving recovery of ice storm costs related to ice storms in January and December 2007.case.
·Depreciation and Amortization expenses increased $6 million primarily due to an increase in  amortization of regulatory assets, largest of which was related to the Generation Cost Recovery regulatory asset.  The increase is offset by a corresponding increase in revenues from riders as discussed above.
·Taxes Other Than Income Taxes increased $2 million primarily due to an increase in real and personal property tax.
·Other Income decreased $4 million primarily due to carrying charges related to the Generation Cost Recovery regulatory assets and a decrease in the equity component of AFUDC.
·Income TaxInterest Expense increased $2 million primarily due to an increase in pretax book income.long-term borrowings in the last half of 2009.

Financial ConditionFINANCIAL CONDITION

LIQUIDITY

PSO participates in the Utility Money Pool, which provides access to AEP’s liquidity.  PSO relies upon ready access to capital markets, cash flows from operations and access to the Utility Money Pool to fund current operations and capital expenditures.  See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of liquidity.

Credit Ratings

PSO’s credit ratings as of September 30, 2009March 31, 2010 were as follows:

 Moody’s S&P Fitch
      
Senior Unsecured DebtBaa1 BBB  BBB+

Moody’s, S&P Moody’s and Fitch have PSO on stable outlook.  If PSO receives a downgradeDowngrades from any of the rating agencies its borrowing costs could increase and access to borrowed funds could be negatively affected.PSO’s borrowing costs.

Cash FlowCASH FLOW

Cash flows for the ninethree months ended September 30,March 31, 2010 and 2009 and 2008 were as follows:

 2009  2008  2010 2009
 (in thousands)  (in thousands)
Cash and Cash Equivalents at Beginning of Period $1,345  $1,370  $796  $1,345 
Cash Flows from (Used for):            
Operating Activities  232,759   42,386  (60,332) 103,803 
Investing Activities  (142,945)  (161,523) 5,380  (59,145)
Financing Activities  (89,852)  120,011   55,082   (44,726)
Net Increase (Decrease) in Cash and Cash Equivalents  (38)  874   130   (68)
Cash and Cash Equivalents at End of Period $1,307  $2,244  $926  $1,277 
Operating Activities

Net Cash Flows Used for Operating Activities were $60 million in 2010.  PSO produced Net Income of $4 million during the period and had noncash expense items of $27 million for Depreciation and Amortization and $21 million for Deferred Income Taxes, offset by a $28 million increase in the deferral of Property Taxes.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The activity in working capital relates to a $15 million inflow from Accounts Payable primarily due to timing differences for payments to affiliates and payments of items accrued at December 31, 2009.  The $82 million o utflow from Fuel Over/Under-Recovery, Net was primarily due to refunding to customers the prior month’s fuel over-recoveries through lower fuel factors.

Net Cash Flows from Operating Activities were $233$104 million in 2009.  PSO produced Net Income of $74$6 million during the period and had a noncash expense item of $84$28 million for Depreciation and Amortization.Amortization, offset by a $28 million increase in the deferral of Property Taxes and a $14 million increase in Deferred Income Taxes.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The activity in working capital relates to a number of items.  The $86$93 million inflow from Accounts Receivable, Net was primarily due to receiving the SIA refund from the AEP East companies and lower customer receivables.re ceivables.  The $46$37 million inflow from Accrued Taxes, Net was the result of increased accruals related to property and income taxes.  The $38$29 million outflow from Accounts Payable was primarily due to decreases in customer accounts factored, fueltiming differences for payments to affiliates and purchased power payables.

Net Cash Flowspayment of items accrued at December 31, 2008.  The $37 million inflow from Operating Activities were $42 million in 2008.  PSO producedFuel Over/Under-Recovery, Net Income of $69 million during the period and had noncash expense items of $78 million for Depreciation and Amortization and $71 million for Deferred Income Taxes.  PSO established a $72 million regulatory asset for an OCC order approving recovery of ice storm costs related to storms in January and December 2007.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The activity in working capital relates to a number of items.  The $81 million outflow from Accounts Payable was primarily due to a decrease in accounts payable accruals and purchased power payable.  The $36 million inflow from Accrued Taxes, Net was the result of a refund for the 2007 overpayment of federal income taxes and increased accruals related to property and income taxes.  The $47 million outflow from Fuel Over/Under-Recovery, Net resulted from rapidly increasing natural gas costs which fuels the majority of PSO’s generating facilities.lower fuel costs.

Investing Activities

Net Cash Flows from Investing Activities were $5 million during 2010 and Net Cash Flows Used for Investing Activities were $59 million during 2009 and 2008 were $143 million and $162 million, respectively.2009.  Construction Expenditures of $135$55 million and $214$52 million in 20092010 and 2008,2009, respectively, were primarily related to projects for improved generation, transmission and distribution service reliability.  During 2009,2010, PSO had a net increasedecrease of $8$63 million in loans to the Utility Money Pool.  During 2008,2009, PSO had a net decreaseincrease of $51$7 million in loans to the Utility Money Pool.

Financing Activities

Net Cash Flows from Financing Activities were $55 million during 2010.  PSO had a net increase of $69 million in borrowings from the Utility Money Pool.  This inflow was partially offset by $13 million paid in dividends on common stock.

Net Cash Flows Used for Financing Activities were $90$45 million during 2009.  PSO had a net decrease of $70 million in borrowings from the Utility Money Pool.  PSO retired $50 million of Senior Unsecured Notes in September 2009 and issued $34 million of Pollution Control Bonds in February 2009.  In addition, PSO paid $22$7 million in dividends on common stock.  In addition, PSO received capital contributions from the Parent of $20 million.

Net Cash Flows from Financing Activities were $120 million during 2008.  PSO had a net increase of $125 million in borrowings from the Utility Money Pool.  PSO repurchased $34 million in Pollution Control Bonds in May 2008.  PSO received capital contributions from the Parent of $30 million.

Financing Activity

Long-termdid not have any long-term debt issuances andor retirements during the first ninethree months of 2009 were:2010.

Issuances
  Principal Interest Due
Type of Debt Amount Rate Date
  (in thousands) (%)  
Pollution Control Bonds $33,700  5.25 2014

Retirements
  
Principal
Amount Paid
 Interest Due
Type of Debt  Rate Date
  (in thousands) (%)  
Senior Unsecured Notes $50,000  4.70 2009

Liquidity

Although the financial markets were volatile at both a global and domestic level, PSO issued $34 million of Pollution Control Bonds during the first nine months of 2009.  The credit situation appears to have improved but could impact PSO’s future operations and ability to issue debt at reasonable interest rates.

PSO participates in the Utility Money Pool, which provides access to AEP’s liquidity.  PSO relies upon cash flows from operations and access to the Utility Money Pool to fund current operations and capital expenditures.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of liquidity.

Summary Obligation InformationSUMMARY OBLIGATION INFORMATION

A summary of contractual obligations is included in the 20082009 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.year-end.

Significant FactorsREGULATORY ACTIVITY

New Generation/Purchased Power AgreementOklahoma Regulatory Activity

SeeIn 2009, the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section additional discussion of relevant factors.OCC approved PSO’s Capital Reliability Rider (CRR) filing which requires PSO to file a base rate case no later than July 2010.

Litigation and Regulatory ActivitySIGNIFICANT FACTORS

LITIGATION AND ENVIRONMENTAL ISSUES

In the ordinary course of business, PSO is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot state what the eventual outcome of these proceedings will be or what the timing of theand amount of any loss, fine or penalty may be.penalty.  Management does, however, assessassesses the probability of loss for such contingencieseach contingency and accrues a liability for cases which have a probable likelihood of loss andif the loss amount can be estimated.  For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 20082009 Annual Report.  Also,Additionally, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the “Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries” section.Contingencies.  Adverse results in thesethes e proceedings have the potential to materially affect PSO’s net income, financial condition and cash flows.

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

Critical Accounting EstimatesCRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 20082009 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncementsbenefits.

See the “New Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of the adoption and impact 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 andAnd Qualitative Disclosures About Risk Management Activities” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for disclosures abouta discussion of risk management activities.  The following tables provide information about AEP’s risk management activities’ effect on PSO.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in PSO’s Condensed Balance Sheet as of September 30, 2009 and the reasons for changes in total MTM value as compared to December 31, 2008.

Reconciliation of MTM Risk Management Contracts to
Condensed Balance Sheet
September 30, 2009
(in thousands)

  MTM Risk Management Contracts  
Cash Flow
Hedge
Contracts
  
Collateral
Deposits
  Total 
Current Assets $3,834  $72  $(1) $3,905 
Noncurrent Assets  299   13   -   312 
Total MTM Derivative Contract Assets  4,133   85   (1)  4,217 
                 
Current Liabilities  4,279   501   (15)  4,765 
Noncurrent Liabilities  447   37   (11)  473 
Total MTM Derivative Contract Liabilities  4,726   538   (26)  5,238 
                 
Total MTM Derivative Contract Net Assets (Liabilities) $(593) $(453) $25  $(1,021)

MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2009
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2008 $1,660 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period  (750)
Fair Value of New Contracts at Inception When Entered During the Period (a)  - 
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period  (17)
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts  - 
Changes in Fair Value Due to Market Fluctuations During the Period (b)  (43)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)  (1,443)
Total MTM Risk Management Contract Net Assets (Liabilities)  (593)
Cash Flow Hedge Contracts  (453)
Collateral Deposits  25 
Total MTM Derivative Contract Net Assets (Liabilities) at September 30, 2009 $(1,021)

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

The following table presents the maturity, by year, of net assets/liabilities to give an indication of when these MTM amounts will settle and generate or (require) cash:

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets (Liabilities)
September 30, 2009
(in thousands)

  
Remainder
2009
  2010  2011  2012  2013  
After
2013
  Total 
Level 1 (a) $47  $-  $-  $-  $-  $-  $47 
Level 2 (b)  269   (633)  (287)  6   -   -   (645)
Level 3 (c)  4   1   -   -   -   -   5 
Total MTM Risk Management Contract Net Assets (Liabilities) $320  $(632) $(287) $6  $-  $-  $(593)

(a)Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.  Level 1 inputs primarily consist of exchange traded contracts that exhibit sufficient frequency and volume to provide pricing information on an ongoing basis.
(b)Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.  If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, exchange traded contracts where there was not sufficient market activity to warrant inclusion in Level 1 and OTC broker quotes that are corroborated by the same or similar transactions that have occurred in the market.
(c)Level 3 inputs are unobservable inputs for the asset or liability.  Unobservable inputs shall be used to measure fair value to the extent that the observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.  Level 3 inputs primarily consist of unobservable market data or are valued based on models and/or assumptions.

Credit Risk

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

See Note 8 for further information regarding MTM risk management contracts, cash flow hedging, accumulated other comprehensive income, credit risk and collateral triggering events.

VaR Associated with Risk Management Contracts

Management uses a risk measurement model, which calculates Value at Risk (VaR) to measure commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period.  Based on this VaR analysis, at September 30, 2009, a near term typical change in commodity prices is not expected to have a material effect on PSO’s net income, cash flows or financial condition.

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

Nine Months Ended    Twelve Months Ended
September 30, 2009    December 31, 2008
(in thousands)    (in thousands)
End High Average Low    End High Average Low
$9 $34 $12 $4    $4 $164 $44 $6

Management back-tests its VaR results against performance due to actual price moves.  Based on the assumed 95% confidence interval, the performance due to actual price moves would be expected to exceed the VaR at least once every 20 trading days.  Management’s back-testing results show that its actual performance exceeded VaR far fewer than once every 20 trading days.  As a result, management believes PSO’s VaR calculation is conservative.

As PSO’s VaR calculation captures recent price moves, management also performs regular stress testing of the portfolio to understand PSO’s exposure to extreme price moves.  Management employs a historical-based method whereby the current portfolio is subjected to actual, observed price moves from the last four years in order to ascertain which historical price moves translated into the largest potential MTM loss.  Management then researches the underlying positions, price moves and market events that created the most significant exposure.

Interest Rate Risk

Management utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure.  EaR statistically quantifies the extent to which PSO’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  As calculated on PSO’s debt outstanding as of September 30, 2009, the estimated EaR on PSO’s debt portfolio for the following twelve months was $3.5 million.




 
 
 


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30,March 31, 2010 and 2009 and 2008
(in thousands)
(Unaudited)

 Three Months Ended  Nine Months Ended 
 2009  2008  2009  2008  2010 2009
REVENUES                
Electric Generation, Transmission and Distribution $311,274  $518,182  $853,808  $1,194,737  $228,551  $278,771 
Sales to AEP Affiliates  6,668   32,286   34,181   89,988  8,670   15,823 
Other Revenues  613   781   2,994   2,858   534   693 
TOTAL REVENUES  318,555   551,249   890,983   1,287,583   237,755   295,287 
                     
EXPENSES                     
Fuel and Other Consumables Used for Electric Generation  79,610   288,027   261,762   584,769  40,972   119,399 
Purchased Electricity for Resale  42,090   77,834   132,623   230,432  44,980   44,425 
Purchased Electricity from AEP Affiliates  5,424   15,169   14,755   53,944  10,992   5,915 
Other Operation  48,145   51,432   134,211   152,617  49,662   39,545 
Maintenance  24,601   27,530   77,996   87,772  30,939   25,430 
Deferral of Ice Storm Costs  -   69   -   (71,610)
Depreciation and Amortization  27,799   27,192   84,278   78,079  27,288   27,950 
Taxes Other Than Income Taxes  9,534   7,839   31,243   29,265   10,300   10,751 
TOTAL EXPENSES  237,203   495,092   736,868   1,145,268   215,133   273,415 
                     
OPERATING INCOME  81,352   56,157   154,115   142,315  22,622   21,872 
                     
Other Income (Expense):                     
Other Income  825   34   2,794   4,004 
Interest Income 182   648 
Carrying Costs Income  986   3,183   3,716   6,945  867   1,711 
Allowance for Equity Funds Used During Construction 247   170 
Interest Expense  (13,884)  (13,713)  (43,852)  (43,179)  (17,363)  (14,805)
                     
INCOME BEFORE INCOME TAX EXPENSE  69,279   45,661   116,773   110,085  6,555   9,596 
                     
Income Tax Expense  25,702   17,917   43,036   40,815   2,416   3,558 
                     
NET INCOME  43,577   27,744   73,737   69,270  4,139   6,038 
                     
Preferred Stock Dividend Requirements  53   53   159   159   53   53 
                     
EARNINGS ATTRIBUTABLE TO COMMON STOCK $43,524  $27,691  $73,578  $69,111  $4,086  $5,985 

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.




 
 
 

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the NineThree Months Ended September 30,March 31, 2010 and 2009 and 2008
(in thousands)
(Unaudited)

 Common Stock  Paid-in Capital  Retained Earnings  Accumulated Other Comprehensive Income (Loss)  Total  Common Stock Paid-in Capital Retained Earnings 
Accumulated
Other
Comprehensive
Income (Loss)
 Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2007 $157,230  $310,016  $174,539  $(887) $640,898 
                               
EITF 06-10 Adoption, Net of Tax of $596          (1,107)      (1,107)
Capital Contribution from Parent      30,000           30,000 
TOTAL COMMON SHAREHOLDER’S EQUITY –
DECEMBER 31, 2008
 $157,230  $340,016  $251,704  $(704) $748,246 
           
Common Stock Dividends      (7,250)   (7,250)
Preferred Stock Dividends      (53)   (53)
Other Changes in Common Shareholder’s Equity    4,214  (4,214)    - 
SUBTOTAL – COMMON SHAREHOLDER’S EQUITY           740,943 
           
COMPREHENSIVE INCOME           
Other Comprehensive Income, Net of Taxes:           
Cash Flow Hedges, Net of Tax of $12        22  22 
NET INCOME      6,038     6,038 
TOTAL COMPREHENSIVE INCOME              6,060 
           
TOTAL COMMON SHAREHOLDER’S EQUITY –
MARCH 31, 2009
 $157,230  $344,230  $246,225  $(682) $747,003 
           
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2009 $157,230  $364,231  $290,880  $(599) $811,742 
           
Common Stock Dividends      (12,687)   (12,687)
Preferred Stock Dividends          (159)      (159)      (53)    (53)
SUBTOTAL – COMMON SHAREHOLDER’S EQUITY                  669,632            799,002 
                               
COMPREHENSIVE INCOME                               
Other Comprehensive Income, Net of Taxes:                               
Cash Flow Hedges, Net of Tax of $74              137   137 
Cash Flow Hedges, Net of Tax of $62        116  116 
NET INCOME          69,270       69,270       4,139     4,139 
TOTAL COMPREHENSIVE INCOME                  69,407               4,255 
                               
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2008 $157,230  $340,016  $242,543  $(750) $739,039 
TOTAL COMMON SHAREHOLDER’S EQUITY –
MARCH 31, 2010
 $157,230  $364,231  $282,279  $(483) $803,257 
                               
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2008 $157,230  $340,016  $251,704  $(704) $748,246 
                    
Capital Contribution from Parent      20,000           20,000 
Common Stock Dividends          (21,750)      (21,750)
Preferred Stock Dividends          (159)      (159)
Gain on Reacquired Preferred Stock      1           1 
Other Changes in Common Shareholder’s Equity      4,214   (4,214)      - 
SUBTOTAL – COMMON SHAREHOLDER’S EQUITY                  746,338 
                    
COMPREHENSIVE INCOME                    
Other Comprehensive Loss, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $78              (145)  (145)
NET INCOME          73,737       73,737 
TOTAL COMPREHENSIVE INCOME                  73,592 
                    
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2009 $157,230  $364,231  $299,318  $(849) $819,930 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.




 
 
 

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
September 30, 2009March 31, 2010 and December 31, 20082009
(in thousands)
(Unaudited)

 2009  2008  2010 2009
CURRENT ASSETS      
Cash and Cash Equivalents $1,307  $1,345  $926  $796 
Advances to Affiliates  8,450   -   -   62,695 
Accounts Receivable:              
Customers  23,043   39,823   32,961   38,239 
Affiliated Companies  69,413   138,665   58,353   59,096 
Miscellaneous  5,871   8,441   7,461   7,242 
Allowance for Uncollectible Accounts  (340)  (20)  (128)  (304)
Total Accounts Receivable  97,987   186,909   98,647   104,273 
Fuel  22,367   27,060   21,608   20,892 
Materials and Supplies  44,541   44,047   46,560   44,914 
Risk Management Assets  3,905   5,830   3,263   2,376 
Deferred Tax Benefits  34,177   9,123 
Deferred Income Tax Benefits  14,312   26,335 
Accrued Tax Benefits  503   3,876   32,860   15,291 
Regulatory Asset for Under-Recovered Fuel Costs  31,025   - 
Prepayments and Other Current Assets  7,083   3,371   11,311   9,139 
TOTAL CURRENT ASSETS  220,320   281,561   260,512   286,711 
              
PROPERTY, PLANT AND EQUIPMENT              
Electric:              
Production  1,294,115   1,266,716   1,304,060   1,300,069 
Transmission  638,645   622,665   633,864   617,291 
Distribution  1,551,382   1,468,481   1,627,977   1,596,355 
Other Property, Plant and Equipment  250,053   248,897   244,558   228,705 
Construction Work in Progress  59,356   85,252   81,462   67,138 
Total Property, Plant and Equipment  3,793,551   3,692,011   3,891,921   3,809,558 
Accumulated Depreciation and Amortization  1,228,141   1,192,130   1,234,393   1,220,177 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET  2,565,410   2,499,881   2,657,528   2,589,381 
              
OTHER NONCURRENT ASSETS              
Regulatory Assets  277,790   304,737   276,679   279,185 
Long-term Risk Management Assets  312   917   157   50 
Deferred Charges and Other Noncurrent Assets  20,979   13,702   40,328   13,880 
TOTAL OTHER NONCURRENT ASSETS  299,081   319,356   317,164   293,115 
              
TOTAL ASSETS $3,084,811  $3,100,798  $3,235,204  $3,169,207 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



 
 
 

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
September 30, 2009March 31, 2010 and December 31, 20082009
(Unaudited)

 2009  2008   2010 2009
CURRENT LIABILITIES (in thousands)   (in thousands)
Advances from Affiliates $-  $70,308   $68,743  $- 
Accounts Payable:               
General  52,529   84,121    101,867   76,895 
Affiliated Companies  69,287   86,407    78,260   71,099 
Long-term Debt Due Within One Year – Nonaffiliated  150,000   50,000 
Risk Management Liabilities  4,765   4,753    536   2,579 
Customer Deposits  42,622   40,528    41,603   42,002 
Accrued Taxes  61,746   19,000    37,591   19,471 
Regulatory Liability for Over-Recovered Fuel Costs  95,983   58,395    -   51,087 
Provision for Revenue Refund  -   52,100 
Other Current Liabilities  46,878   61,194    56,929   60,905 
TOTAL CURRENT LIABILITIES  523,810   526,806    385,529   324,038 
               
NONCURRENT LIABILITIES               
Long-term Debt – Nonaffiliated  718,738   834,859    968,808   968,121 
Long-term Risk Management Liabilities  473   378    117   144 
Deferred Income Taxes  553,261   514,720    602,506   588,768 
Regulatory Liabilities and Deferred Investment Tax Credits  325,694   323,750    317,573   326,931 
Employee Benefits and Pension Obligations   108,101   107,748 
Deferred Credits and Other Noncurrent Liabilities  137,647   146,777    44,055   36,457 
TOTAL NONCURRENT LIABILITIES  1,735,813   1,820,484    2,041,160   2,028,169 
               
TOTAL LIABILITIES  2,259,623   2,347,290    2,426,689   2,352,207 
               
Cumulative Preferred Stock Not Subject to Mandatory Redemption  5,258   5,262    5,258   5,258 
               
Rate Matters (Note 3)       
Commitments and Contingencies (Note 4)               
               
COMMON SHAREHOLDER’S EQUITY               
Common Stock – Par Value – $15 Per Share:               
Authorized – 11,000,000 Shares               
Issued – 10,482,000 Shares               
Outstanding – 9,013,000 Shares  157,230   157,230    157,230   157,230 
Paid-in Capital  364,231   340,016    364,231   364,231 
Retained Earnings  299,318   251,704    282,279   290,880 
Accumulated Other Comprehensive Income (Loss)  (849)  (704)   (483)  (599)
TOTAL COMMON SHAREHOLDER’S EQUITY  819,930   748,246    803,257   811,742 
               
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $3,084,811  $3,100,798   $3,235,204  $3,169,207 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

 
 
 

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the NineThree Months Ended September 30,March 31, 2010 and 2009 and 2008
(in thousands)
(Unaudited)

 2009  2008  2010 2009
OPERATING ACTIVITIES          
Net Income $73,737  $69,270  $4,139  $6,038 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:        
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:    
Depreciation and Amortization  84,278   78,079  27,288  27,950 
Deferred Income Taxes  13,103   70,856  20,526  (13,835)
Deferral of Ice Storm Costs  -   (71,610)
Carrying Costs Income (867) (1,711)
Allowance for Equity Funds Used During Construction  (1,224)  (1,840) (247) (170)
Mark-to-Market of Risk Management Contracts  2,185   6,973  (2,959) (562)
Property Taxes (27,797) (28,050)
Fuel Over/Under-Recovery, Net  (14,566)  (47,192) (82,112) 36,650 
Change in Other Noncurrent Assets  (4,669)  9,920  (10,473) 429 
Change in Other Noncurrent Liabilities  (2,768)  (34,426) 1,764  (1,879)
Changes in Certain Components of Working Capital:            
Accounts Receivable, Net  86,010   21,846  5,626  92,561 
Fuel, Materials and Supplies  4,199   (6,881) (2,362) 1,386 
Margin Deposits  314   8,554 
Accounts Payable  (38,023)  (81,228) 15,235  (28,623)
Accrued Taxes, Net  46,119   35,624  1,152  36,694 
Other Current Assets  (4,136)  (1,676) (2,108) (3,511)
Other Current Liabilities  (11,800)  (13,883)  (7,137)  (19,564)
Net Cash Flows from Operating Activities  232,759   42,386 
Net Cash Flows from (Used for) Operating Activities  (60,332)  103,803 
            
INVESTING ACTIVITIES            
Construction Expenditures  (134,756)  (214,319) (54,837) (52,368)
Change in Advances to Affiliates, Net  (8,450)  51,202  62,695  (7,009)
Other Investing Activities  261   1,594   (2,478)  232 
Net Cash Flows Used for Investing Activities  (142,945)  (161,523)
Net Cash Flows from (Used for) Investing Activities  5,380   (59,145)
            
FINANCING ACTIVITIES            
Capital Contribution from Parent  20,000   30,000 
Issuance of Long-term Debt – Nonaffiliated  33,248   -  -  33,283 
Change in Advances from Affiliates, Net  (70,308)  125,029  68,743  (70,308)
Retirement of Long-term Debt – Nonaffiliated  (50,000)  (33,700)
Retirement of Cumulative Preferred Stock  (2)  - 
Principal Payments for Capital Lease Obligations  (1,128)  (1,159) (1,026) (398)
Dividends Paid on Common Stock  (21,750)  -  (12,687) (7,250)
Dividends Paid on Cumulative Preferred Stock  (159)  (159) (53) (53)
Other Financing Activities  247   -   105   - 
Net Cash Flows from (Used for) Financing Activities  (89,852)  120,011   55,082   (44,726)
            
Net Increase (Decrease) in Cash and Cash Equivalents  (38)  874  130  (68)
Cash and Cash Equivalents at Beginning of Period  1,345   1,370   796   1,345 
Cash and Cash Equivalents at End of Period $1,307  $2,244  $926  $1,277 
            
SUPPLEMENTARY INFORMATION            
Cash Paid for Interest, Net of Capitalized Amounts $55,152  $39,739  $8,267  $29,174 
Net Cash Paid for Income Taxes  4,423   44,559 
Net Cash Paid (Received) for Income Taxes (1,331) 391 
Noncash Acquisitions Under Capital Leases  2,802   403  13,274  391 
Construction Expenditures Included in Accounts Payable at September 30,  7,315   12,251 
Construction Expenditures Included in Accounts Payable at March 31, 28,799  11,776 

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 MattersNote 1
New Accounting Pronouncements and Extraordinary ItemNote 2
Rate MattersNote 3
Commitments, Guarantees and ContingenciesNote 4
Benefit PlansNote 6
Business SegmentsNote 7
Derivatives and HedgingNote 8
Fair Value MeasurementsNote 9
Income TaxesNote 10
Financing ActivitiesNote 11
Company-wide Staffing and Budget ReviewNote 12



 
 
 







SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED


 
 
 

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

Results of OperationsRESULTS OF OPERATIONS

ThirdFirst Quarter of 20092010 Compared to ThirdFirst Quarter of 20082009

Reconciliation of ThirdFirst Quarter of 20082009 to ThirdFirst Quarter of 20092010
Net Income Before Extraordinary Loss
(in millions)

Third Quarter of 2008    $48 
        
Changes in Gross Margin:       
Retail and Off-system Sales Margins (a)  (16)    
Transmission Revenues  2     
Other  1     
Total Change in Gross Margin      (13)
         
Total Expenses and Other:        
Other Operation and Maintenance  16     
Depreciation and Amortization  (1)    
Taxes Other Than Income Taxes  (1)    
Other Income  4     
Interest Expense  6     
Total Expenses and Other      24 
         
Income Tax Expense      6 
         
Third Quarter of 2009     $65 
First Quarter of 2009$12 
Changes in Gross Margin:
Retail Margins (a)18 
Off-system Sales1 
Transmission Revenues2 
Other(11)
Total Change in Gross Margin10 
Total Expenses and Other:
Other Operation and Maintenance5 
Depreciation and Amortization3 
Taxes Other Than Income Taxes(1)
Other Income9 
Interest Expense(2)
Equity Earnings of Unconsolidated Subsidiaries1 
Total Expenses and Other15 
Income Tax Expense(6)
First Quarter of 2010$31 

(a)Includes firm wholesale sales to municipals and cooperatives.

The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·Retail and Off-system Sales Margins decreased $16increased $18 million primarily due to a $12the following:
·A $13 million decreaseincrease in wholesale fuel recoveryretail sales primarily due to favorable weather and a $7slight increases in usage in the commercial and industrial classes.
·A $3 million impairment of a fuel regulatory asset related to deferred mining costsincrease in base rates in Arkansas.
·A $2 million increase in FERC wholesale and municipal revenue.
·Transmission Revenues increased $2 million primarily due to higher rates in the SPP region.

Total Expenses and Other and Income Tax Expense changed between years as follows:

·Other Operation and Maintenance expenses decreased $16 million primarily due to storm recovery costs for Hurricanes Ike and Gustav in 2008 and the deferral in September 2009 of a portion of the January 2009 Northern Arkansas ice storm costs.
·Other Income increased $4 million primarily due to an $8 million increase in the equity component of AFUDC as a result of construction at the Turk Plant and Stall Unit and the reapplication of the accounting guidance for “Regulated Operations” for the generation portion of SWEPCo’s Texas retail jurisdiction effective April 2009.  See “Texas Rate Matters – Texas Restructuring – SPP” section of Note 3.  This increase was partially offset by lower interest income.
·Interest Expense decreased $6 million primarily due to higher AFUDC debt as a result of construction at the Turk Plant and Stall Unit and lower interest expense on debt and other.
·Income Tax Expense decreased $6 million primarily due to changes in certain book/tax differences accounted for on a flow-through basis, partially offset by an increase in pretax book income.

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

Reconciliation of Nine Months Ended September 30, 2008 to Nine Months Ended September 30, 2009
Income Before Extraordinary Loss
(in millions)

Nine Months Ended September 30, 2008    $69 
        
Changes in Gross Margin:       
Retail and Off-system Sales Margins (a)  (9)    
Transmission Revenues  7     
Other  (1)    
Total Change in Gross Margin      (3)
         
Total Expenses and Other:        
Other Operation and Maintenance  30     
Taxes Other Than Income Taxes  1     
Other Income  15     
Interest Expense  5     
Total Expenses and Other      51 
         
Income Tax Expense      (4)
         
Nine Months Ended September 30, 2009     $113 

(a)Includes firm wholesale sales to municipals and cooperatives.

The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·Retail and Off-system Sales Margins decreased $9 million primarily due to:
·An $8 million decrease in wholesale fuel recovery.
·A $9 million decrease in industrial sales due to reduced operating levels and suspended operations by certain large industrial customers in SWEPCo’s service territory.
·A $7 million impairment of a fuel regulatory asset related to deferred mining costs in Arkansas.
These decreases were partially offset by:
·An $8 million increase in rate relief related to the Louisiana Formula Rate Plan.  See “Louisiana Rate Matters – Formula Rate Filing” section of Note 3.
·An $8 million increase in wholesale and municipal revenue due to higher prices and the annual true-up for formula rate customers.
·Transmission Revenues increased $7 million primarily due to higher rates in the SPP region.
·Other revenues decreased $1$11 million primarily due to a decrease in revenuesresulting from coal deliveries fromthe deconsolidation of SWEPCo’s mining subsidiary, Dolet Hills Lignite Company, LLC (DHLC).  Prior to Cleco Corporation, a nonaffiliated entity.the deconsolidation, SWEPCo recorded revenues from coal deliveries from DHLC to CLECO.  SWEPCo prospectively adopted the “Consolidation” accounting guidance effective January 1, 2010 and began accounting for DHLC under the equity method of accounting.  The decreased revenue from coal deliveries was offset by a corresponding decrease in Other Operation and Maintenance expenses from mining operations as discussed below.

Total Expenses and Other and Income Tax Expense changed between years as follows:indicated:

·Other Operation and Maintenance expenses decreased $30$5 million primarily due to:to the following:
 ·An $18 million decrease in distribution expenses related to storm recovery costs primarily for Hurricanes Ike and Gustav in 2008.
·A $5 million decrease in steam plant maintenance expense primarily due to a reduction in planned and unplanned outages.
·A $2$8 million decrease in expenses for coal deliveriesmining operations from SWEPCo’s mining subsidiary, Dolet Hills Lignite Company, LLC.DHLC.  The decreased expenses for coal deliveriesmining operations were partially offset by a corresponding decrease in revenues from mining operations as discussed above.
This decrease was partially offset by:
 ·A $2 million gain on sale of property during the first quarter of 2009 related to the sale of percentage ownership of the Turk Plant to nonaffiliated companies.companies who exercised their participation options.
·Depreciation and Amortization expenses decreased $3 million primarily due to lower Arkansas depreciation resulting from the Arkansas Base Rate Filing and the deconsolidation of DHLC.
·Other Income increased $15$9 million primarily due to an increase in theAFUDC equity component of AFUDC as a result of construction at the Turk Plant and Stall Unit and the reapplication of the“Regulated Operations” accounting guidance for “Regulated Operations” for the generation portion of SWEPCo’s TexasTexas’ retail jurisdiction effective Aprilthe second quarter of 2009.  See “Texas Rate Matters – Texas Restructuring – SPP” section of Note 3.  This increase was partially offset by lower interest income.
·Interest Expense decreased $5increased $2 million primarily due to higherincreased long-term debt outstanding and capital leases, partially offset by an increase in the debt component of AFUDC debt as a result of constructiondue to generation projects at the Turk Plant and Stall Unit, partially offset by higher interest expense on debt.Unit.
·Income Tax Expense increased $4$6 million primarily due to an increase in pretax book income, partially offset by changes in certain book/tax differences accounted for on a flow-through basis.
FINANCIAL CONDITION

Financial ConditionLIQUIDITY

SWEPCo participates in the Utility Money Pool, which provides access to AEP’s liquidity.  SWEPCo relies upon ready access to capital markets, cash flows from operations and access to the Utility Money Pool to fund current operations and capital expenditures.  See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of liquidity.

Credit Ratings

SWEPCo’s credit ratings as of September 30, 2009March 31, 2010 were as follows:

 Moody’s S&P Fitch
      
Senior Unsecured DebtBaa3 BBB  BBB+

Moody’s and S&P and Moody’s have SWEPCo on stable outlook.  In July 2009, Fitch changed its rating outlook forhas SWEPCo from stable to negative.  If SWEPCo receives a downgradeon negative outlook.  Downgrades from any of the rating agencies its borrowing costs could increase and access to borrowed funds could be negatively affected.SWEPCo’s borrowing costs.

Cash FlowCASH FLOW

Cash flows for the ninethree months ended September 30,March 31, 2010 and 2009 and 2008 were as follows:

  2009  2008 
  (in thousands) 
Cash and Cash Equivalents at Beginning of Period $1,910  $1,742 
Cash Flows from (Used for):        
Operating Activities  335,922   134,516 
Investing Activities  (472,183)  (619,487)
Financing Activities  136,440   485,981 
Net Increase in Cash and Cash Equivalents  179   1,010 
Cash and Cash Equivalents at End of Period $2,089  $2,752 
  2010 2009
  (in thousands)
Cash and Cash Equivalents at Beginning of Period $1,661  $1,910 
Cash Flows from (Used for):      
 Operating Activities  (21,572)  93,470 
 Investing Activities  (277,945)  (103,382)
 Financing Activities  299,536   9,739 
Net Increase (Decrease) in Cash and Cash Equivalents  19   (173)
Cash and Cash Equivalents at End of Period $1,680  $1,737 

Operating Activities

Net Cash Flows Used for Operating Activities were $22 million in 2010.  SWEPCo produced Net Income of $31 million during the period and had a noncash expense item of $33 million for Depreciation and Amortization, offset by a $29 million increase in the deferral of Property Taxes.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The activity in working capital relates to a number of items.  The $46 million outflow from Accounts Payable was primarily due to timing differences for payments of items accrued at December 31, 2009.  The $39 million inflow from Accrued Taxes, N et was the result of an increase in accruals related to property tax.  The $17 million inflow from Fuel, Materials and Supplies was primarily due to a reduction in coal inventory and a decrease in the average cost per ton.  The $16 million outflow from Accrued Interest was primarily due to the timing of interest payments in relation to the accruals for payments.

Net Cash Flows from Operating Activities were $336$93 million in 2009.  SWEPCo produced Net Income of $107$12 million during the period and had a noncash itemsexpense item of $109$37 million for Depreciation and Amortization, partially offset by $32a $30 million increase in Allowance for Equity Funds Used During Constructionthe deferral of Property Taxes and $21$27 million increase in Deferred Income Taxes.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The activity in working capital relates to a number of items.  The $81$95 million inflow from Accounts Receivable, Net was primarily due to the receipt of payment for SIA from the AEP East companies.  Th e $59 million inflow from Accrued Taxes, Net was the result of increased accruals related to income and property taxes.  The $53$50 million outflow from Other Current Liabilities was due to a decrease in check clearing,checks outstanding, a refund to wholesale customers for the SIA and payments of employee-related expenses.  The $50 million inflow from Accrued Taxes, Net was the result of an increase in accruals related to federal and property tax.  The $25 million inflow from Accounts Payable was primarily due to increases related to accruals related to tax payments partially offset for a decrease in customer accounts factored, net.  The $20 million outflow from Accrued Interest was primarily due to increased long-term debt outstanding as well as the timing betweenof interest payments in relation to the accruals and payments for senior unsecured notes.payments.  The $62$27 million inflow from Fuel Over/Under-Recovery, Net was the result of a surcharge to customers in Texas for under-recovered fuel cost and a decrease in fuel costs.

Net Cash Flows from Operating Activities were $135 millioncosts in 2008.  SWEPCo produced Net Income of $69 million during the period and had a noncash expense item of $109 million for Depreciation and Amortization and $37 million for Deferred Income Taxes.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The activity in working capital relates to a number of items.  The $47 million inflow from Accounts Receivable, Net was primarily duerelation to the assignmentrecovery of certain ERCOT contracts to an affiliate company.  The $35 million outflowthese costs from Accounts Payable was primarily due to a decrease in purchased power payables.  The $29 million inflow from Accrued Taxes, Net was due to a refund for the 2007 overpayment of federal income taxes.  The $99 million outflow from Fuel Over/Under-Recovery, Net was the result of higher fuel costs.customers.

Investing Activities

Net Cash Flows Used for Investing Activities during 2010 and 2009 and 2008 were $472$278 million and $619$103 million, respectively.  Construction Expenditures of $470$89 million and $424$170 million in 20092010 and 2008,2009, respectively, were primarily related to new generation projects at the Turk Plant and Stall Unit.  SWEPCo’s net increase inDuring 2010, SWEPCo increased loans to the Utility Money Pool duringby $187 million.  During 2009, and 2008 were $107 million and $196 million, respectively.  Proceeds from Sales of AssetsSWEPCo increased loans to the Utility Money Pool by $38 million.  These outflows in 2009 primarily includeswere partially offset by $104 million in proceeds from sales of assets primarily relating to the sale of a portion of Turk Plant to joint owners.

Financing Activities

Net Cash Flows from Financing Activities were $136$300 million during 2009.  SWEPCo received2010 related to a Capital Contribution from Parent$350 million issuance of $143Senior Unsecured Notes and a $54 million issuance of Pollution Control Bonds.  These increases were partially offset by a $54 million retirement of Pollution Control Bonds and $12a $50 million from proceeds on sale leasebackretirement of a utility property.Notes Payable – Affiliated.

Net Cash Flows from Financing Activities were $486$10 million during 2008.  SWEPCo issued $400 million of Senior Unsecured Notes.2009.  SWEPCo received a Capital Contributioncapital contributions from the Parent of $100 million.  SWEPCo retired $46$18 million and had a net decrease of Nonaffiliated Long-term Debt.

Financing Activity$3 million in borrowings from the Utility Money Pool.

Long-term debt issuances and principal payments maderetirements during the first ninethree months of 20092010 were:

Issuances

None
  
Principal
Amount
 Interest Due
Type of Debt  Rate Date
  (in thousands) (%)  
Senior Unsecured Notes $350,000  6.20 2040
Pollution Control Bonds         53,500   3.25  2015

Principal PaymentsRetirements
 
Principal
Amount Paid
 Interest Due 
Principal
Amount Paid
 Interest Due
Type of Debt  Rate Date Rate Date
 (in thousands) (%)   (in thousands) (%)  
Notes Payable – Nonaffiliated $3,304  4.47 2011
Notes Payable – Affiliated $50,000  4.45 2010
Pollution Control Bonds   53,500   Variable  2019


Liquidity

The financial markets were volatile at both a global and domestic level.  The credit situation appears to have improved but could impact SWEPCo’s future operations and ability to issue debt at reasonable interest rates.

SWEPCo participates in the Utility Money Pool, which provides access to AEP’s liquidity.  SWEPCo relies upon cash flows from operations and access to the Utility Money Pool to fund current operations and capital expenditures.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of liquidity.
Summary Obligation InformationSUMMARY OBLIGATION INFORMATION

A summary of contractual obligations is included in the 20082009 Annual Report and has not changed significantly from year-end.year-end other than debt issuances and retirements discussed in “Cash Flow” above.

Significant FactorsREGULATORY ACTIVITY

LitigationTexas Regulatory Activity

In April 2010, a settlement was approved by the PUCT to increase SWEPCo’s base rates by approximately $15 million annually, effective May 2010, including a return on equity of 10.33%.  The settlement also allows SWEPCo a $10 million one-year surcharge rider to recover additional vegetation management costs that SWEPCo must spend within two years.

SIGNIFICANT FACTORS

REGULATORY ISSUES

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which is expected to be in-service in 2012.  SWEPCo owns 73% of the Turk Plant and Regulatory Activitywill operate the completed facility.  The Turk Plant is currently estimated to cost $1.7 billion, excluding AFUDC, with SWEPCo’s share estimated to cost $1.3 billion, excluding AFUDC.  Notices of appeal are outstanding at the Arkansas Supreme Court and the Circuit Court of Hempstead County, Arkansas.  Complaints are also outstanding at the LPSC, the Texas Court of Appeals and the Federal District Court for the Western District of Arkansas.  See “Turk Plant” section of Note 3.

LITIGATION AND ENVIRONMENTAL ISSUES

In the ordinary course of business, SWEPCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot state what the eventual outcome of these proceedings will be or what the timing of theand amount of any loss, fine or penalty may be.penalty.  Management does, however, assessassesses the probability of loss for such contingencieseach contingency and accrues a liability for cases which have a probable likelihood of loss if the loss amount can be estimated.  For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 20082009 Annual Report.  Also,Additionally, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the “Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries” section.Contingencies.  Adverse results in theset hese proceedings have the potential to materially affect SWEPCo’s net income, financial condition and cash flows.

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

Critical Accounting EstimatesCRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 20082009 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncementsbenefits.

See the “New Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of the adoption and impact 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 andAnd Qualitative Disclosures About Risk Management Activities” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for disclosures abouta discussion of risk management activities.  The following tables provide information about AEP’s risk management activities’ effect on SWEPCo.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in SWEPCo’s Condensed Consolidated Balance Sheet as of September 30, 2009 and the reasons for changes in total MTM value as compared to December 31, 2008.

Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
September 30, 2009
(in thousands)

  MTM Risk Management Contracts  Cash Flow Hedge Contracts  
Collateral
Deposits
  Total 
Current Assets $5,260  $69  $(2) $5,327 
Noncurrent Assets  462   18   -   480 
Total MTM Derivative Contract Assets  5,722   87   (2)  5,807 
                 
Current Liabilities  3,446   25   (22)  3,449 
Noncurrent Liabilities  233   -   (19)  214 
Total MTM Derivative Contract Liabilities  3,679   25   (41)  3,663 
                 
Total MTM Derivative Contract Net Assets (Liabilities) $2,043  $62  $39  $2,144 
MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2009
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2008 $2,643 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period  (1,183)
Fair Value of New Contracts at Inception When Entered During the Period (a)  - 
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period  (35)
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts  - 
Changes in Fair Value Due to Market Fluctuations During the Period (b)  41 
Changes in Fair Value Allocated to Regulated Jurisdictions (c)  577 
Total MTM Risk Management Contract Net Assets  2,043 
Cash Flow Hedge Contracts  62 
Collateral Deposits  39 
Total MTM Derivative Contract Net Assets at September 30, 2009 $2,144 

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

The following table presents the maturity, by year, of net assets/liabilities to give an indication of when these MTM amounts will settle and generate or (require) cash:

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets (Liabilities)
September 30, 2009
(in thousands)

  
Remainder
2009
  2010  2011  2012  2013  
After
2013
  Total 
Level 1 (a) $56  $-  $-  $-  $-  $-  $56 
Level 2 (b)  412   1,996   (439)  12   -   -   1,981 
Level 3 (c)  4   2   -   -   -   -   6 
Total MTM Risk Management Contract Net Assets (Liabilities) $472  $1,998  $(439) $12  $-  $-  $2,043 

(a)Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.  Level 1 inputs primarily consist of exchange traded contracts that exhibit sufficient frequency and volume to provide pricing information on an ongoing basis.
(b)Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.  If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, exchange traded contracts where there was not sufficient market activity to warrant inclusion in Level 1 and OTC broker quotes that are corroborated by the same or similar transactions that have occurred in the market.
(c)Level 3 inputs are unobservable inputs for the asset or liability.  Unobservable inputs shall be used to measure fair value to the extent that the observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.  Level 3 inputs primarily consist of unobservable market data or are valued based on models and/or assumptions.

Credit Risk

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

See Note 8 for further information regarding MTM risk management contracts, cash flow hedging, accumulated other comprehensive income, credit risk and collateral triggering events.

VaR Associated with Risk Management Contracts

Management uses a risk measurement model, which calculates Value at Risk (VaR) to measure commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period.  Based on this VaR analysis, at September 30, 2009, a near term typical change in commodity prices is not expected to have a material effect on net income, cash flows or financial condition.

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

Nine Months Ended    Twelve Months Ended
September 30, 2009    December 31, 2008
(in thousands)    (in thousands)
End High Average Low    End High Average Low
$15 $49 $19 $6    $8 $220 $62 $8

Management back-tests its VaR results against performance due to actual price moves.  Based on the assumed 95% confidence interval, the performance due to actual price moves would be expected to exceed the VaR at least once every 20 trading days.  Management’s back-testing results show that its actual performance exceeded VaR far fewer than once every 20 trading days.  As a result, management believes SWEPCo’s VaR calculation is conservative.

As SWEPCo’s VaR calculation captures recent price moves, management also performs regular stress testing of the portfolio to understand SWEPCo’s exposure to extreme price moves.  Management employs a historical-based method whereby the current portfolio is subjected to actual, observed price moves from the last four years in order to ascertain which historical price moves translated into the largest potential MTM loss.  Management then researches the underlying positions, price moves and market events that created the most significant exposure.

Interest Rate Risk

Management utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure.  EaR statistically quantifies the extent to which SWEPCo’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  As calculated on SWEPCo’s debt outstanding as of September 30, 2009, the estimated EaR on SWEPCo’s debt portfolio for the following twelve months was $733 thousand.



 
 
 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30,March 31, 2010 and 2009 and 2008
(in thousands)
(Unaudited)

 Three Months Ended  Nine Months Ended 
 2009  2008  2009  2008  2010 2009
REVENUES                
Electric Generation, Transmission and Distribution $392,616  $489,014  $1,021,991  $1,200,356  $333,078  $302,383 
Sales to AEP Affiliates  9,420   11,508   23,470   42,692  9,333  8,344 
Lignite Revenues – Nonaffiliated  12,334   11,470   30,572   31,661  -  10,720 
Other Revenues  604   471   1,525   1,164   393   355 
TOTAL REVENUES  414,974   512,463   1,077,558   1,275,873   342,804   321,802 
                    
EXPENSES                    
Fuel and Other Consumables Used for Electric Generation  161,879   197,474   405,329   462,282  122,888  126,315 
Purchased Electricity for Resale  30,413   50,449   85,149   145,097  41,886  24,397 
Purchased Electricity from AEP Affiliates  6,865   36,170   30,395   108,542  9,752  13,010 
Other Operation  64,686   64,377   178,456   186,713  58,253  54,204 
Maintenance  17,267   33,694   67,283   88,854  17,419  26,702 
Depreciation and Amortization  36,714   35,842   109,065   108,875  33,243  36,792 
Taxes Other Than Income Taxes  14,127   12,623   44,995   45,747   15,895   15,389 
TOTAL EXPENSES  331,951   430,629   920,672   1,146,110   299,336   296,809 
                    
OPERATING INCOME  83,023   81,834   156,886   129,763  43,468  24,993 
                    
Other Income (Expense):                    
Interest Income  388   5,417   1,205   7,834  79  454 
Allowance for Equity Funds Used During Construction  12,932   4,152   31,706   10,167  15,517  6,405 
Interest Expense  (16,605)  (22,659)  (51,894)  (57,071)  (18,544)  (16,299)
                    
INCOME BEFORE INCOME TAX EXPENSE  79,738   68,744   137,903   90,693 
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS 40,520  15,553 
                    
Income Tax Expense  14,680   20,353   25,367   21,717  10,156  3,853 
                
INCOME BEFORE EXTRAORDINARY LOSS  65,058   48,391   112,536   68,976 
                
EXTRAORDINARY LOSS, NET OF TAX  -   -   (5,325)  - 
Equity Earnings of Unconsolidated Subsidiaries  719   - 
                    
NET INCOME  65,058   48,391   107,211   68,976  31,083  11,700 
                    
Less: Net Income Attributable to Noncontrolling Interest  1,022   976   2,971   2,870   1,151   1,137 
                    
NET INCOME ATTRIBUTABLE TO SWEPCo SHAREHOLDERS  64,036   47,415   104,240   66,106  29,932  10,563 
                    
Less: Preferred Stock Dividend Requirements  58   58   172   172   57   57 
                    
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER $63,978  $47,357  $104,068  $65,934  $29,875  $10,506 

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.





 
 
 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the NineThree Months Ended September 30,March 31, 2010 and 2009 and 2008
(in thousands)
(Unaudited)

  SWEPCo Common Shareholder       
  Common Stock  Paid-in Capital  
Retained
Earnings
  
Accumulated
Other
Comprehensive
Income (Loss)
  
Noncontrolling
Interest
  Total 
                   
TOTAL EQUITY – DECEMBER 31, 2007 $135,660  $330,003  $523,731  $(16,439) $1,687  $974,642 
                         
EITF 06-10 Adoption, Net of Tax of $622          (1,156)          (1,156)
SFAS 157 Adoption, Net of Tax of $6          10           10 
Capital Contribution from Parent      100,000               100,000 
Common Stock Dividends – Nonaffiliated                  (4,266)  (4,266)
Preferred Stock Dividends          (172)          (172)
SUBTOTAL – EQUITY                      1,069,058 
                         
COMPREHENSIVE INCOME                        
Other Comprehensive Income (Loss), Net of Taxes:                        
Cash Flow Hedges, Net of Tax of $65              (127)  7   (120)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $380              706       706 
NET INCOME          66,106       2,870   68,976 
TOTAL COMPREHENSIVE INCOME                      69,562 
                         
TOTAL EQUITY – SEPTEMBER 30, 2008 $135,660  $430,003  $588,519  $(15,860) $298  $1,138,620 
                         
TOTAL EQUITY – DECEMBER 31, 2008 $135,660  $530,003  $615,110  $(32,120) $276  $1,248,929 
                         
Capital Contribution from Parent      142,500               142,500 
Common Stock Dividends – Nonaffiliated                  (2,886)  (2,886)
Preferred Stock Dividends          (172)          (172)
Other Changes in Equity      2,476   (2,476)          - 
SUBTOTAL – EQUITY                      1,388,371 
                         
COMPREHENSIVE INCOME                        
Other Comprehensive Income, Net of Taxes:                        
Cash Flow Hedges, Net of Tax of $421              782       782 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $8,919              16,563       16,563 
NET INCOME          104,240       2,971   107,211 
TOTAL COMPREHENSIVE INCOME                      124,556 
                         
TOTAL EQUITY – SEPTEMBER 30, 2009 $135,660  $674,979  $716,702  $(14,775) $361  $1,512,927 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.





SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2009 and December 31, 2008
(in thousands)
(Unaudited)

  2009  2008 
CURRENT ASSETS      
Cash and Cash Equivalents $2,089  $1,910 
Advances to Affiliates  106,662   - 
Accounts Receivable:        
Customers  46,018   53,506 
Affiliated Companies  48,708   121,928 
Miscellaneous  11,275   12,052 
Allowance for Uncollectible Accounts  (25)  (135)
Total Accounts Receivable  105,976   187,351 
Fuel  91,641   100,018 
Materials and Supplies  53,705   49,724 
Risk Management Assets  5,327   8,185 
Regulatory Asset for Under-Recovered Fuel Costs  246   75,006 
Prepayments and Other Current Assets  37,068   20,147 
TOTAL CURRENT ASSETS  402,714   442,341 
         
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
Production  1,817,505   1,808,482 
Transmission  838,137   786,731 
Distribution  1,451,365   1,400,952 
Other Property, Plant and Equipment  716,747   711,260 
Construction Work in Progress  1,098,069   869,103 
Total Property, Plant and Equipment  5,921,823   5,576,528 
Accumulated Depreciation and Amortization  2,091,205   2,014,154 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET  3,830,618   3,562,374 
         
OTHER NONCURRENT ASSETS        
Regulatory Assets  251,008   210,174 
Long-term Risk Management Assets  480   1,500 
Deferred Charges and Other Noncurrent Assets  44,090   36,696 
TOTAL OTHER NONCURRENT ASSETS  295,578   248,370 
         
TOTAL ASSETS $4,528,910  $4,253,085 
  SWEPCo Common Shareholder    
  Common Stock Paid-in Capital 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Noncontrolling
Interest
 Total
                   
TOTAL EQUITY – DECEMBER 31, 2008 $135,660  $530,003  $615,110  $(32,120) $276  $1,248,929 
                   
Capital Contribution from Parent     17,500            17,500 
Common Stock Dividends – Nonaffiliated              (1,115)  (1,115)
Preferred Stock Dividends        (57)        (57)
Other Changes in Equity     2,476   (2,476)        - 
SUBTOTAL – EQUITY                 1,265,257 
                   
COMPREHENSIVE INCOME                  
Other Comprehensive Income, Net of Taxes:                  
Cash Flow Hedges, Net of Tax of $51           95      95 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $243           451      451 
NET INCOME        10,563      1,137   11,700 
TOTAL COMPREHENSIVE INCOME                 12,246 
                   
TOTAL EQUITY – MARCH 31, 2009 $135,660  $549,979  $623,140  $(31,574) $298  $1,277,503 
                   
TOTAL EQUITY – DECEMBER 31, 2009 $135,660  $674,979  $726,478  $(12,991) $31  $1,524,157 
                   
Common Stock Dividends – Nonaffiliated              (809)  (809)
Preferred Stock Dividends        (57)        (57)
SUBTOTAL – EQUITY                 1,523,291 
                   
COMPREHENSIVE INCOME                  
Other Comprehensive Income, Net of Taxes:                  
Cash Flow Hedges, Net of Tax of $42           88      88 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $127           
 
235 
     235 
NET INCOME        29,932      1,151   31,083 
TOTAL COMPREHENSIVE INCOME                 31,406 
                   
TOTAL EQUITY – MARCH 31, 2010 $135,660  $674,979  $756,353  $(12,668) $373  $1,554,697 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


 
 
 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITYASSETS
September 30, 2009March 31, 2010 and December 31, 20082009
(in thousands)
(Unaudited)

  2009  2008 
CURRENT LIABILITIES (in thousands) 
Advances from Affiliates $-  $2,526 
Accounts Payable:        
General  114,990   133,538 
Affiliated Companies  77,565   51,040 
Short-term Debt – Nonaffiliated  5,273   7,172 
Long-term Debt Due Within One Year – Nonaffiliated  4,406   4,406 
Long-term Debt Due Within One Year – Affiliated  50,000   - 
Risk Management Liabilities  3,449   6,735 
Customer Deposits  39,884   35,622 
Accrued Taxes  83,771   33,744 
Accrued Interest  16,831   36,647 
Provision for Revenue Refund  28,507   54,100 
Other Current Liabilities  61,419   102,535 
TOTAL CURRENT LIABILITIES  486,095   468,065 
         
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated  1,420,746   1,423,743 
Long-term Debt – Affiliated  -   50,000 
Long-term Risk Management Liabilities  214   516 
Deferred Income Taxes  427,181   403,125 
Regulatory Liabilities and Deferred Investment Tax Credits  334,570   335,749 
Asset Retirement Obligations  53,789   53,433 
Employment Benefits and Pension Obligations  122,309   117,772 
Deferred Credits and Other Noncurrent Liabilities  166,382   147,056 
TOTAL NONCURRENT LIABILITIES  2,525,191   2,531,394 
         
TOTAL LIABILITIES  3,011,286   2,999,459 
         
Cumulative Preferred Stock Not Subject to Mandatory Redemption  4,697   4,697 
         
Commitments and Contingencies (Note 4)        
         
EQUITY        
Common Stock – Par Value – $18 Per Share:        
Authorized – 7,600,000 Shares        
Outstanding – 7,536,640 Shares  135,660   135,660 
Paid-in Capital  674,979   530,003 
Retained Earnings  716,702   615,110 
Accumulated Other Comprehensive Income (Loss)  (14,775)  (32,120)
TOTAL COMMON SHAREHOLDER’S EQUITY  1,512,566   1,248,653 
         
Noncontrolling Interest  361   276 
         
TOTAL EQUITY  1,512,927   1,248,929 
         
TOTAL LIABILITIES AND EQUITY $4,528,910  $4,253,085 
  2010 2009
CURRENT ASSETS      
Cash and Cash Equivalents $1,680  $1,661 
Advances to Affiliates  238,817   34,883 
Accounts Receivable:      
Customers  31,172   46,657 
Affiliated Companies  25,390   19,542 
Miscellaneous  15,376   9,952 
Allowance for Uncollectible Accounts  (1)  (64)
Total Accounts Receivable  71,937   76,087 
Fuel
  (March 31, 2010 amount includes $31,636 related to Sabine)
  99,740   121,453 
Materials and Supplies  45,987   54,484 
Risk Management Assets  2,055   3,049 
Deferred Income Tax Benefits  12,731   13,820 
Accrued Tax Benefits  10,203   16,164 
Regulatory Asset for Under-Recovered Fuel Costs  10,291   1,639 
Prepayments and Other Current Assets  25,251   20,503 
TOTAL CURRENT ASSETS  518,692   343,743 
       
PROPERTY, PLANT AND EQUIPMENT      
Electric:      
Production  1,837,260   1,837,318 
Transmission  875,469   870,069 
Distribution  1,457,777   1,447,559 
Other Property, Plant and Equipment
(March 31, 2010 amount includes $229,220 related to Sabine)
  638,983   733,310 
Construction Work in Progress  1,253,122   1,176,639 
Total Property, Plant and Equipment  6,062,611   6,064,895 
Accumulated Depreciation and Amortization
(March 31, 2010 amount includes $88,067 related to Sabine)
  2,049,962   2,086,333 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET  4,012,649   3,978,562 
       
OTHER NONCURRENT ASSETS      
Regulatory Assets  283,964   268,165 
Long-term Risk Management Assets  244   84 
Deferred Charges and Other Noncurrent Assets  91,196   49,479 
TOTAL OTHER NONCURRENT ASSETS  375,404   317,728 
       
TOTAL ASSETS $4,906,745  $4,640,033 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
March 31, 2010 and December 31, 2009
(Unaudited)

  2010 2009
CURRENT LIABILITIES (in thousands)
Accounts Payable:      
General $115,639  $160,870 
Affiliated Companies  58,288   59,818 
Short-term Debt – Nonaffiliated  13,218   6,890 
Long-term Debt Due Within One Year – Nonaffiliated  -   4,406 
Long-term Debt Due Within One Year – Affiliated  -   50,000 
Risk Management Liabilities  989   844 
Customer Deposits  41,815   41,269 
Accrued Taxes  54,966   24,720 
Accrued Interest  17,661   33,179 
Obligations Under Capital Leases  12,670   14,617 
Regulatory Liability for Over-Recovered Fuel Costs  12,852   13,762 
Provision for SIA Refund  21,003   19,307 
Other Current Liabilities  40,891   71,781 
TOTAL CURRENT LIABILITIES  389,992   501,463 
       
NONCURRENT LIABILITIES      
Long-term Debt – Nonaffiliated  1,769,331   1,419,747 
Long-term Risk Management Liabilities  632   221 
Deferred Income Taxes  498,283   485,936 
Regulatory Liabilities and Deferred Investment Tax Credits  346,091   333,935 
Asset Retirement Obligations  48,732   60,562 
Employee Benefits and Pension Obligations  123,616   125,956 
Obligations Under Capital Leases  119,562   134,044 
Deferred Credits and Other Noncurrent Liabilities  51,112   49,315 
TOTAL NONCURRENT LIABILITIES  2,957,359   2,609,716 
       
TOTAL LIABILITIES  3,347,351   3,111,179 
       
Cumulative Preferred Stock Not Subject to Mandatory Redemption  4,697   4,697 
       
Rate Matters (Note 3)      
Commitments and Contingencies (Note 4)      
       
EQUITY      
Common Stock – Par Value – $18 Per Share:      
Authorized – 7,600,000 Shares      
Outstanding – 7,536,640 Shares  135,660   135,660 
Paid-in Capital  674,979   674,979 
Retained Earnings  756,353   726,478 
Accumulated Other Comprehensive Income (Loss)  (12,668)  (12,991)
TOTAL COMMON SHAREHOLDER’S EQUITY  1,554,324   1,524,126 
       
Noncontrolling Interest  373   31 
       
TOTAL EQUITY  1,554,697   1,524,157 
       
TOTAL LIABILITIES AND EQUITY $4,906,745  $4,640,033 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



 
 
 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the NineThree Months Ended September 30,March 31, 2010 and 2009 and 2008
(in thousands)
(Unaudited)

  2009  2008 
OPERATING ACTIVITIES      
Net Income $107,211  $68,976 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:        
Depreciation and Amortization  109,065   108,875 
Deferred Income Taxes  (20,571)  37,162 
Extraordinary Loss, Net of Tax  5,325   - 
Allowance for Equity Funds Used During Construction  (31,706)  (10,167)
Mark-to-Market of Risk Management Contracts  510   7,905 
Fuel Over/Under-Recovery, Net  61,880   (98,928)
Change in Other Noncurrent Assets  13,498   (211)
Change in Other Noncurrent Liabilities  4,539   (15,619)
Changes in Certain Components of Working Capital:        
Accounts Receivable, Net  81,322   46,835 
Fuel, Materials and Supplies  4,396   (16,665)
Accounts Payable  24,584   (34,819)
Accrued Taxes, Net  50,027   29,271 
Accrued Interest  (19,816)  5,498 
Other Current Assets  (1,017)  6,929 
Other Current Liabilities  (53,325)  (526)
Net Cash Flows from Operating Activities  335,922   134,516 
         
INVESTING ACTIVITIES        
Construction Expenditures  (470,379)  (424,092)
Change in Advances to Affiliates, Net  (106,662)  (195,628)
Proceeds from Sales of Assets  105,500   483 
Other Investing Activities  (642)  (250)
Net Cash Flows Used for Investing Activities  (472,183)  (619,487)
         
FINANCING ACTIVITIES        
Capital Contribution from Parent  142,500   100,000 
Issuance of Long-term Debt – Nonaffiliated  -   437,113 
Change in Short-term Debt, Net – Nonaffiliated  (1,899)  9,234 
Change in Advances from Affiliates, Net  (2,526)  (1,565)
Retirement of Long-term Debt – Nonaffiliated  (3,304)  (45,939)
Principal Payments for Capital Lease Obligations  (7,853)  (8,424)
Proceeds from Sale/Leaseback  12,222   - 
Dividends Paid on Common Stock – Nonaffiliated  (2,971)  (4,266)
Dividends Paid on Cumulative Preferred Stock  (172)  (172)
Other Financing Activities  443   - 
Net Cash Flows from Financing Activities  136,440   485,981 
         
Net Increase in Cash and Cash Equivalents  179   1,010 
Cash and Cash Equivalents at Beginning of Period  1,910   1,742 
Cash and Cash Equivalents at End of Period $2,089  $2,752 

 2010 2009
OPERATING ACTIVITIES      
Net Income $31,083  $11,700 
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:      
Depreciation and Amortization  33,243   36,792 
Deferred Income Taxes  477   (27,042)
Allowance for Equity Funds Used During Construction  (15,517)  (6,405)
Mark-to-Market of Risk Management Contracts  1,324   (752)
Property Taxes  (28,569)  (29,792)
Fuel Over/Under-Recovery, Net  (9,565)  26,786 
Change in Other Noncurrent Assets  409   6,230 
Change in Other Noncurrent Liabilities  3,779   331 
Changes in Certain Components of Working Capital:      
Accounts Receivable, Net  (5,975)  94,646 
Fuel, Materials and Supplies  17,008   (4,775)
Accounts Payable  (46,408)  (2,717)
Accrued Taxes, Net  38,552   58,794 
Accrued Interest  (15,512)  (20,160)
Other Current Assets  (4,310)  326 
Other Current Liabilities  (21,591)  (50,492)
Net Cash Flows from (Used for) Operating Activities  (21,572)  93,470 
      
INVESTING ACTIVITIES      
Construction Expenditures  (88,731)  (169,603)
Change in Advances to Affiliates, Net  (187,000)  (37,649)
Proceeds from Sales of Assets  174   104,824 
Other Investing Activities  (2,388)  (954)
Net Cash Flows Used for Investing Activities  (277,945)  (103,382)
      
FINANCING ACTIVITIES      
Capital Contribution from Parent  -   17,500 
Issuance of Long-term Debt – Nonaffiliated  399,650   (15)
Borrowings from Revolving Credit Facilities  23,743   27,435 
Change in Advances from Affiliates, Net  -   (2,526)
Retirement of Long-term Debt – Nonaffiliated  (53,500)  (1,101)
Retirement of Long-term Debt – Affiliated  (50,000)  - 
Repayments to Revolving Credit Facilities  (17,415)  (28,048)
Principal Payments for Capital Lease Obligations  (2,858)  (2,334)
Dividends Paid on Common Stock – Nonaffiliated  (809)  (1,115)
Dividends Paid on Cumulative Preferred Stock  (57)  (57)
Other Financing Activities  782   - 
Net Cash Flows from Financing Activities  299,536   9,739 
      
Net Increase (Decrease) in Cash and Cash Equivalents  19   (173)
Cash and Cash Equivalents at Beginning of Period  1,661   1,910 
Cash and Cash Equivalents at End of Period $1,680  $1,737 
      
SUPPLEMENTARY INFORMATION            
Cash Paid for Interest, Net of Capitalized Amounts $82,033  $44,255  $31,789  $51,573 
Net Cash Received for Income Taxes  (6,196)  (20,835)  (1,062)  (1,117)
Noncash Acquisitions Under Capital Leases  26,175   21,807   169   1,568 
Construction Expenditures Included in Accounts Payable at September 30,  60,219   94,837 
Construction Expenditures Included in Accounts Payable at March 31,  71,395   72,331 

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 MattersNote 1
New Accounting Pronouncements and Extraordinary ItemNote 2
Rate MattersNote 3
Commitments, Guarantees and ContingenciesNote 4
Acquisition
AcquisitionsNote 5
Benefit PlansNote 6
Business SegmentsNote 7
Derivatives and HedgingNote 8
Fair Value MeasurementsNote 9
Income TaxesNote 10
Financing ActivitiesNote 11
Company-wide Staffing and Budget ReviewNote 12


 
 
 
 


INDEX TO 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 MattersAPCo, CSPCo, I&M, OPCo, PSO, SWEPCo
2.New Accounting Pronouncements and Extraordinary ItemAPCo, CSPCo, I&M, OPCo, PSO, SWEPCo
3.Rate MattersAPCo, CSPCo, I&M, OPCo, PSO, SWEPCo
4.Commitments, Guarantees and ContingenciesAPCo, CSPCo, I&M, OPCo, PSO, SWEPCo
5.AcquisitionAcquisitionsSWEPCo
6.Benefit PlansAPCo, CSPCo, I&M, OPCo, PSO, SWEPCo
7.Business SegmentsAPCo, CSPCo, I&M, OPCo, PSO, SWEPCo
8.Derivatives and HedgingAPCo, CSPCo, I&M, OPCo, PSO, SWEPCo
9.Fair Value MeasurementsAPCo, CSPCo, I&M, OPCo, PSO, SWEPCo
10.Income TaxesAPCo, CSPCo, I&M, OPCo, PSO, SWEPCo
11.Financing ActivitiesAPCo, CSPCo, I&M, OPCo, PSO, SWEPCo
12.Company-wide Staffing and Budget ReviewAPCo, CSPCo, I&M, OPCo, PSO, SWEPCo

 
 
 

1.SIGNIFICANT ACCOUNTING MATTERS

General

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

In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary.  NetThe net income for the three and nine months ended September 30, 2009March 31, 2010 is not necessarily indicative of results that may be expected for the year ending December 31, 2009.  Management reviewed subsequent events through the Registrant Subsidiaries’ Form 10-Q issuance date of October 30, 2009.  APCo’s, CSPCo’s, I&M’s and PSO’s accompanying2010.  The condensed financial statements are unaudited and should be read in conjunction with theirthe audited 20082009 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K for the year ended December 31, 20082009 as filed with the SEC on February 27, 2009.  OPCo’s and SWEPCo’s accompanying condensed financial statements are unaudited and should be read in conjunction with their audited 2008 financial statements and notes thereto, which are included in Current Report on Form 8-K as filed with the SEC on May 1, 2009.26, 2010.

Variable Interest Entities

The accounting guidance for “Variable Interest Entities” is a consolidation model that considers risk absorptionif a company has a controlling financial interest in a VIE.  A controlling financial interest will have both (a) the power to direct the activities of a variable interest entity (VIE), also referredVIE that most significantly impact the VIE’s economic performance and (b) the obligation to as variability.absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.  Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.”  In determining whether they are the primary beneficiary of a VIE, each Registrant Subsidiary considers factors such as equity at risk, the amount of the VIE’s variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE and other factors.  Management believes that significant assumptions and judgments were applied consistently.  In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required.  Also, see “ASU 2009-17 ‘Consolidations’ ” section of Note 2 for a discussion of the impact of new accounting guidance effective January 1, 2010.

SWEPCo is currently the primary beneficiary of Sabine and DHLC.  OPCoSabine.  As of January 1, 2010, SWEPCo is no longer the primary beneficiary of JMG.DHLC as defined by new accounting guidance for “Variable Interest Entities.”  I&M is currently the primary beneficiary of DCC Fuel LLC (DCC Fuel).  APCo, CSPCo, I&M, OPCo, PSO and SWEPCo each hold a significant variable interest in AEPSC.  I&M and CSPCo each hold a significant variable interest in AEGCo.  SWEPCo holds a significant variable interest in DHLC.

Sabine is a mining operator providing mining services to SWEPCo.  SWEPCo has no equity investment in Sabine but is Sabine’s only customer.  SWEPCo guarantees the debt obligations and lease obligations of Sabine.  Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo.  The creditors of Sabine have no recourse to any AEP entity other than SWEPCo.  Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee.  In addition, SWEPCo determines how much coal will be mined for each year.  Based on these facts, management has concluded that SWEPCo is the primary beneficiarybeneficia ry and is required to consolidate Sabine.  SWEPCo’s total billings from Sabine for the three months ended September 30,March 31, 2010 and 2009 and 2008 were $34$43 million and $31 million, respectively, and for the nine months ended September 30, 2009 and 2008 were $95 million and $79$35 million, respectively.  See the tables below for the classification of Sabine’s assets and liabilities on SWEPCo’s Condensed Consolidated Balance Sheets.

DHLC is a wholly-owned subsidiary of SWEPCo.  DHLC is a mining operator whothat sells 50% of the lignite produced to SWEPCo and 50% to Cleco Corporation, a nonaffiliated company.CLECO.�� SWEPCo and Cleco CorporationCLECO share half of the executive board seats with equaland its voting rights and eachequally.  Each entity guarantees a 50% share of DHLC’s debt.  SWEPCo and Cleco CorporationCLECO equally approve DHLC’s annual budget.  The creditors of DHLC have no recourse to any AEP entity other than SWEPCo.  As SWEPCo is the sole equity owner of DHLC it receives 100% of the management fee.  Based on the structure and equity ownership,shared control of DHLC’s operations, management has concluded as of January 1, 2010 that SWEPCo is no longer the primary beneficiary and is no longer required to consolidate DHLC.  SWEPCo’s total billings from DHLC for the three months ended September 30,Ma rch 31, 2010 and 2009 and 2008 were $12$13 million and $11 million, respectively, and for the nine months ended September 30, 2009 and 2008 were $31 million and $32 million, respectively.  See the tablestable below for the classification of DHLC assets and liabilities on SWEPCo’s Condensed Consolidated Balance Sheets.Sheet at December 31, 2009 as well as SWEPCo’s investment and maximum exposure as of March 31, 2010.  As of March 31, 2010, DHLC is reported as an equity investment in Deferred Charges and Other Noncurrent Assets on SWEPCo’s Condensed Consolidated Balance Sheet.  Also, see “ASU 2009-17 ‘Consolidations’ ” section of Note 2 for discussion of impact of new accounting guidance effective January 1, 2010.

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

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
VARIABLE INTEREST ENTITIES
September 30, 2009March 31, 2010
(in millions)
 Sabine  DHLC 
ASSETS       Sabine 
Current Assets $38  $19  $51 
Net Property, Plant and Equipment  133   29   146 
Other Noncurrent Assets  30   10   34 
Total Assets $201  $58  $231 
            
LIABILITIES AND EQUITY            
Current Liabilities $27  $15  $35 
Noncurrent Liabilities  174   40   196 
Equity  -   3   - 
Total Liabilities and Equity $201  $58  $231 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
VARIABLE INTEREST ENTITIES
December 31, 2008
(in millions)
  Sabine  DHLC 
ASSETS      
Current Assets $33  $22 
Net Property, Plant and Equipment  117   33 
Other Noncurrent Assets  24   11 
Total Assets $174  $66 
         
LIABILITIES AND EQUITY        
Current Liabilities $32  $18 
Noncurrent Liabilities  142   44 
Equity  -   4 
Total Liabilities and Equity $174  $66 

OPCo has a lease agreement with JMG to finance OPCo’s Flue Gas Desulfurization (FGD) system installed on OPCo’s Gavin Plant.  The PUCO approved the original lease agreement between OPCo and JMG.  JMG owns and leases the FGD to OPCo.  JMG is considered a single-lessee leasing arrangement with only one asset.  OPCo’s lease payments are the only form of repayment associated with JMG’s debt obligations even though OPCo does not guarantee JMG’s debt.  The creditors of JMG have no recourse to any AEP entity other than OPCo for the lease payment.  Based on the structure of the entity, management has concluded OPCo is the primary beneficiary and is required to consolidate JMG.  In April 2009, OPCo paid JMG $58 million which was used to retire certain long-term debt of JMG.  While this payment was not contractually required, OPCo made this payment in anticipation of purchasing the outstanding equity of JMG.  In July 2009, OPCo purchased all of the outstanding equity ownership of JMG for $28 million resulting in an elimination of OPCo’s Noncontrolling Interest related to JMG and an increase in Common Shareholder’s Equity of $54 million.  In August and September 2009, JMG reacquired $218 million of auction rate debt, funded by OPCo capital contributions to JMG.  These reacquisitions were not contractually required.  JMG is a wholly-owned subsidiary of OPCo with a capital structure of 85% equity, 15% debt.

OPCo’s intent is to cancel the lease and dissolve JMG in December 2009.  The assets and liabilities of JMG will remain incorporated with OPCo’s business.  OPCo’s total billings from JMG for the three months ended September 30, 2009 and 2008 were $1 million and $13 million, respectively, and for the nine months ended September 30, 2009 and 2008 were $50 million and $39 million, respectively.  See the tables below for the classification of JMG’s assets and liabilities on OPCo’s Condensed Consolidated Balance Sheets.

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

OHIO POWER COMPANY CONSOLIDATED
VARIABLE INTEREST ENTITY
September 30, 2009
(in millions)
 JMG 
ASSETS    Sabine  DHLC 
Current Assets $18  $51  $8 
Net Property, Plant and Equipment  407   149   44 
Other Noncurrent Assets  -   35   11 
Total Assets $425  $235  $63 
            
LIABILITIES AND EQUITY            
Current Liabilities $20  $36  $17 
Noncurrent Liabilities  46   199   38 
Equity  359   -   8 
Total Liabilities and Equity $425  $235  $63 

OHIO POWER COMPANY CONSOLIDATED
VARIABLE INTEREST ENTITY
December 31, 2008
(SWEPCo’s investment in millions)
  JMG 
ASSETS   
Current Assets $11 
Net Property, Plant and Equipment  423 
Other Noncurrent Assets  1 
Total Assets $435 
     
LIABILITIES AND EQUITY    
Current Liabilities $161 
Noncurrent Liabilities  257 
Equity  17 
Total Liabilities and Equity $435 
DHLC was:

 March 31, 2010 
 As Reported on   
 the Consolidated Maximum 
 Balance Sheet Exposure 
 (in millions) 
Capital Contribution from Parent $7  $7 
Retained Earnings  1   1 
SWEPCo’s Guarantee of Debt  -   44 
         
Total Investment in DHLC $8  $52 
In September 2009, I&M entered into a nuclear fuel sale and leaseback transaction with DCC Fuel.  DCC Fuel was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.  DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions.  DCC Fuel is a single-lessee leasing arrangement with only one asset and is capitalized with all debt.  Payments on the lease will be made semi-annually on April 1 and October 1, beginning in April 2010.  As of September 30, 2009, no payments have been made by I&M to DCC Fuel.  The lease was recorded as a capital lease on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the 48 month lease term.  Based on the structure,I&M’s control of DCC Fuel, management has concluded that I&M is the primaryprimar y beneficiary and is required to consolidate DCC Fuel.  The capital lease is eliminated upon consolidation.  See the tables below for the classification of DCC Fuel’s assets and liabilities on I&M’s Condensed Consolidated Balance Sheets.

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

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIESCONSOLIDATED
VARIABLE INTEREST ENTITIESENTITY
September 30,March 31, 2010 and December 31, 2009
(in millions)
DCC Fuel
ASSETS
Current Assets$38 
Net Property, Plant and Equipment101 
Other Noncurrent Assets65 
Total Assets$204 
LIABILITIES AND EQUITY
Current Liabilities$38 
Noncurrent Liabilities166 
Equity- 
Total Liabilities and Equity$204 

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
December 31, 2008
(in millions)
DCC Fuel
ASSETS
Current Assets$- 
Net Property, Plant and Equipment- 
Other Noncurrent Assets- 
Total Assets$- 
LIABILITIES AND EQUITY
Current Liabilities$- 
Noncurrent Liabilities- 
Equity- 
Total Liabilities and Equity$- 
  DCC Fuel 
ASSETS 2010  2009 
Current Assets $56  $47 
Net Property, Plant and Equipment  77   89 
Other Noncurrent Assets  49   57 
Total Assets $182  $193 
         
LIABILITIES AND EQUITY        
Current Liabilities $41  $39 
Noncurrent Liabilities  141   154 
Equity  -   - 
Total Liabilities and Equity $182  $193 

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

Total AEPSC billings to the Registrant Subsidiaries were as follows:

 Three Months Ended September 30,  Nine Months Ended September 30, 
 2009  2008  2009  2008  Three Months Ended March 31, 
Company (in millions)  2010  2009 
 (in millions) 
APCo $50  $62  $146  $179  $59  $50 
CSPCo  31   34   91   98   35   29 
I&M  32   37   93   109   34   29 
OPCo  43   52   130   151   49   41 
PSO  21   28   64   87   24   21 
SWEPCo  35   35   94   101   35   29 

The carrying amount and classification of variable interest in AEPSC’s accounts payable as of March 31, 2010 and December 31, 2009 are as follows:

September 30, 2009 December 31, 2008 2010 2009 
As Reported in the Maximum As Reported in the Maximum As Reported in the Maximum As Reported in the Maximum 
Balance Sheet Exposure Balance Sheet Exposure Balance Sheet Exposure Balance Sheet Exposure 
Company(in millions) 
(in millions) 
APCo $20  $20  $27  $27  $23  $23  $23  $23 
CSPCo  12   12   15   15   15   15   13   13 
I&M  13   13   14   14   14   14   13   13 
OPCo  17   17   21   21   20   20   18   18 
PSO  9   9   10   10   9   9   9   9 
SWEPCo  13   13   14   14   14   14   14   14 

AEGCo, a wholly-owned subsidiary of AEP, is consolidated by AEP.  AEGCo owns a 50% ownership interest in Rockport Plant Unit 1, leases a 50% interest in Rockport Plant Unit 2 and owns 100% of the Lawrenceburg Generating Station.  AEGCo sells all the output from the Rockport Plant to I&M and KPCo.  In May 2007, AEGCo began leasing the Lawrenceburg Generating Station to CSPCo.  AEP guarantees all the debt obligations of AEGCo.  I&M and CSPCo are considered to have a significant interest in AEGCo due to these transactions.  I&M and CSPCo are exposed to losses to the extent they cannot recover the costs of AEGCo through their normal business operations.  Due to the natureAEP management’s control over AEGCo no subsidiary of the AEP Power Pool, there is a sharing of the cost of Rockport and Lawrenceburg Plants such that no member of the AEP Power Pool is the primary beneficiary of AEGCo’s Rockport or Lawrenceburg Plants.AEGCo.   In the event AEGCo would require financing or other support outside the billings to I&M, CSPCo and KPCo, this financing would be provided by AEP.  For additional information regarding AEGCo’s lease, seeSee “Rockport Lease” section of Note 13 in the 20082009 Annual Report.Report for additional information regarding AEGCo’s lease.

Total billings from AEGCo wereare as follows:

Three Months Ended September 30, Nine Months Ended September 30, Three Months Ended March 31, 
2009 2008 2009 2008 2010 2009 
Company(in millions) 
(in millions) 
CSPCo $28  $47  $60  $96  $15  $17 
I&M  59   65   183   181   56   63 

The carrying amount and classification of variable interest in AEGCo’s accounts payable as of March 31, 2010 and December 31, 2009 are as follows:

September 30, 2009 December 31, 2008 March 31, 2010 December 31, 2009 
As Reported in   As Reported in   As Reported in the   As Reported in the   
the Consolidated Maximum the Consolidated Maximum Consolidated Maximum Consolidated Maximum 
Balance Sheet Exposure Balance Sheet Exposure Balance Sheet Exposure Balance Sheet Exposure 
Company(in millions) 
(in millions) 
CSPCo $6  $6  $5  $5  $6  $6  $6  $6 
I&M  20   20   23   23   18   18   23   23 

Revenue Recognition – Traditional Electricity Supply and DemandRelated Party Transactions

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

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

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

CSPCo and OPCo Revised Depreciation RatesDHLC

Effective January 1, 2009, CSPCo2010, SWEPCo deconsolidated DHLC due to the adoption of new accounting guidance.  See “ASU 2009-17 ‘Consolidations’ ” section of Note 2.  DHLC sells 50% of its lignite mining output to SWEPCo and OPCo revised book depreciation rates for generating plants consistent with a recently completed depreciation study.  OPCo’s overall higher depreciation rates primarily relatedthe other 50% to shortened depreciable lives for certain OPCo generating facilities.  In comparing 2009CLECO.  SWEPCo purchased $12.9 million of lignite from DHLC and 2008, the changerecorded these costs in depreciation rates resulted in a net increase (decrease) in depreciation expense of:Fuel on its Condensed Consolidated Balance Sheet at March 31, 2010.

AEP Power Pool Purchases from OVEC

  Total Depreciation Expense Variance 
  Three Months Ended   Nine Months Ended 
  September 30,   September 30, 
   2009/2008   2009/2008 
  (in thousands) 
CSPCo $ (4,430)  $  (13,104)
OPCo      17,810       52,040 
In January 2010, the AEP Power Pool began purchasing power from OVEC to serve off-system sales and retail sales through June 2010.  Purchases serving off-system sales are reported net as a reduction in Electric Generation, Transmission and Distribution revenues and purchases serving retail sales are reported in Purchased Electricity for Resale expenses on the respective income statements.  The following table shows the amounts recorded for the three months ended March 31, 2010:

  Three Months Ended March 31, 2010 
  Reported in  Reported in 
Company Revenues  Expenses 
  (in thousands) 
APCo $(2,895) $2,194 
CSPCo  (1,576)  1,148 
I&M  (1,589)  1,158 
OPCo  (1,816)  1,330 

Adjustments to Reported Cash Flows

In the Financing Activities section of SWEPCo’s Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2009, SWEPCo corrected the presentation of borrowings on lines of credit of $28 million from Change in Short-term Debt, Net to Borrowings from Revolving Credit Facilities.  SWEPCo also corrected the presentation of repayments on lines of credit of $28 million for the three months ended March 31, 2009 to Repayments to Revolving Credit Facilities from Change in Short-term Debt, Net.  The correction to present borrowings and repayments on lines of credit on a gross basis was not material to SWEPCo’s financial statements and had no impact on SWEPCo’s previously reported net income, changes in shareholder’s equity, financial position or net cash flows from financing activities.

2.NEW ACCOUNTING PRONOUNCEMENTS AND EXTRAORDINARY ITEM

NEW ACCOUNTING PRONOUNCEMENTS

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

PronouncementsPronouncement Adopted During 2009The First Quarter of 2010

The following standards werestandard was effective during the first nine monthsquarter of 2009.2010.  Consequently, its impact is reflected in the financial statements and footnotes reflect theirstatements.  The following paragraphs discuss its impact.

SFAS 141 (revised 2007) “Business Combinations” (SFAS 141R)ASU 2009-17 “Consolidations” (ASU 2009-17)

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

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

The Registrant Subsidiaries adopted SFAS 141R, including the FSP, effective January 1, 2009.  It is effective prospectively for business combinations with an acquisition date on or after January 1, 2009.  The Registrant Subsidiaries had no business combinations in 2009.  The Registrant Subsidiaries will apply it to any future business combinations.  SFAS 141R is included in the “Business Combination” accounting guidance.

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

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

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

OPCo:
·Reclassifies Interest Expense of $233 thousand and $1.1 million for the three and nine months ended September 30, 2008 as Net Income Attributable to Noncontrolling Interest below Net Income in the presentation of Earnings Attributable to OPCo Common Shareholder in its Condensed Consolidated Statements of Income.
·Reclassifies Minority Interest of $16.8 million as of December 31, 2008 as Noncontrolling Interest in Total Equity on its Condensed Consolidated Balance Sheets.
·Separately reflects changes in Noncontrolling Interest in its Condensed Consolidated Statements of Changes in Equity and Comprehensive Income (Loss).
·Reclassifies dividends paid to noncontrolling interests of $1.1 million for the nine months ended September 30, 2008 from Operating Activities to Financing Activities on the Condensed Consolidated Statements of Cash Flows.

SWEPCo:
·Reclassifies Minority Interest Expense of $976 thousand and $2.9 million for the three and nine months ended September 30, 2008 as Net Income Attributable to Noncontrolling Interest below Net Income in the presentation of Earnings Attributable to SWEPCo Common Shareholder in its Condensed Consolidated Statements of Income.
·Reclassifies Minority Interest of $276 thousand as of December 31, 2008 as Noncontrolling Interest in Total Equity on its Condensed Consolidated Balance Sheets.
·Separately reflects changes in Noncontrolling Interest on the Condensed Consolidated Statements of Changes in Equity and Comprehensive Income (Loss).
·Reclassifies dividends paid to noncontrolling interests of $4.3 million for the nine months ended September 30, 2008 from Operating Activities to Financing Activities on the Condensed Consolidated Statements of Cash Flows.

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

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

The Registrant Subsidiaries adopted SFAS 161 effective January 1, 2009.  This standard increased the disclosures related to derivative instruments and hedging activities.  See Note 8.  SFAS 161 is included in the “Derivatives and Hedging” accounting guidance.

SFAS 165 “Subsequent Events” (SFAS 165)

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

The Registrant Subsidiaries adopted this standard effective second quarter of 2009.  The standard increased disclosure by requiring disclosure of the date through which subsequent events have been reviewed.  The standard did not change management’s procedures for reviewing subsequent events.  SFAS 165 is included in the “Subsequent Events” accounting guidance.
SFAS 168 “The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles” (SFAS 168)
In June 2009, the FASB issued SFAS 168 establishing the FASB Accounting Standards CodificationTM as the authoritative source of accounting principles for preparation of financial statements and reporting in conformity with GAAP by nongovernmental entities.

The Registrant Subsidiaries adopted SFAS 168 effective third quarter of 2009.  It required an update of all references to authoritative accounting literature.  SFAS 168 is included in the “Generally Accepted Accounting Principles” accounting guidance.
EITF Issue No. 08-5 “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement” (EITF 08-5)
In September 2008, the FASB ratified the consensus on liabilities with third-party credit enhancements when the liability is measured and disclosed at fair value.  The consensus treats the liability and the credit enhancement as two units of accounting.  Under the consensus, the fair value measurement of the liability does not include the effect of the third-party credit enhancement.  Consequently, changes in the issuer’s credit standing without the support of the credit enhancement affect the fair value measurement of the issuer’s liability.  Entities will need to provide disclosures about the existence of any third-party credit enhancements related to their liabilities.  In the period of adoption, entities must disclose the valuation method(s) used to measure the fair value of liabilities within its scope and any change in the fair value measurement method that occurs as a result of its initial application.

The Registrant Subsidiaries adopted EITF 08-5 effective January 1, 2009.  With the adoption of FSP SFAS 107-1 and APB 28-1, it is applied to the fair value of long-term debt.  The application of this standard had an immaterial effect on the fair value of debt outstanding.  EITF 08-5 is included in the “Fair Value Measurements and Disclosures” accounting guidance.

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

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

The Registrant Subsidiaries adopted EITF 08-6 effective January 1, 2009 with no impact on the financial statements.  It was applied prospectively.  EITF 08-6 is included in the “Investments – Equity Method and Joint Ventures” accounting guidance.
FSP SFAS 107-1 and APB 28-1 “Interim Disclosures about Fair Value of Financial Instruments” (FSP SFAS 107-1 and APB 28-1)
In April 2009, the FASB issued FSP SFAS 107-1 and APB 28-1 requiring disclosure about the fair value of financial instruments in all interim reporting periods.  The standard requires disclosure of the method and significant assumptions used to determine the fair value of financial instruments.

The Registrant Subsidiaries adopted the standard effective second quarter of 2009.  This standard increased the disclosure requirements related to financial instruments.  See “Fair Value Measurements of Long-term Debt” section of Note 9.  FSP SFAS 107-1 and APB 28-1 is included in the “Financial Instruments” accounting guidance.
FSP SFAS 115-2 and SFAS 124-2 “Recognition and Presentation of Other-Than-Temporary Impairments” (FSP SFAS 115-2 and SFAS 124-2)
In April 2009, the FASB issued FSP SFAS 115-2 and SFAS 124-2 amending the other-than-temporary impairment (OTTI) recognition and measurement guidance for debt securities.  For both debt and equity securities, the standard requires disclosure for each interim reporting period of information by security class similar to previous annual disclosure requirements.

The Registrant Subsidiaries adopted the standard effective second quarter of 2009.  The adoption had no impact on APCo, CSPCo, OPCo, PSO and SWEPCo.  For I&M, the adoption had no impact on its financial statements but increased disclosure requirements related to financial instruments.  See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 9.  FSP SFAS 115-2 and SFAS 124-2 is included in the “Investments – Debt and Equity Securities” accounting guidance.

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

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

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

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

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

The Registrant Subsidiaries adopted SFAS 157-2 effective January 1, 2009.  The Registrant Subsidiaries will apply these requirements to applicable fair value measurements which include new asset retirement obligations and impairment analyses related to long-lived assets, equity investments, goodwill and intangibles.  The Registrant Subsidiaries did not record any fair value measurements for nonrecurring nonfinancial assets and liabilities in the first nine months of 2009.  SFAS 157-2 is included in the “Fair Value Measurements and Disclosures” accounting guidance.
FSP SFAS 157-4 “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and
Identifying Transactions That Are Not Orderly” (FSP SFAS 157-4)
In April 2009, the FASB issued FSP SFAS 157-4 providing additional guidance on estimating fair value when the volume and level of activity for an asset or liability has significantly decreased, including guidance on identifying circumstances indicating when a transaction is not orderly.  Fair value measurements shall be based on the price that would be received to sell an asset or paid to transfer a liability in an orderly (not a distressed sale or forced liquidation) transaction between market participants at the measurement date under current market conditions.  The standard also requires disclosures of the inputs and valuation techniques used to measure fair value and a discussion of changes in valuation techniques and related inputs, if any, for both interim and annual periods.

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

Pronouncements Effective in the Future

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

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

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

The new accounting guidance is effective for interim and annual periods beginning after the issuance date.  Although management has not completed an analysis, management does not expect this update to have a material impact on the financial statements.  The Registrant Subsidiaries will adopt ASU 2009-05 effective fourth quarter of 2009.
ASU 2009-12 “Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent)” (ASU 2009-12)
In September 2009, the FASB issued ASU 2009-12 updating the “Fair Value Measurement and Disclosures” accounting guidance for the fair value measurement of investments in certain entities that calculate net asset value per share (or its equivalent).  The guidance permits a reporting entity to measure the fair value of an investment within its scope on the basis of the net asset value per share of the investment (or its equivalent).

The new accounting guidance is effective for interim and annual periods ending after December 15, 2009.  Although management has not completed an analysis, management does not expect this update to have a material impact on the financial statements.  The Registrant Subsidiaries will adopt ASU 2009-12 effective fourth quarter of 2009.

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

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

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

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

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

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

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

In June 2009, the FASB issued SFAS 1672009-17 amending the analysis an entity must perform to determine if it has a controlling financial interest in a variable interest entity (VIE).  This newVIE.  In addition to presentation and disclosure guidance, ASU 2009-17 provides that the primary beneficiary of a VIE must have both:

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

The Registrant Subsidiaries adopted the prospective provisions of ASU 2009-17 effective January 1, 2010.  This standard also requiresrequired separate presentation on the face of the statement of financial position for assets which can only be used to settle obligations of amaterial consolidated VIE and liabilities for which creditors do not have recourse to the general credit of the primary beneficiary.

SFAS 167 is effective for interim and annual reporting in fiscal years beginning after November 15, 2009.  Early adoption is prohibited.  Management continues to review the impact of the changes in the consolidation guidance on the financial statements.  This standard will increase disclosure requirements related to transactions with VIEs and may change the presentation of consolidated VIE’sVIEs’ assets and liabilities on the Registrant Subsidiaries’ balance sheets.  The Registrant Subsidiaries will adopt SFAS 167 effectiveUpon adoption, SWEPCo deconsolidated DHLC.  DHLC was deconsolidated due to the shared control between SWEPCo and CLECO.  After January 1, 2010.  SFAS 167 is included in2010, SWEPCo reports DHLC using the “Consolidation” accounting guidance.

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

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

This standard is effective for fiscal years ending after December 15, 2009.  Management expects this standard to increase the disclosure requirements related to AEP’s benefit plans.  The Registrant Subsidiaries will adopt the standard effective for the 2009 Annual Report.  FSP SFAS 132R-1 is included in the “Compensation – Retirement Benefits” accounting guidance.

Future Accounting Changes

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

EXTRAORDINARY ITEM

SWEPCo Texas Restructuring

In August 2006, the PUCT adopted a rule extending the delay in implementation of customer choice in SWEPCo’s SPP area of Texas until no sooner than January 1, 2011.  In May 2009, the governor of Texas signed a bill related to SWEPCo’s SPP area of Texas that requires continued cost of service regulation until certain stages have been completed and approved by the PUCT such that fair competition is available to all Texas retail customer classes.  Based upon the signing of the bill, SWEPCo re-applied “Regulated Operations” accounting guidance for the generation portion of SWEPCo’s Texas retail jurisdiction effective second quarter of 2009.  Management believes that a switch to competition in the SPP area of Texas will not occur.  The reapplication of “Regulated Operations” accounting guidance resulted in an $8 million ($5 million, net of tax) extraordinary loss.accounting.
 
3.RATE MATTERS

TheAs discussed in the 2009 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 20082009 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 20092010 and updates the 20082009 Annual Report.

OhioRegulatory Assets Not Yet Being Recovered
  APCo  I&M 
  March 31,  December 31,  March 31,  December 31, 
  2010  2009  2010  2009 
Noncurrent Regulatory Assets (excluding fuel) (in thousands)  (in thousands) 
Regulatory assets not yet being recovered pending future proceedings to determine the recovery method and timing:            
             
Regulatory Assets Currently Not Earning a Return            
Mountaineer Carbon Capture and Storage Project $111,461  $110,665  $-  $- 
Virginia Environmental Rate Adjustment Clause  27,232   25,311   -   - 
Virginia Transmission Rate Adjustment Clause  21,088   26,184   -   - 
Special Rate Mechanism for Century Aluminum  12,474   12,422   -   - 
Deferred Wind Power Costs  10,581   5,372   -   - 
Deferred PJM Fees  -   -   6,597   6,254 
Total Regulatory Assets Not Yet Being Recovered $182,836  $179,954  $6,597  $6,254 

  CSPCo  OPCo 
  March 31,  December 31,  March 31,  December 31, 
  2010  2009  2010  2009 
Noncurrent Regulatory Assets (excluding fuel) (in thousands)  (in thousands) 
Regulatory assets not yet being recovered pending future proceedings to determine the recovery method and timing:            
             
Regulatory Assets Currently Earning a Return            
Customer Choice Deferrals $28,994  $28,781  $28,494  $28,330 
Line Extension Carrying Costs  28,379   26,590   17,530   16,278 
Storm Related Costs  17,014   17,014   9,794   9,794 
Acquisition of Monongahela Power  10,706   10,282   -   - 
Regulatory Assets Currently Not Earning a Return                
Peak Demand Reduction/Energy Efficiency  5,796   4,071   5,713   4,007 
Total Regulatory Assets Not Yet Being Recovered $90,889  $86,738  $61,531  $58,409 

 PSO SWEPCo 
 March 31, December 31, March 31, December 31, 
 2010 2009 2010 2009 
Noncurrent Regulatory Assets (excluding fuel)(in thousands) (in thousands) 
Regulatory assets not yet being recovered pending future proceedings to determine the recovery method and timing:            
             
Regulatory Assets Currently Not Earning a Return            
Storm Related Costs $11,329  $-  $-  $- 
Asset Retirement Obligation  -   -   521   471 
Total Regulatory Assets Not Yet Being Recovered $11,329  $-  $521  $471 
CSPCo and OPCo Rate Matters

Ohio Electric Security Plan Filings – Affecting CSPCo and OPCo

In March 2009, theThe PUCO issued an order which was amended by a rehearing entry in JulyMarch 2009 that modified and approved CSPCo’s and OPCo’s ESPs thatwhich established standard service offer rates.rates at the start of the April 2009 billing cycle.  The ESPs will beare in effect through 2011.  The ESP order authorized revenue increases during the ESP period and capped the overall revenuealso limits annual rate increases for CSPCo to 7% in 2009, 6% in 2010 and 6% in 2011 and for OPCo to 8% in 2009, 7% in 2010 and 8% in 2011.  Some rate components and increases are exempt from these limitations.  CSPCo and OPCo implemented rates for the April 2009 billing cycle.  In its July 2009 rehearing entry, the PUCO required CSPCo and OPCo to reduce rates implemented in April 2009 by $22 million and $27 million, respectively, on an annualized basis.  CSPCo and OPCo are collectingcollected the 2009 annualized revenue increase over the last nine months of 2009.

The order provides a FAC for the three-year period of the ESP.  The FAC increase will be phased in to avoid having the resultant rate increases exceed the ordered annual caps described above.  The FAC increase before phase-in will beis subject to quarterly true-ups, to actual recoverable FAC costs and to annual accounting audits and prudency reviews.  The order allows CSPCo and OPCo to defer any unrecovered FAC costs resulting from the annual caps/phase-in plancaps and to accrue associated carrying charges on such deferrals at CSPCo’s and OPCo’s weighted average cost of capital.  TheAny deferred FAC regulatory asset balance at the end of the three-year ESP period will be recovered through a non-bypassable surcharge over the period 2012 through 2018.

  Management expects to recover the CSPCo FAC deferral during 2010.  That recovery will include deferrals associated with the Ormet interim arrangement and is subject to the PUCO’s ultimate decision regarding the Ormet interim arrangement deferrals plus related carrying charges.  See the “Ormet Interim Arrangement” section below.  The FAC deferrals at September 30, 2009as of March 31, 2010 were $36$10 million and $238$345 million for CSPCo and OPCo, respectively, inclusiveexcluding $1 million and $13 million, respectively, of unrecognized equity carrying charges atcosts.

Discussed below are the weighted average cost of capital.  Inoutstanding uncertainties related to the July 2009 rehearing order, the PUCO once again rejected a proposal by several intervenors to offset the FAC costs with a credit for off-system sales margins.  As a result, CSPCo and OPCo will retain the benefit of their share of the AEP System’s off-system sales.ESP order:

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

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

·  CSPCo should attempt to mitigate the costs of its gridSMART advanced metering proposal that will affect portions of its service territory by seeking funds under the American Recovery and Reinvestment Act of 2009.  As a result, a rider was established to recover $32 million related to gridSMART during the three-year ESP period.  In August 2009, CSPCo filed for $75 million in federal grant funding under the American Recovery and Reinvestment Act of 2009.
·  CSPCo and OPCo can recover their incremental carrying costs related to environmental investments made from 2001 through 2008 that are not reflected in existing rates.  Future recovery during the ESP period of incremental carrying charges on environmental expenditures incurred beginning in 2009 may be requested in annual filings.

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

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

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

In August 2009, an intervenor filed for rehearing requesting, among other things, that the PUCO order CSPCo and OPCo to cease and desist from charging ESP rates, to revert to the rate stabilization plan rates and to compel a refund, including interest, of the amounts collected by CSPCo and OPCo.  CSPCo and OPCo filed a response stating the rates being charged by CSPCo and OPCo have been authorized by the PUCO and there was no basis for precluding CSPCo and OPCo from continuing to charge those rates.  In September 2009, certain intervenors filed appeals of the March 2009 order and the July 2009 rehearing entryappeal with the Supreme Court of Ohio.  OneOhio raising several issues including alleged retroactive ratemaking, recovery of carrying charges on certain environmental investments, Provider of Last Resort (POLR) charges and the intervenors, the Ohio Consumers’ Counsel, has asked the courtdecision not to stay, pending the outcome of its appeal, a portion of the authorized ESPoffset rates which the Ohio Consumers’ Counsel characterizes as being retroactive.  In October 2009,by off-system sales margins.  A decision from the Supreme Court of Ohio deniedis pending.
In November 2009, the Ohio Consumers' Counsel's request forIndustrial Energy Users-Ohio group filed a stay and granted motions to dismiss both appeals.

In September 2009, CSPCo and OPCo filed their initial quarterly FAC filingnotice of appeal with the PUCOSupreme Court of Ohio challenging components of the ESP order including the POLR charge, the distribution riders for gridSMARTSM and adjusted their estimated phase-in deferrals toenhanced reliability, the amounts shown inPUCO’s conclusion and supporting evaluation that the filing, which wasmodified ESPs are more favorable than the expected results of a decrease inmarket rate offer, the FAC deferralunbundling of $6 million for CSPCothe fuel and an increase innon-fuel generation rate components, the FAC deferralscope and design of $17 million for OPCo.  An order approving the FAC 2009 filings will not be issued until a financial auditfuel adjustment clause and prudency reviewthe approval of the plan after the 150-day statutory deadline.  A decision from the Supreme Court of Ohio is performed by independent third parties and reviewed by the PUCO.pending.

In OctoberApril 2010, the Industrial Energy Users-Ohio group filed another notice of appeal with the Supreme Court of Ohio challenging alleged retroactive ratemaking, CSPCo's and OPCo's abilities to collect through the FAC amounts deferred under the Ormet interim arrangement and the approval of the plan after the 150-day statutory deadline.  A decision from the Supreme Court of Ohio is pending.

In 2009, the PUCO convened a workshop to begin to determine the methodology for the Significantly Excessive Earnings Test (SEET).  The SEET requires that the PUCO to determine, following the end of each year of the ESP, if rate adjustments included in the ESP resulted in significantly excessive earnings.  This will be determined by measuring whether the utility’s earned return on common equity is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, which have comparable business and financial risk.  In the March 2009 ESP order, the PUCO determined that off-system sales margins and FAC deferral phase-in credits should be excluded from the SEET methodology.  However, the July 2009 PUCO rehearing entry deferred those issues to the SEET workshop.  If the rate adjustments, in the aggregate, result in significantly excessive earnings, the excess amount would be returned to customers.  The PUCO staff recommended that the SEET be calculated on an individual company basis and not on a combined CSPCo/OPCo basis and that off-system sales margins be included in the earnings test.  It is unclear at this time whether the FAC phase-in deferral credits will be included in the earnings test.  Management believes that CSPCo and OPCo should not be requir ed to refund unrecovered FAC regulatory assets until they are collected, assuming there are excessive earnings in that year.  In April 2010, the PUCO heard arguments related to various SEET issues including the treatment of the FAC deferrals.  The PUCO’s decision on the SEET review of CSPCo’s and OPCo’s 2009 earningsmethodology is not expected to be finalized until the workshop is completed, the PUCO issues SEET guidelines, a SEET filing is made by CSPCo and OPCo in 2010related to 2009 earnings and the PUCO issues an order thereon.  The SEET workshop will also determine whether CSPCo’s and OPCo’s earnings will be measured on an individual company basis or on a combined CSPCo/OPCo basis.

In October 2009, an intervenor filed a complaint for writ of prohibition with the Supreme Court of Ohio requesting the Court to prohibitApril 2010, CSPCo and OPCo from billing and collecting any ESP rate increases thatfiled a request with the PUCO authorized as the intervenor believes the PUCO's statutory jurisdiction over CSPCo's and OPCo's ESP application ended on December 28, 2008, which was 150 days after theto delay their SEET filing of the ESP applications.until July 2010.  As a result, CSPCo and OPCo plan on filing a response in oppositionare unable to the complaint for writdetermine whether they will be required to return any of prohibition.their ESP revenues to customers.

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

Ormet Interim Arrangement

CSPCo, OPCo and Ormet, a large aluminum company, filed an application with the PUCO for approval of an interim arrangement governing the provision of generation service to Ormet.  This interim arrangement was effective from January 2009 through September 2009.  In January 2009, the PUCO approved the application.  In March 2009, the PUCO approved a FAC in the ESP filings.  The approval of the FAC, together with the PUCO approval of the interim arrangement, provided the basis to record regulatory assets for the difference between the approved market price and the rate paid by Ormet.  Through September 2009, the last month of the interim arrangement, CSPCo and OPCo had $30 million and $34 million, respectively, of deferred FAC related to the interim arrangement including recognized carryin g charges but excluding $1 million and $1 million, respectively, of unrecognized equity carrying costs.  In November 2009, CSPCo and OPCo requested that the PUCO approve recovery of the deferrals under the interim agreement, plus a weighted average cost of capital carrying charge.  The interim arrangement deferrals are included in CSPCo’s and OPCo’s FAC phase-in deferral balance.  See “Ohio Electric Security Plan Filings” section above.  In the ESP proceeding, intervenors requested that CSPCo and OPCo be required to refund the Ormet-related regulatory assets and requested that the PUCO prevent CSPCo and OPCo from collecting the Ormet-related revenues in the future.  The PUCO did not take any action on this request in the ESP proceeding.  The intervenors raised the issue again in response to CSPCo’s and OPCo’s November 2009 filing to approve recovery of the deferrals under the interim agreement.  If CSPCo and OPCo are not ultimately permitted to fully recover their requested deferrals under the interim arrangement, it would reduce future net income and cash flows and impact financial condition.

Economic Development Rider

In April 2010, the Industrial Energy Users-Ohio filed a notice of appeal of the PUCO-approved Economic Development Rider (EDR) with the Supreme Court of Ohio.  The Industrial Energy Users-Ohio raised several issues including (a) the PUCO lost jurisdiction over CSPCo’s and OPCo’s ESP proceedings and related proceedings when the PUCO failed to issue ESP orders within the 150 days statutory deadline, (b) the EDR should not be exempt from the ESP annual rate limitations and (c) CSPCo and OPCo should not be allowed to apply a weighted average long-term debt carrying cost on deferred EDR regulatory assets.

As of March 31, 2010, CSPCo and OPCo have incurred $21 million and $12 million, respectively, in EDR costs.  Of these costs, CSPCo and OPCo have collected $8 million and $6 million, respectively, through the EDR, which CSPCo and OPCo began collecting in January 2010.  The remaining $13 million and $6 million for CSPCo and OPCo, respectively, are recorded as EDR regulatory assets.  Management cannot predict the amounts CSPCo and OPCo will defer for future recovery through the EDR.  If CSPCo and OPCo are not ultimately permitted to recover their deferrals or are required to refund revenue collected, it would reduce future net income and cash flows and impact financial condition.

Environmental Investment Carrying Cost Rider

In February 2010, CSPCo and OPCo filed an application with the PUCO to establish an Environmental Investment Carrying Cost Rider to recover carrying costs related to environmental investments in 2009.  CSPCo’s and OPCo’s proposed initial rider would recover $29 million and $37 million, respectively, from July 2010 through December 2011 for carrying costs for 2009 through 2011.  If approved, the implementation of the rider will likely not impact cash flows, but will impact the ESP phase-in plan deferrals associated with the FAC since this rider is within the rate increase caps authorized by the PUCO in the ESP proceedings.

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 toof building and operating a 629 MWan IGCC power plant using clean-coal technology.  In June 2006, the PUCO issued an order approving a tariff to allowplant.  CSPCo and OPCo to recover pre-construction costs over a period of no more than twelve months effective July 1, 2006.  During that period, CSPCo and OPCohave each collected $12 million in pre-construction costs authorized in a June 2006 PUCO order and each incurred $11 million in pre-construction costs.  As a result, CSPCo and OPCo each established a net regulatory liability of approximately $1 million.

The June 2006 order also provided that if CSPCo and OPCo have not commenced a continuous course of construction of the proposed IGCC plant within five years of thebefore June 2006 PUCO order,2011, all pre-construction cost recoveries associated with itemscosts that may be utilized in projects at other jurisdictionssites must be refunded to Ohio ratepayers with interest.

In September 2008, the Ohio Consumers’ Counsel  Intervenors have filed a motionmotions with the PUCO requesting all pre-construction costs be refunded to Ohio ratepayersratepay ers with interest.  In October 2008, CSPCo and OPCo filed a response with the PUCO that argued the Ohio Consumers’ Counsel’s motion was without legal merit and contrary to past precedent.  In January 2009, a PUCO Attorney Examiner issued an order that required CSPCo and OPCo to file a detailed statement outlining the status of the construction of the IGCC plant, including whether CSPCo and OPCo are engaged in a continuous course of construction on the IGCC plant.  In February 2009, CSPCo and OPCo filed a statement that CSPCo and OPCo have not commenced construction of the IGCC plant and CSPCo and OPCo believe there exist real statutory barriers to the construction of any new base load generation in Ohio, including the IGCC plant.  The statement also indicated that while construction on the IGCC plant might not begin by June 2011, changes in circumstances could result in the commencement of construction on a continuous course by that time.

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

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

Ormet – Affecting CSPCo and OPCoSWEPCo Rate Matters

In December 2008, CSPCo, OPCoTurk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which is expected to be in service in 2012.  SWEPCo owns 73% of the Turk Plant and Ormet, a large aluminum companywill operate the completed facility.  The Turk Plant is currently operating at a reduced loadestimated to cost $1.7 billion, excluding AFUDC, with SWEPCo’s share estimated to cost $1.3 billion, excluding AFUDC.  As of March 31, 2010, excluding costs attributable to its joint owners, SWEPCo has capitalized approximately $777 million of expenditures (including AFUDC and capitalized interest, and related transmission costs of $35 million).  As of March 31, 2010, the joint owners and SWEPCo have contractual construction commitments of approximately 330 MW (Ormet operated at$459 million (including related transmission costs of $7 million).  SWEPCo’s share of the contractual construction commitments is $337 million.  If the plant is cancelled, the joint owners and SWEPCo would incur contractual construction cancellation fees, based on construction status as of March 31, 2010, of approximately $121 million (including related transmission cancellation fees of $1 million).  SWEPCo’s share of the contractual construction cancellation fees would be approximately $89 million.

Discussed below are the outstanding uncertainties related to the Turk Plant:

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN).  Following an approximate 500 MWappeal by certain intervenors, the Arkansas Court of Appeals issued a unanimous decision that, if upheld by the Arkansas Supreme Court, would reverse the APSC’s grant of the CECPN.  The Arkansas Court of Appeals concluded that SWEPCo’s need for base load in 2008), filed an application withcapacity, the PUCO for approvalconstruction and financing of an interim arrangement governing the provision of generation service to Ormet.  The interim arrangement was effective January 1, 2009 and expired in September 2009 upon the filing of a new PUCO-approved long-term power contract between Ormet and CSPCo/OPCo that was effective prospectively through 2018.  Under the interim arrangement, Ormet would pay the then-current applicable generation tariff rates and riders and CSPCo and OPCo would defer as a regulatory asset, beginning in 2009, the difference between the PUCO-approved 2008 market price of $53.03 per MWHTurk Plant and the applicable generation tariff ratesproposed transmission facilities’ construction and riders.  CSPColocation should have been considered by the APSC in a single docket instead of separate dockets.  The Arkansas Supreme Court granted petitions filed by SWEPCo and OPCo proposedthe APSC to recoverreview the deferral throughArkansas Court of Appeals’ decision.  The Court heard oral argument s in April 2010.  A decision from the new FAC phased-in mechanism that they proposed in the ESP proceeding.  In January 2009, the PUCO approved the application as an interim arrangement.  In February 2009, an intervenor filed an application for rehearing of the PUCO’s interim arrangement approval.  In March 2009, the PUCO granted that application for further consideration of the matters specified in the rehearing application.  In the PUCO’s July 2009 order discussed below, CSPCo and OPCo were directed to file an application to recover the appropriate amounts of the deferrals under the interim agreement and for the remainder of 2009.Arkansas Supreme Court is pending.

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

In March 2009, the PUCOPUCT issued an order approving a Certificate of Convenience and Necessity (CCN) for the Turk Plant with the following conditions: (a) a cap on the recovery of jurisdictional capital costs for the Turk Plant based on the previously estimated $1.522 billion projected construction cost, excluding AFUDC and related transmission costs, (b) a cap on recovery of annual CO2 emission costs at $28 per ton through the year 2030 and (c) a requirement to hold Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers.  SWEPCo appealed the PUCT’s order contending the two cost cap restrictions are unlawful.  The Texas Industrial Energy Consumers fi led an appeal contending that the PUCT’s grant of a conditional CCN for the Turk Plant was unnecessary to serve retail customers.  In February 2010, the Texas District Court affirmed the PUCT in all respects.  In March 2010, SWEPCo and the Texas Industrial Energy Consumers appealed the Texas District Court decision.

The LPSC approved SWEPCo’s application to construct the Turk Plant.  The Sierra Club petitioned the LPSC to begin an investigation into the construction of the Turk Plant which was rejected by the LPSC in November 2009.  In December 2009, the Sierra Club refiled its petition as a stand alone complaint proceeding.  In February 2010, SWEPCo filed a motion to dismiss and denied the allegations in the ESP filings which includedcomplaint.
In November 2008, SWEPCo received its required air permit approval from the Arkansas Department of Environmental Quality (ADEQ) and commenced construction at the site.  In January 2010, the Arkansas Pollution Control and Ecology Commission (APCEC) upheld the air permit.  In February 2010, the parties who unsuccessfully appealed the air permit to the APCEC filed a FACnotice of appeal of the APCEC’s decision with the Circuit Court of Hempstead County, Arkansas.

The wetlands permit was issued by the U.S. Army Corps of Engineers in December 2009.  In February 2010, the Sierra Club, the Audubon Society and others filed a complaint in the Federal District Court for the ESP period.Western District of Arkansas against the U.S. Army Corps of Engineers challenging the process used and the terms of the permit issued to SWEPCo authorizing certain wetland and stream impacts.

Management believes that SWEPCo’s planning, certification and construction of the Turk Plant has been in material compliance with all applicable laws and regulations.  Further, management expects that SWEPCo will ultimately be able to complete construction of the Turk Plant and related transmission facilities and place those facilities in service.  However, if SWEPCo is unable to complete the Turk Plant construction and place the Turk Plant in service or if SWEPCo cannot recover all of its investment in and expenses related to the Turk Plant, it would reduce future net income and cash flows and impact financial condition.

Stall Unit

SWEPCo is constructing the Stall Unit, an intermediate load 500 MW natural gas-fired combustion turbine combined cycle generating unit, at its existing Arsenal Hill Plant located in Shreveport, Louisiana.  The approvalStall Unit is currently estimated to cost $431 million, including $51 million of AFUDC, and is expected to be in service in mid-2010.  The LPSC and the APSC issued orders capping SWEPCo’s Stall Unit construction costs at $445 million including AFUDC and excluding related transmission costs.

As of March 31, 2010, SWEPCo has capitalized construction costs of $402 million, including AFUDC, and has contractual construction commitments of an ESP FAC, together withadditional $17 million.  If the January 2009 PUCO approvalfinal cost of the Ormet interim arrangement, providedStall Unit were to exceed the basis to record regulatory assets$445 million cost cap, the APSC or LPSC could disallow their jurisdictional allocation of construction costs in excess of the caps and thereby reduce future net income and cash flows and impact financial condition.

Louisiana Fuel Adjustment Clause Audit

Consultants for the differentialLPSC issued their audit report of SWEPCo’s Louisiana retail FAC.  Various recommendations were contained within the audit report including two recommendations that might result in a financial impact that could be material for SWEPCo.  The first recommendation is that SWEPCo should provide the approved market price of $53.03 versus the rate paid by Ormetvariable operation and maintenance and SO2 allowance costs that were included in SWEPCo’s purchased power costs and that those costs should be disallowed from 2003 until the effective date of the 2009-2018 power contract.

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

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

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

Hurricane Ike – Affecting CSPCo and OPCo

In September 2008, the service territories of CSPCo and OPCo were impacted by strong winds from the remnants of Hurricane Ike.  Under the RSP, which was effective in 2008, CSPCo and OPCo could seek a distribution rate adjustment to recover incremental distribution expenses related to major storm service restoration efforts.  In September 2008, CSPCo and OPCo established regulatory assets of $17 million and $10 million, respectively, for the expected recovery of the storm restoration costs.  In December 2008, the PUCO approved these regulatory assets along with a long-term debt only carrying cost on these regulatory assets.  In its order approving the deferrals, the PUCO stated that the mechanism for recovery would be determined in CSPCo’s and OPCo’s next distribution rate filings.  At September 30, 2009, CSPCo and OPCo have accrued for future recovery regulatory assets of $18 million and $10 million, respectively, including the approved long-term debt only carrying costs.  If CSPCo and OPCo are not ultimately permitted to recover their storm damage deferrals, it would have an adverse effect on future net income and cash flows.

Texas Rate Matters

Texas Restructuring – SPP – Affecting SWEPCo

In August 2006, the PUCT adopted a rule extending the delay in implementation of customer choice in SWEPCo’s SPP area of Texas until no sooner than January 1, 2011.  In May 2009, the governor of Texas signed a bill related to SWEPCo’s SPP area of Texas that requires continued cost of service regulation until certain stages have been completed and approved by the PUCT such that fair competition is available to all Texas retail customer classes.  Based upon the signing of the bill, SWEPCo re-applied “Regulated Operations” accounting guidance for the generation portion of SWEPCo’s Texas retail jurisdiction in the second quarter of 2009.  Management believes that a switch to competition in the SPP area of Texas will not occur.  The reapplication of “Regulated Operations” accounting guidance resulted in an $8 million ($5 million, net of tax) extraordinary loss.

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

2009 Texas Base Rate Filing – Affecting SWEPCo

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

The proposed Stall Unit rider would recoveraudi t report contained a return onrecommendation that SWEPCo should reflect the Stall Unit investment while the Stall Unit is under construction and continuing after it is placed in service plus recovery of depreciation when it is placed in service in 2010.  The proposed Turk Plant rider would recover a return on the Turk Plant investment and will continue until such time that the Turk Plant is included in base rates.  Both riders would terminate when base rates are increased to include recovery of the Turk Plant’s and the Stall Unit’s respective plant investments, plus a return thereon, and a recovery of their related operating expenses.  Management is unable to predict the outcome of this filing.

Stall Unit – Affecting SWEPCo

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

Turk Plant – Affecting SWEPCo

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

Virginia Rate Matters

Virginia E&R Costs Recovery Filing – Affecting APCo

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

The Virginia E&R cost recovery mechanism under Virginia law ceased effective with costs incurred through December 2008.  However, the 2007 amendments to Virginia’s electric utility restructuring law provide for a rate adjustment clause to be requested in 2009 to recover incremental E&R costs incurred through December 2008.  Under this amendment, APCo filed an application, in May 2009, to recover $102 million of unrecovered 2008 incremental deferred E&R costs plus its 2008 equity costs based on a 12.5% return on equity on its E&R capital investments. However, APCo deferred and recognized income under the E&R legislation based on a return on equity of 10.1%, which was the Virginia SCC staff’s recommendationreductions in the prior E&R case.  In October 2009, a stipulation agreement was reached betweenLouisiana FAC rates as soon as possible, including interest through the parties and filed withdate the Virginia SCC addressing all matters other than rate design and customer class allocation issues.  The stipulation agreement allows APCo to recover Virginia incremental E&R costs of $90 million, representing costs deferred during 2008 plus unrecognized 2008 equity costs, using a 10.6% return on equity for collection in 2010.  This will result in an immaterial adjustment which will be recordedrefunds are reflected in the fourth quarter of 2009.  The Virginia SCC is expected to approve the stipulation agreement in the fourth quarter of 2009.

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

Mountaineer Carbon Capture and Storage Project – Affecting APCo

In January 2008, APCo and ALSTOM Power, Inc. (Alstom), an unrelated third party, entered into an agreement to jointly construct a CO2 capture demonstration facility.  APCo and Alstom will each own part of the CO2 capture facility.  APCo will also construct and own the necessary facilities to store the CO2.  RWE AG, a German electric power and natural gas public utility, and the Electric Power Research Institute are participating in the project and providing some funding to offset APCo's costs.  APCo’s combined estimated cost for its necessary storage facilities and its share of the CO2 capture demonstration facility is $74 million.  In May 2009, the West Virginia Department of Environmental Protection issued a permit to inject CO2 that requires, among other items, that APCo monitor the wells for at least 20 years following the cessation of CO2 injection.  In September 2009, the capture portion of the project was placed into service and in October 2009, APCo started injecting CO2 in underground storage.  The injection of CO2 required the recordation of an asset retirement obligation and an offsetting regulatory asset at its estimated net present value of $36 million in October 2009.  Through September 30, 2009, APCo incurred $71 million in capitalized project costs which are included in Regulatory Assets.

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

Virginia Base Rate Filing – Affecting APCo

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

Rate Adjustment Clauses – Affecting APCo

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

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

Virginia Fuel Factor Proceeding – Affecting APCo

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

APCo’s Filings for an IGCC Plant – Affecting APCo

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

West Virginia Rate Matters

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

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

In May 2009, various intervenors submitted testimony supporting adjustments to APCo’s actual and projected ENEC costs.  The intervenors also proposed alternative rate phase-in plans ranging from three to five years.  Specifically, the WVPSC staff and the West Virginia Consumer Advocate recommended an increase of $338 million and $294 million, respectively, with $119 million and $117 million, respectively, being collected during the first year and suggested that the remaining rate increases for future years be determined in subsequent ENEC filings.  In June 2009, APCo filed rebuttal testimony.  In the rebuttal testimony, APCo accepted certain intervenor adjustments to the forecasted ENEC costs and reduced the requested increase to $358 million with a proposed first-year increase of $144 million.  The intervenors’ forecast adjustments would not impact earnings since the ENEC mechanism would continue to true-up to actual costs.  The primary difference between the intervenors’ $117 million first-year increase and APCo’s $144 million first-year increase is the intervenors’ proposed disallowance of up to $36 million of actual and projected coal costs.

In September 2009, the WVPSC issued an order granting a $320 million increase to be phased in over the next four years with a first-year increase of $112 million.  As of September 30, 2009, APCo’s ENEC under-recovery balance was $255 million which is included in Regulatory Assets.  The WVPSC also approved a fixed annual carrying cost rate of 4%, effective October 1, 2009, to be applied to the incremental deferred regulatory asset balance that will result from the phase-in plan.  The order disallowed an immaterial amount of deferred ENEC costs which was recognized in September 2009.  It also lowered annual coal cost projections by $27 million and deferred recovery of unrecovered ENEC deferrals related to price increases on certain renegotiated coal contracts.  The WVPSC indicated that it would review the prudency of these additional costs in the next ENEC proceeding.  As of September 30, 2009, APCo has deferred $13 million of unrecovered coal costs on the renegotiated coal contracts which is included in APCo’s $255 million ENEC under-recovery regulatory asset and has an additional $5 million in purchased fuel costs on the renegotiated coal contracts which is recorded in Fuel on the Condensed Consolidated Balance Sheets.  Although management believes the portion of its deferred ENEC under-recovery balance attributable to renegotiated coal contracts is probable of recovery, if the WVPSC were to disallow a portion of APCo’s deferred ENEC costs including any costs incurred in the future related to the renegotiated coal contracts, it could have an adverse effect on future net income and cash flows.

APCo’s Filings for an IGCC Plant – Affecting APCo

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

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

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

The Virginia SCC issued an order in April 2008 denying APCo’s requests, in part, upon its finding that the estimated cost of the plant was uncertain and may escalate.  The Virginia SCC also expressed concern that the $2.2 billion estimated cost did not include a retrofitting of carbon capture and sequestration facilities.  In July 2008, based on the unfavorable order received in Virginia, the WVPSC issued a notice seeking comments from parties on how the WVPSC should proceed.  Various parties, including APCo, filed comments with the WVPSC.  In September 2009, the WVPSC removed the IGCC case as an active case from its docket and indicated that the conditional CPCN granted in 2008 must be reconsidered if and when APCo proceeds forward with the IGCC plant.

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

Through September 30, 2009, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia jurisdiction, approximately $2 million applicable to its FERC jurisdiction and approximately $9 million applicable to its Virginia jurisdiction.

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

Mountaineer Carbon Capture and Storage Project – Affecting APCo

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

Indiana Rate Matters

Indiana Base Rate Filing – Affecting I&M

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

In December 2008, I&M and all of the intervenors jointly filed a settlement agreement with the IURC proposing to resolve all of the issues in the case.  The settlement agreement incorporated the $69 million annual reduction in revenues from the depreciation rate reduction in the development of an agreed to revenue increase of $44 million, which included a $22 million increase in base rates based on an authorized return on equity of 10.5% and a $22 million initial increase in tracker rates for incremental PJM, net emission allowance and demand side management (DSM) costs.  The agreement also establishes an off-system sales sharing mechanism and other provisions which include continued funding for the eventual decommissioning of the Cook Plant.

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

Rockport and Tanners Creek Plants Environmental Facilities – Affecting I&M

In January 2009, I&M filed a petition with the IURC requesting approval of a Certificate of Public Convenience and Necessity (CPCN) to use advanced coal technology which would allow I&M to reduce airborne emissions of NOx and mercury from its existing coal-fired steam electric generating units at the Rockport and Tanners Creek Plants.  In addition, the petition requested approval to construct and recover the costs of selective non-catalytic reduction (SNCR) systems at the Tanners Creek Plant and to recover the costs of activated carbon injection (ACI) systems on both generating units at the Rockport Plant.  The petition requested to depreciate the ACI systems over an accelerated 10-year period and the SNCR systems over the 11-year remaining useful life of the Tanners Creek generating units.

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

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

Indiana Fuel Clause Filing (Cook Plant Unit 1 Fire and Shutdown) – Affecting I&M

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

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

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

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

Michigan Rate Matters
2008 Power Supply Cost Recovery (PSCR) Reconciliation (Cook Plant Unit 1 Fire and Shutdown) – Affecting I&M
In March 2009, I&M filed with the Michigan Public Service Commission (MPSC) its 2008 PSCR reconciliation.  The filing also included an adjustment to reduce the incremental fuel cost of replacement power due to the Cook Plant Unit 1 outage with a portion of the accidental insurance proceeds from the Cook Plant Unit 1 outage policy, which began in mid-December 2008.  See “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.  In May 2009, the MPSC set a procedural schedule for testimony and hearings to be held in the fourth quarter of 2009.  A final order is anticipated in the first quarter of 2010.  Management is unable to predict the outcome of this proceeding and whether it will have an adverse effect on future net income and cash flows.

Oklahoma Rate Matters

PSO Fuel and Purchased Power – Affecting PSO

2006 and Prior Fuel and Purchased Power

Proceedings addressing PSO’s historic fuel costs from 2001 through 2006 remain open at the OCC due to two issues.  The first issue relates to the allocation of off-system sales margins (OSS) among the AEP operating companies in accordance with a FERC-approved allocation agreement.  In June 2008, the Oklahoma Industrial Energy Consumers (OIEC) appealed the ALJ recommendations that concluded the FERC and not the OCC had jurisdiction over this matter.  In August 2008, the OCC filed a complaint with the FERC concerning this allocation of OSS issue.  In December 2008, under an adverse FERC ruling, PSO recorded a regulatory liability to return the reallocated OSS to customers.  Effective with the March 2009 billing cycle, PSO began refunding the additional reallocated OSS to its customers.FAC.  See “Allocation of Off-system Sales Margins” section within “FERC Rate Matters.”  Management is unable to predict how the LPSC will rule on the recommendations in the audit report and its financial statement impact on net income, cash flows and financial condition.

The second issue concerns a 2002 under-recovery of $42 million of PSO fuel costs resulting from a reallocation among AEP West companies of purchased power costs for periods prior to 2002.  PSO recovered the $42 million by offsetting it against an existing fuel over-recovery during the period June 2007 through May 2008.  In the June 2008 appeal by the OIEC of the ALJ recommendations, the OIEC contended that PSO should not have collected the $42 million without specific OCC approval nor collected the $42 million before the OSS allocation issue was resolved.  As such, the OIEC contends that the OCC could and should require PSO to refund the $42 million it collected through its fuel clause.  In August 2008, the OCC heard the OIEC appeal and a decision is pending.  Although the OSS allocation issue has been resolved at the FERC, if the OCC were to order PSO to make an additional refund for all or a part of the $42 million, it would have an adverse effect on future net income and cash flows.

2007 Fuel and Purchased Power2009 Texas Base Rate Filing

In September 2008, the OCC initiated a review of PSO’s generation, purchased power and fuel procurement processes and costs for 2007.  In August 2009, SWEPCo filed a joint stipulation and settlement agreement (settlement) was filedrate case with the OCC requesting the OCC to issue an order accepting the fuel adjustment clause for 2007 and find that PSO’s fuel procurement practices, policies and decisions were prudent.  In September 2009, the OCC issued a final order approving the settlement.

2008 Oklahoma Base Rate Filing Appeal – Affecting PSO

In July 2008, PSO filed an application with the OCCPUCT to increase its base rates by $133approximately $75 million (later adjusted to $127 million) on an annual basis.  At the time of the filing, PSO was recovering $16 million a year for costs related to new peaking units recently placed into service through a Generation Cost Recovery Rider (GCRR).  Subsequent to implementation of the new base rates, the GCRR terminates and PSO recovers these costs through the new base rates.  Therefore, PSO’s net annual requested increase in total revenues was actually $117 million (later adjusted to $111 million).  The proposed revenue requirement reflectedannually including a return on equity of 11.25%11.5%.

In January 2009, the OCC issued a final order approving an $81 million increase in PSO’s non-fuel base revenues based on a 10.5% return on equity.  The rate increase includes a $59 million increase in base rates and a $22 million increasefiling included requests for costs to be recovered throughfinancing cost riders outside of base rates.  The $22 million increase includes $14 million for purchase power capacity costs and $8 million for the recovery of carrying costs associated with PSO’s program to convert overhead distribution lines to underground service.  The $8 million recovery of carrying costs associated with the overhead to underground conversion program will occur only if PSO makes the required capital expenditures.  The final order approved lower depreciation rates and also provided for the deferral of $6 million of generation maintenance expenses to be recovered over a six-year period.  The deferral was recorded in the first quarter of 2009.  PSO was given authority to record additional under/over recovery deferrals for future distribution storm costs above or below the amount included in base rates and for certain transmission reliability expenses.  The new rates reflecting the final order were implemented with the first billing cycle of February 2009.  During 2009, PSO accrued a regulatory liability of approximately $1$32 million related to a delay in installing gridSMART technologies as the OCC final order had included $2 million of additional revenues for this purpose.

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

Oklahoma Capital Reliability Rider Filing – Affecting PSO

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

$16 million and other requested increases of $27 million.  In October 2009, all but two of the parties to the CRR filing agreed to a stipulation that was filed with the OCC to collect no more than $30 million of revenues under the CRR on an annual basis beginning JanuaryApril 2010, until PSO’s next base rate order.  The CRR revenues are subject to refund with interest pending the OCC’s audit.  The stipulation also provides for an offsetting fuel revenue reduction via a modification to the fuel adjustment factor of Oklahoma jurisdictional customers on an annual basis by $30 million beginning January 2010 and refunds of certain over-recovered fuel balances during the first quarter of 2010.  Finally, the stipulation requires that PSO shall file a base rate case no later than July 2010.  Management is unable to predict the outcome of this application.

PSO Purchase Power Agreement – Affecting PSO

As a result of the 2008 Request for Proposals following a December 2007 OCC order that found PSO had a need for new base load generation by 2012, PSO and Exelon Generation Company LLC, a subsidiary of Exelon Corporation, executed a long-term purchase power agreement (PPA).  The PPA is for the annual purchase of approximately 520 MW of electric generation from the 795 MW natural gas-fired generating plant in Jenks, Oklahoma for a term of approximately ten years beginning in June 2012.  In May 2009, an application seeking approval was filed with the OCC.  In July 2009, OCC staff, the Independent Evaluator and the Oklahoma Industrial Energy Consumers filed responsive testimony in support of PSO’s proposed PPA with Exelon.  In August 2009, a settlement agreement was filed withapproved by the OCC.PUCT to increase SWEPCo’s base rates by approximately $15 million annually, effective May 2010, including a return on equity of 10.33%, which consists of $5 million related to construction of the Stall Unit and $10 million in other increases.  In September 2009, the OCC approvedaddition, the settlement agreement including the recovery of these purchased powerwill decrease annual depreciation expense by $17 million and allows SWEPCo a $10 million on e-year surcharge rider to recover additional vegetation management costs through a separate base load purchased power rider.that SWEPCo must spend within two years.

Louisiana Rate Matters

2008 Formula Rate Filing – Affecting SWEPCo

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

2009 Formula Rate Filing – Affecting SWEPCo

In April 2009, SWEPCo filed the second FRP which would increase its annual Louisiana retail rates by an additional $4 million effective in August 2009 pursuant to the approved FRP.  SWEPCo implemented the FRP rate increase as filed in August 2009, subject to refund.  In October 2009, consultants for the LPSC objected to certain components of SWEPCo’s FRP calculation.  The consultants also recommended refunding the SIA through SWEPCo’s FRP.  See “Allocation of Off-system Sales Margins” section within “FERC Rate Matters.”  SWEPCo will continue to work with the LPSC regarding the issues raised in their objection.  SWEPCo believes the rates as filed are in compliance with the FRP methodology previously approved by the LPSC.  If the LPSCLPS C disagrees with SWEPCo, it could result in material refunds.refunds which would reduce future net income and cash flows and impact financial condition.

Stall Unit – Affecting SWEPCoAPCo and WPCo Rate Matters

2009 Virginia Base Rate Case

In May 2006, SWEPCo announcedJuly 2009, APCo filed a generation and distribution base rate increase with the Virginia SCC of $154 million annually based on a 13.35% return on common equity.  The Virginia SCC staff and intervenors have recommended revenue increases ranging from $33 million to $94 million.  Interim rates, subject to refund, became effective in December 2009 but were discontinued in February 2010 when Virginia newly enacted legislation suspended the collection of interim rates.  The Virginia SCC is required to issue a final order no later than July 2010 with new rates effective August 2010.  The enacted legislation also stated that depending on the revenue awarded, a refund of interim rates may not be necessary.  If a refund is required, it would reduce future net income and cash flows and impact f inancial condition.

Mountaineer Carbon Capture and Storage Project

APCo and ALSTOM Power, Inc. (Alstom), an unrelated third party, jointly constructed a CO2 capture validation facility, which was placed into service in September 2009.  APCo also constructed and owns the necessary facilities to store the CO2.  In October 2009, APCo started injecting CO2 into the underground storage facilities.  The injection of CO2 required the recording of an asset retirement obligation and an offsetting regulatory asset.  Through March 31, 2010, APCo has recorded a noncurrent regulatory asset of $111 million consisting of $72 million in project costs and $39 million in asset retirement costs.

In APCo’s July 2009 Virginia base rate filing, APCo requested recovery of and a return on its estimated increased Virginia jurisdictional share of its project costs and recovery of the related asset retirement obligation regulatory asset amortization and accretion.  The Virginia Attorney General and the Virginia SCC staff have recommended in the pending Virginia base rate case that no recovery be allowed for the project.  APCo plans to build an intermediate load, 500 MW, natural gas-fired, combustion turbine, combined cycle generating unit atseek recovery of the West Virginia jurisdictional costs in its existing Arsenal Hill Plant location in Shreveport, Louisiana to be named the Stall Unit.  SWEPCo submitted the appropriate filings to the LPSC, the PUCT, the APSC and the Louisiana Department of Environmental Quality to seek approvals to construct the Stall Unit.  The Stall Unit is currently estimated to cost $435 million, including $49 million of AFUDC, andnext West Virginia base rate filing which is expected to be filed in servicethe second quarter of 2010.  If APCo cannot recover all of its investment in mid-2010.

The Louisiana Department of Environmental Quality issued an air permit forand expenses related to the Stall Unit in March 2008.  In July 2008, a Louisiana ALJ issued a recommendation that SWEPCo be authorized to construct, ownMountaineer Carbon Capture and operate the Stall Unit and recommended that costs be capped at $445 million including AFUDC and excluding related transmission costs.  In October 2008, the LPSC issued a final order effectively approving the ALJ recommendation.  In March 2007, the PUCT approved SWEPCo’s request for a certificate of necessity for the facility based on a prior cost estimate.  In December 2008, SWEPCo submitted an amended filing seeking approval from the APSC to construct the unit.  The APSC staff filed testimony in March 2009 supporting the approval of the plant.  In June 2009, the APSC approved the construction of the unit with a series of conditions consistent with those designated by the LPSC, including a requirement for an independent monitor and a $445 million cost cap including AFUDC and excluding related transmission costs.

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

APCo’s Filings for an IGCC Plant

Temporary Funding of Financing Costs during Construction – Affecting SWEPCo

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

Louisiana Fuel Adjustment Clause Audit – Affecting SWEPCo

In July 2009, consultants for the LPSC issued their audit report of SWEPCo’s Louisiana retail FAC.  Various recommendations were contained within the audit report including two recommendations that might result in a financial impact that could be material for SWEPCo.  The first recommendation is that SWEPCo should provide the variable operation and maintenance and SO2 allowance costs that were included in SWEPCo’s purchased power costs and that those costs should be disallowed from 2003 until the effective date of the order in this proceeding.  Management does not believe any variable operation and maintenance and SO2 allowance costs included in SWEPCo’s purchased power costs since 2003 would be material.  The second recommendation is that the LPSC should discontinue SWEPCo’s tiered sharing mechanism related to off-system sales margins on a prospective basis.  In addition, the audit report contained a recommendation that SWEPCo should reflect the SIA refunds as reductions in the Louisiana FAC rates as soon as possible, including interest through the date the refunds are reflected in the FAC.  See “Allocation of Off-system Sales Margins” section within “FERC Rate Matters.”  Management is unable to predict how the LPSC will rule on the recommendations in the audit report and its financial statement impact on net income and cash flows.

Turk Plant – Affecting SWEPCo

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

Arkansas Rate Matters

Turk Plant – Affecting SWEPCo

In August 2006, SWEPCo announced plans to build the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas.  SWEPCo submitted filings with the APSC, the PUCT and the LPSC seeking certification of the plant.  In 2007, the Oklahoma Municipal Power Authority (OMPA) acquired an approximate 7% ownership interest in the Turk Plant, paid SWEPCo $13.5 million for its share of the accrued construction costs and began paying its proportional share of ongoing costs. During the first quarter of 2009, the Arkansas Electric Cooperative Corporation (AECC) and the East Texas Electric Cooperative (ETEC) acquired ownership interests in the Turk Plant representing approximately 12% and 8%, respectively, paid SWEPCo $104 million in the aggregate for their shares of accrued construction costs and began paying their proportional shares of ongoing construction costs.  The joint owners are billed monthly for their share of the on-going construction costs exclusive of AFUDC.  Through September 30, 2009, the joint owners paid SWEPCo $196 million for their share of the Turk Plant construction expenditures.  SWEPCo owns 73% of the Turk Plant and will operate the completed facility.  The Turk Plant is currently estimated to cost $1.6 billion, excluding AFUDC, with SWEPCo’s share estimated to cost $1.2 billion, excluding AFUDC.  In addition, SWEPCo will own 100% of the related transmission facilities which are currently estimated to cost $131 million, excluding AFUDC.

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

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

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

In March 2008, the LPSC approved the application to construct the Turk Plant.  In August 2008, the PUCT issued an order approving the Turk Plant with the following four conditions: (a) the capping of capital costs for the Turk Plant at the previously estimated $1.522 billion projected construction cost, excluding AFUDC and related transmission costs, (b) capping CO2 emission costs at $28 per ton through the year 2030, (c) holding Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers and (d) providing the PUCT all updates, studies, reviews, reports and analyses as previously required under the Louisiana and Arkansas orders.  In October 2008, SWEPCo appealed the PUCT’s order regarding the two cost cap restrictions as being unlawful.  In October 2008, an intervenor filed an appeal contending that the PUCT’s grant of a conditional Certificate of Public Convenience and Necessity (CPCN) to construct a 629 MW IGCC power plant in Mason County, West Virginia.  APCo also requested the Virginia SCC and the WVPSC to approve a surcharge rate mechanism to provide for the Turk Plant was not necessary to serve retail customers. If the cost cap restrictions are upheld and construction or CO2 emissiontimely recovery of pre-construction costs exceed the restrictions or if the intervenor appeal is successful, it could have an adverse effect on net income, cash flows and possibly financial condition.

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

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

SWEPCo is also working with the U.S. Army Corps of Engineers for the approval of a wetlands and stream impact permit.  In March 2009, SWEPCo reported to the U.S. Army Corps of Engineers an inadvertent impact on approximately 2.5 acres of wetlands at the Turk Plant construction site prior to the receipt of the permit.  The U.S. Army Corps of Engineers directed SWEPCo to cease further work impacting the wetland areas.  Construction has continued on other areas outside of the proposed Army Corps of Engineers permitted areas of the Turk Plant pending the Army Corps of Engineers review.  SWEPCo has entered into a Consent Agreement and Final Order with the Federal EPA to resolve liability for the inadvertent impact and agreed to pay a civil penalty of approximately $29 thousand.

The Arkansas Governor’s Commission on Global Warming issued its final report to the governor in October 2008.  The Commission was established to set a global warming pollution reduction goal together with a strategic plan for implementation in Arkansas.  The Commission’s final report included a recommendation that the Turk Plant employ post combustion carbon capture and storage measures as soon as it starts operating.  To date, the report’s effect is only advisory, but if legislation is passed as a result of the findings in the Commission’s report, it could impact SWEPCo’s ability to complete construction on schedule in 2012 and on budget.

If the Turk Plant cannot be completed and placed in service, SWEPCo would seek approval to recover its prudently incurred capitalized constructioncapital costs, including any cancellation feesoperating costs and a return on unrecovered balances through ratesequity once the facility is placed into commercial operation.  The WVPSC granted APCo the CPCN and approved the requested cost recovery.  Various intervenors filed petitions with the WVPSC to reconsider the order.

In 2008, the Virginia SCC issued an order denying APCo’s request for a surcharge rate mechanism based upon its finding that the estimated cost of the plant was uncertain and may escalate.  The Virginia SCC also expressed concerns that the estimated costs did not include a retrofitting of carbon capture and sequestration facilities.  During 2009, based on an unfavorable order received in allVirginia, the WVPSC removed the IGCC case as an active case from its docket and indicated that the conditional CPCN granted in 2008 must be reconsidered if and when APCo proceeds forward with the IGCC plant.

Through March 31, 2010, APCo deferred for future recovery pre-construction IGCC costs of its jurisdictions.  As of September 30, 2009, and excluding costs attributableapproximately $9 million applicable to its joint owners, SWEPCo has capitalizedWest Virginia jurisdiction, approximately $646$2 million of expenditures (including AFUDCapplicable to its FERC jurisdiction and capitalized interest, and related transmission costs of $24 million).  As of September 30, 2009, the joint owners and SWEPCo have contractual construction commitments of approximately $515$9 million (including related transmission costs of $1 million) and, if the plant had been cancelled, would have incurred cancellation fees of $136 million (including related transmission cancellation fees of $1 million).applicable to its Virginia jurisdiction.

Management believes that SWEPCo’s planning, certification andAPCo will not start construction of the Turk PlantIGCC plant until sufficient assurance of full cost recovery exists in Virginia and in West Virginia.  If the plant is cancelled, APCo plans to date have been in material compliance with all applicable laws and regulations, except for the inadvertent wetlands intrusion discussed above.  Further, management expects that SWEPCo will ultimately be able to complete constructionseek recovery of the Turk Plant and related transmission facilities and place those facilities in service.  However,its prudently incurred deferred pre-construction costs which, if for any reason SWEPCo is unable to complete the Turk Plant construction and place the Turk Plant in service, itnot recoverable, would adversely impactreduce future net income and cash flows and possiblyimpact financial condition unless the resultant losses can be fully recovered, with a return on unrecovered balances, through rates in all of its jurisdictions.condition.

Arkansas Base RateAPCo’s 2009 Expanded Net Energy Charge (ENEC) Filing – Affecting SWEPCo

In February 2009, SWEPCo filed an application with the APSC for a base rate increase of $25 million based on a requested return on equity of 11.5%.  SWEPCo also requested a separate rider to recover financing costs related to the construction of the Stall Unit and Turk Plant.

In September 2009, SWEPCo, the APSCWVPSC issued an order approving APCo’s March 2009 ENEC request.  The approved order provided for recovery of an under-recovered balance plus a projected increase in ENEC costs over a four-year phase-in period with an overall increase of $320 million and a first-year increase of $112 million, effective October 2009.  The WVPSC also approved a fixed annual carrying cost rate of 4%, effective October 2009, to be applied to the incremental deferred regulatory asset balance that will result from the phase-in plan.  In March 2010, APCo filed its second-year request with the WVPSC to increase rates in July 2010 by $86 million.  As of March 31, 2010, APCo’s ENEC under-recovery balance was $318 million which is included in noncurrent regulatory assets.

The September 2009 order also lowered annual coal cost projections by $27 million and deferred recovery of unrecovered ENEC deferrals related to price increases on certain renegotiated coal contracts.  The WVPSC indicated that it would review the prudency of these additional costs in the next ENEC proceeding.  As of March 31, 2010, APCo has deferred $23 million of unrecovered coal costs on the renegotiated coal contracts which is included in APCo’s $318 million ENEC regulatory asset and has recorded an additional $5 million in fuel inventory related to the renegotiated coal contracts, which is recorded in Fuel on the balance sheets.  Although management believes the portion of its deferred ENEC under-recovery balance attributable to renegotiated coal contracts is probable of recovery, if the WVPSC we re to disallow a portion of APCo’s deferred ENEC costs including any costs incurred in the future related to the renegotiated coal contracts, it could reduce future net income and cash flows and impact financial condition.

WPCo Merger with APCo

In a proceeding established by the WVPSC to explore options to meet WPCo's future power supply requirements, the WVPSC, in November 2009, issued an order approving a joint stipulation among APCo, WPCo, the WVPSC staff and the ArkansasConsumer Advocate Division.  The order approved the recommendation of the signatories to the stipulation that WPCo merge into APCo and be supplied from APCo's existing power resources.  The order also indicated that it is in the best interests of West Virginia customers that the merger occur as quickly as possible.  Merger approvals from the WVPSC, Virginia SCC and the FERC are required.  No merger approval filings have been made.

PSO Rate Matters

PSO Fuel and Purchased Power

2006 and Prior Fuel and Purchased Power

The OCC filed a complaint with the FERC related to the allocation of off-system sales margins (OSS) among the AEP operating companies in accordance with a FERC-approved allocation agreement.  The FERC issued an adverse ruling in 2008.  As a result, PSO recorded a regulatory liability in 2008 to return reallocated OSS to customers.  Starting in March 2009, PSO refunded the additional reallocated OSS to its customers through February 2010.

A reallocation of purchased power costs among AEP West companies for periods prior to 2002 resulted in an under-recovery of $42 million of PSO fuel costs.  PSO recovered the $42 million by offsetting it against an existing fuel over-recovery during the period June 2007 through May 2008.  The Oklahoma Industrial Energy Consumers (OIEC) has contended that PSO should not have collected the $42 million without specific OCC approval.  As such, the OIEC contends that the OCC should require PSO to refund the $42 million it collected through its fuel clause.  The OCC has heard the OIEC appeal and a decision is pending.  In March 2010, PSO filed motions to advance this proceeding since the FERC has ruled on the allocation of off-system sales margins proceeding and PSO has refunded the additional margins to its retail customers.  If the OCC were to order PSO to refund all or a part of the $42 million, it would reduce future net income and cash flows and impact financial condition.

2008 Fuel and Purchased Power

In July 2009, the OCC initiated a proceeding to review PSO’s fuel and purchased power adjustment clause for the calendar year 2008 and also initiated a prudency review of the related costs.  In March 2010, the Oklahoma Attorney General entered intoand the OIEC recommended the fuel clause adjustment rider be amended so that the shareholder’s portion of off-system sales margins sharing decrease from 25% to 10%.  The OIEC also recommended that the OCC conduct a settlement agreement in which the settling parties agreed to an $18 million increase based on a return on equitycomprehensive review of 10.25%.  In addition, the settlement agreement decreased depreciation expense by $10 million.  The settlement agreement would increase SWEPCo’s annual pretax income by approximately $28 million.  The settlement agreement also includes a separate rider of approximately $11 million annually that will allow SWEPCo to recover carrying costs, depreciationall affiliate transactions during 2007 and operation and maintenance expenses on the Stall Unit once it is placed into service.  Until then, SWEPCo will continue to accrue AFUDC on the Stall Unit.  The other parties to the case do not oppose the settlement agreement.2008.  If the settlement agreement is approved by the APSC, new base rates will become effective for all bills rendered on or after November 25, 2009.OCC were to issue an unfavorable decision, it would reduce future net income and cash flows and impact financial condition.

2008 Oklahoma Base Rate Appeal

In January 2009, the OCC issued a final order approving an ice storm struck$81 million increase in northern Arkansas affecting SWEPCo’s customers.  SWEPCo incurred incremental operation and maintenance expenses abovePSO’s non-fuel base revenues based on a 10.5% return on equity.  The new rates reflecting the estimated amount of storm restoration costs included in existing base rates.  In May 2009, SWEPCo filed an applicationfinal order were implemented with the APSC seeking authorityfirst billing cycle of February 2009.  PSO and intervenors filed appeals with the Oklahoma Supreme Court raising various issues.  The Oklahoma Supreme Court assigned the case to defer $4 million (later adjustedthe Court of Civil Appeals.  If the intervenors’ appeals are successful, it could reduce future net income and cash flows and impact financial condition.

I&M Rate Matters

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

I&M filed applications with the IURC to $3 million) of expensed incremental operation and maintenance costs and to address the recovery of these deferred expenses in the pending base rate case.  In July 2009, the APSC issued an order approving the deferral request subject to investigation, analysis and audit of the costs.  In August 2009, the APSC staff filed testimony that recommended recovery ofincrease its fuel adjustment charge by approximately $1 million per year through amortization of the deferred ice storm costs over three years in base rates.  This amount was included in the $18 million base rate increase agreed upon in the settlement agreement.  In September 2009, based upon the APSC audit and recommendation, management established a regulatory asset of $3$53 million for the recoveryperiod of April 2009 through September 2009.  The filings sought increases for previously under-recovered fuel clause expenses.

As fully discussed in the “Cook Plant Unit 1 Fire and Shutdown” section of Note 4, Cook Unit 1 was shut down in September 2008 due to significant turbine damage and a small fire on the electric generator.  Unit 1 was placed back into service in December 2009 at slightly reduce power.  The unit outage resulted in increased replacement power fuel costs.  The filing only requested the cost of replacement power through mid-December 2008, the date when I&M began receiving accidental outage insurance proceeds.  I&M committed to absorb the costs of replacement power through the date the unit returned to service, which occurred in December 2009.

I&M reached an agreement with intervenors, which was approved by the IURC in March 2009, to collect its existing prior period under-recovery regulatory asset deferral balance over twelve months instead of over six months as initially proposed.  Under the agreement, the fuel factors were placed into effect, subject to refund, and a subdocket was established to consider issues relating to the Unit 1 shutdown including the treatment of the ice storm restorationaccidental outage insurance proceeds.  A procedural schedule has been established for the subdocket with hearings expected to be held in November 2010.
Management believes that I&M is entitled to retain the accidental outage insurance proceeds since it made customers whole regarding the replacement power costs.  If any fuel clause revenues or accidental outage insurance proceeds have to be refunded, it would reduce future net income and cash flows and impact financial condition.

Stall2009 Power Supply Cost Recovery (PSCR) Reconciliation (Cook Plant Unit – Affecting SWEPCo1 Fire and Shutdown)

In March 2010, I&M filed its 2009 PSCR reconciliation with the MPSC.  The filing included an adjustment to exclude from the PSCR the incremental fuel cost of replacement power due to the Cook Plant Unit 1 outage from mid-December 2008 through December 2009, the period during which I&M received and recognized the accidental outage insurance proceeds.  Management believes that I&M is entitled to retain the accidental outage insurance proceeds since it made customers whole regarding the replacement power costs.  If any fuel clause revenues or accidental outage insurance proceeds have to be refunded, it would reduce future net income and cash flows and impact financial condition.  See “Stall Unit”the “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.

Michigan Base Rate Filing

In January 2010, I&M filed for a $63 million increase in annual base rates based on an 11.75% return on common equity.  I&M can request interim rates, subject to refund, after six months.  The MPSC must issue a final order within “Louisiana Rate Matters” for disclosure.one year.

FERC Rate Matters

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

SECASeams Elimination Cost Allocation (SECA) Revenue Subject to Refund

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

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

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

In September 2006, AEP filed briefs jointly with other affected companies noting exceptions to the ALJ’s initial decision and asking the FERC to reverse the decision in large part.decision.  Management believes based on advice of legal counsel, that the FERC should reject the ALJ’s initial decision because it contradicts prior related FERC decisions, which are presently subject to rehearing.  Furthermore, management believes the ALJ’s findings on key issues are largely without merit.  AEP and SECA ratepayers arehave been engaged in settlement discussions in an effort to settle the SECA issue.  However, if the ALJ’s initial decision is upheld in its entirety, it could result in a refund of a portion or all of the unsettled SECA revenues.  In December 2009, several parties filed a motion with the U.S. Court of Appeals to force the FERC to res olve the SECA issue.

Based on anticipated settlements, theThe AEP East companies provided reserves for net refunds for current and future SECA settlements totaling $39$44 million and $5 million in 2006 and 2007, respectively, applicable to a total ofthe $220 million of SECA revenues.revenues collected.  APCo’s, CSPCo’s, I&M’s and OPCo’s portions of the provision are as follows:

 2007  2006 
Company (in millions)  (in millions) 
APCo $1.7  $12.4  $14.1 
CSPCo  0.9   6.9   7.8 
I&M  1.0   7.3   8.3 
OPCo  1.3   9.4   10.7 

In February 2009, a settlement agreement wasSettlements approved by the FERC resulting in the completion of a $1 million settlement applicable to $20consumed $10 million of SECA revenue.  Including this most recent settlement, AEP has completed settlements totaling $10 millionthe reserve for refunds applicable to $112 million of SECA revenues.revenue.  The balance in the reserve for future settlements as of March 31, 2010 was $34 million.  As of September 30, 2009,March 31, 2010 there were no in-process settlements.  APCo’s, CSPCo’s, I&M’s and OPCo’s reserve balancebalances at September 30, 2009 was:March 31, 2010 were:

Company March 31, 2010 
 September 30, 2009  (in millions) 
Company (in millions) 
APCo $10.7  $10.7 
CSPCo  5.9   5.9 
I&M  6.3   6.3 
OPCo  8.2   8.2 

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

The FERC PJM Regional Transmission Rate Proceeding

With the elimination of T&O rates, the expiration of SECA rates and after considerable administrative litigation at the FERC in which AEP sought to mitigate the effect of the T&O rate elimination, the FERC failed to implement a regional rate in PJM.  As a result, the AEP East companies’ retail customers incur the bulk of the cost of the existing AEP east transmission zone facilities even though other non-affiliated entities transmit power over AEP’s lines.  However, the FERC ruled that the cost of any new 500 kV and higher voltage transmission facilities built in PJM would be shared by all customers in the region.  It is expected that most of the new 500 kV and higher voltage transmission facilities will be built in other zones of PJM, not AEP’s zone.  The AEP East companies will need to obtain state regulatory approvals for recovery of any costs of new facilities that are assigned to them by PJM.  In February 2008, AEP filed a Petition for Review of the FERC orders in this case in the United States Court of Appeals.  In August 2009, the United States Court of Appeals issued an opinion affirming FERC’s refusal to implement a regional rate design in PJM.

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

The FERC PJM and MISO Regional Transmission Rate Proceeding

In the SECA proceedings, the FERC ordered the RTOs and transmission owners in the PJM/MISO region (the Super Region) to file, by August 1, 2007, a proposal to establish a permanent transmission rate design for the Super Region to be effective February 1, 2008.  All of the transmission owners in PJM and MISO, with the exception of AEP and one MISO transmission owner, elected to support continuation of zonal rates in both RTOs.  In September 2007, AEP filed a formal complaint proposing a highway/byway rate design be implemented for the Super Region where users pay based on their use of the transmission system.  AEP argued the use of other PJM and MISO facilities by AEP is not as large as the use of the AEP East companies’ transmission by others in PJM and MISO and as a result the use of zonal rates would be unfair and discriminatory to AEP’s East zone retail customers.  Therefore, a regional rate design change is required to recognize that the provision and use of transmission service in the Super Region is not sufficiently uniform between transmission owners and users to justify zonal rates.  In January 2008, the FERC denied AEP’s complaint.  AEP filed a rehearing request with the FERC in March 2008.  In December 2008, the FERC denied AEP’s request for rehearing.  In February 2009, AEP filed an appeal in the U.S. Court of Appeals.  If the court appeal is successful, earnings could benefit for a certain period of time due to regulatory lag until the AEP East companies reduce future retail revenues in their next fuel or base rate proceedings to reflect the resultant additional wholesale transmission T&O revenues reduction of transmission cost to retail customers.  This case is pending before the U.S. Court of Appeals which in August 2009 ruled against AEP in a similar case.  See “The FERC PJM Regional Transmission Rate Proceeding” section above.impact financial condition.

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

In August 2008, theThe OCC filed a complaint at the FERC alleging that AEP inappropriately allocated off-system sales margins between the AEP East companies and the AEP West companies and did not properly allocate off-system sales margins within the AEP West companies.  The PUCT, the APSC and the Oklahoma Industrial Energy Consumers intervened in this filing.

In November 2008, the FERC issued a final order concluding that AEP inappropriately deviated from off-system sales margin allocation methods in the SIA and the CSW Operating Agreement for the period June 2000 through March 2006.  The FERC ordered AEP to recalculate and reallocate the off-system sales margins in compliance with the SIA and to have the AEP East companies issue refunds to the AEP West companies.  Although the FERC determined that AEP deviated from the CSW Operating Agreement, the FERC determined the allocation methodology was reasonable.  The FERC ordered AEP to submit a revised CSW Operating Agreement for the period June 2000 to March 2006.  In December 2008, AEP filed a motion for rehearing and a revised CSW Operating Agreement for the period June 2000 to March 2006.  The motion for rehearing is still pending.

In January 2009, AEP filedmade a compliance filing with the FERC and the AEP East companies refunded approximately $250 million from the AEP East companies to the AEP West companies.  Following authorized regulatory treatment, the AEP West companies shared a portion of SIA margins with their customers during the period June 2000 to March 2006.  In December 2008, the AEP West companies recorded a provision for refund reflecting the sharing.  In January 2009,Refunds have been or are currently being returned to PSO’s and SWEPCo’s Texas, Arkansas and FERC customers.  SWEPCo refunded approximately $13 million to FERC wholesale customers.  In February 2009, SWEPCo filed a settlement agreementis working with the PUCT that provides forLPSC to determine how the TexasFERC ordered refund will be made to its Louisiana retail jurisdiction amount to be included in the March 2009 fuel cost report submitted to the PUCT.  PSO began refunding approximately $54 million plus accrued interest to Oklahoma retail customers through the fuel adjustment clause over a 12-month period beginning with the March 2009 billing cycle.

In July 2009, consultantscustomers.  Consultants for the LPSC issued an audit report of SWEPCo’s Louisiana retail fuel adjustment clause.  Within this report, the consultants for thet he LPSC recommended that SWEPCo refund the SIA, including interest, through the fuel adjustment clause.  See “Louisiana Fuel Adjustment Clause Audit” section within “Louisiana“SWEPCo Rate Matters.”  In October 2009, otherOther consultants for the LPSC recommended refunding the SIA through SWEPCo’s formula rate plan.  See “2009 Formula Rate Filing” section within “Louisiana Rate Matters.”  SWEPCo is working with the APSC and the LPSC to determine the effect the FERC order will have on retail rates.  Management cannot predict the outcome of the requested FERC rehearing proceeding orif there will be any future state regulatory proceedings but believes the AEP West companies’ provision for refund regarding related future state regulatory proceedings is adequate.

Modification of the Transmission Agreement (TA) – Affecting APCo, CSPCo, I&M and OPCo

APCo, CSPCo, I&M, KPCo and OPCo are parties to the TA entered into in 1984, as amended, that provides for a sharing of the cost of transmission lines operated at 138-kV and above and transmission stations operated at 345kV and above.containing extra-high voltage facilities.  In June 2009,  AEPSC, on behalf of the parties to the TA, filed with the FERC a request to modify the TA.  Under the proposed amendments, WPCoKGPCo and KGPCoWPCo will be added as parties to the TA.  In addition, the amendments would provide for the allocation of PJM transmission costs on the basis of the TA parties’ 12-month coincident peak and reimburse the majority of PJM transmission revenues based on individual cost of service instead of the MLR method used in the present TA.  AEPSC requested the effective date to be the first day of the month following a final non-appealable FERC order. 0; The delayed effective date was approved by the FERC in August 2009 when the FERC accepted the new TA for filing.  Settlement discussions are in process.  Managementprogress.  Once approved by the FERC, management is unable to predict whether the effect, if any, itparties to the TA will haveexperience regulatory lag and its effect on future net income and cash flows due to timing of the implementation of the modified TA by various state regulatorsregulators.

PJM/MISO Market Flow Calculation Errors – Affecting APCo, CSPCo, I&M and OPCo

During 2009, an analysis conducted by MISO and PJM discovered several instances of unaccounted for power flows on numerous coordinated flowgates.  These flows affected the settlement data for congestion revenues and expenses and date back to the start of the FERC’s new approved TA.MISO market in 2005.  PJM has provided MISO an initial analysis of amounts they believe they owe MISO.  MISO disputes PJM’s methodology.

Settlement discussions between MISO and PJM have been unsuccessful, and as a result, in March 2010, MISO filed two related complaints against PJM at the FERC related to the above claim.  MISO seeks to recover a total of approximately $145 million from PJM.  Given that PJM passes its costs on to its members, if PJM is held liable for these damages, PJM members, including the AEP East companies, may be held responsible for a share of the refunds or payments PJM is directed to make to MISO.  AEP has intervened and filed a protest to one complaint.  Management believes that MISO's claims filed at the FERC are without merit and that PJM's right to recover from AEP and other members any damages awarded to MISO is limited.  If the FERC orders a settlement above the AEP East companies’ re serve related to their estimated portion of PJM additional costs, it could reduce future net income and cash flows and impact financial condition.

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

In July 2008, AEP filed an application with the FERC in July 2008 to increase its open access transmission tariff (OATT) rates for wholesale transmission service within PJM by $63 million annually.PJM.  The filing seekssought to implement a formula rate allowing annual adjustments reflecting future changes in the AEP East companies' cost of service.  In September 2008, theThe FERC issued an order conditionally accepting AEP’s proposed formula rate subject to a compliance filing, established a settlement proceeding with an ALJ and delayed the requested October 2008 effective date for five months.  In October 2008, AEP filed the required compliance filing and began settlement discussions with the intervenors and the FERC staff.  Thestaff which resulted in a settlement discussions are currently ongoing.that was filed with the FERC in April 2010.

The requestedpending settlement results in a $51 million annual increase which the AEP East companies began billingbeginning in April 2009 for service as of March 1, 2009, will produce a $63of which approximately $7 million annualized increase in revenues.  Approximately $8 million of the increase will beis being collected from nonaffiliated customers within PJM.  The remaining $55$44 million requested would beis being billed to the AEP East companies but would beand is generally offset by compensation from PJM for use of the AEP East companies’ transmission facilities so that retail rates for jurisdictions other than Ohio arenet income is not directly affected.  Retail rates for CSPCo and OPCo would be increased on an annual basis through the transmission cost recovery rider (TCRR) mechanism by approximately $10 million and $13 million, respectively.  The TCRR includes a true-up mechanism so CSPCo’s and OPCo’s net income will not be adversely affected by a FERC-ordered transmission rate increase.

In May 2009,The pending settlement also results in an additional $30 million increase for the first annual update of the formula rate, was filed with the FERC which reflected increased transmission service revenue requirements of approximately $32 million on an annualized basis, effectivebeginning in August 2009 for service as of July 1, 2009 to be billed in August 2009.  Approximately $4 million of the increase will be collected from nonaffiliated customers within PJM.  Retail rates for CSPCo and OPCo would be increased throughPJM with the TCRR mechanism by approximately $5remaining $26 million and $7 million, respectively.  Beginning in December 2009, APCo's Virginia transmission rate adjustment clause is expectedbeing billed to become effective and thus APCo will recover approximately $2 million of this increase.  Retail rates for otherthe AEP East jurisdictions are not directly affected.companies.

Under the formula, the secondan annual update will be filed to be effective July 1, 2010 and each year thereafter.  Also, beginning with the July 1, 2010 update, the rates each year will include an adjustment to true-up the prior year's collections to the actual costs for the prior year.  Management is unable to predict the outcome ofexpects the settlement discussions or any further proceedings that might be necessary if settlement discussions are not successful.

SPP Transmission Formula Rate Filing – Affecting PSO and SWEPCo

In June 2007, AEPSC filed revised tariffs to establish an up-to-date revenue requirement for SPP transmission services over the facilities owned by PSO and SWEPCo and to implement an open access transmission tariff (OATT) formula rate.  PSO and SWEPCo requested an effective date of September 1, 2007 for the revised tariff.  If approved as filed, the revised tariff will increase annual network transmission service revenues from nonaffiliated municipal and rural cooperative utilities in the AEP pricing zone of SPP by approximately $10 million.

In August 2007, the FERC issued an order conditionally accepting PSO’s and SWEPCo’s proposed formula rate, subject to a compliance filing, suspended the effective date until February 1, 2008 and established a hearing schedule and settlement proceedings.  New rates, subject to refund, were implemented in February 2008.  Multiple intervenors protested or requested rehearing of the August 2007 order.  In October 2007, PSO and SWEPCo filed the required compliance filing, and began settlement discussions with the intervenors and FERC staff.  Under the formula, rates were updated effective July 1, 2009 and will be updated each year thereafter.  Also, beginning withapproved by the July 1, 2010 update, the rates each year will include an adjustment to true-up the prior year's collections to the actual costs for the prior year.  In February 2009, a settlement agreement was reached and was filed with the FERC.  In 2009, a provision for refund was recorded by PSO and SWEPCo based upon the pending settlement.  In June 2009, the FERC approved the settlement agreement and refunds were made to customers.

Transmission Agreement (TA) – Affecting APCo, CSPCo, I&M and OPCo

Certain transmission facilities placed in service in 1998 were inadvertently excluded from the AEP East companies’ TA calculation prior to January 2009.  The excluded equipment was the Inez stationStation which had been determined as eligible equipment for inclusion in the TA in 1995 by the AEP TA transmission committee.  The amount involved was $7 million annually.  Management does not believe that it is probable that a material retroactive rate adjustment will result from the omission.  However, if a retroactive adjustment is required, APCo, CSPCo, I&M and OPCoit could experience adverse effects onreduce future net income and cash flows and impact financial condition.


4.       COMMITMENTS, GUARANTEES AND CONTINGENCIES
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 20082009 Annual Report should be read in conjunction with this report.

GUARANTEES

Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.”  There is no collateral held in relation to any guarantees.  In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

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

Certain Registrant Subsidiaries enter into standby letters of credit (LOCs) with third parties.  These LOCs cover items such as insurance programs, security deposits and debt service reserves.  These LOCs were issued in the ordinary course of business under the two $1.5 billion 5-year credit facilities.  The facilities are structured as two $1.5 billion credit facilities, of which $750 million may be issued under each credit facility as LOCs.

The Registrant Subsidiaries and certain other companies in the AEP System have a $627 million 3-year credit agreement.  As of September 30, 2009, $372March 31, 2010, $477 million of letters of creditLOCs were issued by Registrant Subsidiaries under the $627 million 3-year credit agreement to support variable rate Pollution Control Bonds.  The Registrant Subsidiaries and certain other companies in the AEP System had a $350 million 364-day credit agreement that expired in April 2009.

At September 30, 2009,As of March 31, 2010, the maximum future payments of the LOCs were as follows:

      Borrower
  Amount Maturity Sublimit
Company (in thousands)     
$1.5 billion LOC:        
I&M $300  March 2010                                  N/A 
SWEPCo  4,448  December 2009                                  N/A 
         
$627 million LOC:        
APCo $126,716  June 2010 $                          300,000 
I&M  77,886  May 2010                            230,000 
OPCo  166,899  June 2010                            400,000 

      Borrower
Company Amount Maturity Sublimit
  (in thousands)     
$1.5 billion LOCs:        
I&M $300  March 2011               N/A 
SWEPCo  4,448  December 2010               N/A 
         
$627 million LOC:        
APCo $232,292  June 2010 to November 2010 $       300,000 
I&M  77,886  May 2010         230,000 
OPCo  166,899  June 2010         400,000 
Guarantees of Third-Party Obligations – Affecting SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation in the amount of approximately $65 million.  Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine Mining Company (Sabine), a consolidated variable interest entity.  This guarantee ends upon depletion of reserves and completion of final reclamation.  Based on the latest study, it is estimated the reserves will be depleted in 2029 with final reclamation completed by 2036.  A new study is in process to include new, expanded areas of the mine.  As of September 30, 2009,March 31, 2010, SWEPCo has collected approximately $42$45 million through a riderrid er for final mine closure and reclamation costs, of which $2 million is recorded in Other Current Liabilities, $17 million is recorded in Asset Retirement Obligations and $23$21 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $22 million is recorded in Asset Retirement Obligations on SWEPCo’s Condensed Consolidated Balance Sheets.

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

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

Contracts

The Registrant Subsidiaries enter into certain types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, exposure generally does not exceed the sale price.  Prior to September 30, 2009,March 31, 2010, the Registrant Subsidiaries entered into sale agreements which includedincluding indemnifications with a maximum exposure that was not significant for any individual Registrant Subsidiary.  There are no material liabilities recorded for any indemnifications.

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

Master Lease Agreements

CertainThe Registrant Subsidiaries lease certain equipment under master lease agreements.  GE Capital Commercial Inc. (GE) notified management in November 2008 that they elected to terminate the Master Leasing Agreements in accordance with the termination rights specified within the contract.  In 2010 and 2011, the Registrant Subsidiaries will be required to purchase all equipment under the lease and pay GE an amount equal to the unamortized value of all equipment then leased.  In December 2008 and 2009, management signed new master lease agreements with one-year commitment periods that include lease terms of up to 10 years.  Management expects to enter into additional replacement leasing arrangements for the equipment affected by this notification prior to the termination dates of 2010 and 2011.

For equipment under the GE master lease agreements that expire prior toin 2011, the lessor is guaranteed receipt of up to 87% of the unamortized balance of the equipment at the end of the lease term.  If the fair market value of the leased equipment is below the unamortized balance at the end of the lease term, the Registrant Subsidiaries are committed to pay the difference between the fair market value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance.  Under the new master lease agreements, the lessor is guaranteed receipt ofa residual value up to 68%a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term.  If the actual fair market value of the leased equipment is below the unamortized balanceguaranteed residual value at the end of the lease term, the Registrant SubsidiariesSubs idiaries are committed to pay the difference between the actual fair market value and unamortized balance, with the total guarantee not to exceed 68% of the unamortized balance.  Historically, at the end of the lease term the fair marketresidual value has been in excess of the unamortized balance.guarantee.  At September 30, 2009,March 31, 2010, the maximum potential loss by Registrant Subsidiary for these lease agreements assuming the fair market value of the equipment is zero at the end of the lease term is as follows:

Maximum 
Potential  Maximum 
Loss  Potential 
Company(in thousands)  Loss 
 (in thousands) 
APCo $804   $236 
CSPCo  343    57 
I&M  555    405 
OPCo  750    187 
PSO  1,024    351 
SWEPCo  665    322 

Historically, at the end of the lease term the fair value has been in excess of the unamortized balance.

Railcar Lease

In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars.  The lease is accounted for as an operating lease.  In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars).  The assignment is accounted for as operating leases for I&M and SWEPCo.  The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years.  I&M and SWEPCo intend to renew these leases for the full lease term of twenty years, via the renewal options.  The future minimum lease obligations are $19$18 million forfo r I&M and $22$21 million for SWEPCo for the remaining railcars as of September 30, 2009.March 31, 2010.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from approximately 84% under the current five-yearfive year lease term to 77% at the end of the 20-year20 year term of the projected fair market value of the equipment.  I&M and SWEPCo have assumed the guarantee under the return-and-sale option.  I&M’s maximum potential loss related to the guarantee is approximately $12 million ($8 million, net of tax) and SWEPCo’s is approximately $13 million ($9 million, net of tax) assuming the fair market value of the equipment is zero at the end of the current five-year lease term.term.  However, management believes that the fair market value wouldwou ld produce a sufficient sales price to avoid any loss.

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

ENVIRONMENTAL CONTINGENCIES

Federal EPA Complaint and Notice of Violation – Affecting CSPCo

The Federal EPA, certain special interest groups and a number of states alleged that a unit jointly owned byAPCo, CSPCo, Dayton PowerI&M and Light Company and Duke Energy Ohio, Inc.OPCo modified certain units at the Beckjord Station was modifiedtheir coal-fired generating plants in violation of the NSR requirements of the CAA.

  Cases with similar allegations against CSPCo, Dayton Power and Light Company (DP&L) and Duke Energy Ohio, Inc. were also filed related to their jointly-owned units.  The cases were settled with the exception of a case involving a jointly-owned Beckjord caseunit which had a liability trial in 2008.trial.  Following the trial, the jury found no liability for claims made against the jointly-owned Beckjord unit.  In December 2008, however, the court ordered a new trial in the Beckjord case.  Following a second liability trial in 2009, the jury again found no liability at the jointly-owned Beckjord unit.  In 2009, theThe defendants and the plaintiffs filed appeals.appealed to the Seventh Circuit Court of Appeals.  Beckjord is operated by Duke Energy Ohio, Inc.

Notice of Enforcement and Notice of Citizen Suit – Affecting SWEPCo

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

In February 2008, theThe Federal EPA issued a Notice of Violation (NOV) based on alleged violations of a percent sulfur in fuel limitation and the heat input values listed in the previous state permit.  The NOV also alleges that a permit alteration issued by the Texas Commission on Environmental Quality in 2007 was improper.  In March 2008, SWEPCo met with the Federal EPA to discuss the alleged violations in March 2008.violations.  The Federal EPA did not object to the settlement of similar alleged violations in the federal citizen suit.  Management is unable to predict the timing of any future action by the Federal EPA or the effect of such actions on net income, cash flows or financial condition.

Carbon Dioxide (CO2) Public Nuisance Claims – Affecting AEP East CompaniesAPCo, CSPCo, I&M, OPCo, PSO and AEP West CompaniesSWEPCo

In 2004, eight states and the City of New York filed an action in Federal District Court for the Southern District of New York against AEP, AEPSC, Cinergy Corp, Xcel Energy, Southern Company and Tennessee Valley Authority.  The Natural Resources Defense Council, on behalf of three special interest groups, filed a similar complaint against the same defendants.  The actions allege that CO2 emissions from the defendants’ power plants constitute a public nuisance under federal common law due to impacts of global warming and sought injunctive relief in the form of specific emission reduction commitments from the defendants.  The dismissal of this lawsuit was appealed totrial court dismissed the Second Circuit Court of Appeals.  In April 2007, the U.S. Supreme Court issued a decision holding that the Federal EPA has authority to regulate emissions of CO2 and other GHG under the CAA.  The Second Circuit requested supplemental briefs addressing the impact of the U.S. Supreme Court’s decision on this case.lawsuits.

In September 2009, the Second Circuit Court of Appeals issued a ruling vacating the dismissal andon appeal remanding the casecases to the Federal District Court for the Southern District of New York.  The Second Circuit held that the issues of climate change and global warming do not raise political questions and that Congress’ refusal to regulate GHGCO2 emissions does not mean that plaintiffs must wait for an initial policy determination by Congress or the President’s administration to secure the relief sought in their complaints.  The court stated that Congress could enact comprehensive legislation to regulate CO2 emissions or that the Federal EPA could regulate CO2 emissions under existing CAA authorities and that either of these actions could override any decision made by the district court under federal common law.  The Second Circuit did not rule on whether the plaintiffs could proceed with their state common law nuisance claims.  Management believes the actions are without merit and intends to continue to defend against the claims including seeking further review by the Second Circuit and, if necessary, the United States Supreme Court.The defendants’ petition for rehearing was denied.

In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that GHGCO2 emissions exacerbated the effects of Hurricane Katrina.  The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs’ complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims.  AEP companies, including theThe court granted petitions for rehearing and scheduled oral argument for May 24, 2010.  The Registrant Subsidiaries were initially dismissed from this case without prejudice, but are named as a defendant in a pending fourth amended complaint.

Management believes the actions are without merit and intends to continue to defend against the claims.

Alaskan Villages’ Claims – Affecting AEP East CompaniesAPCo, CSPCo, I&M, OPCo, PSO and AEP West CompaniesSWEPCo

In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company, and other electric generating companies.  The complaint alleges that the defendants' emissions of CO2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together.  The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance.  The plaintiffs also allege that the effects of global warming willwi ll require the relocation of the village at an alleged cost of $95 million to $400 million.  In October 2009, the judge dismissed plaintiffs’ federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs’ lack of standing to bring the claim.  The judge also dismissed plaintiffs’ state law claims without prejudice to refiling in state court.  The plaintiffs appealed the decision.  Management believes the action is without merit and intends to defend against the claims.
 
The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation – Affecting I&M

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

Superfund addresses clean-up of hazardous substances that have been released to the environment.  The Federal EPA administers the clean-up programs.  Several states have enacted similar laws.  In March 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M to take voluntary action necessary to prevent and/or mitigate public harm.  I&M requested remediation proposals from environmental consulting firms.  In May 2008, I&M issued a contract to one of the consulting firms and started remediation work in accordance with a plan approved by MDEQ.  I&M recorded approximately $4$11 million of expense during 2008.  Based upon updated information,prior to January 1, 2010, $3 million of which I&M recorded additional expense of $7 million in March 2009.  As the remediation work is completed, I&M’s cost may continue to increase.  I&MManagement cannot predict the amount of additional cost, if any.

Amos Plant – Request to Show Cause – Affecting APCo and OPCo

In March 2010, APCo and OPCo received a request to show cause from the Federal EPA alleging that certain reporting requirements under Superfund and the Emergency Planning and Community Right-to-Know Act had been violated and inviting APCo and OPCo to engage in settlement negotiations.  The request includes a proposed civil penalty of approximately $300 thousand.  Management indicated a willingness to engage in good faith negotiations and meet with representatives of the Federal EPA.  APCo and OPCo have not admitted that any violations occurred or that the amount of the proposed penalty is reasonable.

Defective Environmental Equipment – Affecting CSPCo and OPCo

As part of the AEP System’s continuing environmental investment program, management chose to retrofit wet flue gas desulfurization systems on units utilizing the jet bubbling reactor (JBR) technology.  The following plants have been scheduled for the installation of the JBR technology.  technology or are currently utilizing JBR retrofits:

JBRs
Scheduled for
Plant NamePlant OwnersInstallation
CardinalOPCo/ Buckeye Power, Inc.3
Conesville
CSPCo/Dayton Power and Light Company/
Duke Energy Ohio, Inc.
1
Muskingum River (a)OPCo1

(a)Contracts for the Muskingum River project have been temporarily suspended during the early development stage of the project.

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

NUCLEAR CONTINGENCIES – AFFECTING I&M

I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC).  I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant.  The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037.  The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements.  By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generating units, for a nuclear power plant incident at any nuclear plant in the U.S.  Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial .

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

In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in significant turbine damage and a small fire on the electric generator.  This equipment, located in the turbine building, is separate and isolated from the nuclear reactor.  The turbine rotors that caused the vibration were installed in 2006 and are within the vendor’s warranty period.  The warranty provides for the repair or replacement of the turbine rotors if the damage was caused by a defect in materials or workmanship.  I&M is working with its insurance company, Nuclear Electric Insurance Limited (NEIL), and its turbine vendor, Siemens, to evaluate the extent of the damage resulting from the incident and facilitate repairs to return the unit to service.  Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $330$395 million.  Management believes that I&M should recover a significant portion of these costs through theth e turbine vendor’s warranty, insurance and the regulatory process.  I&M is repairingrepaired Unit 1 to resumeand it resumed operations as early as the fourth quarter ofin December 2009 at slightly reduced power.  Should post-repair operations prove unsuccessful,The Unit 1 rotors were repaired and reinstalled due to the extensive lead time required to manufacture and install new turbine rotors.  As a result, the replacement of parts will extend the outage into 2011.

The refueling outagerepaired turbine rotors and other equipment is scheduled for the Unit 1 planned outage in the fall of 2009 for Unit 1 was rescheduled to the spring of 2010.  Management anticipates that the loss of capacity from Unit 1 will not affect I&M’s ability to serve customers due to the existence of sufficient generating capacity in the AEP Power Pool.2011.

I&M maintains property insurance through NEIL with a $1 million deductible.  As of September 30, 2009,March 31, 2010, I&M recorded $122$143 million in Prepayments and Other Current Assets on its Condensed Consolidated Balance SheetsSheet representing recoverable amounts under the property insurance policy.  Through September 30, 2009,March 31, 2010, I&M received partial payments of $72$118 million from NEIL for the cost incurred to date to repair the property damage.  In April 2010, I&M received a $45 million payment from NEIL.

I&M also maintainsmaintained a separate accidental outage insurance policy with NEIL whereby, after a 12-week deductible period, I&M is entitled to weekly payments of $3.5 million for the first 52 weeks following the deductible period.  After the initial 52 weeks of indemnity, the policy pays $2.8 million per week for up to an additional 110 weeks.  I&M began receiving payments under the accidental outage policy in December 2008.NEIL.  In 2009, I&M recorded $145$185 million in revenues under this policy and applied $59 millionreduced the cost of the accidental outage insurance proceeds to reduce customer bills.replacement power in customers’ bills by $78 million.

NEIL is reviewing claims made under the insurance policies to ensure that claims associated with the outage are covered by the policies.  The treatment of property damage costs, replacement power costs and insurance proceeds will be the subject of future regulatory proceedings in Indiana and Michigan.  If the ultimate costs of the incident are not covered by warranty, insurance or through the regulatory process or if the unit is not returned to service in a reasonable period of time or if any future regulatory proceedings are adverse, it could have an adverse impact on net income, cash flows and financial condition.

OPERATIONAL CONTINGENCIES

Fort Wayne Lease – Affecting I&M

Since 1975, I&M has leased certain energy delivery assets from the City of Fort Wayne, Indiana under a long-term lease that expiresexpired on February 28, 2010.  I&M has been negotiating with Fort Wayne to purchase the assets at the end of the lease, but no agreement has been reached.  Recent mediation with Fort Wayne was also unsuccessful.  Fort Wayne issued a technical notice of default under the lease to I&M in August 2009.  I&M responded to Fort Wayne in October 2009 that it did not agree there was a default under the lease.  In October 2009, I&M filed for declaratory and injunctive relief in Indiana state court.  The parties agreed to submit this matter to mediation.  In February 2010, the court issued a stay to continue mediation.  I&M is making monthly payments to an escrow account in lieu of rent.& #160; I&M will seek recovery in rates for any amount it may pay related to this dispute.  At this time, management cannot predict the outcome of this dispute or its potential impact on net income or cash flows.

Coal Transportation Rate Dispute - Affecting PSO

In 1985, the Burlington Northern Railroad Co. (now BNSF) entered into a coal transportation agreement with PSO.  The agreement contained a base rate subject to adjustment, a rate floor, a reopener provision and an arbitration provision.  In 1992, PSO reopened the pricing provision.  The parties failed to reach an agreement and the matter was arbitrated, with the arbitration panel establishing a lowered rate as of July 1, 1992 (the 1992 Rate), and modifying the rate adjustment formula.  The decision did not mention the rate floor.  From April 1996 through the contract termination in December 2001, the 1992 Rate exceeded the adjusted rate, determined according to the decision.  PSO paid the adjusted rate and contended that the panel eliminated the rate floor.  BNSF invoicedinv oiced 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.  In August 2009, the U.S. District Court upheld the arbitration board’s decision.  BNSF appealed the U.S. District Court’s decision.

Rail Transportation Litigation – Affecting PSO

In October 2008, the Oklahoma Municipal Power Authority and the Public Utilities Board of the City of Brownsville, Texas, as co-owners of Oklaunion Plant, filed a lawsuit in United States District Court, Western District of Oklahoma against AEP alleging breach of contract and breach of fiduciary duties related to negotiations for rail transportation services for the plant.  The plaintiffs allege that AEP assumed the duties of the project manager, PSO, and operated the plant for the project manager and is therefore responsible for the alleged breaches.  Trial is scheduled for December 2009.  Management intends to vigorously defend against these allegations.  Management believes a provision recorded in 2008 should be sufficient.

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

In 2002, the FERC held a hearing related to a complaint filed by Nevada Power Company and Sierra Pacific Power Company (the Nevada utilities).  The complaint sought to break long-term contracts entered during the 2000 and 2001 California energy price spike which the customers alleged were “high-priced.”  The complaint alleged that AEP subsidiaries sold power at unjust and unreasonable prices because the market for power was allegedly dysfunctional at the time such contracts were executed.  In 2003, the FERC rejected the complaint.  In 2006, the U.S. Court of Appeals for the Ninth Circuit reversed the FERC order and remanded the case to the FERC for further proceedings.  That decision was appealed to the U.S. Supreme Court.  In June 2008, the U.S. Supreme Court affirmed the validity of contractually-agreed rates except in cases of serious harm to the public.  The U.S. Supreme Court affirmed the Ninth Circuit’s remand on two issues, market manipulation and excessive burden on consumers.  The FERC initiated remand procedures and gave the parties time to attempt to settle the issues.  Management recorded a provision in 2008.  In September 2009, the parties reached a settlement and a portion of the provision was reversed.

5.ACQUISITIONACQUISITIONS

20092010

Oxbow Mine LigniteValley Electric Membership Corporation – Affecting SWEPCo

In AprilNovember 2009, SWEPCo agreedsigned a letter of intent to purchase 50%the transmission and distribution assets of Valley Electric Membership Corporation (VEMCO).  The current estimate of the Oxbow Mine lignite reserves for $13purchase is $99 million, and DHLC agreedplus the assumption of certain liabilities, subject to purchase 100% of all associated mining equipment and assets for $16 million from the North American Coal Corporation and its affiliates, Red River Mining Company and Oxbow Property Company, LLC.  Cleco Power LLC (Cleco) will acquire the remaining 50% interest in the lignite reserves for $13 million.  SWEPCo expects to complete the transaction in the fourth quarter of 2009.adjustments at closing.  Consummation of the transaction is subject to regulatory approval by the LPSC, the APSC, the Rural Utilities Service and the APSCNational Rural Utilities Cooperative Finance Corporation.  In January 2010, the VEMCO members approved the transaction.  In April 2010, a joint application between SWEPCo and VEMCO was filed with the transferLPSC.  SWEPCo will seek recovery from Louisiana customers for all costs related to this acquisition.  VEMCO services approximately 30,000 customers in Louisiana.   SWEPCo expects to complete the transaction in the third quarter of 2010 upon receipt of regulatory and other regulatory instruments.  If approved, DHLC will acquire and own the Oxbow Mine mining equipment and related assets and it will operate the Oxbow Mine.  The Oxbow Mine is located near Coushatta, Louisiana and will be used as one of the fuel sources for SWEPCo’s and Cleco’s jointly-owned Dolet Hills Generating Station.approvals.

20082009

None

6.BENEFIT PLANS

The Registrant SubsidiariesAPCo, CSPCo, I&M, OPCo, PSO and SWEPCo participate in AEP sponsored qualified pension plans and nonqualified pension plans.  A substantial majority of employees are covered by either one qualified plan or both a qualified and a nonqualified pension plan.  In addition, the Registrant SubsidiariesAPCo, CSPCo, I&M, OPCo, PSO and SWEPCo participate in other postretirement benefit plans sponsored by AEP to provide medical and death benefits for retired employees.

Components of Net Periodic Benefit Cost

The following tables providetable provides the components of AEP’s net periodic benefit cost for the plans for the three and nine months ended September 30, 2009March 31, 2010 and 2008:2009:
   Other Postretirement 
 Pension Plans Benefit Plans 
 Three Months Ended September 30, Three Months Ended September 30, 
 2009 2008 2009 2008 
 (in millions) 
Service Cost $26  $25  $11  $10 
Interest Cost  64   62   27   28 
Expected Return on Plan Assets  (80)  (84)  (21)  (27)
Amortization of Transition Obligation  -   -   7   7 
Amortization of Net Actuarial Loss  14   10   11   3 
Net Periodic Benefit Cost $24  $13  $35  $21 

  Other Postretirement   Other Postretirement 
Pension Plans Benefit Plans Pension Plans Benefit Plans 
Nine Months Ended September 30, Nine Months Ended September 30, Three Months Ended March 31, Three Months Ended March 31, 
2009 2008 2009 2008 2010 2009 2010 2009 
(in millions) (in millions) 
Service Cost $78  $75  $32  $31  $28  $26  $12  $10 
Interest Cost  191   187   82   84   63   63   28   27 
Expected Return on Plan Assets  (241)  (252)  (61)  (83)  (78)  (80)  (26)  (20)
Amortization of Transition Obligation  -   -   20   21   -   -   7   7 
Amortization of Net Actuarial Loss  44   29   32   8   22   15   7   11 
Net Periodic Benefit Cost $72  $39  $105  $61  $35  $24  $28  $35 

The following tables providetable provides the Registrant Subsidiaries’ net periodic benefit cost (credit) for the plans for the three and nine months ended September 30, 2009March 31, 2010 and 2008:2009:
   Other Postretirement 
 Pension Plans Benefit Plans 
 Three Months Ended September 30, Three Months Ended September 30, 
 2009 2008 2009 2008 
Company(in thousands) 
APCo $2,614  $834  $6,058  $3,797 
CSPCo  687   (351)  2,638   1,545 
I&M  3,484   1,821   4,359   2,496 
OPCo  2,067   318   5,139   2,908 
PSO  770   509   2,283   1,420 
SWEPCo  1,208   935   2,363   1,411 

  Other Postretirement   Other Postretirement 
Pension Plans Benefit Plans Pension Plans Benefit Plans 
Nine Months Ended September 30, Nine Months Ended September 30, Three Months Ended March 31, Three Months Ended March 31, 
2009 2008 2009 2008 2010 2009 2010 2009 
Company(in thousands) (in thousands) 
APCo $7,844  $2,503  $18,173  $11,196  $3,954  $2,615  $4,762  $6,058 
CSPCo  2,063   (1,049)  7,915   4,542   1,486   688   2,062   2,638 
I&M  10,454   5,462   13,075   7,342   5,035   3,485   3,464   4,358 
OPCo  6,201   957   15,418   8,541   3,439   2,067   3,965   5,139 
PSO  2,310   1,525   6,850   4,194   1,360   770   1,861   2,283 
SWEPCo  3,623   2,806   7,090   4,163   1,774   1,208   1,893   2,363 

7.BUSINESS SEGMENTS

The Registrant Subsidiaries have one reportable segment.  The one reportable segment, is an integrated electricity generation, transmission and distribution business.  All of theThe Registrant Subsidiaries’ other activities are insignificant.  The Registrant Subsidiaries’ operations are managed as one segmenton 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.DERIVATIVES AND HEDGING

Objectives for Utilization of Derivative InstrumentsOBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

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


Strategies for Utilization of Derivative Instruments to Achieve ObjectivesSTRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

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

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

The following table representstables represent the gross notional volume of the Registrant Subsidiaries’ outstanding derivative contracts as of September 30,March 31, 2010 and December 31, 2009:
Notional Volume of Derivative InstrumentsNotional Volume of Derivative InstrumentsNotional Volume of Derivative Instruments 
September 30, 2009
March 31, 2010March 31, 2010 
(in thousands)(in thousands)(in thousands) 
 
Primary Risk Unit of             Unit of             
Exposure Measure APCo CSPCo I&M OPCo PSO SWEPCo Measure APCo CSPCo I&M OPCo PSO SWEPCo 
Commodity:         
Power MWHs 172,458  91,400  88,122  104,830  177   211  MWHs  156,031  88,273  90,380  101,589  15  18 
Coal Tons 12,029  5,889  7,299  20,448  5,659   6,394  Tons  11,112  6,616  4,928  31,865  5,597  8,075 
Natural Gas MMBtus 24,861  13,176  12,703  15,112  1,279   1,521  MMBtus  12,027  6,804  6,862  7,831  -  - 
Heating Oil and Gasoline Gallons 1,499  612  710  1,079  858   806  Gallons  1,218  529  597  898  717  659 
Interest Rate USD $20,802  $ 10,993  $10,703  $13,455  $1,124   $1,431  USD $12,703 $7,198 $7,198 $9,124 $705 $908 
                                   
Interest Rate and Foreign Currency
 USD $-  $ -  $-   $-  $ -   $3,847  USD $150,000 $- $- $- $- $3,547 
 
Notional Volume of Derivative InstrumentsNotional Volume of Derivative Instruments 
December 31, 2009December 31, 2009 
(in thousands)(in thousands) 
 
Primary Risk Exposure Unit of Measure APCo CSPCo I&M OPCo PSO SWEPCo 
Commodity:     
Power MWHs  191,121  96,828  99,265  112,745  10  12 
Coal Tons  11,347  5,615  5,150  23,631  5,936  6,790 
Natural Gas MMBtus  17,867  9,051  9,129  10,539  -  - 
Heating Oil and Gasoline Gallons  1,164  474  552  838  668  628 
Interest Rate USD $21,054 $10,658 $10,716 $13,487 $1,137 $1,457 
                     
Interest Rate and Foreign Currency USD $- $- $- $- $- $3,798 

Fair Value Hedging Strategies

At certain times, AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative transactions in orderas part of an overall strategy to manage existing fixed interest rate risk exposure.  Thesethe mix of fixed-rate and floating-rate debt.  Certain interest rate derivative transactions effectively modify an exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate.  This strategy is not actively employed by any of the Registrant Subsidiaries in 2009.  During 2008, APCo had designatedProvided specific criteria are met, these interest rate derivatives are designated as fair value hedges.

Cash Flow Hedging Strategies

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

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

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

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

Accounting for Derivative Instruments and the Impact on the Financial Statements
ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS

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

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

According to the accounting guidance for “Derivatives and Hedging,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral.  For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles.  For the September 30, 2009March 31, 2010 and December 31, 20082009 balance sheets, the Registrant Subsidiaries netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows:

September 30, 2009 December 31, 2008 
Cash Collateral Cash Collateral Cash Collateral Cash Collateral  March 31, 2010 December 31, 2009 
Received Paid Received Paid  Cash Collateral Cash Collateral Cash Collateral Cash Collateral 
Netted Against Netted Against Netted Against Netted Against  Received Paid Received Paid 
Risk Management Risk Management Risk Management Risk Management  Netted Against Netted Against Netted Against Netted Against 
Assets Liabilities Assets Liabilities  Risk Management Risk Management Risk Management Risk Management 
Company(in thousands)  Assets Liabilities Assets Liabilities 
 (in thousands) 
APCo $9,679  $32,791  $2,189  $5,621   $10,391  $51,936  $3,789  $31,806 
CSPCo  5,129   17,375   1,229   3,156    5,879   29,408   1,920   16,108 
I&M  4,946   16,763   1,189   3,054    5,929   29,520   1,936   16,222 
OPCo  5,883   20,013   1,522   3,909    6,766   35,771   2,235   19,512 
PSO  1   26   -   105    -   349   -   194 
SWEPCo  2   41   -   124    -   572   -   305 

The following table representstables represent the gross fair value impact of the Registrant Subsidiaries’ derivative activity on the Condensed Balance Sheets as of September 30,March 31, 2010 and December 31, 2009:

Fair Value of Derivative Instruments 
September 30, 2009 
  
 Risk       
 Management       
APCoContracts Hedging Contracts     
     Interest Rate     
 Commodity Commodity and Foreign     
 (a) (a) Currency (a) Other (a) (b) Total 
Balance Sheet Location(in thousands) 
Current Risk Management Assets $474,612  $5,253  $-  $(396,430) $83,435 
Long-term Risk Management Assets  200,051   1,295   -   (143,594)  57,752 
Total Assets  674,663   6,548   -   (540,024)  141,187 
                     
Current Risk Management Liabilities  435,880   4,833   -   (409,711)  31,002 
Long-term Risk Management Liabilities  181,925   1,737   -   (160,008)  23,654 
Total Liabilities  617,805   6,570   -   (569,719)  54,656 
                     
Total MTM Derivative Contract Net Assets (Liabilities) $56,858  $(22) $-  $29,695  $86,531 
CSPCo          
 Risk       
 Management       
 Contracts Hedging Contracts     
     Interest Rate     
 Commodity Commodity and Foreign     
 (a) (a) Currency (a) Other (a) (b) Total 
Balance Sheet Location(in thousands) 
Current Risk Management Assets $249,520  $2,763  $-  $(208,367) $43,916 
Long-term Risk Management Assets  105,415   682   -   (75,528)  30,569 
Total Assets  354,935   3,445   -   (283,895)  74,485 
                     
Current Risk Management Liabilities  229,126   2,552   -   (215,403)  16,275 
Long-term Risk Management Liabilities  95,828   921   -   (84,227)  12,522 
Total Liabilities  324,954   3,473   -   (299,630)  28,797 
                     
Total MTM Derivative Contract Net Assets (Liabilities) $29,981  $(28) $-  $15,735  $45,688 
I&M          
Fair Value of Derivative Instruments
March 31, 2010
Fair Value of Derivative Instruments
March 31, 2010
 
Risk         
APCoAPCo 
Management        Risk       
Contracts Hedging Contracts      Management       
    Interest Rate      Contracts Hedging Contracts     
Commodity Commodity and Foreign          Interest Rate     
(a) (a) Currency (a) Other (a) (b) Total  Commodity Commodity and Foreign     
Balance Sheet Location(in thousands)  (a) (a) Currency (a) Other (a) (b) Total 
 (in thousands) 
Current Risk Management Assets $247,098  $2,678  $-  $(206,656) $43,120   $482,823  $4,882  $207  $(409,383) $78,529 
Long-term Risk Management Assets  103,663   660   -   (74,731)  29,592    226,173   274   -   (160,600)  65,847 
Total Assets  350,761   3,338   -   (281,387)  72,712    708,996   5,156   207   (569,983)  144,376 
                                        
Current Risk Management Liabilities  226,991   2,465   -   (213,445)  16,011    458,322   8,189   908   (432,258)  35,161 
Long-term Risk Management Liabilities  94,356   889   -   (83,124)  12,121    214,123   899   -   (184,634)  30,388 
Total Liabilities  321,347   3,354   -   (296,569)  28,132    672,445   9,088   908   (616,892)  65,549 
                                        
Total MTM Derivative Contract Net Assets (Liabilities) $29,414  $(16) $-  $15,182  $44,580   $36,551  $(3,932) $(701) $46,909  $78,827 

OPCo          
Fair Value of Derivative Instruments
December 31, 2009
Fair Value of Derivative Instruments
December 31, 2009
 
Risk         
APCoAPCo 
Management        Risk       
Contracts Hedging Contracts      Management       
    Interest Rate      Contracts Hedging Contracts     
Commodity Commodity and Foreign          Interest Rate     
(a) (a) Currency (a) Other (a) (b) Total  Commodity Commodity and Foreign     
Balance Sheet Location(in thousands)  (a) (a) Currency (a) Other (a) (b) Total 
 (in thousands) 
Current Risk Management Assets $342,276  $3,215  $-  $(286,497) $58,994   $332,764  $3,621  $-  $(268,429) $67,956 
Long-term Risk Management Assets  137,788   790   -   (102,253)  36,325    132,044   -   -   (84,903)  47,141 
Total Assets  480,064   4,005   -   (388,750)  95,319    464,808   3,621   -   (353,332)  115,097 
                                        
Current Risk Management Liabilities  319,115   2,944   -   (294,615)  27,444    309,639   5,084   -   (288,931)  25,792 
Long-term Risk Management Liabilities  127,345   1,057   -   (112,268)  16,134    118,702   80   -   (98,418)  20,364 
Total Liabilities  446,460   4,001   -   (406,883)  43,578    428,341   5,164   -   (387,349)  46,156 
                                        
Total MTM Derivative Contract Net Assets (Liabilities) $33,604  $4  $-  $18,133  $51,741   $36,467  $(1,543) $-  $34,017  $68,941 
PSO          
 Risk       
 Management       
 Contracts Hedging Contracts     
     Interest Rate     
 Commodity Commodity and Foreign     
 (a) (a) Currency (a) Other (a) (b) Total 
Balance Sheet Location(in thousands) 
Current Risk Management Assets $21,839  $107  $-  $(18,041) $3,905 
Long-term Risk Management Assets  5,178   23   -   (4,889)  312 
Total Assets  27,017   130   -   (22,930)  4,217 
                     
Current Risk Management Liabilities  22,283   536   -   (18,054)  4,765 
Long-term Risk Management Liabilities  5,327   47   -   (4,901)  473 
Total Liabilities  27,610   583   -   (22,955)  5,238 
                     
Total MTM Derivative Contract Net Assets (Liabilities) $(593) $(453) $-  $25  $(1,021)


SWEPCo          
 Risk       
 Management       
 Contracts Hedging Contracts     
     Interest Rate     
 Commodity Commodity and Foreign     
 (a) (a) Currency (a) Other (a) (b) Total 
Balance Sheet Location(in thousands) 
Current Risk Management Assets $31,905  $102  $-  $(26,680) $5,327 
Long-term Risk Management Assets  8,004   16   6   (7,546)  480 
Total Assets  39,909   118   6   (34,226)  5,807 
                     
Current Risk Management Liabilities  30,092   33   25   (26,701)  3,449 
Long-term Risk Management Liabilities  7,774   4   -   (7,564)  214 
Total Liabilities  37,866   37   25   (34,265)  3,663 
                     
Total MTM Derivative Contract Net Assets (Liabilities) $2,043  $81  $(19) $39  $2,144 
Fair Value of Derivative Instruments
March 31, 2010

CSPCo           
  Risk       
  Management       
  Contracts Hedging Contracts     
      Interest Rate     
  Commodity Commodity and Foreign     
Balance Sheet Location (a) (a) Currency (a) Other (a) (b) Total 
  (in thousands) 
Current Risk Management Assets  $273,981  $2,726  $-  $(232,345) $44,362 
Long-term Risk Management Assets   128,131   155   -   (91,022)  37,264 
Total Assets   402,112   2,881   -   (323,367)  81,626 
                      
Current Risk Management Liabilities   260,063   4,632   -   (245,288)  19,407 
Long-term Risk Management Liabilities   121,335   508   -   (104,643)  17,200 
Total Liabilities   381,398   5,140   -   (349,931)  36,607 
                      
Total MTM Derivative Contract Net Assets (Liabilities)  $20,714  $(2,259) $-  $26,564  $45,019 


Fair Value of Derivative Instruments
December 31, 2009

CSPCo           
  Risk       
  Management       
  Contracts Hedging Contracts     
      Interest Rate     
  Commodity Commodity and Foreign     
Balance Sheet Location (a) (a) Currency (a) Other (a) (b) Total 
  (in thousands) 
Current Risk Management Assets  $168,137  $1,805  $-  $(135,599) $34,343 
Long-term Risk Management Assets   66,816   -   -   (42,934)  23,882 
Total Assets   234,953   1,805   -   (178,533)  58,225 
                      
Current Risk Management Liabilities   156,463   2,574   -   (145,985)  13,052 
Long-term Risk Management Liabilities   60,048   41   -   (49,776)  10,313 
Total Liabilities   216,511   2,615   -   (195,761)  23,365 
                      
Total MTM Derivative Contract Net Assets (Liabilities)  $18,442  $(810) $-  $17,228  $34,860 
                      

Fair Value of Derivative Instruments
March 31, 2010
 
            
I&M           
  Risk       
  Management       
  Contracts Hedging Contracts     
      Interest Rate     
  Commodity Commodity and Foreign     
Balance Sheet Location (a) (a) Currency (a) Other (a) (b) Total 
  (in thousands) 
Current Risk Management Assets  $274,350  $2,763  $-  $(230,409) $46,704 
Long-term Risk Management Assets   139,429   156   -   (90,931)  48,654 
Total Assets   413,779   2,919   - �� (321,340)  95,358 
                      
Current Risk Management Liabilities   258,206   4,672   -   (243,455)  19,423 
Long-term Risk Management Liabilities   121,330   512   -   (104,536)  17,306 
Total Liabilities   379,536   5,184   -   (347,991)  36,729 
                      
Total MTM Derivative Contract Net Assets (Liabilities)  $34,243  $(2,265) $-  $26,651  $58,629 


Fair Value of Derivative Instruments
December 31, 2009

I&M 
  Risk       
  Management       
  Contracts Hedging Contracts     
      Interest Rate     
  Commodity Commodity and Foreign     
Balance Sheet Location (a) (a) Currency (a) Other (a) (b) Total 
  (in thousands) 
Current Risk Management Assets  $167,847  $1,839  $-  $(135,248) $34,438 
Long-term Risk Management Assets   72,127   -   -   (42,993)  29,134 
Total Assets   239,974   1,839   -   (178,241)  63,572 
                      
Current Risk Management Liabilities   156,561   2,596   -   (145,721)  13,436 
Long-term Risk Management Liabilities   60,217   41   -   (49,872)  10,386 
Total Liabilities   216,778   2,637   -   (195,593)  23,822 
                      
Total MTM Derivative Contract Net Assets (Liabilities)  $23,196  $(798) $-  $17,352  $39,750 

Fair Value of Derivative Instruments
March 31, 2010
 
 
OPCo
           
  Risk       
  Management       
  Contracts Hedging Contracts     
      Interest Rate     
  Commodity Commodity and Foreign     
Balance Sheet Location (a) (a) Currency (a) Other (a) (b) Total 
  (in thousands) 
Current Risk Management Assets  $377,428  $3,204  $-  $(321,405) $59,227 
Long-term Risk Management Assets   160,257   178   -   (116,689)  43,746 
Total Assets   537,685   3,382   -   (438,094)  102,973 
                      
Current Risk Management Liabilities   360,508   5,332   -   (336,384)  29,456 
Long-term Risk Management Liabilities   153,975   586   -   (134,208)  20,353 
Total Liabilities   514,483   5,918   -   (470,592)  49,809 
                      
Total MTM Derivative Contract Net Assets (Liabilities)  $23,202  $(2,536) $-  $32,498  $53,164 


Fair Value of Derivative Instruments
December 31, 2009

OPCo   
  Risk       
  Management       
  Contracts Hedging Contracts     
      Interest Rate     
  Commodity Commodity and Foreign     
Balance Sheet Location (a) (a) Currency (a) Other (a) (b) Total 
  (in thousands) 
Current Risk Management Assets  $255,179  $2,199  $-  $(207,330) $50,048 
Long-term Risk Management Assets   88,064   -   -   (60,061)  28,003 
Total Assets   343,243   2,199   -   (267,391)  78,051 
                      
Current Risk Management Liabilities   240,877   2,998   -   (219,484)  24,391 
Long-term Risk Management Liabilities   81,186   47   -   (68,723)  12,510 
Total Liabilities   322,063   3,045   -   (288,207)  36,901 
                      
Total MTM Derivative Contract Net Assets (Liabilities)  $21,180  $(846) $-  $20,816  $41,150 
                    

Fair Value of Derivative Instruments
March 31, 2010
 
 
PSO
           
  Risk       
  Management       
  Contracts Hedging Contracts     
      Interest Rate     
  Commodity Commodity and Foreign     
Balance Sheet Location (a) (a) Currency (a) Other (a) (b) Total 
  (in thousands) 
Current Risk Management Assets  $12,892  $170  $-  $(9,799) $3,263 
Long-term Risk Management Assets   2,279   1   -   (2,123)  157 
Total Assets   15,171   171   -   (11,922)  3,420 
                      
Current Risk Management Liabilities   10,169   181   -   (9,814)  536 
Long-term Risk Management Liabilities   2,567   7   -   (2,457)  117 
Total Liabilities   12,736   188   -   (12,271)  653 
                      
Total MTM Derivative Contract Net Assets (Liabilities)  $2,435  $(17) $-  $349  $2,767 


Fair Value of Derivative Instruments
December 31, 2009

PSO           
  Risk       
  Management       
  Contracts Hedging Contracts     
      Interest Rate     
  Commodity Commodity and Foreign     
Balance Sheet Location (a) (a) Currency (a) Other (a) (b) Total 
  (in thousands) 
Current Risk Management Assets  $14,885  $179  $-  $(12,688) $2,376 
Long-term Risk Management Assets   2,640   -   -   (2,590)  50 
Total Assets   17,525   179   -   (15,278)  2,426 
                      
Current Risk Management Liabilities   14,981   301   -   (12,703)  2,579 
Long-term Risk Management Liabilities   2,913   -   -   (2,769)  144 
Total Liabilities   17,894   301   -   (15,472)  2,723 
                      
Total MTM Derivative Contract Net Assets (Liabilities)  $(369) $(122) $-  $194  $(297)

Fair Value of Derivative Instruments
March 31, 2010
 
 
SWEPCo
           
  Risk       
  Management       
  Contracts Hedging Contracts     
      Interest Rate     
  Commodity Commodity and Foreign     
Balance Sheet Location (a) (a) Currency (a) Other (a) (b) Total 
  (in thousands) 
Current Risk Management Assets  $17,797  $157  $17  $(15,916) $2,055 
Long-term Risk Management Assets   3,747   1   3   (3,507)  244 
Total Assets   21,544   158   20   (19,423)  2,299 
                      
Current Risk Management Liabilities   16,818   5   107   (15,941)  989 
Long-term Risk Management Liabilities   4,680   6   -   (4,054)  632 
Total Liabilities   21,498   11   107   (19,995)  1,621 
                      
Total MTM Derivative Contract Net Assets (Liabilities)  $46  $147  $(87) $572  $678 


Fair Value of Derivative Instruments
December 31, 2009

SWEPCo           
  Risk       
  Management       
  Contracts Hedging Contracts     
      Interest Rate     
  Commodity Commodity and Foreign     
Balance Sheet Location (a) (a) Currency (a) Other (a) (b) Total 
  (in thousands) 
Current Risk Management Assets  $22,847  $169  $42  $(20,009) $3,049 
Long-term Risk Management Assets   4,145   -   5   (4,066)  84 
Total Assets   26,992   169   47   (24,075)  3,133 
                      
Current Risk Management Liabilities   20,788   -   89   (20,033)  844 
Long-term Risk Management Liabilities   4,568   -   -   (4,347)  221 
Total Liabilities   25,356   -   89   (24,380)  1,065 
                      
Total MTM Derivative Contract Net Assets (Liabilities)  $1,636  $169  $(42) $305  $2,068 

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

The tables below presentspresent the Registrant Subsidiaries’ activity of derivative risk management contracts for the three and nine months ended September 30,March 31, 2010 and 2009:
Amount of Gain (Loss) Recognized 
on Risk Management Contracts 
For the Three Months Ended March 31, 2010 
              
Location of Gain (Loss) APCo CSPCo I&M OPCo PSO SWEPCo 
  (in thousands) 
Electric Generation, Transmission and Distribution Revenues  $4,173  $9,607  $6,885  $10,221  $683  $788 
Sales to AEP Affiliates   (2,361)  (1,562)  (1,443)  253   (176)  (308)
Regulatory Assets (a)   -   -   -   -   331   (47)
Regulatory Liabilities (a)   17,027   3,681   15,092   4,093   2,638   (1,011)
Total Gain (Loss) on Risk Management Contracts  $18,839  $11,726  $20,534  $14,567  $3,476  $(578)

Amount of Gain (Loss) Recognized 
on Risk Management Contracts 
For the Three Months Ended September 30, 2009 
             
 APCo CSPCo I&M OPCo PSO SWEPCo 
 (in thousands) 
Location of Gain (Loss)                  
Electric Generation, Transmission and Distribution Revenues $2,240  $6,551  $7,127  $3,155  $(850) $(1,067)
Sales to AEP Affiliates  (237)  (238)  (292)  302   1,135   1,347 
Regulatory Assets  -   -   -   -   (600)  5 
Regulatory Liabilities  24,750   7,800   6,917   8,775   (497)  (16)
Total Gain (Loss) on Risk Management Contracts $26,753  $14,113  $13,752  $12,232  $(812) $269 
Amount of Gain (Loss) Recognized
on Risk Management Contracts
 
For the Three Months Ended March 31, 2009 
              
Location of Gain (Loss) APCo CSPCo I&M OPCo PSO SWEPCo 
  (in thousands) 
Electric Generation, Transmission and Distribution Revenues  $9,817  $10,745  $18,178  $12,711  $1,255  $1,523 
Sales to AEP Affiliates   (7,020)  (4,076)  (3,971)  (3,214)  (1,462)  (1,781)
Regulatory Assets (a)   (755)  -   -   -   -   (41)
Regulatory Liabilities (a)   20,622   2,237   5,562   2,697   334   386 
Total Gain (Loss) on Risk Management Contracts  $22,664  $8,906  $19,769  $12,194  $127  $87 

Amount of Gain (Loss) Recognized 
on Risk Management Contracts 
For the Nine Months Ended September 30, 2009 
             
 APCo CSPCo I&M OPCo PSO SWEPCo 
 (in thousands) 
Location of Gain (Loss)                  
Electric Generation, Transmission and Distribution Revenues $13,211  $26,557  $31,333  $27,453  $(2) $151 
Sales to AEP Affiliates  (7,563)  (4,707)  (4,710)  (1,191)  510   372 
Regulatory Assets  (755)  -   -   -   (600)  (98)
Regulatory Liabilities  75,108   18,876   13,285   21,811   (1,379)  233 
Total Gain (Loss) on Risk Management Contracts $80,001  $40,726  $39,908  $48,073  $(1,471) $658 
(a)Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or non-current within the balance sheet.

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

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

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes.  Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in Revenuesrevenues on a net basis on the Condensed Statements of Income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in Revenuesrevenues or Expensesexpenses on the Condensed Statements of Income depending on the relevant facts and circumstances.  However, unrealized and some realized gains and losses in regulated jurisdictions (APCo, I&M, PSO, the non-Texas portion of SWEPCo generation and beginning Aprilin the second quarter of 2009 the Texas portion of SWEPCo generation) for bothb oth trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”  SWEPCo returned to cost-based regulation and re-applied the accounting guidance for “Regulated Operations” for the generation portion of SWEPCo’s Texas retail jurisdiction effective Aprilthe second quarter of 2009.

Accounting for Fair Value Hedging Strategies

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

The Registrant Subsidiaries record realized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged, in Interest Expense on the Condensed Statements of Income.  During the three and nine months ended September 30,March 31, 2010 and 2009, the Registrant Subsidiaries did not employ any fair value hedging strategies.  During the three and nine months ended September 30, 2008, APCo designated interest rate derivatives as fair value hedges and did not recognize any hedge ineffectiveness related to these derivative transactions.

Accounting for Cash Flow Hedging Strategies

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

Realized gains and losses on derivative contracts for the purchase and sale of electricity, coal, heating oil and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the Condensed Statements of Income, or in Regulatory Assets or Regulatory Liabilities on the Condensed Balance Sheets, depending on the specific nature of the risk being hedged.  The Registrant Subsidiaries do not hedge all variable price risk exposure related to commodities.  During the three and nine months ended September 30,March 31, 2010 and 2009, and 2008, APCo, CSPCo, I&M and OPCo recognized immaterial amounts related to hedge ineffectiveness.designated commodity derivatives as cash flow hedges.

Beginning in 2009, AEPSC, on behalf of the Registrant Subsidiaries executed financial heating oil and gasoline derivative contracts to hedge the price risk of diesel fuel and gasoline purchases.  The Registrant Subsidiaries reclassify gains and losses on financial fuel derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the Condensed Balance Sheets into Other Operation andexpense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the Condensed Statements of Income.  The Registrant Subsidiaries do not hedge all fuel price exposure.  During the three and nine months ended September 30,March 31, 2010 and 2009, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo recognized no hedge ineffectiveness related to this hedge strategy.the Registrant Subsidiaries designated cash flow hedging strategies of forecasted fuel purchases.

The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financing from Accumulated Other Comprehensive Income (Loss) into Interest Expense in those periods in which hedged interest payments occur.  During the three and nine months ended September 30, 2009, OPCo recognized a $1 million loss and a $6 million gain, respectively, in Interest Expense related to hedge ineffectiveness onMarch 31, 2010, APCo designated interest rate derivatives designated as cash flow hedges.  During the three and nine months ended September 30, 2008, APCo andMarch 31, 2009, OPCo recognized immaterial amounts in Interest Expense related to hedge ineffectiveness.designated interest rate derivatives as cash flow hedges.

The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the Condensed Balance Sheets into Depreciation and Amortization expense on the Condensed Statements of Income over the depreciable lives of the fixed assets that were designated as the hedged items in qualifying foreign currency hedging relationships.  The Registrant Subsidiaries do not hedge all foreign currency exposure.  During the three and nine months ended September 30,March 31, 2010 and 2009, SWEPCo designated foreign currency derivatives as cash flow hedges.

During the three months ended March 31, 2010 and 2008, APCo, OPCo and SWEPCo recognized no2009, hedge ineffectiveness related to thiswas immaterial or nonexistent for all of the hedge strategy.strategies disclosed above.

The following tables providesprovide details on designated, effective cash flow hedges included in AOCI on the Condensed Balance Sheets and the reasons for changes in cash flow hedges for the three and nine months ended September 30,March 31, 2010 and 2009.  All amounts in the following tables are presented net of related income taxes.

Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges 
For the Three Months Ended September 30, 2009 
                   
  APCo  CSPCo  I&M  OPCo  PSO  SWEPCo 
  (in thousands) 
Commodity Contracts                  
Beginning Balance in AOCI as of
  July 1, 2009
 $2,296  $1,189  $1,170  $1,526  $127  $141 
Changes in Fair Value Recognized in AOCI  (451)  (232)  (227)  (346)  (377)  (45)
Amount of (Gain) or Loss Reclassified from AOCI to Income Statements/within Balance Sheets:                        
Electric Generation, Transmission and Distribution Revenues  (720)  (1,815)  (1,385)  (2,126)  -   - 
Fuel and Other Consumables Used for Electric Generation  (39)  (17)  (20)  (27)  (20)  (22)
Purchased Electricity for Resale  444   1,116   852   1,313   -   - 
Property, Plant and Equipment  (23)  (9)  (12)  (17)  (12)  (9)
Regulatory Assets  1,664   -   226   -   -   - 
Regulatory Liabilities  (2,709)  -   (369)  -   -   - 
Ending Balance in AOCI as of
  September 30, 2009
 $462  $232  $235  $323  $(282) $65 
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges 
For the Three Months Ended March 31, 2010 
                   
Commodity Contracts APCo  CSPCo  I&M  OPCo  PSO  SWEPCo 
  (in thousands) 
Balance in AOCI as of January 1, 2010 $(743) $(376) $(382) $(366) $(78) $112 
Changes in Fair Value Recognized in AOCI  (2,499)  (1,457)  (1,471)  (1,670)  86   3 
Amount of (Gain) or Loss Reclassified from AOCI to Income Statement/within Balance Sheet:                        
Electric Generation, Transmission and Distribution Revenues  26   65   54   76   -   - 
Other Operation Expense  (6)  (8)  (6)  (5)  (6)  (7)
Maintenance Expense  (14)  (6)  (5)  (4)  (4)  (4)
Fuel and Other Consumables Used for Electric Generation  -   -   -   (9)  -   - 
Purchased Electricity for Resale  146   382   316   440   -   - 
Property, Plant and Equipment�� (9)  (7)  (5)  (5)  (6)  (4)
Regulatory Assets (a)  648   -   81   -   -   - 
Regulatory Liabilities (a)  -   -   -   -   -   - 
Balance in AOCI as of March 31, 2010 $(2,451) $(1,407) $(1,418) $(1,543) $(8) $100 

Interest Rate and Foreign Currency             
Contracts APCo CSPCo I&M OPCo PSO SWEPCo 
  (in thousands) 
Balance in AOCI as of January 1, 2010  $(6,450) $-  $(9,514) $12,172  $(521) $(5,047)
Changes in Fair Value Recognized in AOCI   (456)  -   -   -   -   (107)
Amount of (Gain) or Loss Reclassified from AOCI to Income Statement/within Balance Sheet:                         
Depreciation and Amortization Expense   -   -   -   1   -   - 
Interest Expense   418   -   252   (341)  46   207 
Balance in AOCI as of March 31, 2010  $(6,488) $-  $(9,262) $11,832  $(475) $(4,947)
 
 
                   
  APCo  CSPCo  I&M  OPCo  PSO  SWEPCo 
  (in thousands) 
Interest Rate and Foreign Currency                  
Contracts                  
Beginning Balance in AOCI as of
  July 1, 2009
 $(7,285) $-  $(10,017) $16,662  $(613) $(5,497)
Changes in Fair Value Recognized in AOCI  -   -   -   (4,038)  -   82 
Amount of (Gain) or Loss Reclassified from AOCI to Income Statements/within Balance Sheets:                        
Depreciation and Amortization Expense  -   -   (2)  1   -   - 
Interest Expense  418   -   253   (113)  46   208 
Ending Balance in AOCI as of
  September 30, 2009
 $(6,867) $-  $(9,766) $12,512  $(567) $(5,207)
Total Contracts APCo  CSPCo  I&M  OPCo  PSO  SWEPCo 
  (in thousands) 
Balance in AOCI as of January 1, 2010 $(7,193) $(376) $(9,896) $11,806  $(599) $(4,935)
Changes in Fair Value Recognized in AOCI  (2,955)  (1,457)  (1,471)  (1,670)  86   (104)
Amount of (Gain) or Loss Reclassified from AOCI to Income Statement/within Balance Sheet:                        
Electric Generation, Transmission and Distribution Revenues  26   65   54   76   -   - 
Other Operation Expense  (6)  (8)  (6)  (5)  (6)  (7)
Maintenance Expense  (14)  (6)  (5)  (4)  (4)  (4)
Fuel and Other Consumables Used for Electric Generation  -   -   -   (9)  -   - 
Purchased Electricity for Resale  146   382   316   440   -   - 
Depreciation and Amortization Expense  -   -   -   1   -   - 
Interest Expense  418   -   252   (341)  46   207 
Property, Plant and Equipment  (9)  (7)  (5)  (5)  (6)  (4)
Regulatory Assets (a)  648   -   81   -   -   - 
Regulatory Liabilities (a)  -   -   -   -   -   - 
Balance in AOCI as of March 31, 2010 $(8,939) $(1,407) $(10,680) $10,289  $(483) $(4,847)
    (a)Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or non-current within the balance sheet.  
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges 
For the Three Months Ended March 31, 2009 
             
 APCo CSPCo I&M OPCo PSO SWEPCo 
 (in thousands) 
Commodity Contracts                  
Balance in AOCI as of January 1, 2009 $2,726  $1,531  $1,482  $1,898  $-  $- 
Changes in Fair Value Recognized in AOCI  380   118   113   136   (24)  (21)
Amount of (Gain) or Loss Reclassified from AOCI to Income Statement/within Balance Sheet:                        
Electric Generation, Transmission and Distribution Revenues  (251)  (613)  (504)  (759)  -   - 
Purchased Electricity for Resale  462   1,126   926   1,394   -   - 
Regulatory Assets  1,639   -   163   -   -   - 
Regulatory Liabilities  (890)  -   (89)  -   -   - 
Balance in AOCI as of March 31, 2009 $4,066  $2,162  $2,091  $2,669  $(24) $(21)


                   
  APCo  CSPCo  I&M  OPCo  PSO  SWEPCo 
  (in thousands) 
TOTAL Contracts                  
Beginning Balance in AOCI as of
  July 1, 2009
 $(4,989) $1,189  $(8,847) $18,188  $(486) $(5,356)
Changes in Fair Value Recognized in AOCI  (451)  (232)  (227)  (4,384)  (377)  37 
Amount of (Gain) or Loss Reclassified from AOCI to Income Statements/within Balance Sheets:                        
Electric Generation, Transmission and Distribution Revenues  (720)  (1,815)  (1,385)  (2,126)  -   - 
Fuel and Other Consumables Used for Electric Generation  (39)  (17)  (20)  (27)  (20)  (22)
Purchased Electricity for Resale  444   1,116   852   1,313   -   - 
Depreciation and Amortization Expense  -   -   (2)  1   -   - 
Interest Expense  418   -   253   (113)  46   208 
Property, Plant and Equipment  (23)  (9)  (12)  (17)  (12)  (9)
Regulatory Assets  1,664   -   226   -   -   - 
Regulatory Liabilities  (2,709)  -   (369)  -   -   - 
Ending Balance in AOCI as of
  September 30, 2009
 $(6,405) $232  $(9,531) $12,835  $(849) $(5,142)


Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges 
For the Nine Months Ended September 30, 2009 
                   
  APCo  CSPCo  I&M  OPCo  PSO  SWEPCo 
  (in thousands) 
Commodity Contracts                  
Beginning Balance in AOCI as of January 1, 2009 $2,726  $1,531  $1,482  $1,898  $-  $- 
Changes in Fair Value Recognized in AOCI  (278)  (257)  (233)  (325)  (246)  100 
Amount of (Gain) or Loss Reclassified from AOCI to Income Statements/within Balance Sheets:                        
Electric Generation, Transmission and Distribution Revenues  (1,429)  (3,586)  (2,774)  (4,319)  -   - 
Fuel and Other Consumables Used for Electric Generation  (45)  (21)  (24)  (32)  (23)  (25)
Purchased Electricity for Resale  1,038   2,576   2,033   3,120   -   - 
Property, Plant and Equipment  (26)  (11)  (13)  (19)  (13)  (10)
Regulatory Assets  3,800   -   457   -   -   - 
Regulatory Liabilities  (5,324)  -   (693)  -   -   - 
Ending Balance in AOCI as of
  September 30, 2009
 $462  $232  $235  $323  $(282) $65 
  APCo  CSPCo  I&M  OPCo  PSO  SWEPCo 
  (in thousands) 
Interest Rate and Foreign Currency Contracts                  
Balance in AOCI as of January 1, 2009 $(8,118) $-  $(10,521) $1,752  $(704) $(5,924)
Changes in Fair Value Recognized in AOCI  -   -   -   263   -   (91)
Amount of (Gain) or Loss Reclassified from AOCI to Income Statement/within Balance Sheet:                        
Depreciation and Amortization Expense  -   -   (2)  1   -   - 
Interest Expense  416   -   252   23   46   207 
Balance in AOCI as of March 31, 2009 $(7,702) $-  $(10,271) $2,039  $(658) $(5,808)


                   
  APCo  CSPCo  I&M  OPCo  PSO  SWEPCo 
  (in thousands) 
Interest Rate and Foreign Currency                  
Contracts                  
Beginning Balance in AOCI as of January 1, 2009 $(8,118) $-  $(10,521) $1,752  $(704) $(5,924)
Changes in Fair Value Recognized in AOCI  -   -   -   10,915   -   95 
Amount of (Gain) or Loss Reclassified from AOCI to Income Statements/within Balance Sheets:                        
Depreciation and Amortization Expense  -   -   (4)  3   -   - 
Interest Expense  1,251   -   759   (158)  137   622 
Ending Balance in AOCI as of
  September 30, 2009
 $(6,867) $-  $(9,766) $12,512  $(567) $(5,207)
  APCo  CSPCo  I&M  OPCo  PSO  SWEPCo 
  (in thousands) 
TOTAL Contracts                  
Balance in AOCI as of January 1, 2009 $(5,392) $1,531  $(9,039) $3,650  $(704) $(5,924)
Changes in Fair Value Recognized in AOCI  380   118   113   399   (24)  (112)
Amount of (Gain) or Loss Reclassified from AOCI to Income Statement/within Balance Sheet:                        
Electric Generation, Transmission and Distribution Revenues  (251)  (613)  (504)  (759)  -   - 
Purchased Electricity for Resale  462   1,126   926   1,394   -   - 
Depreciation and Amortization Expense  -   -   (2)  1   -   - 
Interest Expense  416   -   252   23   46   207 
Regulatory Assets  1,639   -   163   -   -   - 
Regulatory Liabilities  (890)  -   (89)  -   -   - 
Balance in AOCI as of March 31, 2009 $(3,636) $2,162  $(8,180) $4,708  $(682) $(5,829)

                   
  APCo  CSPCo  I&M  OPCo  PSO  SWEPCo 
  (in thousands) 
TOTAL Contracts                  
Beginning Balance in AOCI as of January 1, 2009 $(5,392) $1,531  $(9,039) $3,650  $(704) $(5,924)
Changes in Fair Value Recognized in AOCI  (278)  (257)  (233)  10,590   (246)  195 
Amount of (Gain) or Loss Reclassified from AOCI to Income Statements/within Balance Sheets:                        
Electric Generation, Transmission and Distribution Revenues  (1,429)  (3,586)  (2,774)  (4,319)  -   - 
Fuel and Other Consumables Used for Electric Generation  (45)  (21)  (24)  (32)  (23)  (25)
Purchased Electricity for Resale  1,038   2,576   2,033   3,120   -   - 
Depreciation and Amortization Expense  -   -   (4)  3   -   - 
Interest Expense  1,251   -   759   (158)  137   622 
Property, Plant and Equipment  (26)  (11)  (13)  (19)  (13)  (10)
Regulatory Assets  3,800   -   457   -   -   - 
Regulatory Liabilities  (5,324)  -   (693)  -   -   - 
Ending Balance in AOCI as of
  September 30, 2009
 $(6,405) $232  $(9,531) $12,835  $(849) $(5,142)


Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the Condensed Balance Sheets at September 30,March 31, 2010 and December 31, 2009 were:

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
September 30,March 31, 2010

  Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax 
    Interest Rate   Interest Rate   Interest Rate 
    and Foreign   and Foreign   and Foreign 
Company Commodity Currency Commodity Currency Commodity Currency 
  (in thousands) 
APCo  $672  $207  $(4,604) $(908) $(2,451) $(6,488)
CSPCo   345   -   (2,604)  -   (1,407)  - 
I&M   362   -   (2,627)  -   (1,418)  (9,262)
OPCo   463   -   (2,999)  -   (1,543)  11,832 
PSO   165   -   (182)  -   (8)  (475)
SWEPCo   151   3   (4)  (90)  100   (4,947)

  Expected to be Reclassified to   
  Net Income During the Next   
  Twelve Months   
      Maximum Term for 
    Interest Rate Exposure to 
    and Foreign Variability of Future 
Company Commodity Currency Cash Flows 
  (in thousands) (in months) 
APCo  $(2,045) $(1,223)  21 
CSPCo   (1,177)  -   21 
I&M   (1,190)  (1,007)  21 
OPCo   (1,278)  1,359   21 
PSO   (5)  (87)  21 
SWEPCo   102   (829)  32 
Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
December 31, 2009

Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax 
  Interest Rate   Interest Rate   Interest Rate  Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax 
  and Foreign   and Foreign   and Foreign    Interest Rate   Interest Rate   Interest Rate 
Commodity Currency Commodity Currency Commodity Currency    and Foreign   and Foreign   and Foreign 
Company(in thousands)  Commodity Currency Commodity Currency Commodity Currency 
 (in thousands) 
APCo $3,371  $-  $(3,393) $-  $462  $(6,867)  $1,999  $-  $(3,542) $-  $(743) $(6,450)
CSPCo  1,770   -   (1,798)  -   232   -    984   -   (1,794)  -   (376)  - 
I&M  1,718   -   (1,734)  -   235   (9,766)   1,011   -   (1,809)  -   (382)  (9,514)
OPCo  2,066   -   (2,062)  -   323   12,512    1,242   -   (2,088)  -   (366)  12,172 
PSO  85   -   (538)  -   (282)  (567)   178   -   (300)  -   (78)  (521)
SWEPCo  81   6   -   (25)  65   (5,207)   168   5   -   (46)  112   (5,047)


Expected to be Reclassified to   
Net Income During the Next   
Twelve Months   
Expected to be Reclassified toExpected to be Reclassified to
Net Income During the NextNet Income During the Next
Twelve MonthsTwelve Months
    Maximum Term for 
  Interest Rate Exposure to     
  and Foreign Variability of Future    Interest Rate
Commodity Currency Cash Flows    and Foreign
Company(in thousands) (in months)  Commodity Currency
 (in thousands)
APCo $751  $(1,459)  17   $(691) $(1,301)
CSPCo  388   -   17    (349)  - 
I&M  381   (1,007)  17    (358)  (1,007)
OPCo  497   1,359   17    (335)  1,359 
PSO  (267)  (142)  15    (79)  (114)
SWEPCo  57   (829)  38    111   (829)

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

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

Credit Risk

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

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

Collateral Triggering Events

Under a limited number of derivative and non-derivative counterparty contracts primarily related to pre-2002 risk management activities and under the tariffs of the RTOs and Independent System Operators (ISOs), the Registrant Subsidiaries are obligated to post an amount of collateral if certain credit ratings decline below investment grade.  The amount of collateral required fluctuates based on market prices and total exposure.  On an ongoing basis, theAEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts.  Management believes that a downgrade below investment grade is unlikely.  The following table representstables represent the Registrant Subsidiaries’Subsidiaries�� aggregate fair value of such derivative contracts, the amount of collateral the Registrant Subsidiaries would have been required to post for all derivative and non-derivative contracts if the credit ratings had declined below investment grade and how much was attributable to RTO and ISO activities as of September 30, 2009.March 31, 2010 and December 31, 2009:

 March 31, 2010
  Amount of Collateral the Amount       
  Registrant Subsidiaries Attributable to  Aggregate Amount of Collateral the Amount
Aggregate Fair Would Have Been RTO and ISO  Fair Value of Registrant Subsidiaries Attributable to
Value Contracts Required to Post Activities  Derivative Would Have Been RTO and ISO
Company (in thousands)  Contracts Required to Post Activities
 (in thousands)
APCo $9,340  $9,340  $8,699  $                  2,487 $                                     7,362 $                   7,362
CSPCo  4,950   4,950   4,610                    1,407                                      4,165                    4,165
I&M  4,772   4,772   4,445                    1,419                                      4,201                    4,201
OPCo  5,677   5,677   5,288                    1,619                                      4,793                    4,793
PSO  3,180   3,180   2,259                       652                                      3,072                    2,420
SWEPCo  3,782   3,782   2,687                       775                                      3,653                    2,878

As of September 30,March 31, 2010, the Registrant Subsidiaries were not required to post any cash collateral.
  December 31, 2009
       
  Aggregate Amount of Collateral the Amount
  Fair Value of Registrant Subsidiaries Attributable to
  Derivative Would Have Been RTO and ISO
Company Contracts Required to Post Activities
   (in thousands)
APCo $2,229  $8,433  $7,947 
CSPCo  1,129   4,272   4,026 
I&M  1,139   4,309   4,060 
OPCo  1,315   4,975   4,688 
PSO  689   2,772   2,083 
SWEPCo  819   3,297   2,477 
As of December 31, 2009, the Registrant Subsidiaries were not required to post any cash collateral.

In addition, a majority of the Registrant Subsidiaries’ non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable.  These cross-default provisions could be triggered if there was a non-performance event under borrowed debt in excess of $50 million.  On an ongoing basis, AEPSC’sAEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts.  Management believes that a non-performance event under these provisions is unlikely.  The following table representstables represent the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, the amount this exposure has been reduced by cash collateral posted by the Registrant Subsidiaries and if a cross-default provision would have been triggered, the settlement amount that would be required after considering the Registrant Subsidiaries’ contractual netting arrangements as of September 30,March 31, 2010 and December 31, 2009:

 March 31, 2010 
       
 Liabilities of   Additional 
 Contracts with Cross   Settlement Liability 
 Default Provisions   if Cross Default 
 Liabilities of Contracts with Cross Default Provisions prior to Contractual Netting Arrangements  Amount of Cash Collateral Posted Additional Settlement Liability if Cross Default Provision is Triggered  Prior to Contractual Amount of Cash Provision is 
Company (in thousands)  Netting Arrangements Collateral Posted Triggered 
  (in thousands) 
APCo $239,073  $3,315  $43,244   $210,308  $12,031  $51,454 
CSPCo  126,514   1,757   22,841    118,468   6,806   28,714 
I&M  122,614   1,694   22,281    119,474   6,864   28,959 
OPCo  158,388   2,015   35,933    136,386   7,833   33,045 
PSO  6,760   -   3,151    40   -   - 
SWEPCo  5,664   -   1,027    158   -   86 


  December 31, 2009
        
  Liabilities of   Additional 
  Contracts with Cross   Settlement Liability 
  Default Provisions   if Cross Default 
  Prior to Contractual Amount of Cash Provision is 
Company Netting Arrangements Collateral Posted Triggered 
   (in thousands) 
APCo  $154,924  $3,115  $33,186 
CSPCo   78,489   1,578   16,813 
I&M   79,158   1,592   16,955 
OPCo   91,430   1,838   19,615 
PSO   40   -   40 
SWEPCo   139   -   93 
9.FAIR VALUE MEASUREMENTS

With the adoption of newFair Value Hierarchy and Valuation Techniques

The accounting guidance the Registrant Subsidiaries are required to provide certainfor “Fair Value Measurements and Disclosures” establishes a fair value disclosureshierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.  When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value.  Valuation models utilize various inputs such as commodity, interest rate and, to a lesser de gree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.

For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1.  Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated.  Management typically obtains multiple broker quotes, which were previously only requiredare non-binding in nature but are based on recent trades in the annual report.  The new accounting guidance did not changemarketplace.  When multiple broker quotes are obtained, the methodquoted bid and ask prices are averaged. &# 160;In certain circumstances, a broker quote may be discarded if it is a clear outlier.  Management uses a historical correlation analysis between the broker quoted location and the illiquid locations and if the points are highly correlated, these locations are included within Level 2 as well.  Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information.  Long-dated and illiquid complex or structured transactions and FTRs can introduce the need for internally developed modeling inputs based upon extrapolations and assumptions of observable market data to calculate the amounts reportedestimate fair value.  When such inputs have a significant impact on the balance sheets.measurement of fair value, the instrument is categorized as Level 3.

AEP utilizes its trustee’s external pricing service in its estimate of the fair value of the underlying investments held in the nuclear trusts.  AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value.  AEP’s investment managers perform their own valuation testing to verify the fair values of the securities.  AEP receives audit reports of the trustee’s operating controls and valuation processes.  The trustee uses multiple pricing vendors for the assets held in the trusts.  Equities are classified as Level 1 holdings if they are actively traded on exchanges.  Fixed income securities do not trade on an exchange and do not have an official closing price.  Pricing vendors calculate bond valuations u sing financial models and matrices.  Fixed income securities are typically classified as Level 2 holdings because their valuation inputs are based on observable market data.  Observable inputs used for valuing fixed income securities are benchmark yields, reported trades, broker/dealer quotes, issuer spreads, two-sided markets, benchmark securities, bids, offers, reference data and economic events.  Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments.  Investments with unobservable valuation inputs are classified as Level 3 investments.

Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equities.  They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets.

Items classified as Level 2 are primarily investments in individual fixed income securities.  These fixed income securities are valued using models with input data as follows:

Type of Fixed Income Security
United StatesState and Local
Type of InputGovernmentCorporate DebtGovernment
Benchmark YieldsXXX
Broker QuotesXXX
Discount MarginsXX
Treasury Market UpdateX
Base SpreadXXX
Corporate ActionsX
Ratings Agency UpdatesXX
Prepayment Schedule and HistoryX
Yield AdjustmentsX

Fair Value Measurements of Long-term Debt

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

The book values and fair values of Long-term Debt for the Registrant Subsidiaries at September 30, 2009as of March 31, 2010 and December 31, 20082009 are summarized in the following table:

 September 30, 2009  December 31, 2008 
 Book Value  Fair Value  Book Value  Fair Value  March 31, 2010  December 31, 2009 
Company (in thousands)  Book Value  Fair Value  Book Value  Fair Value 
 (in thousands) 
APCo $3,372,360  $3,605,111  $3,174,512  $2,858,278  $3,411,244  $3,651,615  $3,477,306  $3,699,373 
CSPCo  1,536,291   1,613,545   1,443,594   1,410,609   1,588,592   1,680,540   1,536,393   1,616,857 
I&M  2,077,699   2,187,235   1,377,914   1,308,712   2,053,090   2,185,441   2,077,906   2,192,854 
OPCo  3,242,299   3,366,787   3,039,376   2,953,131   3,329,109   3,495,805   3,242,505   3,380,084 
PSO  868,738   913,767   884,859   823,150   968,808   1,020,923   968,121   1,007,183 
SWEPCo  1,475,152   1,555,651   1,478,149   1,358,122   1,769,331   1,850,116   1,474,153   1,554,165 

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities.  By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines.  In general, limitations include:

·Acceptable investments (rated investment grade or above when purchased).
·Maximum percentage invested in a specific type of investment.
·Prohibition of investment in obligations of AEP or its affiliates.
·Withdrawals permitted only for payment of decommissioning costs and trust expenses.
·Target asset allocation is 50% fixed income and 50% equity securities.

I&M maintains trust records for each regulatory jurisdiction.  These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities.  The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.

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

The following is a summary of nuclear trust fund investments at September 30, 2009March 31, 2010 and December 31, 2008:2009:

 September 30, 2009 December 31, 2008 
 Estimated Gross Other-Than- Estimated Gross Other-Than- 
 Fair Unrealized Temporary Fair Unrealized Temporary 
 Value Gains Impairments Value Gains Impairments 
 (in millions) 
Cash $19  $-  $-  $18  $-  $- 
Debt Securities  780   35   (2)  773   52   (3)
Equity Securities  565   223   (135)  469   89   (82)
Spent Nuclear Fuel and Decommissioning Trusts $1,364  $258  $(137) $1,260  $141  $(85)
 March 31, 2010 December 31, 2009 
 Estimated Gross Other-Than- Estimated Gross Other-Than- 
 Fair Unrealized Temporary Fair Unrealized Temporary 
 Value Gains Impairments Value Gains Impairments 
 (in thousands) 
Cash and Cash Equivalents $15,683  $-  $-  $14,412  $-  $- 
Fixed Income Securities:                        
United States Government  450,711   14,166   (1,890)  400,565   12,708   (3,472)
Corporate Debt  58,688   4,913   (2,115)  57,291   4,636   (2,177)
State and Local Government  326,354   3,402   509   368,930   7,924   991 
Subtotal Fixed Income Securities  835,753   22,481   (3,496)  826,786   25,268   (4,658)
Equity Securities – Domestic  581,576   261,157   (118,469)  550,721   234,437   (119,379)
Spent Nuclear Fuel and Decommissioning Trusts $1,433,012  $283,638  $(121,965) $1,391,919  $259,705  $(124,037)

The following table provides the securities activity within the decommissioning and SNF trusts for the three and nine months ended September 30,March 31, 2010 and 2009:
      Gross Realized 
Proceeds From Purchases Gross Realized Gains Losses on 
Investment Sales of Investments on Investment Sales Investment Sales 
(in millions)        Gross Realized 
Three Months Ended $113  $129  $1  $-  Proceeds From Purchases Gross Realized Gains Losses on 
Nine Months Ended  524   571   10   (1)
March 31, Investment Sales of Investments on Investment Sales Investment Sales 
 (in thousands) 
2010  $232,078  $247,632  $5,328  $181 
2009   158,086   178,407   2,882   348 

The adjusted cost of debt securities was $745$813 million and $721$801 million as of September 30, 2009March 31, 2010 and December 31, 2008,2009, respectively.

The fair value of debt securities held in the nuclear trust funds, summarized by contractual maturities, at September 30, 2009March 31, 2010 was as follows:
Fair Value Fair Value 
of Debt of Debt 
Securities Securities 
(in millions) (in thousands) 
Within 1 year $27  $15,542 
1 year – 5 years  217   308,892 
5 years – 10 years  241   255,731 
After 10 years  295   255,588 
Total $780  $835,753 

Fair Value Measurements of Financial Assets and Liabilities

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

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

The following tables set forth, by level within the fair value hierarchy, the Registrant Subsidiaries’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2009March 31, 2010 and December 31, 2008.2009.  As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  There have not been any significant changes in AEP’s valuationmanagement’s valuati on techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis as of September 30,
March 31, 2010
APCo         
 Level 1 Level 2 Level 3 Other Total
Assets:(in thousands)
               
Risk Management Assets               
Risk Management Commodity Contracts (a) (g)$3,734  $673,530  $28,138  $(569,091) $136,311 
Cash Flow Hedges:              
Commodity Hedges (a) -   5,137   -   (4,465)  672 
Interest Rate/Foreign Currency Hedges (a) -   207   -   -   207 
Dedesignated Risk Management Contracts (b) -   -   -   7,186   7,186 
Total Risk Management Assets$3,734  $678,874  $28,138  $(566,370) $144,376 
               
Liabilities:              
               
Risk Management Liabilities               
Risk Management Commodity Contracts (a) (g)$3,832  $655,568  $9,451  $(610,636) $58,215 
Cash Flow Hedges:              
Commodity Hedges (a) -   9,069   -   (4,465)  4,604 
Interest Rate/Foreign Currency Hedges (a) -   908   -   -   908 
DETM Assignment (c) -   -   -   1,822   1,822 
Total Risk Management Liabilities$3,832  $665,545  $9,451  $(613,279) $65,549 

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2009
APCo               APCo         
 Level 1  Level 2  Level 3  Other  Total  Level 1 Level 2 Level 3 Other Total
Assets: (in thousands) Assets:(in thousands)
                             
Other Cash Deposits (d) $421  $-  $-  $51  $472 Other Cash Deposits (d)$421  $-  $-  $51  $472 
                                  
Risk Management Assets                                  
Risk Management Contracts (a)  5,625   637,506   27,559   (542,921)  127,769 Risk Management Contracts (a) 2,344   449,406   12,866  (360,248)  104,368 
Cash Flow and Fair Value Hedges (a)  -   6,518   -   (3,147)  3,371 Cash Flow and Fair Value Hedges (a) -   3,620   -  (1,621)  1,999 
Dedesignated Risk Management Contracts (b)  -   -   -   10,047   10,047 Dedesignated Risk Management Contracts (b) -   -   -   8,730   8,730 
Total Risk Management Assets  5,625   644,024   27,559   (536,021)  141,187 Total Risk Management Assets 2,344   453,026   12,866   (353,139)  115,097 
                                  
Total Assets $6,046  $644,024  $27,559  $(535,970) $141,659 Total Assets$2,765  $453,026  $12,866  $(353,088) $115,569 
                                  
Liabilities:                    Liabilities:             
                                  
Risk Management Liabilities                                  
Risk Management Contracts (a) $6,116  $603,805  $3,911  $(566,033) $47,799 Risk Management Contracts (a)$2,648  $422,063  $3,438  $(388,265) $39,884 
Cash Flow and Fair Value Hedges (a)  -   6,540   -   (3,147)  3,393 Cash Flow and Fair Value Hedges (a) -   5,163   -  (1,621)  3,542 
DETM Assignment (c)  -   -   -   3,464   3,464 DETM Assignment (c) -   -   -   2,730   2,730 
Total Risk Management Liabilities $6,116  $610,345  $3,911  $(565,716) $54,656 Total Risk Management Liabilities$2,648  $427,226  $3,438  $(387,156) $46,156 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis as of December
March 31, 20082010
APCo               
CSPCoCSPCo         
 Level 1  Level 2  Level 3  Other  Total  Level 1 Level 2 Level 3 Other Total
Assets: (in thousands) Assets:(in thousands)
                           
Other Cash Deposits (d) $656  $-  $-  $52  $708 
                    
Risk Management Assets                                
Risk Management Contracts (a)  16,105   667,748   11,981   (597,676)  98,158 
Cash Flow and Fair Value Hedges (a)  -   6,634   -   (1,413)  5,221 
Risk Management Commodity Contracts (a) (g)Risk Management Commodity Contracts (a) (g)$2,113  $382,034  $15,918  $(322,850) $77,215 
Cash Flow Hedges:Cash Flow Hedges:           
Commodity Hedges (a)Commodity Hedges (a) -  2,870   -  (2,525) 345 
Dedesignated Risk Management Contracts (b)  -   -   -   12,856   12,856 Dedesignated Risk Management Contracts (b) -   -   -   4,066   4,066 
Total Risk Management Assets  16,105   674,382   11,981   (586,233)  116,235 Total Risk Management Assets$2,113  $384,904  $15,918  $(321,309) $81,626 
                    
Total Assets $16,761  $674,382  $11,981  $(586,181) $116,943 
                                
Liabilities:                    Liabilities:           
                                
Risk Management Liabilities                                
Risk Management Contracts (a) $18,808  $628,974  $3,972  $(601,108) $50,646 
Cash Flow and Fair Value Hedges (a)  -   2,545   -   (1,413)  1,132 
Risk Management Commodity Contracts (a) (g)Risk Management Commodity Contracts (a) (g)$2,168  $371,835  $5,348  $(346,379) $32,972 
Cash Flow Hedges:Cash Flow Hedges:           
Commodity Hedges (a)Commodity Hedges (a) -  5,129   -  (2,525) 2,604 
DETM Assignment (c)  -   -   -   5,230   5,230 DETM Assignment (c) -   -   -   1,031   1,031 
Total Risk Management Liabilities $18,808  $631,519  $3,972  $(597,291) $57,008 Total Risk Management Liabilities$2,168  $376,964  $5,348  $(347,873) $36,607 

Assets and Liabilities Measured at Fair Value on a Recurring Basis as of September 30,
December 31, 2009
CSPCo               CSPCo         
 Level 1  Level 2  Level 3  Other  Total  Level 1 Level 2 Level 3 Other Total
Assets: (in thousands) Assets:(in thousands)
                           
Other Cash Deposits (d) $20,056  $-  $-  $21  $20,077 Other Cash Deposits (d)$16,129  $-  $-  $21  $16,150 
                                
Risk Management Assets                                
Risk Management Contracts (a)  2,981   335,327   14,603   (285,521)  67,390 Risk Management Contracts (a) 1,188  227,150   6,518  (182,038) 52,818 
Cash Flow and Fair Value Hedges (a)  -   3,429   -   (1,659)  1,770 Cash Flow and Fair Value Hedges (a) -  1,805   -  (821) 984 
Dedesignated Risk Management Contracts (b)  -   -   -   5,325   5,325 Dedesignated Risk Management Contracts (b) -   -   -   4,423   4,423 
Total Risk Management Assets  2,981   338,756   14,603   (281,855)  74,485 Total Risk Management Assets 1,188   228,955   6,518   (178,436)  58,225 
                                
Total Assets $23,037  $338,756  $14,603  $(281,834) $94,562 Total Assets$17,317  $228,955  $6,518  $(178,415) $74,375 
                                
Liabilities:                    Liabilities:           
                                
Risk Management Liabilities                                
Risk Management Contracts (a) $3,241  $317,618  $2,071  $(297,767) $25,163 Risk Management Contracts (a)$1,342  $213,330  $1,742  $(196,226) $20,188 
Cash Flow and Fair Value Hedges (a)  -   3,457   -   (1,659)  1,798 Cash Flow and Fair Value Hedges (a) -  2,615   -  (821) 1,794 
DETM Assignment (c)  -   -   -   1,836   1,836 DETM Assignment (c) -   -   -   1,383   1,383 
Total Risk Management Liabilities $3,241  $321,075  $2,071  $(297,590) $28,797 Total Risk Management Liabilities$1,342  $215,945  $1,742  $(195,664) $23,365 

Assets and Liabilities Measured at Fair Value on a Recurring Basis as of
March 31, 2010
I&M         
 Level 1 Level 2 Level 3 Other Total
Assets:(in thousands)
               
Risk Management Assets               
Risk Management Commodity Contracts (a) (g)$2,131  $393,603  $16,054  $(320,892) $90,896 
Cash Flow Hedges:              
Commodity Hedges (a) -   2,908   -   (2,546)  362 
Dedesignated Risk Management Contracts (b) -   -   -   4,100   4,100 
Total Risk Management Assets 2,131   396,511   16,054   (319,338)  95,358 
               
Spent Nuclear Fuel and Decommissioning Trusts               
Cash and Cash Equivalents (e) -   6,057   -   9,626   15,683 
Fixed Income Securities:              
United States Government -   450,711   -   -   450,711 
Corporate Debt -   58,688   -   -   58,688 
State and Local Government -   326,354   -   -   326,354 
Subtotal Fixed Income Securities -   835,753   -   -   835,753 
Equity Securities – Domestic (f) 581,576   -   -   -   581,576 
Total Spent Nuclear Fuel and Decommissioning Trusts 581,576   841,810   -   9,626   1,433,012 
               
Total Assets$583,707  $1,238,321  $16,054  $(309,712) $1,528,370 
               
Liabilities:              
               
Risk Management Liabilities               
Risk Management Commodity Contracts (a) (g)$2,186  $369,967  $5,392  $(344,483) $33,062 
Cash Flow Hedges:              
Commodity Hedges (a) -   5,173   -   (2,546)  2,627 
DETM Assignment (c) -   -   -   1,040   1,040 
Total Risk Management Liabilities$2,186  $375,140  $5,392  $(345,989) $36,729 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 20082009
CSPCo               
I&MI&M         
 Level 1  Level 2  Level 3  Other  Total  Level 1 Level 2 Level 3 Other Total
Assets: (in thousands) Assets:(in thousands)
               
Other Cash Deposits (d) $31,129  $-  $-  $1,171  $32,300 
                                
Risk Management Assets                               
Risk Management Contracts (a)  9,042   366,557   6,724   (328,027)  54,296 Risk Management Contracts (a)$1,198  $231,777  $6,571  $(181,446) $58,100 
Cash Flow and Fair Value Hedges (a)  -   3,725   -   (794)  2,931 Cash Flow and Fair Value Hedges (a) -  1,839   -  (828) 1,011 
Dedesignated Risk Management Contracts (b)  -   -   -   7,218   7,218 Dedesignated Risk Management Contracts (b) -   -   -   4,461   4,461 
Total Risk Management Assets  9,042   370,282   6,724   (321,603)  64,445 Total Risk Management Assets 1,198   233,616   6,571   (177,813)  63,572 
           
Spent Nuclear Fuel and Decommissioning Trusts           
Cash and Cash Equivalents (e)Cash and Cash Equivalents (e) -  3,562   -  10,850  14,412 
Fixed Income Securities:Fixed Income Securities:           
United States GovernmentUnited States Government -  400,565   -  -  400,565 
Corporate DebtCorporate Debt -  57,291   -  -  57,291 
State and Local GovernmentState and Local Government -   368,930   -   -   368,930 
Subtotal Fixed Income SecuritiesSubtotal Fixed Income Securities -  826,786   -  -  826,786 
Equity Securities (f)Equity Securities (f) 550,721   -   -   -   550,721 
Total Spent Nuclear Fuel and Decommissioning Trusts  550,721   830,348   -   10,850   1,391,919 
                                
Total Assets $40,171  $370,282  $6,724  $(320,432) $96,745 Total Assets$551,919  $1,063,964  $6,571  $(166,963) $1,455,491 
                                
Liabilities:                    Liabilities:           
                                
Risk Management Liabilities                               
Risk Management Contracts (a) $10,559  $344,860  $2,227  $(329,954) $27,692 Risk Management Contracts (a)$1,353  $213,242  $1,755  $(195,732) $20,618 
Cash Flow and Fair Value Hedges (a)  -   1,429   -   (794)  635 Cash Flow and Fair Value Hedges (a) -  2,637   -  (828) 1,809 
DETM Assignment (c)  -   -   -   2,937   2,937 DETM Assignment (c) -   -   -   1,395   1,395 
Total Risk Management Liabilities $10,559  $346,289  $2,227  $(327,811) $31,264 Total Risk Management Liabilities$1,353  $215,879  $1,755  $(195,165) $23,822 

Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31, 2010
OPCo          
 Level 1 Level 2 Level 3 Other Total 
Assets:(in thousands) 
                
Other Cash Deposits (d)$2,054  $-  $-  $1,229 $3,283 
                
Risk Management Assets                
Risk Management Commodity Contracts (a) (g) 2,432   512,728   18,344   (435,673)  97,831  
Cash Flow Hedges:               
Commodity Hedges (a) -   3,370   -   (2,907)  463  
Dedesignated Risk Management Contracts (b) -   -   -   4,679   4,679  
Total Risk Management Assets 2,432   516,098   18,344   (433,901)  102,973  
                
Total Assets$4,486  $516,098  $18,344  $(432,672) $106,256  
                
Liabilities:               
                
 Risk Management Liabilities               
Risk Management Commodity Contracts (a) (g)$2,495  $501,643  $6,164  $(464,678) $45,624  
Cash Flow Hedges:               
Commodity Hedges (a) -   5,906   -   (2,907)  2,999  
DETM Assignment (c) -   -   -   1,186   1,186  
Total Risk Management Liabilities$2,495  $507,549  $6,164  $(466,399) $49,809  

Assets and Liabilities Measured at Fair Value on a Recurring Basis as of September 30,
December 31, 2009
I&M               
OPCoOPCo         
 Level 1  Level 2  Level 3  Other  Total  Level 1 Level 2 Level 3 Other Total
Assets: (in thousands) Assets:(in thousands)
           
Other Cash Deposits (d)Other Cash Deposits (d)$1,075  $-  $-  $24  $1,099 
                           
Risk Management Assets                           
Risk Management Contracts (a) $2,874  $331,776  $14,087  $(282,877) $65,860 Risk Management Contracts (a) 1,383  332,904   7,644  (270,272) 71,659 
Cash Flow and Fair Value Hedges (a)  -   3,323   -   (1,605)  1,718 Cash Flow and Fair Value Hedges (a) -  2,199   -  (957) 1,242 
Dedesignated Risk Management Contracts (b)  -   -   -   5,134   5,134 Dedesignated Risk Management Contracts (b) -   -   -   5,150   5,150 
Total Risk Management Assets  2,874   335,099   14,087   (279,348)  72,712 Total Risk Management Assets 1,383   335,103   7,644   (266,079)  78,051 
                    
Spent Nuclear Fuel and Decommissioning Trusts                    
Cash and Cash Equivalents (e)  -   9,597   -   9,136   18,733 
Debt Securities (f)  -   780,227   -   -   780,227 
Equity Securities (g)  565,482   -   -   -   565,482 
Total Spent Nuclear Fuel and Decommissioning Trusts  565,482   789,824   -   9,136   1,364,442 
                                
Total Assets $568,356  $1,124,923  $14,087  $(270,212) $1,437,154 Total Assets$2,458  $335,103  $7,644  $(266,055) $79,150 
                                
Liabilities:                    Liabilities:           
                                
Risk Management Liabilities                                
Risk Management Contracts (a) $3,125  $314,195  $2,002  $(294,694) $24,628 Risk Management Contracts (a)$1,562  $317,114  $2,075  $(287,549) $33,202 
Cash Flow and Fair Value Hedges (a)  -   3,339   -   (1,605)  1,734 Cash Flow and Fair Value Hedges (a) -  3,045   -  (957) 2,088 
DETM Assignment (c)  -   -   -   1,770   1,770 DETM Assignment (c) -   -   -   1,611   1,611 
Total Risk Management Liabilities $3,125  $317,534  $2,002  $(294,529) $28,132 Total Risk Management Liabilities$1,562  $320,159  $2,075  $(286,895) $36,901 

Assets and Liabilities Measured at Fair Value on a Recurring Basis

March 31, 2010
PSO         
 Level 1 Level 2 Level 3 Other Total
Assets:(in thousands)
               
Risk Management Assets               
Risk Management Commodity Contracts (a) (g)$-  $14,983  $4  $(11,732) $3,255 
Cash Flow Hedges:              
Commodity Hedges (a) -   170   -   (5)  165 
Total Risk Management Assets$-  $15,153  $4  $(11,737) $3,420 
               
Liabilities:              
               
Risk Management Liabilities               
Risk Management Commodity Contracts (a) (g)$-  $12,550  $2  $(12,081) $471 
Cash Flow Hedges:              
Commodity Hedges (a) -   187   -   (5)  182 
Total Risk Management Liabilities$-  $12,737  $2  $(12,086) $653 

Assets and Liabilities Measured at Fair Value on a Recurring Basis as of
December 31, 20082009
I&M               
PSOPSO         
 Level 1  Level 2  Level 3  Other  Total  Level 1 Level 2 Level 3 Other Total
Assets: (in thousands) Assets:(in thousands)
                             
Risk Management Assets                             
Risk Management Contracts (a) $8,750  $357,405  $6,508  $(319,857) $52,806 Risk Management Contracts (a)$-  $17,494  $14  $(15,260) $2,248 
Cash Flow and Fair Value Hedges (a)  -   3,605   -   (768)  2,837 Cash Flow and Fair Value Hedges (a) -   179   -   (1)  178 
Dedesignated Risk Management Contracts (b)  -   -   -   6,985   6,985 
Total Risk Management Assets  8,750   361,010   6,508   (313,640)  62,628 Total Risk Management Assets$-  $17,673  $14  $(15,261) $2,426 
                    
Spent Nuclear Fuel and Decommissioning Trusts                    
Cash and Cash Equivalents (e)  -   7,818   -   11,845   19,663 
Debt Securities (f)  -   771,216   -   -   771,216 
Equity Securities (g)  468,654   -   -   -   468,654 
Total Spent Nuclear Fuel and Decommissioning Trusts  468,654   779,034   -   11,845   1,259,533 
                    
Total Assets $477,404  $1,140,044  $6,508  $(301,795) $1,322,161 
                                  
Liabilities:                    Liabilities:             
                                  
Risk Management Liabilities                                  
Risk Management Contracts (a) $10,219  $336,280  $2,156  $(321,722) $26,933 Risk Management Contracts (a)$-  $17,865  $12  $(15,454) $2,423 
Cash Flow and Fair Value Hedges (a)  -   1,383   -   (768)  615 Cash Flow and Fair Value Hedges (a) -   301   -   (1)  300 
DETM Assignment (c)  -   -   -   2,842   2,842 
Total Risk Management Liabilities $10,219  $337,663  $2,156  $(319,648) $30,390 Total Risk Management Liabilities$-  $18,166  $12  $(15,455) $2,723 

Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31, 2010
SWEPCo         
 Level 1 Level 2 Level 3 Other Total
Assets:(in thousands)
               
Risk Management Assets               
Risk Management Commodity Contracts (a) (g)$-  $21,234  $7  $(19,096) $2,145 
Cash Flow Hedges:              
Commodity Hedges (a) -   157   -   (6)  151 
Interest Rate/Foreign Currency Hedges (a) -   19   -   (16)  3 
Total Risk Management Assets$-  $21,410  $7  $(19,118) $2,299 
               
Liabilities:              
               
Risk Management Liabilities               
Risk Management Commodity Contracts (a) (g)$-  $21,192  $3  $(19,668) $1,527 
Cash Flow Hedges:              
Commodity Hedges (a) -   10   -   (6)  4 
Interest Rate/Foreign Currency Hedges (a) -   106   -   (16)  90 
Total Risk Management Liabilities$-  $21,308  $3  $(19,690) $1,621 

Assets and Liabilities Measured at Fair Value on a Recurring Basis as of September 30,
December 31, 2009
OPCo               
SWEPCoSWEPCo         
 Level 1  Level 2  Level 3  Other  Total  Level 1 Level 2 Level 3 Other Total
Assets: (in thousands) Assets:(in thousands)
               
Other Cash Deposits (d) $1,075  $-  $-  $24  $1,099 
                               
Risk Management Assets                               
Risk Management Contracts (a)  3,419   456,035   16,801   (389,110)  87,145 Risk Management Contracts (a)$-  $26,945  $22  $(24,007) $2,960 
Cash Flow and Fair Value Hedges (a)  -   3,987   -   (1,921)  2,066 Cash Flow and Fair Value Hedges (a) -   216   -   (43)  173 
Dedesignated Risk Management Contracts (b)  -   -   -   6,108   6,108 
Total Risk Management Assets  3,419   460,022   16,801   (384,923)  95,319 Total Risk Management Assets$-  $27,161  $22  $(24,050) $3,133 
                    
Total Assets $4,494  $460,022  $16,801  $(384,899) $96,418 
                               
Liabilities:                    Liabilities:          
                               
Risk Management Liabilities                               
Risk Management Contracts (a) $3,717  $436,519  $2,415  $(403,240) $39,411 Risk Management Contracts (a)$-  $25,312  $19  $(24,312) $1,019 
Cash Flow and Fair Value Hedges (a)  -   3,983   -   (1,921)  2,062 Cash Flow and Fair Value Hedges (a) -   89   -   (43)  46 
DETM Assignment (c)  -   -   -   2,105   2,105 
Total Risk Management Liabilities $3,717  $440,502  $2,415  $(403,056) $43,578 Total Risk Management Liabilities$-  $25,401  $19  $(24,355) $1,065 


Assets and Liabilities Measured at Fair Value on a Recurring Basis as of December 31, 2008
OPCo               
  Level 1  Level 2  Level 3  Other  Total 
Assets: (in thousands) 
                
Other Cash Deposits (d) $4,197  $-  $-  $2,431  $6,628 
                     
Risk Management Assets                    
Risk Management Contracts (a)  11,200   575,415   8,364   (515,162)  79,817 
Cash Flow and Fair Value Hedges (a)  -   4,614   -   (983)  3,631 
Dedesignated Risk Management Contracts (b)  -   -   -   8,941   8,941 
Total Risk Management Assets  11,200   580,029   8,364   (507,204)  92,389 
                     
Total Assets $15,397  $580,029  $8,364  $(504,773) $99,017 
                     
Liabilities:                    
                     
Risk Management Liabilities                    
Risk Management Contracts (a) $13,080  $550,278  $2,801  $(517,548) $48,611 
Cash Flow and Fair Value Hedges (a)  -   1,770   -   (983)  787 
DETM Assignment (c)  -   -   -   3,637   3,637 
Total Risk Management Liabilities $13,080  $552,048  $2,801  $(514,894) $53,035 

Assets and Liabilities Measured at Fair Value on a Recurring Basis as of September 30, 2009
PSO               
  Level 1  Level 2  Level 3  Other  Total 
Assets: (in thousands) 
                
Risk Management Assets               
Risk Management Contracts (a) $818  $25,801  $16  $(22,503) $4,132 
Cash Flow and Fair Value Hedges (a)  -   125   -   (40)  85 
Total Risk Management Assets $818  $25,926  $16  $(22,543) $4,217 
                     
Liabilities:                    
                     
Risk Management Liabilities                    
Risk Management Contracts (a) $771  $26,446  $11  $(22,528) $4,700 
Cash Flow and Fair Value Hedges (a)  -   578   -   (40)  538 
Total Risk Management Liabilities $771  $27,024  $11  $(22,568) $5,238 
Assets and Liabilities Measured at Fair Value on a Recurring Basis as of December 31, 2008
PSO               
  Level 1  Level 2  Level 3  Other  Total 
Assets: (in thousands) 
                
Risk Management Assets               
Risk Management Contracts (a) $3,295  $39,866  $8  $(36,422) $6,747 
                     
Liabilities:                    
                     
Risk Management Liabilities                    
Risk Management Contracts (a) $3,664  $37,835  $10  $(36,527) $4,982 
DETM Assignment (c)  -   -   -   149   149 
Total Risk Management Liabilities $3,664  $37,835  $10  $(36,378) $5,131 

Assets and Liabilities Measured at Fair Value on a Recurring Basis as of September 30, 2009
SWEPCo               
  Level 1  Level 2  Level 3  Other  Total 
Assets: (in thousands) 
                
Risk Management Assets               
Risk Management Contracts (a) $972  $38,392  $24  $(33,668) $5,720 
Cash Flow and Fair Value Hedges (a)  -   237   -   (150)  87 
Total Risk Management Assets $972  $38,629  $24  $(33,818) $5,807 
                     
Liabilities:                    
                     
Risk Management Liabilities                    
Risk Management Contracts (a) $916  $36,411  $18  $(33,707) $3,638 
Cash Flow and Fair Value Hedges (a)  -   175   -   (150)  25 
Total Risk Management Liabilities $916  $36,586  $18  $(33,857) $3,663 

Assets and Liabilities Measured at Fair Value on a Recurring Basis as of December 31, 2008
SWEPCo               
  Level 1  Level 2  Level 3  Other  Total 
Assets: (in thousands) 
                
Risk Management Assets               
Risk Management Contracts (a) $3,883  $61,471  $14  $(55,710) $9,658 
Cash Flow and Fair Value Hedges (a)  -   107   -   (80)  27 
Total Risk Management Assets $3,883  $61,578  $14  $(55,790) $9,685 
                     
Liabilities:                    
                     
Risk Management Liabilities                    
Risk Management Contracts (a) $4,318  $58,390  $17  $(55,834) $6,891 
Cash Flow and Fair Value Hedges (a)  -   265   -   (80)  185 
DETM Assignment (c)  -   -   -   175   175 
Total Risk Management Liabilities $4,318  $58,655  $17  $(55,739) $7,251 
(a)Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.”
(b)“Dedesignated Risk Management Contracts” areRepresents contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for “Derivatives and Hedging.”  At the time of the normal election, the MTM value was frozen and no longer fair valued.  This MTM value will be amortized into revenues over the remaining life of the contract.contracts.
(c)See “Natural Gas Contracts with DETM” section of Note 15 in the 20082009 Annual Report.
(d)Amounts in “Other” column primarily represent cash deposits with third parties.  Level 1 amounts primarily represent investments in money market funds.
(e)Amounts in “Other” column primarily represent accrued interest receivables from financial institutions.  Level 2 amounts primarily represent investments in money market funds.
(f)Amounts represent corporate, municipal and treasury bonds.
(g)Amounts represent publicly traded equity securities and equity-based mutual funds.
(g)Substantially comprised of power contracts for APCo, CSPCo, I&M and OPCo and coal contracts for PSO and SWEPCo.
There have been no transfers between Level 1 and Level 2 during the three months ended March 31, 2010.

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

  APCo CSPCo I&M OPCo PSO SWEPCo
Three Months Ended September 30, 2009 (in thousands)
Balance as of July 1, 2009 $13,900  $7,372  $7,135  $9,410  $12  $15 
Realized (Gain) Loss Included in Net Income (or Changes in Net Assets) (a)  (2,762)  (1,465)  (1,418)  (2,087)  (11)  (13)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)  -   347   -   (185)  -   - 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income  -   -   -   -   -   - 
Purchases, Issuances and Settlements  -   -   -   -   -   - 
Transfers in and/or out of Level 3 (b)  2,322   1,231   1,192   1,525   -   - 
Changes in Fair Value Allocated to Regulated Jurisdictions (c)  10,188   5,047   5,176   5,723   4   4 
Balance as of September 30, 2009 $23,648  $12,532  $12,085  $14,386  $5  $6 
Three Months Ended March 31, 2010 APCo CSPCo I&M OPCo PSO SWEPCo
  (in thousands)
Balance as of January 1, 2010 $9,428  $4,776  $4,816  $5,569  $2  $3 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)  8,947   5,056   5,099   5,818   -   - 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)  -   6,122   -   6,987   -   - 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income  -   -   -   -   -   - 
Purchases, Issuances and Settlements (c)  (10,221)  (5,743)  (5,792)  (6,612)  -   - 
Transfers into Level 3 (d) (h)  439   222   224   259   -   - 
Transfers out of Level 3 (e) (h)  269   137   138   159   -   - 
Changes in Fair Value Allocated to Regulated Jurisdictions (g)  9,825   -   6,177   -   -   1 
Balance as of March 31, 2010 $18,687  $10,570  $10,662  $12,180  $2  $4 

  APCo CSPCo I&M OPCo PSO SWEPCo
Nine Months Ended September 30, 2009 (in thousands)
Balance as of January 1, 2009 $8,009  $4,497  $4,352  $5,563  $(2) $(3)
Realized (Gain) Loss Included in Net Income (or Changes in Net Assets) (a)  (6,448)  (3,621)  (3,504)  (4,473)  3   5 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)  -   6,069   -   6,906   -   - 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income  -   -   -   -   -   - 
Purchases, Issuances and Settlements  -   -   -   -   -   - 
Transfers in and/or out of Level 3 (b)  (328)  (184)  (178)  (228)  -   - 
Changes in Fair Value Allocated to Regulated Jurisdictions (c)  22,415   5,771   11,415   6,618   4   4 
Balance as of September 30, 2009 $23,648  $12,532  $12,085  $14,386  $5  $6 

Three Months Ended September 30, 2008 APCo CSPCo I&M OPCo PSO SWEPCo 
  (in thousands) 
Balance as of July 1, 2008 $(18,560) $(11,122) $(10,675) $(13,245) $(23) $(45) 
Realized (Gain) Loss Included in Net Income   (or Changes in
   Net Assets) (a)
  4,466   2,670   2,561   3,287   4   13  
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)  -   (1,317)  -   (1,574)  -   26  
Realized and Unrealized Gains (Losses)   Included in Other
   Comprehensive Income
  -   -   -   -   -   -  
Purchases, Issuances and Settlements  -   -   -   -   -   -  
Transfers in and/or out of Level 3 (b)  5,595   3,360   3,228   3,914   (1,249)  (1,471) 
Changes in Fair Value Allocated to Regulated   Jurisdictions (c)  3,858   3,814   2,373   4,285   61   49  
Balance as of September 30, 2008 $(4,641) $(2,595) $(2,513) $(3,333) $(1,207) $(1,428) 

Nine Months Ended September 30, 2008 APCo CSPCo I&M OPCo PSO SWEPCo 
  (in thousands) 
Balance as of January 1, 2008 $(697) $(263) $(280) $(1,607) $(243) $(408) 
Realized (Gain) Loss Included in Net Income   (or Changes in
   Net Assets) (a)
  332   88   105   1,063   170   290  
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)  -   190   -   126   -   56  
Realized and Unrealized Gains (Losses)   Included in Other
   Comprehensive Income
  -   -   -   -   -   -  
Purchases, Issuances and Settlements  -   -   -   -   -   -  
Transfers in and/or out of Level 3 (b)  (731)  (454)  (430)  (244)  (1,249)  (1,472) 
Changes in Fair Value Allocated to Regulated   Jurisdictions (c)  (3,545)  (2,156)  (1,908)  (2,671)  115   106  
Balance as of September 30, 2008 $(4,641) $(2,595) $(2,513) $(3,333) $(1,207) $(1,428) 
  APCo CSPCo I&M OPCo PSO SWEPCo
Three Months Ended March 31, 2009 (in thousands)
Balance as of January 1, 2009 $8,009  $4,497  $4,352  $5,563  $(2) $(3)
Realized (Gain) Loss Included in Net Income   (or Changes in Net Assets) (a)  (3,898)  (2,189)  (2,118)  (2,700)  3   5 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)  -   3,264   -   4,045   -   - 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income  -   -   -   -   -   - 
Purchases, Issuances and Settlements  -   -   -   -   -   - 
Transfers in and/or out of Level 3 (f)  (74)  (42)  (40)  (52)  -   - 
Changes in Fair Value Allocated to Regulated Jurisdictions (g)  7,810   764   3,898   946   -   - 
Balance as of March 31, 2009 $11,847  $6,294  $6,092  $7,802  $1  $2 

(a)Included in revenues on the Condensed Statements of Income.
(b)“TransfersRepresents the change in and/fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
(c)Represents the settlement of risk management commodity contracts for the reporting period.
(d)Represents existing assets or out ofliabilities that were previously categorized as Level 3” represent2.
(e)Represents existing assets or liabilities that were previously categorized as Level 3.
(f)Represents existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Levellevel 3 for which the lowest significant input became observable during the period.
(c)(g)“Changes in Fair Value Allocated to Regulated Jurisdictions” relatesRelates to the net gains (losses) of those contracts that are not reflected on the Condensed Statements of Income.  These net gains (losses) are recorded as regulatory liabilities/assets.assets/liabilities.
(h)Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.

10.INCOME TAXES

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

The Registrant Subsidiaries are no longer subject to U.S. federal examination for years before 2000.2001.  The Registrant Subsidiaries have completed the exam for the years 2001 through 2006 and have issues that are being pursued at the appeals level.  The years 2007 and 2008 are currently under examination.  Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for income taxes have been made for potential liabilities resulting from such matters.  In addition, the Registrant Subsidiaries accrue interest on these uncertain tax positions.  Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on net income.

The Registrant Subsidiaries file income tax returns in various state and local jurisdictions.  These taxing authorities routinely examine their tax returns and the Registrant Subsidiaries are currently under examination in several state and local jurisdictions.  Management believes that previously filed tax returns have positions that may be challenged by these tax authorities.  However, management does not believebelieves that the ultimate resolution of these audits will not materially impact net income.  With few exceptions, the Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2000.

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

Federal Tax Legislation – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

The American RecoveryPatient Protection and ReinvestmentAffordable Care Act and the related Health Care and Education Reconciliation Act (Health Care Acts), were enacted in March 2010.  The Health Care Acts amend tax rules so that the portion of 2009 was signed into lawemployer health care costs that are reimbursed by the President in February 2009.  It providedMedicare Part D prescription drug subsidy will no longer be deductible by the employer for several new grant programs and expandedfederal income tax credits and an extensionpurposes effective for years beginning after December 31, 2012.  Because of the 50% bonus depreciation provision enactedloss of the future tax deduction, a reduction in the Economic Stimulus Act of 2008.  The enacted provisions are not expecteddeferred tax asset related to have a material impact on net income or financial condition.  However, management forecasts the bonus depreciation provision could provide a significant favorable cash flow benefitnondeductible OPEB liabilities accrued to date was recorded by the Registrant Subsidiaries in 2009.March 2010.  This reduction did not materially affect the Registrant Subsidiaries' cash flows or financial condition.  For the three months ended March 31, 2010, the Registrant Subsidiaries reflected a decrease in deferred tax assets, which was partially offset by recording net tax regulatory assets in jurisdictions with regulated operations, resulting in a decrease in net income as follows:

 Net Reduction Tax  
 to Deferred Regulatory Decrease in
Company Tax Assets Assets, Net Net Income
 (in thousands)
APCo$9,397  $8,831  $566 
CSPCo 4,386   2,970   1,416 
I&M 7,212   6,528   684 
OPCo 8,385   4,020   4,365 
PSO 3,172   3,172   - 
SWEPCo 3,412   3,412   - 


11.       FINANCING ACTIVITIES

Long-term Debt

Long-term debt and other securities issued, retired and principal payments made during the first ninethree months of 20092010 were:
    Principal Interest Due
Company Type of Debt Amount Rate Date
    (in thousands) (%)  
Issuances:         
APCo Pollution Control Bonds $17,500  4.625 2021
CSPCo Floating Rate Notes  150,000  Variable 2012
OPCo Pollution Control Bonds  86,000  3.125 2043
SWEPCo Senior Unsecured Notes  350,000  6.20 2040
   SWEPCo Pollution Control Bonds  53,500   3.25  2015

    Principal Interest Due
Company Type of Debt Amount Rate Date
    (in thousands) (%)  
Issuances:         
APCo Senior Unsecured Notes $350,000  7.95 2020
CSPCo Pollution Control Bonds  60,000  3.875 2038
CSPCo Pollution Control Bonds  32,245  5.80 2038
I&M Senior Unsecured Notes  475,000  7.00 2019
I&M Notes Payable  102,300  5.44 2013
I&M Pollution Control Bonds  50,000  6.25 2025
I&M Pollution Control Bonds  50,000  6.25 2025
OPCo Senior Unsecured Notes  500,000  5.375 2021
PSO Pollution Control Bonds  33,700  5.25 2014

    Principal Interest Due
Company Type of Debt Amount Paid Rate Date
    (in thousands) (%)  
Retirements and Principal Payments:         
APCo Senior Unsecured Notes $150,000  6.60 2009
APCo Land Note  12  13.718 2026
OPCo Pollution Control Bonds  218,000  Variable 2028-2029
OPCo Notes Payable  1,000  6.27 2009
OPCo Notes Payable  6,500  7.21 2009
OPCo Notes Payable  70,000  7.49 2009
PSO Senior Unsecured Notes  50,000  4.70 2009
SWEPCo Notes Payable  3,304  4.47 2011

In January 2009, AEP Parent loaned I&M $25 million of 5.375% Notes Payable due in 2010.
During 2008, the Registrant Subsidiaries chose to begin eliminating their auction-rate debt position due to market conditions.  As of September 30, 2009, SWEPCo had $54 million of tax-exempt long-term debt sold at an auction rate of 0.862% that resets every 35 days.  The instruments under which the bonds are issued allow for conversion to other short-term variable-rate structures, term-put structures and fixed-rate structures.  In the third quarter of 2009, OPCo reacquired $218 million of auction-rate debt related to JMG with interest rates at the contractual maximum of 13%.  OPCo was unable to refinance the debt without JMG's consent.  OPCo sought approval from the PUCO to terminate the JMG relationship and received the approval in June 2009.  In July 2009, OPCo purchased JMG's outstanding equity ownership for $28 million which enabled OPCo to reacquire this debt.
    Principal Interest Due
Company Type of Debt Amount Paid Rate Date
    (in thousands) (%)  
Retirements and Principal Payments:         
APCo Land Note $4  13.718 2026
APCo Notes Payable – Affiliated  100,000  4.708 2010
CSPCo Notes Payable – Affiliated  100,000  4.64 2010
I&M Notes Payable – Affiliated  25,000  5.375 2010
SWEPCo Notes Payable – Affiliated  50,000  4.45 2010
   SWEPCo Pollution Control Bonds  53,500   Variable  2019

On behalf of the Registrant Subsidiaries,OPCo, trustees held $321$303 million of reacquired auction-rate tax-exempt long-term debt as shownof March 31, 2010.
In April 2010, OPCo retired $400 million of variable rate Senior Unsecured Notes due in the following table, including the $2182010 and I&M issued $85 million related to JMG.  of 4.00% Notes Payable due in 2014.

Dividend Restrictions

The Registrant Subsidiaries planpay dividends to reissue the debt.Parent provided funds are legally available.  Various financing arrangements, charter provisions and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to the Parent in the form of dividends.
 September 30, 2009 
Company(in thousands) 
APCo $17,500 
OPCo  303,000 

Federal Power Act

The Federal Power Act prohibits each of the Registrant Subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.”  The term “capital account” is not defined in the Federal Power Act or its regulations.  As applicable, the Registrant Subsidiaries understand “capital account” to mean the par value of the common stock multiplied by the number of shares outstanding.

Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generating plants.  Because of their respective ownership of such plants, this reserve applies to APCo and I&M.

None of these restrictions limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings.

Charter and Leverage Restrictions

Provisions within the articles or certificates of incorporation of the Registrant Subsidiaries relating to preferred stock or shares restrict the payment of cash dividends on common and preferred stock or shares.  Pursuant to credit agreement leverage restrictions, as of March 31, 2010, approximately $180 million of the retained earnings of APCo, $149 million of the retained earnings of CSPCo, $5 million of the retained earnings of I&M, $243 million of the retained earnings of OPCo, $102 million of the retained earnings of SWEPCo and none of the retained earnings of PSO have restrictions related to the payment of dividends.

Utility Money Pool – AEP System

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of its subsidiaries.  The corporate borrowing program includes a Utility Money Pool, which funds the utility subsidiaries.  The AEP System Utility Money Pool operates in accordance with the terms and conditions approved in a regulatory order.  The amount of outstanding loans (borrowings) to/from the Utility Money Pool as of September 30, 2009March 31, 2010 and December 31, 2008 are2009 is 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 ninethree months ended September 30, 2009March 31, 2010 are described in the following table:

        Loans   
Maximum Maximum Average Average (Borrowings) Authorized          Loans  
Borrowings Loans to Borrowings Loans to to/from Utility Short-Term  Maximum Maximum Average Average (Borrowings) Authorized
from Utility Utility from Utility Utility Money Money Pool as of Borrowing  Borrowings Loans Borrowings Loans to/from Utility Short-Term
Money Pool Money Pool Money Pool Pool September 30, 2009 Limit  from Utility to Utility from Utility to Utility Money Pool as of Borrowing
Company(in thousands)  Money Pool Money Pool Money Pool Money Pool March 31, 2010 Limit
 (in thousands)
APCo $420,925  $-  $203,296  $-  $(231,788) $600,000  $379,016  $-  $246,229  $-  $(347,425) $600,000 
CSPCo  203,306   9,029   124,804   5,666   (20,095)  350,000   134,592   37,818   32,368   14,303   37,818  350,000 
I&M  491,107   161,072   109,469   46,765   160,749   500,000   -   151,044   -   101,121   85,186  500,000 
OPCo  522,934   367,743   255,870   94,655   367,743   600,000   -   618,559   -   470,254   617,299  600,000 
PSO  77,976   87,443   56,378   36,404   8,450   300,000   72,418   74,751   26,958   51,041   (68,743) 300,000 
SWEPCo  62,871   158,843   18,530   48,420   106,662   350,000   78,616   274,958   39,458   168,501   238,817  350,000 

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows:
 Nine Months Ended September 30, Three Months Ended March 31,
 2009 2008 2010 2009
Maximum Interest Rate 2.28% 5.37% 0.34% 2.28%
Minimum Interest Rate 0.27% 2.91% 0.09% 1.22%

The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the ninethree months ended September 30,March 31, 2010 and 2009 and 2008 are summarized for all Registrant Subsidiaries in the following table:

 Average Interest Rate for Funds  Average Interest Rate for Funds  Average Interest Rate for Funds Average Interest Rate for Funds
 Borrowed from  Loaned to  Borrowed from Loaned to
 the Utility Money Pool for the  the Utility Money Pool for the  the Utility Money Pool for the the Utility Money Pool for the
 Nine Months Ended September 30,  Nine Months Ended September 30,  Three Months Ended March 31, Three Months Ended March 31,
 2009  2008  2009  2008  2010 2009 2010 2009
Company     
APCo  1.14%  3.62%  -%  3.25% 0.16% 1.76% -% -%
CSPCo  1.13%  3.66%  0.57%  2.99% 0.18% 1.62% 0.14% -%
I&M  1.46%  3.19%  0.49%  -% -% 1.86% 0.16% 1.76%
OPCo  1.21%  3.24%  0.38%  3.62% -% 1.65% 0.16% -%
PSO  2.01%  3.04%  1.04%  4.53% 0.16% 2.01% 0.16% 1.63%
SWEPCo  1.66%  3.36%  0.77%  3.01% 0.19% 1.86% 0.13% 1.68%

To meet its short-term borrowing needs, DHLC is also a member of the Utility Money Pool.  Effective January 1, 2010, SWEPCo no longer consolidates DHLC.  DHLC’s money pool activity for the three months ended March 31, 2010 is described in the following table:

Maximum Maximum Average Average Borrowings
Borrowings Loans Borrowings Loans from Utility
from Utility to Utility from Utility to Utility Money Pool as of
Money Pool Money Pool Money Pool Money Pool March 31, 2010
(in thousands)
$17,886  $-  $13,195  $-  $13,060 

DHLC’s maximum, minimum and average interest rates for funds borrowed from and loaned to the Utility Money Pool for the three months ended March 31, 2010 were as follows:

  Maximum Minimum Maximum Minimum Average Average
  Interest Rates Interest Rates Interest Rates Interest Rates Interest Rate Interest Rate
  for Funds for Funds for Funds for Funds for Funds for Funds
Three Months Borrowed from Borrowed from Loaned to the Loaned to the Borrowed from Loaned to the
Ended the Utility the Utility Utility Money Utility Money the Utility Utility Money
March 31, Money Pool Money Pool Pool Pool Money Pool Pool
2010 0.34% 0.09% -% -% 0.16% -%

Short-term Debt

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

   September 30, 2009 December 31, 2008 
   Outstanding Interest Outstanding Interest    March 31, 2010 December 31,  2009
 Type of Debt Amount Rate (b) Amount Rate (b)    Outstanding Interest Outstanding Interest
Company   (in thousands)   (in thousands)    Type of Debt Amount Rate (b) Amount Rate (b)
   (in thousands)   (in thousands)   
SWEPCo Line of Credit – Sabine Mining Company (a) $5,273  1.60% $7,172  1.54%  Line of Credit – Sabine (a) $13,218  2.12% $6,890   2.06%

(a)Sabine Mining Company is a consolidated variable interest entity.
(b)Weighted average rate.

Credit Facilities

Credit FacilitiesAEP has credit facilities totaling $3 billion to support the commercial paper program.  The facilities are structured as two $1.5 billion credit facilities, of which $750 million may be issued under each credit facility as letters of credit.  As of March 31, 2010, the maximum future payments for letters of credit issued under the two $1.5 billion credit facilities were $300 thousand for I&M and $4 million for SWEPCo.

The Registrant Subsidiaries and certain other companies in the AEP System have a $627 million 3-year credit agreement.  Under the facility, letters of credit may be issued.  As of September 30, 2009, $372March 31, 2010, $477 million of letters of credit were issued by Registrant Subsidiaries under the $627 million 3-year credit agreement to support variable rate Pollution Control Bonds as follows:

Company Amount
Company (in thousands)
APCo $126,716232,292 
I&M  77,886 
OPCo  166,899 
Sale of Receivables – AEP Credit

Under a securitization arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit financing costs, uncollectible accounts experience for each company’s receivables and administrative costs.  The costs of factoring customer accounts receivable are reported in Other Operation of the participant’s income statement.  AEP Credit purchases accounts receivable through purchase agreements with CSPCo, I&M, OPCo, PSO, SWEPCo and a portion of APCo.  APCo does not have regulatory authority to sell its West Virginia accounts receivable.  Customer accounts receivable securitized for the electric operating companies are managed by the Registrant Subsid iaries.  The Registrant Subsidiaries continue to service the receivables.

The amount of securitized accounts receivable and accrued unbilled revenues for each Registrant Subsidiary was as follows:
Company March 31, 2010  December 31, 2009 
  (in thousands) 
APCo $184,319  $143,938 
CSPCo  172,014   169,095 
I&M  131,480   130,193 
OPCo  168,388   160,977 
PSO  71,675   73,518 
SWEPCo  107,259   117,297 

The fees paid by the Registrant Subsidiaries to AEP Credit for factoring customer accounts receivable were:

  Three Months 
  Ended 
Company March 31, 2010 
  (in thousands) 
APCo  $1,881 
CSPCo   2,908 
I&M   1,787 
OPCo   2,700 
PSO   1,384 
SWEPCo   1,671 

The Registrant Subsidiaries and certain other companies in the AEP System had a $350 million 364-day credit agreement that expired in April 2009.

Sales of Receivables

AEP Credit has a sale of receivables agreement with banks and commercial paper conduits.  Underproceeds on the sale of receivables agreement,to AEP Credit sells an interest infor the receivables it acquires from affiliated utility subsidiaries to the commercial paper conduits and banks and receives cash.three months ended March 31, 2010 were:
  Three Months 
  Ended 
Company March 31, 2010 
  (in thousands) 
APCo  $441,711 
CSPCo   424,685 
I&M   339,208 
OPCo   441,510 
PSO   214,647 
SWEPCo   318,959 

12.       COMPANY-WIDE STAFFING AND BUDGET REVIEW

In July 2009, AEP Credit renewedApril 2010, management began initiatives to decrease both labor and increased its salenon-labor expenditures with a goal of receivables agreement.  The saleachieving significant reductions in operation and maintenance expenses.  One initiative is to offer a one-time voluntary severance program.  Participating employees will receive two weeks of receivables agreement provides a commitmentbase pay for every year of $750 million from bank conduits to purchase receivables.  This agreementservice.  It is anticipated that more than 2,000 employees will expire in Julyaccept voluntary severances and terminate employment no later than May 2010.  The previous salesecond simultaneous initiative will involve all business units and departments seeking to identify process improvements, streamlined organizational designs and other efficiencies that can deliver additional lasting savings.  There is the potential that actions taken as a result of receivables agreement provided a commitment of $700 million.this effort could lead to some involuntary separations.  Affected employees would receive the same severance package as those who volunteered.

Management expects to record a charge to expense in the second quarter of 2010 related to these initiatives.   At this time, management is unable to predict the impact of these initiatives on net income, cash flows and financial condition.


 
 
 

COMBINED MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT SUBSIDIARIES

The following is a combined presentation of certain components of the Registrant Subsidiaries’ management’s discussion and analysis.  The information in this section completes the information necessary for management’s discussion and analysis of financial condition and net income and is meant to be read with (i) Management’s Financial Discussion and Analysis, (ii) financial statements, and (iii) footnotes and (iv) the schedules of each individual registrant.  The combined Management’s Discussion and Analysis of Registrant Subsidiaries section of the 2008 Annual Report should also be read in conjunction with this report.

EXECUTIVE OVERVIEW

Economic SlowdownConditions

The Registrant Subsidiaries’ retail margins increased primarily due to rate increases in Indiana, Ohio, Oklahoma and Virginia and higher residential and commercial KWHdemand for electricity as a result of favorable weather.  Margins from off-system sales appearincreased for all Registrant Subsidiaries.  The largest increases were in the eastern region primarily due to be stable; nevertheless, some segments of their service territories are experiencing slowdowns.  Management is currently monitoring the following:higher physical sales reflecting favorable generation availability.

·  
Margins from Off-system Sales –  Margins from off-system sales for the AEP System continue to decrease due to reductions in sales volumes and weak market power prices, reflecting reduced overall demand for electricity.  For the first nine months of 2009 in comparison to the first nine months of 2008, off-system sales volumes decreased by 58% for the AEP System.
During 2009, the Registrant Subsidiaries’ operations were impacted by difficult economic conditions especially their industrial sales.  In 2010, APCo, CSPCo and OPCo saw declines in their industrial sales reflecting curtailments or closures of facilities.  In 2009, CSPCo’s and OPCo’s largest customer, Ormet, a major industrial customer, currently operating at a reduced load of approximately 330 MW, (Ormet operated at an approximate 500 MW load in 2008), announced that it will continue operations at this reduced level.  In February 2009, Century Aluminum, a major industrial customer (325 MW load) of APCo, announced the curtailment of operations at its Ravenswood, WV facility.  In 2010, I&M’s, PSO’s and SWEPCo’s industrial usage increased.

·  
Industrial KWH Sales – The AEP System’s industrial KWH sales for both the three and nine months ended September 30, 2009 were down 17%.  Approximately half of the decrease for the first nine months of 2009 was due to cutbacks or closures by customers who produce primary metals served by APCo, CSPCo, I&M, OPCo, PSO and SWEPCo.  The Registrant Subsidiaries also experienced additional significant decreases in KWH sales to customers in the transportation, plastics, rubber and paper manufacturing industries.
2010 Health Care Legislation

·  
Risk of Loss of Major Industrial Customers – The Registrant Subsidiaries maintain close contact with each of their major industrial customers individually with respect to expected electric needs.  The Registrant Subsidiaries factor industrial customer analyses into their operational planning.  In September 2009, CSPCo’s and OPCo’s largest customer, Ormet, a major industrial customer currently operating at a reduced load of approximately 330 MW, (Ormet operated at an approximate 500 MW load in 2008), announced that it will continue operations at this reduced level at least through the end of 2009.  In February 2009, Century Aluminum, a major industrial customer (325 MW load) of APCo, announced the curtailment of operations at its Ravenswood, WV facility.

Credit Markets

The financial marketsPatient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act (Health Care Acts) were volatile at bothenacted in March 2010.  The Health Care Acts amend tax rules so that the portion of employer health care costs that are reimbursed by the Medicare Part D prescription drug subsidy will no longer be deductible by the employer for federal income tax purposes effective for years beginning after December 31, 2012.  Because of the loss of the future tax deduction, a global and domestic level duringreduction in the last quarter of 2008 and first half of 2009.  The Registrant Subsidiaries issued debt as follows duringdeferred tax asset related to the first nine months of 2009:

  Issuance 
Company (in millions) 
APCo $350 
CSPCo  92 
I&M  677 
OPCo  500 
PSO  34 

Management believes thatnondeductible OPEB liabilities accrued to date was recorded by the Registrant Subsidiaries have adequate liquidity, throughin March 2010.  This reduction did not materially affect the Utility Money Pool and projectedRegistrant Subsidiaries’ cash flows from their operations, to support planned business operations and capital expenditures.  Long-term debt of $200 million, $150 million, $680 million and $150 million will mature inor financial condition.  For the three months ended March 31, 2010 for APCo, CSPCo, OPCo and PSO, respectively.  Management intends to refinance or repay debt maturities.  In September 2009, OPCo issued $500 million of senior notes which may be used to pay at maturity some of its outstanding debt due in 2010.

Pension Trust Fund

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

Risk Management Contracts

On behalf of, the Registrant Subsidiaries AEPSC enters into risk management contractsreflected a decrease in deferred tax assets, which was partially offset by recording net tax regulatory assets in jurisdictions with numerous counterparties.  Since open risk management contracts are valued based on changesregulated operations, resulting in market prices of the related commodities, exposures change daily. AEP’s risk management organization monitors these exposures on a daily basis to limit the Registrant Subsidiaries’ economic and financial statement impact on a counterparty basis.decrease in net income as follows:

Budgeted Construction Expenditures
 Net Reduction Tax  
 to Deferred Regulatory Decrease in
Company Tax Assets Assets, Net Net Income
 (in thousands)
APCo$9,397  $8,831  $566 
CSPCo 4,386   2,970   1,416 
I&M 7,212   6,528   684 
OPCo 8,385   4,020   4,365 
PSO 3,172   3,172   - 
SWEPCo 3,412   3,412   - 

Budgeted construction expenditures excluding AFUDC for the Registrant Subsidiaries for 2010 are:

 Budgeted 
 Construction 
 Expenditures 
Company(in millions) 
APCo $356 
CSPCo  256 
I&M  258 
OPCo  300 
PSO  157 
SWEPCo  444 

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

Fuel Inventory

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

LIQUIDITY

Sources of Funding

Short-term funding for the Registrant Subsidiaries comes from AEP’s commercial paper program and revolving credit facilities through the Utility Money Pool.  AEP and its Registrant Subsidiaries operate a money pool to minimize the AEP System’s external short-term funding requirements and sell accounts receivable to provide liquidity.  Under each credit facility, $750 million may be issued as letters of credit (LOC).  The Registrant Subsidiaries generally use short-term funding sources (the Utility Money Pool or receivables sales) to provide for interim financing of capital expenditures that exceed internally generated funds and periodically reduce their outstanding short-term debt through issuances of long-term debt, sale-leasebacks, leasing arrangements and additional capital contributions fro m Parent.

Management believes that the Registrant Subsidiaries have adequate liquidity, through the Utility Money Pool and projected cash flows from Parent.their operations, to support planned business operations and capital expenditures.  Long-term debt of $200 million, $150 million and $680 million will mature in 2010 for APCo, CSPCo and OPCo, respectively.  In 2009, OPCo issued $500 million of senior notes which were used in April 2010 to pay $400 million of senior unsecured notes at maturity.

The Registrant Subsidiaries and certain other companies in the AEP System entered into a $627 million 3-year credit agreement.  The Registrant Subsidiaries may issue LOCs under the credit facility.  Each subsidiary has a borrowing/LOC limit under the credit facility.  As of September 30, 2009,March 31, 2010, a total of $372$477 million of LOCs were issued under the credit agreement to support variable rate demand notes.  The following table shows each Registrant Subsidiaries’ borrowing/LOC limit under the credit facility and the outstanding amount of LOCs.

  LOC Amount 
  Outstanding    LOC Amount
$627 million Against    Outstanding
Credit Facility $627 million    Against
Borrowing/LOC Agreement at  Credit Facility $627 million
Limit September 30, 2009  Borrowing/LOC Agreement at
Company(in millions)  Limit March 31, 2010
(in millions)
APCo $300  $127 APCo$300  $232 
CSPCo  230   - CSPCo 230   - 
I&M  230   78 I&M 230   78 
OPCo  400   167 OPCo 400   167 
PSO  65   - PSO 65   - 
SWEPCo  230   - SWEPCo 230   - 

Dividend Restrictions

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

Sales of Receivables Through AEP Credit

In July 2009, AEP Credit renewed and increased its sale of receivables agreement.  The sale of receivables agreement provides a commitment of $750 million from banks and commercial paper conduits to purchase receivables from AEP Credit.  This agreement will expire in July 2010.  Management intends to extend or replace the sale of receivables agreement.  The previous sale of receivables agreement provided a commitment of $700 million.  At September 30, 2009, $530 million of commitments to purchase accounts receivable were outstanding under the receivables agreement.  AEP Credit purchases accounts receivable from the Registrant Subsidiaries.

SIGNIFICANT FACTORS

Ohio Electric Security Plan FilingsCompany-wide Staffing and Budget Review

In March 2009, the PUCO issued an order, which was amended byApril 2010, management began initiatives to decrease both labor and non-labor expenditures with a rehearing entrygoal of achieving significant reductions in July 2009, that modifiedoperation and approved CSPCo’s and OPCo’s ESPs that established standard servicemaintenance expenses.  One initiative is to offer rates.  The ESPsa one-time voluntary severance program.  Participating employees will be in effect through 2011.�� The ESP order authorized revenue increases during the ESP period and capped the overall revenue increasesreceive two weeks of base pay for CSPCo to 7% in 2009, 6% in 2010 and 6% in 2011 and for OPCo to 8% in 2009, 7% in 2010 and 8% in 2011.  CSPCo and OPCo implemented rates for the April 2009 billing cycle.  In its July 2009 rehearing entry, the PUCO required CSPCo and OPCo to reduce rates implemented in April 2009 by $22 million and $27 million, respectively, on an annualized basis.  CSPCo and OPCo are collecting the 2009 annualized revenue increase over the last nine months of 2009.

The order provides a FAC for the three-year period of the ESP.  The FAC increase will be phased in to avoid having the resultant rate increases exceed the ordered annual caps described above.  The FAC increase before phase-in will be subject to quarterly true-ups to actual recoverable FAC costs and to annual accounting audits and prudency reviews.  The order allows CSPCo and OPCo to defer unrecovered FAC costs resulting from the annual caps/phase-in plan and to accrue carrying charges on such deferrals at CSPCo’s and OPCo’s weighted average cost of capital.  The deferred FAC balance at the end of the three-year ESP period will be recovered through a non-bypassable surcharge over the period 2012 through 2018.  The FAC deferrals at September 30, 2009 were $36 million and $238 million for CSPCo and OPCo, respectively, inclusive of carrying charges at the weighted average cost of capital.

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

In September 2009, CSPCo and OPCo filed their initial quarterly FAC filing with the PUCO and adjusted their estimated phase-in deferrals to the amounts shown in the filing, which was a decrease in the FAC deferral of $6 million for CSPCo and an increase in the FAC deferral of $17 million for OPCo.  An order approving the FAC 2009 filings will not be issued until a financial audit and prudency review is performed by independent third parties and reviewed by the PUCO.

In October 2009, the PUCO convened a workshop to begin to determine the methodology for the Significantly Excessive Earnings Test (SEET).  The SEET requires the PUCO to determine, following the end of eachevery year of service.  It is anticipated that more than 2,000 employees will accept voluntary severances and terminate employment no later than May 2010.  The second simultaneous initiative will involve all business units and departments to identify process improvements, streamlined organizational designs and other efficiencies that can deliver additional lasting savings.  There is the ESP, if rate adjustments included in the ESP resulted in significantly excessive earnings.  This will be determined by measuring whether the utility’s earned return on common equity is significantly in excesspotential that actions taken as a result of the return on common equity that was earned duringthis effort could lead to some involuntary separat ions.  Affected employees would receive the same period by publicly traded companies, including utilities, which have comparable business and financial risk.  In the March 2009 ESP order, the PUCO determined that off-system sales margins and FAC deferral phase-in credits should be excluded from the SEET methodology.  However, the July 2009 PUCO rehearing entry deferredseverance package as those issues to the SEET workshop.  If the rate adjustments, in the aggregate, result in significantly excessive earnings, the excess amount would be returned to customers.  The PUCO’s decision on the SEET review of CSPCo’s and OPCo’s 2009 earnings is not expected to be finalized until the workshop is completed, the PUCO issues SEET guidelines, a SEET filing is made by CSPCo and OPCo in 2010 and the PUCO issues an order thereon. The SEET workshop will also determine whether CSPCo’s and OPCo’s earnings will be measured on an individual company basis or on a combined CSPCo/OPCo basis.

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

Management expects to record a charge to expense in the second quarter of 2010 related to these initiatives.   At this time, management is unable to predict the outcomeimpact of the various ongoing proceedings and litigation discussed above including the SEET, the FAC filing review and the various appeals to the Supreme Court of Ohio relating to the ESP order.  If these proceedings result in adverse rulings, it could have an adverse effect on future net income and cash flows.

New Generation/Purchase Power Agreement

In 2009, AEP is in various stages of construction of the following generation facilities:
                 Commercial
      Total        Nominal Operation
Operating Project   Projected        MW Date
Company Name Location Cost (a) CWIP (b) Fuel Type Plant Type Capacity (Projected)
      (in millions) (in millions)        
AEGCo Dresden(c)Ohio $321(d)$199(d)Gas Combined-cycle 580 2013
SWEPCo Stall Louisiana  386  364 Gas Combined-cycle 500 2010
SWEPCo Turk(e)Arkansas  1,633(e) 622(f)Coal Ultra-supercritical 600(e)2012
APCo Mountaineer(g)West Virginia   (g)   Coal IGCC 629  (g)
CSPCo/OPCo Great Bend(g)Ohio   (g)   Coal IGCC 629  (g)

(a)Amount excludes AFUDC.
(b)Amount includes AFUDC.
(c)In September 2007, AEGCo purchased the partially completed Dresden plant from Dresden Energy LLC, a subsidiary of Dominion Resources, Inc., for $85 million, which is included in the “Total Projected Cost” section above.
(d)During 2009, AEGCo suspended construction of the Dresden Plant.  As a result, AEGCo has stopped recording AFUDC and will resume recording AFUDC once construction is resumed.
(e)SWEPCo owns approximately 73%, or 440 MW, totaling $1.2 billion in capital investment.  See “Turk Plant” section below.
(f)Amount represents SWEPCo’s CWIP balance only.
(g)Construction of IGCC plants is subject to regulatory approvals.

Turk Plant

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

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

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

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

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

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

SWEPCo is also working with the U.S. Army Corps of Engineers for the approval of a wetlands and stream impact permit.  In March 2009, SWEPCo reported to the U.S. Army Corps of Engineers an inadvertent impact on approximately 2.5 acres of wetlands at the Turk Plant construction site prior to the receipt of the permit.  The U.S. Army Corps of Engineers directed SWEPCo to cease further work impacting the wetland areas.  Construction has continued on other areas outside of the proposed Army Corps of Engineers permitted areas of the Turk Plant pending the Army Corps of Engineers review.  SWEPCo has entered into a Consent Agreement and Final Order with the Federal EPA to resolve liability for the inadvertent impact and agreed to pay a civil penalty of approximately $29 thousand.

The Arkansas Governor’s Commission on Global Warming issued its final report to the governor in October 2008.  The Commission was established to set a global warming pollution reduction goal together with a strategic plan for implementation in Arkansas.  The Commission’s final report included a recommendation that the Turk Plant employ post combustion carbon capture and storage measures as soon as it starts operating.  To date, the report’s effect is only advisory, but if legislation is passed as a result of the findings in the Commission’s report, it could impact SWEPCo’s ability to complete construction on schedule in 2012 and on budget.

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

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

PSO Purchase Power Agreement

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

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

Company Amount 
  (in millions) 
APCo $53 
CSPCo  38 
I&M  54 
OPCo  38 
PSO  27 
SWEPCo  25 

In August 2009, the Registrant Subsidiaries applied with the U.S. Department of Energy (DOE) for $411 million in federal stimulus money for gridSMART, clean coal technology and hydro generation projects.  If granted, the funds will provide capital and reduce the amount of money sought from customers.  Management is unable to predict the likelihood of the DOE granting the federal stimulus money to the Registrant Subsidiaries or the timing of the DOE’s decision.  The requested federal stimulus money is proposed for the following projects:

 
Company
 
Proposed Project
Federal Stimulus Funds Requested 
  (in millions) 
APCoCarbon Capture and Sequestration Demonstration Project at the Mountaineer Plant $334 
APCoHydro Generation Modernization Project in London, W.V.  2 
CSPCogridSMART  75 

Environmental Matters

The Registrant Subsidiaries are implementing a substantial capital investment program and incurring additional operational costs to comply with new environmental control requirements.  The sourcesmost significant source is the CAA’s requirements to reduce emissions of these requirements include:

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

In addition, theThe Registrant Subsidiaries are engaged in litigation with respect to certainabout environmental matters,issues, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of spent nuclear fuelSNF and future decommissioning of I&M’s nuclear units.  Management is also involvedengaged in the development of possible future requirements to reduce CO2 and other GHG emissions to address concerns about global climate change.  AllSee a complete discussion of these matters are discussed in the “Environmental Matters”Issues” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 20082009 Annual Report.

Clean Water Act RegulationGlobal Warming

In 2004,While comprehensive economy-wide regulation of CO2 emissions might be achieved through new legislation, the Federal EPA continues to take action to regulate CO2 emissions under the existing requirements of the CAA.  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 entrainedendangerment finding for CO2 emissions from new motor vehicles in the cooling water.December 2009 and final rules approved in April 2010 for new motor vehicles are awaiting publication.  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 coulddetermined that CO2 emissions from stationary sources will be $193 million for the AEP System’s plants.  The Registrant Subsidiaries undertook site-specific studies and have been evaluating site-specific compliance or mitigation measures that could significantly change these cost estimates.  The following table shows the investment amount per Registrant Subsidiary.

 Estimated 
 Compliance 
 Investments 
Company(in millions) 
APCo $21 
CSPCo  19 
I&M  118 
OPCo  31 

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

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

Potential Regulation of CO2 and Other GHG Emissions

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

In April 2009, the Federal EPA issued a proposed endangerment findingregulation under the CAA regarding GHG emissions from motor vehicles.  The proposed endangerment findingb eginning in January 2011 at the earliest, and is subjectexpected to public comment.  This finding could lead to regulation of CO2 and other gases under existing laws.  In September 2009, the Federal EPA issued a final mandatory GHG reporting rule covering a broad range of facilities emitting in excess of 25,000 tons of GHG emissions per year.  The Federal EPA has also issued proposed light duty vehicle GHG emissions standards for model years 2012-2016, and afinalize its proposed scheme to streamline and phase inphase-in regulation of stationary source GHG CO2 emissions through the NSR’sNSR prevention of significant deterioration and CAA’s Title V permitting programs.operating permit programs in 2010.  The Federal EPA stated its intent to finalize the vehicle standards and permitting rule in conjunction with or following a final endangerment finding, and is reconsidering whether to include GHGCO2 emissions in a number of stationary source standards, including standards that apply to new and modified electric utility units.  Some of the policy approaches being discussed by the Federal EPA would have significant and widespread negative consequences for the national economy and major U.S. industrial enterprises, including the AEP System.  Because of these adverse consequences, management believes that these more extreme policies will not ultimately be adopted and that reasonable and comprehensive legislative action is preferable.  Even if reasonableIf substantial CO2 and other GHG emission standardsreductions are imposed, the standards could requirerequired, there will be significant increases in capital expenditures and operating costs which would impact the ultimate retirement of older, less-efficient, coal-fired units.  Management believes that costs of complying with newTo the extent the Registrant Subsidiaries install additional controls on their generating plants to limit CO2 emissions and other GHG emission standards will be treated like all other reasonable costs of serving customers and should be recoverable from customers as costs of doing business, includingreceive regulatory approvals to increase rates, cost recovery could have a positive effect on future earnings.  Prudently incurred capital investments made by the Registrant Subsidiaries in rate-regulated jurisdictions to comply with legal requirements and benefit customers are generally included in rate base for recovery and earn a return on investment.

Proposed Health Care Legislation

The U.S. Congress, supported by President Obama, is debating health care reform that could have a significant impact on the AEP System’s benefits and costs.  The discussion centers around universal coverage, revenue sources  Management would expect these principles to keep it deficit neutral and changesapply to Medicare that could significantly impact the AEP System’s employees and retirees and the benefits andinvestments made to address new environmental requirements.  However, requests for rate increases reflecting these costs of the AEP System’s plans.  Until legislation is final, the impact is impossible to predict.

Adoption of New Accounting Pronouncements

The FASB issued SFAS 141R “Business Combinations” improving financial reporting about business combinations and their effects and FSP SFAS 141 (R)-1.  SFAS 141R can affect tax positions on previous acquisitions.  Thethe Registrant Subsidiaries do not have anyadversely because the regulators could limit the amount or timing of increased costs that would be recoverable through higher rates.  In addition, to the extent the Registrant Subsidiaries’ costs are relatively higher than their competitors’ costs, such tax positions that result in adjustments.  Theas operators of nuclear generation, it could reduce off-system sales or cause the Registrant Subsidiaries adopted SFAS 141R, including the FSP, effective January 1, 2009.  The Registrant Subsidiaries will apply it to any future business combinations.  SFAS 141R is includedlose customers in the “Business Combinations” accounting guidance.

The FASB issued SFAS 160 “Noncontrolling Interests in Consolidated Financial Statements” (SFAS 160), modifying reporting for noncontrolling interest (minority interest) in consolidated financial statements.  The statement requires noncontrolling interest be reported in equity and establishes a new framework for recognizing net income or loss and comprehensive income by the controlling interest.  The Registrant Subsidiaries adopted SFAS 160 retrospectively effective January 1, 2009.  See Note 2.  SFAS 160 is included in the “Consolidation” accounting guidance.

The FASB issued SFAS 161 “Disclosures about Derivative Instruments and Hedging Activities” (SFAS 161), enhancing disclosure requirements for derivative instruments and hedging activities.  The standard requiresjurisdictions that objectives for using derivative instruments be disclosed in termspermit customers to choose their supplier of underlying risk and accounting designation.  This standard increased disclosure requirements related to derivative instruments and hedging activities.  The Registrant Subsidiaries adopted SFAS 161 effective January 1, 2009.  SFAS 161 is included in the “Derivatives and Hedging” accounting guidance.

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

The FASB issued SFAS 168 “The FASB Accounting Standards CodificationSeveral states have adopted programs that directly regulate COTM2 emissions from power plants, but none of these programs are currently in effect in states where the Registrant Subsidiaries have generating facilities.  Certain states have passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements (including Ohio, Michigan, Texas and the Hierarchy of Generally Accepted Accounting Principles” (SFAS 168) establishing the FASB Accounting Standards CodificationTM as the authoritative source of accounting principles for preparation of financial statements and reporting in conformity with GAAP by nongovernmental entities.Virginia).  The Registrant Subsidiaries adopted SFAS 168 effective third quarter of 2009.  It required an update of all referencesare taking steps to authoritative accounting literature.  SFAS 168 is included in the “Generally Accepted Accounting Principles” accounting guidance.comply with these requirements.

The FASB ratified EITF Issue No. 08-5 “Issuer’s Accounting for Liabilities Measured at Fair Value withCertain groups have filed lawsuits alleging that emissions of CO2 are a Third-Party Credit Enhancement” (EITF 08-5) a consensus on liabilities with third-party credit enhancements when the liability is measured“public nuisance” and disclosed at fair value.  The consensus treats the liabilityseeking injunctive relief and/or damages from small groups of coal-fired electricity generators, petroleum refiners and the credit enhancement as two units of accounting.marketers, coal companies and others.  The Registrant Subsidiaries adopted EITF 08-5 effective January 1, 2009.  Withhave been named in pending lawsuits, which management is vigorously defending.  It is not possible to predict the adoptionoutcome of FSP SFAS 107-1these lawsuits or their impact on operations or financial condition.  See “Carbon Dioxide Public Nuisance Claims” and APB 28-1, it is applied to the fair value“Alaskan Villages’ Claims” sections of long-term debt.  The application of this standard had an immaterial effectNote 4.

Future federal and state legislation or regulations that mandate limits on the fair valueemission of debt outstanding.  EITF 08-5 is includedCO2 would result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs.  Excessive costs to comply with future legislation or regulations might force the “Fair Value MeasurementsRegistrant Subsidiaries to close some coal-fired facilities and Disclosures” accounting guidance.could lead to possible impairment of assets.  As a result, mandatory limits could have a material adverse impact on net income, cash flows and financial condition.

The FASB ratified EITF Issue No. 08-6 “Equity Method InvestmentFor detailed information on global warming and the actions the AEP System is taking address potential impacts, see Part I of the 2009 Form 10-K under the headings entitled “Business – General – Environmental and Other Matters – Global Warming and “Combined Management Discussion and Analysis of Registrant Subsidiaries.”

NEW ACCOUNTING PRONOUNCEMENTS

New Accounting Considerations” (EITF 08-6), a consensus on equity method investment accounting including initial and allocated carrying values and subsequent measurements.  Pronouncement Adopted During the First Quarter of 2010

The Registrant Subsidiaries prospectively adopted EITF 08-6ASU 2009-17 “Consolidation” effective January 1, 20092010.  SWEPCo no longer consolidates DHLC effective with no impact on their financial statements.  EITF 08-6 is included in the “Investments – Equity Method and Joint Ventures”adoption of this standard.

See Note 2 for further discussion of accounting guidance.pronouncements.

Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued, management cannot determine the impact on the reporting of the Registrant Subsidiaries’ operations and financial position that may result from any such future changes.  The FASB issued FSP SFAS 107-1 and APB 28-1 requiring disclosure about theis currently working on several projects including revenue recognition, contingencies, financial instruments, emission allowances, fair value measurements, leases, insurance, hedge accounting, consolidation policy and discontinued operations.  Management also expects to see more FASB projects as a result of its desire to converge International Accounting Standards with GAAP.  The ultimate pronouncements resulting from these and future projects could have an impact on future net income and financial instruments in all interim reporting periods.  The standard requires disclosure of the method and significant assumptions used to determine the fair value of financial instruments.  The Registrant Subsidiaries adopted the standard effective second quarter of 2009.  This standard increased the disclosure requirements related to financial instruments.  FSP SFAS 107-1 and APB 28-1 is included in the “Financial Instruments” accounting guidance.position.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

The FASB issued FSP SFAS 115-2Registrant Subsidiaries’ risk management assets and SFAS 124-2 “Recognitionliabilities are managed by AEPSC as agent.  The related risk management policies and Presentation of Other-Than-Temporary Impairments”, amending the other-than-temporary impairment (OTTI) recognitionprocedures are instituted and measurement guidanceadministered by AEPSC.  See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section.  Also, see Note 8 – Derivatives and Hedging and Note 9 – Fair Value Measurements for debt securities.  For both debt and equity securities, the standard requires disclosure for each interim reporting period ofadditional information by security class similar to previous annual disclosure requirements.  The Registrant Subsidiaries adopted the standard effective second quarter of 2009 with no impact on the financial statements and increased disclosure requirements related to financial instruments for I&M only.  FSP SFAS 115-2 and SFAS 124-2 is included in the “Investments – Debt and Equity Securities” accounting guidance.

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

The FASB issued SFAS 157-2 “Effective Datefollowing tables summarize the reasons for changes in total mark-to-market (MTM) value as compared to December 31, 2009:

MTM Risk Management Contract Net Assets (Liabilities)
Three Months Ended March 31, 2010
(in thousands)

APCo   
Total MTM Risk Management Contract Net Assets at December 31, 2009 $45,197 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period  (7,755)
Fair Value of New Contracts at Inception When Entered During the Period (a)  - 
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period  (35)
Changes in Fair Value Due to Market Fluctuations During the Period (c)  (61)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)  6,391 
Total MTM Risk Management Contract Net Assets  43,737 
Cash Flow Hedge Contracts  (4,633)
DETM Assignment (e)  (1,822)
Collateral Deposits  41,545 
Total MTM Derivative Contract Net Assets at March 31, 2010 $78,827 

OPCo   
Total MTM Risk Management Contract Net Assets at December 31, 2009 $26,330 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period  (5,753)
Fair Value of New Contracts at Inception When Entered During the Period (a)  3,028 
Changes in Fair Value Due to Valuation Methodology Changes on Forward Contracts (b)  (715)
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period  (100)
Changes in Fair Value Due to Market Fluctuations During the Period (c)  5,063 
Changes in Fair Value Allocated to Regulated Jurisdictions (d)  28 
Total MTM Risk Management Contract Net Assets  27,881 
Cash Flow Hedge Contracts  (2,536)
DETM Assignment (e)  (1,186)
Collateral Deposits  29,005 
Total MTM Derivative Contract Net Assets at March 31, 2010 $53,164 
PSO   
Total MTM Risk Management Contract Net Assets (Liabilities) at December 31, 2009 $(369)
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period  (185)
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  (10)
Changes in Fair Value Due to Market Fluctuations During the Period (c)  2 
Changes in Fair Value Allocated to Regulated Jurisdictions (d)  2,997 
Total MTM Risk Management Contract Net Assets  2,435 
Cash Flow Hedge Contracts  (17)
Collateral Deposits  349 
Total MTM Derivative Contract Net Assets at March 31, 2010 $2,767 

SWEPCo   
Total MTM Risk Management Contract Net Assets at December 31, 2009 $1,636 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period  (926)
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  (16)
Changes in Fair Value Due to Market Fluctuations During the Period (c)  2 
Changes in Fair Value Allocated to Regulated Jurisdictions (d)  (650)
Total MTM Risk Management Contract Net Assets  46 
Cash Flow Hedge Contracts  60 
Collateral Deposits  572 
Total MTM Derivative Contract Net Assets at March 31, 2010 $678 

(a)Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices.  The contract prices are valued against market curves associated with the delivery location and delivery term.  A significant portion of the total volumetric position has been economically hedged.
(b)Reflects changes in methodology in calculating the credit and discounting liability fair value adjustments.
(c)Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(d)Relates to the net gains (losses) of those contracts that are not reflected on the Condensed Statements of Income.  These net gains (losses) are recorded as regulatory liabilities/assets.
(e)See “Natural Gas Contracts with DETM” section of Note 15 of the 2009 Annual Report.

The following tables present the maturity, by year, of FASB Statement No. 157” (SFAS 157-2),net assets/liabilities to give an indication of when these MTM amounts will settle and generate or (require) cash:

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets (Liabilities)
March 31, 2010
(in thousands)

  Remainder          
APCo 2010   2011-2013   2014  Total 
Level 1 (a) $(99) $1  $-  $(98)
Level 2 (b)  10,109   7,553   300   17,962 
Level 3 (c)  8,887   7,793   2,007   18,687 
Total  18,897   15,347   2,307   36,551 
Dedesignated Risk Management Contracts (d)  3,711   3,475   -   7,186 
Total MTM Risk Management Contract Net Assets $22,608  $18,822  $2,307  $43,737 

  Remainder          
OPCo 2010   2011-2013   2014  Total 
Level 1 (a) $(64) $1  $-  $(63)
Level 2 (b)  7,412   3,478   195   11,085 
Level 3 (c)  5,799   5,074   1,307   12,180 
Total  13,147   8,553   1,502   23,202 
Dedesignated Risk Management Contracts (d)  2,416   2,263   -   4,679 
Total MTM Risk Management Contract Net Assets $15,563  $10,816  $1,502  $27,881 

  Remainder       
PSO 2010   2011 - 2013  Total 
Level 1 (a) $-  $-  $- 
Level 2 (b)  2,708   (275)  2,433 
Level 3 (c)  2   -   2 
Total MTM Risk Management Contract Net Assets (Liabilities) $2,710  $(275) $2,435 

  Remainder       
SWEPCo 2010   2011-2013  Total 
Level 1 (a) $-  $-  $- 
Level 2 (b)  1,235   (1,193)  42 
Level 3 (c)  4   -   4 
Total MTM Risk Management Contract Net Assets (Liabilities) $1,239  $(1,193) $46 

(a)Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.  Level 1 inputs primarily consist of exchange traded contracts that exhibit sufficient frequency and volume to provide pricing information on an ongoing basis.
(b)Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.  If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, exchange traded contracts where there was not sufficient market activity to warrant inclusion in Level 1 and OTC broker quotes that are corroborated by the same or similar transactions that have occurred in the market.
(c)Level 3 inputs are unobservable inputs for the asset or liability.  Unobservable inputs shall be used to measure fair value to the extent that the observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.  Level 3 inputs primarily consist of unobservable market data or are valued based on models and/or assumptions.
(d)Dedesignated Risk Management Contracts are contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for “Derivatives and Hedging.”  At the time of the normal election, the MTM value was frozen and no longer fair valued.  This will be amortized into Revenues over the remaining life of the contracts.

Credit Risk

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

Value at Risk (VaR) Associated with Risk Management Contracts

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

The FASB issued FSP SFAS 157-4 “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (FSP SFAS 157-4), providing additional guidance on estimating fair value when the volume and level of activity for an asset or liability has significantly decreased, including guidance on identifying circumstances indicating when a transaction is not orderly.  Fair value measurements shall be based on the price that would be receivedvariance-covariance method using historical prices to sell an asset or paid to transferestimate volatilities and correlations and assumes a liability in an orderly (not a distressed sale or forced liquidation) transaction between market participants at the measurement date under current market conditions.  The standard also requires disclosures of the inputs and valuation techniques used to measure fair value95% confidence level and a discussion of changesone-day holding period.  Based on this VaR analysis, at March 31, 2010, a near term typical change in valuation techniques and related inputs, if any, for both interim and annual periods.  The Registrant Subsidiaries adopted the standard effective second quarter of 2009.  This standard had no impact on the financial statements but increased disclosure requirements.  FSP SFAS 157-4commodity prices is included in the “Fair Value Measurements and Disclosures” accounting guidance.

Pronouncements Effective in the Future

The FASB issued ASU 2009-05 “Measuring Liabilities at Fair Value” (ASU 2009-05) updating the “Fair Value Measurement and Disclosures” accounting guidance.  The guidance specifies the valuation techniques that should be used to fair value a liability in the absence of a quoted price in an active market.  The new accounting guidance is effective for interim and annual periods beginning after the issuance date.  Although management has not completed an analysis, management does not expect this updateexpected to have a material impacteffect on thenet income, cash flows or financial statements.  The Registrant Subsidiaries will adopt ASU 2009-05 effective fourth quarter of 2009.condition.

The FASB issued ASU 2009-12 “Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent)” (ASU 2009-12) updatingfollowing table shows the “Fair Value Measurementend, high, average, and Disclosures” accounting guidancelow market risk as measured by VaR for the fair value measurementperiods indicated:

 March 31, 2010 December 31, 2009
 (in thousands) (in thousands)
Company End High Average Low End High Average Low
APCo $209  $659  $306  $141  $275 $699 $333 $151
OPCo  162   545   256   117   201  530  244  113
PSO  9   70   19   5   10  34  12  4
SWEPCo  13   93   27   8   16  49  18  6

Management back-tests its VaR results against performance due to actual price movements.  Based on the assumed 95% confidence interval, the performance due to actual price movements would be expected to exceed the VaR at least once every 20 trading days.

As the VaR calculations capture recent price movements, management also performs regular stress testing of investmentsthe portfolio to understand the exposure to extreme price movements.  Management employs a historical-based method whereby the current portfolio is subjected to actual, observed price movements from the last four years in certain entitiesorder to ascertain which historical price movements translated into the largest potential MTM loss.  Management then researches the underlying positions, price movements and market events that calculate net asset value per share (or its equivalent).  The guidance permits a reporting entitycreated the most significant exposure and report the findings to the Risk Executive Committee or the Commercial Operations Risk Committee as appropriate.

Interest Rate Risk

Management utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the fair valueextent to which interest expense could vary over the next twelve months and gives a probabilistic estimate of an investment within its scopedifferent levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  As calculated on the basisRegistrant Subsidiaries’ outstanding debt as of March 31, 2010 and December 31, 2009, the net asset value per share of the investment (or its equivalent).  The new accounting guidance is effective for interim and annual periods ending after December 15, 2009.  Although management has not completed an analysis, management does not expect this update to have a material impactestimated EaR on the financial statements.  The Registrant Subsidiaries will adopt ASU 2009-12 effective fourth quarter of 2009.Subsidiaries’ debt portf olio was as follows:

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

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

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

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

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

The FASB issued FSP SFAS 132R-1 “Employers’ Disclosures about Postretirement Benefit Plan Assets” (FSP SFAS 132R-1) providing additional disclosure guidance for pension and OPEB plan assets.  The standard adds disclosure requirements including hierarchical classes for fair value and concentration of risk.  This standard is effective for fiscal years ending after December 15, 2009.  Management expects this standard to increase the disclosure requirements related to AEP’s benefit plans.  The Registrant Subsidiaries will adopt the standard effective for the 2009 Annual Report.  FSP SFAS 132R-1 is included in the “Compensation – Retirement Benefits” accounting guidance.
  March 31, December 31,
Company 2010 2009
  (in thousands)
APCo $1,295  $1,837 
CSPCo  337   216 
I&M  267   227 
OPCo  1,297   1,373 
PSO  85   119 
SWEPCo  80   305 


 
 
 

CONTROLS AND PROCEDURES

During the thirdfirst quarter of 2009,2010, management, including the principal executive officer and principal financial officer of each of AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo (collectively, the Registrants), evaluated the Registrants’ disclosure controls and procedures.  Disclosure controls and procedures are defined as controls and other procedures of the Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.  Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to the Registrants’ management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

As of September 30, 2009,March 31, 2010, 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 thirdfirst quarter of 20092010 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

 
 
 

PART II.  OTHER INFORMATION

Item 1.     Legal Proceedings

For a discussion of material legal proceedings, see “Commitments, Guarantees and Contingencies,” of Note 4 incorporated herein by reference.

Item 1A.  Risk Factors

Our Annual Report on Form 10-K for the year ended December 31, 20082009 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 20082009 Annual Report on Form 10-K.

General Risks of Our Regulated Operations

Turk Plant permits could be reversed on appeal.  (Applies to AEP and SWEPCo)

In November 2007, theThe APSC granted approval for SWEPCo to build the Turk Plant in Arkansas by issuing a Certificate of Environmental Compatibility and Public Need (CECPN).  Certain intervenors appealed the APSC’s decision to the Arkansas Court of Appeals.  In June 2009, theThe Arkansas Court of Appeals issued a unanimous decision that if upheld by the Arkansas Supreme Court, wouldmay reverse the APSC’s grant of the CECPN permitting construction ofCECPN.  In October 2009, the Turk Plant to serve Arkansas retail customers.  BothSupreme Court granted the petitions filed by SWEPCo and the APSC petitioned the Arkansas Supreme Court to review the Arkansas Court of AppealsAppeals’ decision.

In November 2008, SWEPCo received theits required air permit approval for the Turk Plant from the Arkansas Department of Environmental Quality.Quality (ADEQ).  In December 2008, certain parties filed an appeal of the air permit withJanuary 2010, the Arkansas Pollution Control and Ecology Commission.  A decision onCommission (APCEC) upheld the air permit.  In February 2010, the parties who unsuccessfully appealed the air permit is still pending and not expected until 2010.  These same parties haveto the APCEC filed a petitionnotice of appeal of the APCEC’s decision with the Circuit Court of Hempstead County, Arkansas.

The wetlands permit was issued by the U.S. Army Corps of Engineers in December 2009.  In February 2010, the Sierra Club, the Audubon Society and others filed a complaint in the Federal EPA to reviewDistrict Court for the air permit.  The petition will be acted on by December 2009, according toWestern District of Arkansas against the U.S. Army Corps of Engineers challenging the process used and the terms of a recent settlement between the petitionerspermit issued to SWEPCo authorizing certain wetland and the Federal EPA.  The Turk Plant cannot be placed into service without an air permit.stream impacts.  If SWEPCo is unable to complete the Turk Plant construction and place it in service or if SWEPCo cannot recover all of the investment in and the expenses of the Turk Plant, in service, it would adversely impactreduce future net income and cash flowflows and possiblyimpact financial condition unless the resultant losses can be fully recovered, with a return on any unrecovered balances, through rates in all of its jurisdictions.

Rate recovery approved in OhioOklahoma may be overturned on appeal or may not provide full recovery ofrequire us to refund fuel costs.costs that we have collected. (Applies to AEP, OPCo and CSPCo)
In March 2009, the PUCO issued an order, which was amended by a rehearing entry in July 2009, that modified and approved CSPCo’s and OPCo’s ESPs.  The ESPs will be in effect through 2011.  The ESP order authorized revenue increases during the ESP period and capped the overall revenue increases through a phase-in of the FAC.  The capped increases for CSPCo are 7% in 2009, 6% in 2010 and 6% in 2011 and for OPCo are 8% in 2009, 7% in 2010 and 8% in 2011.  In its July 2009 rehearing entry, the PUCO required CSPCo and OPCo to reduce rates implemented in April 2009 by $22 million and $27 million, respectively, on an annualized basis.  The order provides a FAC for the three-year period of the ESP.  The order allows CSPCo and OPCo to defer unrecovered FAC costs resulting from the annual caps/phase-in plan and to accrue carrying charges on such deferrals at CSPCo’s and OPCo’s weighted average cost of capital.  The deferred FAC balance at the end of the three-year ESP period will be recovered through a non-bypassable surcharge over the period 2012 through 2018.  In August 2009, an intervenor filed for rehearing requesting, among other things, that the PUCO order CSPCo and OPCo to cease and desist from charging ESP rates, to revert to the rate stabilization plan rates and to compel a refund, including interest, of the amounts collected by CSPCo and OPCo.  CSPCo and OPCo filed a response stating the rates being charged by CSPCo and OPCo have been authorized by the PUCO and there was no basis for precluding CSPCo and OPCo from continuing to charge those rates.  In October 2009, an intervenor filed a complaint for writ of prohibition with the Supreme Court of Ohio requesting the Court to prohibit CSPCo and OPCo from billing and collecting any ESP rate increases that the PUCO authorized as the intervenor believes the PUCO's statutory jurisdiction over CSPCo's and OPCo's ESP application ended on December 28, 2008, which was 150 days after the filing of the ESP applications.  CSPCo and OPCo plan on filing a response in opposition to the complaint for writ of prohibition.  If the PUCO and/or the Supreme Court of Ohio reverses all or part of the rate recovery or if deferred fuel costs are not fully recovered for other reasons, it could have an adverse effect on future net income, cash flows and financial condition.

Rate recovery approved in Texas may be overturned on appeal.  (Applies to AEP)

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

In February 2009, the Texas District Court affirmed the PUCT in most respects.  In March 2009, various intervenors appealed the Texas District Court decision to the Texas Court of Appeals.  Management is unable to predict the outcome of these proceedings.  If the appeals are successful, it could have an adverse effect on future net income and cash flows.

Our request for rate recovery in Texas may not be approved in its entirety.  (Applies to AEP and SWEPCo)

In August 2009, SWEPCo filed a base rate case with the PUCT to increase non-fuel base rates by approximately $75 million annually based on a requested return on common equity of 11.5%.  If the PUCT denies all or part of the requested rate recovery, it could have an adverse effect on future net income, cash flows and financial condition.

Our request for rate recovery in Virginia may not be approved in its entirety.  (Applies to AEP and APCo)PSO.)

In July 2009, APCo filedthe OCC initiated a base rate case withproceeding to review PSO’s fuel and purchased power adjustment clause for the Virginia SCC requesting an increase incalendar year 2008 and also initiated a prudency review of the generationrelated costs.  In March 2010, the Oklahoma Attorney General and distribution portionsthe OIEC recommended the fuel clause adjustment rider be amended so that the shareholder’s portion of its base ratesoff-system sales margins sharing decrease from 25% to 10%.  The OIEC also recommended that the OCC conduct a comprehensive review of $169 million (later adjusted to $154 million) annuallyall affiliate transactions during 2007 and a 13.35% return on equity.2008.  If the Virginia SCC denies all or part of the requested rate recovery,OCC were to issue an unfavorable decision, it could have an adverse effect onreduce future net income and cash flows and impact financial condition.

Rate recovery approved in Oklahoma may be overturned on appeal.  (Applies to AEP and PSO)

In January 2009, the OCC issued a final order approving an $81 million increase in PSO’s non-fuel base revenues based on a 10.5% return on equity.  InThe new rates reflecting the final order were implemented with the first billing cycle of February 2009, the Oklahoma Attorney General2009.  PSO and several intervenors filed appeals with the Oklahoma Supreme Court raising several rate casevarious issues.  In July 2009, theThe Oklahoma Supreme Court assigned the case to the Court of Civil Appeals.  If the OCC, the Oklahoma Supreme Court and/or the Court of Civil Appeals reverse all or part of the rate recovery,intervenors’ appeals are successful, it could have an adverse effect onreduce future net income and cash flows and impact financial condition.

Our request for additional recovery in Oklahoma may not be approved in its entirety.

In August 2009, PSO filed an application with the OCC requesting a Capital Reliability Rider (CRR) to recover depreciation, taxes and return on PSO’s net capital investments for generation, transmission and distribution assets that have been placed into service from September 1, 2008 to June 30, 2009.  In October 2009, all but two of the parties to the CRR filing agreed to a stipulation that was filed with the OCC to collect no more than $30 million of revenues under the CRR on an annual basis beginning January 2010 until PSO’s next base rate order.  The stipulation also provides for an offsetting fuel revenue reduction via a modification to the fuel adjustment factor of Oklahoma jurisdictional customers on an annual basis by $30 million beginning January 2010 and refunds of certain over-recovered fuel balances during the first quarter of 2010.  If the OCC denies all or part of the requested rider, it could have an adverse effect on future net income, cash flows and financial condition.
Our request for rate recovery in Arkansas may not be approved in its entirety.(Applies to AEP and SWEPCo)

In February 2009, SWEPCo filed an application with the APSC for a base rate increase of $25 million based on a requested return on equity of 11.5%.  SWEPCo also requested a separate rider to recover financing costs related to the construction of the Stall Unit and Turk Plant.  In September 2009, SWEPCo, the APSC staff and the Arkansas Attorney General entered into a settlement agreement in which the settling parties agreed to an $18 million increase based on a return on equity of 10.25%.  If the APSC denies all or part of the increase in the settlement agreement, it could have an adverse effect on future net income, cash flows and financial condition.

Our future access to assets used to serve a major customer is in question.(Applies to I&M)

Since 1975 I&M has leased certain energy delivery assets from the City of Fort Wayne, Indiana under a long-term lease that expires on February 28, 2010.  I&M has been negotiating with Fort Wayne to purchase the assets at the end of the lease, but no agreement has been reached.  Recent mediation with Fort Wayne was also unsuccessful.  Fort Wayne issued a technical notice of default under the lease to I&M in August 2009.  I&M responded to Fort Wayne in October 2009 that it did not agree there was a default under the lease.  In October 2009, I&M filed for declaratory and injunctive relief in Indiana state court.  I&M will seek recovery in rates for any amount it may pay related to this dispute.  At this time, management cannot predict the outcome of this dispute.  While management believes any triggered costs should be recoverable from customers, without such recovery those costs, if material, could have an adverse effect on future net income, cash flows and financial condition.

Risks Related to Market, Economic or Financial Volatility
Downgrades in our credit ratings could negatively affect our ability to access capital and/or to operate our power trading businesses.  (Applies to
 each registrant)
Since the bankruptcy of Enron, the credit ratings agencies have periodically reviewed our capital structure and the quality and stability of our earnings.  Any negative ratings actions could constrain the capital available to our industry and could limit our access to funding for our operations.  Our business is capital intensive, and we are dependent upon our ability to access capital at rates and on terms we determine to be attractive.  If our ability to access capital becomes significantly constrained, our interest costs will likely increase and our financial condition could be harmed and future net income could be adversely affected.

If Moody’s, S&P or Fitch were to downgrade the long-term rating of any of the securities of the registrants, particularly below investment grade, the borrowing costs of that registrant would increase, which would diminish its financial results.  In addition, the registrant’s potential pool of investors and funding sources could decrease.  In 2009, Fitch changed its rating outlook for SWEPCo from stable to negative and downgraded APCo’s senior unsecured rating to BBB with stable outlook.  In 2009, Moody’s downgraded SWEPCo to Baa3 with stable outlook and changed the rating outlook for APCo from negative to stable.  Moody’s also placed AEP on negative outlook and downgraded OPCo to Baa1 with stable outlook.

Our power trading business relies on the investment grade ratings of our individual public utility subsidiaries’ senior unsecured long-term debt.  Most of our counterparties require the creditworthiness of an investment grade entity to stand behind transactions.  If those ratings were to decline below investment grade, our ability to operate our power trading business profitably would be diminished because we would likely have to deposit cash or cash-related instruments which would reduce our profits.

Risks Related to Owning and Operating Generation Assets and Selling Power
 
Increased regulation of GHG emissions could materially increase our costs or cause some of our electric generating units to be uneconomical to
operate or maintain.  (Applies to each registrant)

In April 2009,We may not fully recover the Federal EPA issued a proposed endangerment finding under the CAA regarding GHG emissions from motor vehicles.  This finding could lead to regulation of CO2 and other gases under existing laws.  In September 2009, the Federal EPA issued a final mandatory GHG reporting rule covering a broad range of facilities emitting in excess of 25,000 tons of GHG emissions per year.  The Federal EPA proposed regulation of stationary source GHG emissions through the NSR’s prevention of significant deterioration and CAA’s Title V permitting programs.  The Federal EPA is reconsidering whether to include GHG emissions in a number of stationary source standards, including standards that apply to electric utility units.  Some of the policy approaches being discussed by the Federal EPA would have significant and widespread negative consequences for the national economy and major U.S. industrial enterprises, including us.  If CO2 and other GHG emission standards are imposed, the standards could require significant increases in capital expenditures and operating costs which would impact the ultimate retirement of older, less-efficient, coal-fired units.  While management believes that costs of complying with new CO2repairing or replacing damaged equipment in Cook Plant Unit 1 and other GHG emission standards willmay be treated like all other reasonable costs of serving customers and should be recoverable from customers as costs of doing business, including capital investments with a return on investment, without such recovery those costs could have an adverse effect on future net income, cash flows and financial condition.
Courts adjudicating nuisance and other similar claims against us may order usrequired to limit or reduce our GHG emissions.pay additional accidental outage insurance proceeds to ratepayers.  (Applies to each registrant)AEP and I&M)
 
Cook Plant Unit 1 is a 1,084 MW nuclear generating unit located in Bridgman, Michigan. In 2004, eight statesSeptember 2008, I&M shut down Unit 1 due to turbine vibrations, which resulted in a small fire on the electric generator.  Unit 1 resumed operations in December 2009 at reduced power, but repair of the property damage and replacement of the turbine rotors and other equipment are estimated to cost approximately $395 million.  Management believes that I&M should recover a significant portion of these costs through the turbine vendor’s warranty, insurance and the City of New York filed an action in Federal District Court for the Southern District of New York against AEP, AEPSC, Cinergy Corp, Xcel Energy, Southern Company and Tennessee Valley Authority.  The Natural Resources Defense Council, on behalf of three special interest groups, filed a similar complaint against the same defendants.  The actions allege that CO2 emissions from the defendants’ power plants constitute a public nuisance under federal common law due to impacts of global warming, and sought injunctive relief in the form of specific emission reduction commitments from the defendants.  The dismissal of this lawsuit was appealed to the Second Circuit Court of Appeals.  In September 2009, the Second Circuit Court issued a ruling vacating the dismissal and remanding the case to the trial court.  The Second Circuit held that the issues of climate change and global warming do not raise political questions and that Congress’ refusal to regulate GHG emissions does not mean that plaintiffs must wait for an initial policy determination by Congress or the President’s administration to secure the relief sought in their complaints.  Similarly, in October 2009, the Fifth Circuit Court of Appeals reversed a decision by the trial court dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that GHG emissions exacerbated the effects of Hurricane Katrina.  The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs’ complaint to a coordinate branch of government, and that no initial policy determination was required to adjudicate these claims.regulatory process.

In March 2009, the IURC approved a settlement agreement with intervenors to collect a prior under-recovered fuel balance. Under the settlement agreement, a subdocket was established to consider issues relating to the Unit 1 shutdown including the treatment of the accidental outage insurance proceeds.  Separately, in March 2010, I&M filed its 2009 PSCR reconciliation with the MPSC.  The trial courts adjudicating these reinstated nuisance claims may orderfiling included an adjustment related to the defendants, including us,incremental fuel cost of replacement power due to limitthe Cook Plant Unit 1 outage.  If any fuel clause revenues or reduce GHG emissions.  This or similar remedies could require usaccidental outage insurance proceeds have to purchase power from third parties to fulfill our commitments to supply power to our customers.  This could have a material impact on our costs.  While management believes such costs should be recoverable from customers as costs of doing business, without such recovery those costs could have an adverse effect onrefunded, it would reduce future net income and cash flows and impact financial condition.

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

The following table provides information about purchases by AEP or its publicly-traded subsidiaries during the quarter ended September 30, 2009March 31, 2010 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 
07/01/09 – 07/31/09  - $-   - $- 
08/01/09 – 08/31/09  -  -   -  - 
09/01/09 – 09/30/09  2(a) 69.50   -  - 
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 
01/01/10 – 01/31/10  - $-   - $- 
02/01/10 – 02/28/10  -  -   -  - 
03/01/10 – 03/31/10  55(a) 69.86   -  - 

(a)APCo purchased 250 shares of its 4.50% cumulative preferred stock and OPCo purchased 5 shares of its 4.50% cumulative preferred stock in a privately-negotiated transactiontransactions outside of an announced program.

Item 4.  Submission Matters to a Vote of Security Holders

NONE

Item 5.  Other Information

NONE

Item 6.  Exhibits

AEP, APCo, OPCo, PSO and SWEPCo

10 – Amended and Restated AEP System Long-term Incentive Plan.

AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

12 – Computation of Consolidated Ratio of Earnings to Fixed Charges.

AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

31(a) – Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b) – Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

32(a) – Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
32(b) – Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

 
 
 

SIGNATURE




Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.  The signature for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.


AMERICAN ELECTRIC POWER COMPANY, INC.



By: /s/Joseph M. Buonaiuto
Joseph M. Buonaiuto
Controller and Chief Accounting Officer




APPALACHIAN POWER COMPANY
COLUMBUS SOUTHERN POWER COMPANY
INDIANA MICHIGAN POWER COMPANY
OHIO POWER COMPANY
PUBLIC SERVICE COMPANY OF OKLAHOMA
SOUTHWESTERN ELECTRIC POWER COMPANY




By: /s/Joseph M. Buonaiuto
Joseph M. Buonaiuto
Controller and Chief Accounting Officer



Date:  OctoberApril 30, 20092010