q309aep10q.htm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended September 30, 2009
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from ____ to ____

Commission
 
Registrant, State of Incorporation,
 
I.R.S. 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.
Yes
X
 
No
   

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

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

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

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

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).
Yes
   
No
X
 

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

 
 

 


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

 
 

 

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

Glossary of 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 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
 
American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEP West companies
 
PSO, SWEPCo, TCC and TNC.
AEPSC
 
American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries.
AFUDC
 
Allowance for Funds Used During Construction.
ALJ
 
Administrative Law Judge.
AOCI
 
Accumulated Other Comprehensive Income.
APB
 
Accounting Principles Board Opinion.
APCo
 
Appalachian Power Company, an AEP electric utility subsidiary.
APSC
 
Arkansas Public Service Commission.
ASU
 
Accounting Standards Update issued by the Financial Accounting Standards Board.
CAA
 
Clean Air Act.
CO2
 
Carbon Dioxide.
Cook Plant
 
Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CSPCo
 
Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW
 
Central and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the legal name of Central and South West Corporation was changed to AEP Utilities, Inc.).
CSW Operating Agreement
 
Agreement, dated January 1, 1997, by and among PSO, SWEPCo, TCC and TNC governing generating capacity allocation.  This agreement was amended in May 2006 to remove TCC and TNC.  AEPSC acts as the agent.
CTC
 
Competition Transition Charge.
CWIP
 
Construction Work in Progress.
DHLC
 
Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo that is a consolidated variable interest entity.
E&R
 
Environmental compliance and transmission and distribution system reliability.
EaR
 
Earnings at Risk, a method to quantify risk exposure.
EIS
 
Energy Insurance Services, Inc., a protected cell captive insurance company that is a consolidated variable interest entity.
EITF
 
Financial Accounting Standards Board’s Emerging Issues Task Force.
EITF 06-10
 
EITF Issue No. 06-10 “Accounting for Collateral Assignment Split-Dollar Life Insurance Arrangements.”
ENEC
 
Expanded Net Energy Cost.
EPS
 
Earnings Per Share.
ERCOT
 
Electric Reliability Council of Texas.
ERISA
 
Employee Retirement Income Security Act of 1974, as amended.
ESP
 
Electric Security Plan.
ETT
 
Electric Transmission Texas, LLC, a 50% equity interest joint venture with MidAmerican Energy Holdings Company formed to own and operate electric transmission facilities in ERCOT.
FAC
 
Fuel Adjustment Clause.
FASB
 
Financial Accounting Standards Board.
Federal EPA
 
United States Environmental Protection Agency.
FERC
 
Federal Energy Regulatory Commission.
FSP
 
FASB Staff Position.
FSP SFAS 107-1 and APB 28-1
 
FSP SFAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments.”
FTR
 
Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP
 
Accounting Principles Generally Accepted in the United States of America.
GHG
 
Greenhouse gases.
I&M
 
Indiana Michigan Power Company, an AEP electric utility subsidiary.
IGCC
 
Integrated Gasification Combined Cycle, technology that turns coal into a cleaner-burning gas.
Interconnection Agreement
 
Agreement, dated July 6, 1951, as amended, by and among APCo, CSPCo, I&M, KPCo and OPCo, defining the sharing of costs and benefits associated with their respective generating plants.
IRS
 
Internal Revenue Service.
IURC
 
Indiana Utility Regulatory Commission.
JBR
 
Jet Bubbling Reactor.
JMG
 
JMG Funding LP.
KGPCo
 
Kingsport Power Company, an AEP electric distribution subsidiary.
KPCo
 
Kentucky Power Company, an AEP electric utility subsidiary.
kV
 
Kilovolt.
KWH
 
Kilowatthour.
LPSC
 
Louisiana Public Service Commission.
MISO
 
Midwest Independent Transmission System Operator.
MLR
 
Member load ratio, the method used to allocate AEP Power Pool transactions to its members.
MMBtu
 
Million British Thermal Units.
MTM
 
Mark-to-Market.
MW
 
Megawatt.
MWH
 
Megawatthour.
NOx
 
Nitrogen oxide.
Nonutility Money Pool
 
AEP Consolidated’s Nonutility Money Pool.
NSR
 
New Source Review.
OCC
 
Corporation Commission of the State of Oklahoma.
OPCo
 
Ohio Power Company, an AEP electric utility subsidiary.
OPEB
 
Other Postretirement Benefit Plans.
OTC
 
Over the counter.
OVEC
 
Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
PATH
 
Potomac Appalachian Transmission Highline, LLC and its subsidiaries, a joint venture with Allegheny Energy Inc. formed to own and operate electric transmission facilities in PJM.
PJM
 
Pennsylvania – New Jersey – Maryland regional transmission organization.
PSO
 
Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO
 
Public Utilities Commission of Ohio.
PUCT
 
Public Utility Commission of Texas.
REP
 
Texas Retail Electric Provider.
Registrant Subsidiaries
 
AEP subsidiaries which are SEC registrants; APCo, CSPCo, I&M, OPCo, PSO and SWEPCo.
Risk Management Contracts
 
Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant
 
A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana, owned by AEGCo and I&M.
RSP
 
Rate Stabilization Plan.
RTO
 
Regional Transmission Organization.
S&P
 
Standard and Poor’s.
SEC
 
United States Securities and Exchange Commission.
SECA
 
Seams Elimination Cost Allocation.
SEET
 
Significant Excess Earnings Test.
SFAS
 
Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board.
SFAS 157
 
Statement of Financial Accounting Standards No. 157, “Fair Value Measurements.”
SIA
 
System Integration Agreement.
SNF
 
Spent Nuclear Fuel.
SO2
 
Sulfur Dioxide.
SPP
 
Southwest Power Pool.
Stall Unit
 
J. Lamar Stall Unit at Arsenal Hill Plant.
SWEPCo
 
Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC
 
AEP Texas Central Company, an AEP electric utility subsidiary.
TEM
 
SUEZ Energy Marketing NA, Inc. (formerly known as Tractebel Energy Marketing, Inc.).
Texas Restructuring   Legislation
 
Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC
 
AEP Texas North Company, an AEP electric utility subsidiary.
True-up Proceeding
 
A filing made under the Texas Restructuring Legislation to finalize the amount of stranded costs and other true-up items and the recovery of such amounts.
Turk Plant
 
John W. Turk, Jr. Plant.
Utility Money Pool
 
AEP System’s Utility Money Pool.
VaR
 
Value at Risk, a method to quantify risk exposure.
VIE
 
Variable Interest Entity.
Virginia SCC
 
Virginia State Corporation Commission.
WPCo
 
Wheeling Power Company, an AEP electric distribution subsidiary.
WVPSC
 
Public Service Commission of West Virginia.
 

 
 

 

FORWARD-LOOKING INFORMATION

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

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

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

 
 

 

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

EXECUTIVE OVERVIEW

Economic Slowdown

Our residential and commercial KWH sales appear to be relatively stable; nevertheless, some segments of our service territories are experiencing slowdowns.  We are currently monitoring the following trends:

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

Regulatory Activity

Our significant 2009 rate proceedings include:

·
Arkansas - In September 2009, SWEPCo reached a rate change settlement agreement that provides for an $18 million increase in revenues based upon a return on equity of 10.25% and a decrease in annual depreciation rates of $10 million.  The combination of these factors should contribute an additional $28 million in annual pretax income to SWEPCo annually.  The settlement agreement also includes a separate rider of approximately $11 million annually for the recovery of carrying costs, depreciation and operation and maintenance expenses on the Stall Unit once it is placed in service as expected in mid-2010.  Approval of the settlement by the APSC is expected in the fourth quarter of 2009.
   
·
Indiana - In March 2009, the IURC approved a modified rate settlement agreement that provides for an annual increase in revenues of $42 million, including a $19 million increase in revenue from base rates and $23 million in additional tracker revenues for certain incurred costs, subject to true-up.
 
·
Ohio - In March 2009, and as amended in July 2009, the PUCO issued an order that modified and approved CSPCo’s and OPCo’s ESP filings.  Among other things, the ESP order authorized capped increases to revenues during the three-year ESP period and also authorized a fuel adjustment clause (FAC) which allows CSPCo and OPCo to phase-in and defer actual FAC costs incurred in excess of the caps, that will be trued-up, subject to annual caps.  The projected revenue increases for CSPCo and OPCo are listed below:

 
Projected Revenue 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 requested a base rate increase with the Virginia SCC of $169 million annually (later adjusted to $154 million) based on a 13.35% return on common equity.  The new rates will become effective, subject to refund, no later than December 2009.
 
In August 2009, the Virginia SCC issued an order which provides for a $130 million fuel revenue increase.  If actual fuel costs are greater or less than the projected fuel costs, APCo will seek appropriate adjustments in APCo’s next fuel factor proceeding.
   
·
West Virginia - In September 2009, the WVPSC issued an order granting a $355 million increase over a four-year phase-in period.  The order lowered annual coal cost projections by $27 million and deferred recovery of unrecovered ENEC deferrals related to price increases on certain renegotiated coal contracts.  The WVPSC indicated that it would review the prudency of these additional costs in the next ENEC proceeding and APCo will adjust rates appropriately.

Mountaineer Carbon Capture and Storage Project

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

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

Turk Plant

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

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

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

Pension Trust Fund

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

Risk Management Contracts

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

Capital Expenditures

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

Fuel Inventory

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

RESULTS OF OPERATIONS

Segments

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

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

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

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

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

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

AEP Consolidated

Third Quarter of 2009 Compared to Third Quarter of 2008

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

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

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

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

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

Utility Operations

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

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

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

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

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

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

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

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

Third Quarter of 2009 Compared to Third Quarter of 2008

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

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

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

·
Retail Margins increased $281 million primarily due to the following:
 
·
An $87 million increase related to the PUCO’s approval of our Ohio ESPs, a $43 million increase related to base rates and recovery of E&R costs in Virginia and construction financing costs in West Virginia, a $22 million increase in base rates in Oklahoma and a $7 million net rate increase for I&M.
 
·
A $151 million increase in fuel margins in Ohio due to the deferral of fuel costs by CSPCo and OPCo in 2009.  The PUCO’s March 2009 approval of CSPCo’s and OPCo’s ESPs allows for the deferral and recovery of fuel and related costs during the ESP period.  See “Ohio Electric Security Plan Filings” section of Note 3.
 
·
A $90 million increase resulting from reduced sharing of off-system sales margins with retail customers in our eastern service territory due to a decrease in total off-system sales.
 
These increases were partially offset by:
 
·
A $61 million decrease in margins from industrial sales due to reduced operating levels and suspended operations by certain large industrial customers in our service territories.
 
·
A $42 million decrease in usage primarily due to a 23% decrease in cooling degree days in our eastern region.
 
·
A $19 million decrease in fuel margins due to higher fuel and purchased power costs related to the Cook Plant Unit 1 shutdown.  This decrease in fuel margins was offset by a corresponding increase in Other Revenues as discussed below.
·
Margins from Off-system Sales decreased $226 million primarily due to lower physical sales volumes and lower margins in our eastern service territory reflecting lower market prices, partially offset by higher trading and marketing margins.
·
Transmission Revenues increased $10 million primarily due to increased rates in the ERCOT and SPP regions.
·
Other Revenues increased $52 million primarily due to Cook Plant accidental outage insurance policy proceeds of $46 million.  Of these insurance proceeds, $19 million were used to reduce customer bills.  This increase in revenues was offset by a corresponding decrease in Retail Margins as discussed above.  See “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.

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

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

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

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

Nine Months Ended September 30, 2008
        $ 1,036  
               
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.

AEP River Operations

Third Quarter of 2009 Compared to Third Quarter of 2008

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

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

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

Generation and Marketing

Third Quarter of 2009 Compared to Third Quarter of 2008

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

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

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

All Other

Third Quarter of 2009 Compared to Third Quarter of 2008

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

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

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

AEP System Income Taxes

Income Tax Expense increased $16 million in the third quarter of 2009 compared to the third quarter of 2008 primarily due to an increase in pretax book income, partially offset by state income taxes and changes in certain book/tax differences accounted for on a flow-through basis.

Income Tax Expense decreased $73 million in the nine-month period ended September 30, 2009 compared to the nine-month period ended September 30, 2008 primarily due to a decrease in pretax book income.

FINANCIAL CONDITION

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

Debt and Equity 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%

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

Liquidity

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

Capital Markets

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

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

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments.  At September 30, 2009, our available liquidity was approximately $3.6 billion as illustrated in the table below:
   
Amount
   
Maturity
   
(in millions)
     
Commercial Paper Backup:
         
Revolving Credit Facility
  $ 1,500    
March 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.

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

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

Sales of Receivables

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

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

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

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

Dividend Policy and Restrictions

We have declared common stock dividends payable in cash in each quarter since July 1910, representing 398 consecutive quarters.  The Board of Directors declared a quarterly dividend of $0.41 per share in October 2009.  Future dividends may vary depending upon our profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time.  We have the option to defer interest payments on the AEP Junior Subordinated Debentures issued in March 2008 for one or more periods of up to 10 consecutive years per period.  During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, our common stock.  We believe that these restrictions will not have a material effect on our cash flows or financial condition or limit any dividend payments in the foreseeable future.

Credit Ratings

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

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

In 2009, Moody’s:

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

In 2009, Fitch:

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

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

Cash Flow

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

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

Operating Activities

 
Nine Months 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.

Net Cash Flows from Operating Activities were $1.9 billion in 2009 consisting primarily of Net Income of $1.1 billion and $1.2 billion of noncash depreciation and amortization.  Other represents items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  Significant changes in other items include the negative impact on cash of an increase in coal inventory reflecting decreased customer demand for electricity as the result of the economic slowdown and unfavorable weather conditions and an increase in under-recovered fuel primarily in Ohio and West Virginia.
 
Net Cash Flows from Operating Activities were $2.1 billion in 2008 consisting primarily of Income Before Discontinued Operations of $1.2 billion and $1.1 billion of noncash depreciation and amortization.  Other represents items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  Significant changes in other items include an increase in under-recovered fuel reflecting higher coal and natural gas prices.

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

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

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

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

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

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

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

Off-balance Sheet Arrangements

Under a limited set of circumstances, we enter into off-balance sheet arrangements to accelerate cash collections, reduce operational expenses and spread risk of loss to third parties.  Our current guidelines restrict the use of off-balance sheet financing entities or structures to traditional operating lease arrangements and sales of customer accounts receivable that we enter in the normal course of business.  Our significant off-balance sheet arrangements  are as follows:
 
 
September 30,
 
December 31,
 
 
2009
 
2008
 
 
(in millions)
 
AEP Credit Accounts Receivable Purchase Commitments
  $ 530     $ 650  
Rockport Plant Unit 2 Future Minimum Lease Payments
    1,996       2,070  
Railcars Maximum Potential Loss From Lease Agreement
    25       25  

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

Summary Obligation Information

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

SIGNIFICANT FACTORS

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

Ohio Electric Security Plan Filings

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

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

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

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

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

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

Cook Plant Unit 1 Fire and Shutdown

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

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

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

Texas Restructuring Appeals

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

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

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

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

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

New Generation/Purchase Power Agreement

AEP is in various stages of construction of the following generation facilities:
                                 
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 effect on net income, cash flows and possibly financial condition.
 
A request to stop pre-construction activities at the site was filed in Federal District Court by certain Arkansas landowners.  In July 2008, the federal court denied the request and the Arkansas landowners appealed the denial to the U.S. Court of Appeals.  In January 2009, SWEPCo filed a motion to dismiss the appeal, which was granted in March 2009.

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

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

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

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

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

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

The American Recovery and Reinvestment Act of 2009

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

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

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

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

Litigation

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

Environmental Matters

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

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

In addition, we are engaged in litigation with respect to certain environmental matters, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of spent nuclear fuel and future decommissioning of our nuclear units.  We are also involved in the development of possible future requirements to reduce CO2 and other GHG emissions to address concerns about global climate change.  All of these matters are discussed in the “Environmental Matters” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2008 Annual Report.

Clean Water Act Regulations

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

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

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

Potential Regulation of CO2 and Other GHG Emissions

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

In April 2009, the Federal EPA issued a proposed endangerment finding under the CAA regarding GHG emissions from motor vehicles.  The proposed endangerment finding is subject to public comment.  This finding could lead to regulation of CO2 and other gases under existing laws.  In September 2009, the Federal EPA issued a final mandatory GHG reporting rule covering a broad range of facilities emitting in excess of 25,000 tons of GHG emissions per year.  The Federal EPA has also issued proposed light duty vehicle GHG emissions standards for model years 2012-2016, and a proposed scheme to streamline and phase in regulation of stationary source GHG emissions through the NSR’s prevention of significant deterioration and CAA’s Title V permitting programs.  The Federal EPA stated its intent to finalize the vehicle standards and permitting rule in conjunction with or following a final endangerment finding, and is reconsidering whether to include GHG emissions in a number of stationary source standards, including standards that apply to electric utility units.  Some of the policy approaches being discussed by the Federal EPA would have significant and widespread negative consequences for the national economy and major U.S. industrial enterprises, including us.  Because of these adverse consequences, management believes that these more extreme policies will not ultimately be adopted and that reasonable and comprehensive legislative action is preferable.  Even if reasonable CO2 and other GHG emission standards are imposed, the standards could require significant increases in capital expenditures and operating costs which would impact the ultimate retirement of older, less-efficient, coal-fired units.  Management believes that costs of complying with new CO2 and other GHG emission standards will be treated like all other reasonable costs of serving customers and should be recoverable from customers as costs of doing business, including capital investments with a return on investment.

Proposed Health Care Legislation

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

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2008 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncements

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

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

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

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

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

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

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

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

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

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

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

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

Pronouncements Effective in the Future

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

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

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

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

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

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

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

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

 
 

 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

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

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

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

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

The following tables provide information on our risk management activities.

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

The following two tables summarize the various mark-to-market (MTM) positions included on our balance sheet as of September 30, 2009 and the reasons for changes in our total MTM value included on our balance sheet as compared to December 31, 2008.

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

   
Utility Operations
   
Generation and
Marketing
   
All Other
   
Sub-Total
MTM Risk Management Contracts
   
Cash Flow Hedge Contracts
   
Collateral
Deposits
   
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)
Nine Months Ended September 30, 2009
(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  

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

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

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

 
Remainder
2009
 
2010
 
2011
 
2012
 
2013
 
After
2013 (f)
 
Total
Utility Operations
                                       
Level 1 (a)
$
(1)
 
$
 
$
 
$
 
$
 
$
 
$
(1)
Level 2 (b)
 
24 
   
43 
   
18 
   
   
   
   
97 
Level 3 (c)
 
19 
   
39 
   
   
   
   
   
67 
Total
 
42 
   
82 
   
24 
   
   
   
   
163 
                                         
Generation and Marketing
                                       
Level 1 (a)
 
(2)
   
   
   
   
   
   
(1)
Level 2 (b)
 
   
14 
   
17 
   
16 
   
19 
   
41 
   
108 
Level 3 (c)
 
   
   
   
   
   
30 
   
37 
Total
 
(1)
   
16 
   
18 
   
18 
   
22 
   
71 
   
144 
                                         
All Other
                                       
Level 1 (a)
 
   
   
   
   
   
   
Level 2 (b)
 
(1)
   
(4)
   
   
   
   
   
(3)
Level 3 (c)
 
   
   
   
   
   
   
Total
 
(1)
   
(4)
   
   
   
   
   
(3)
                                         
Total
                                       
Level 1 (a)
 
(3)
   
   
   
   
   
   
(2)
Level 2 (b)
 
24 
   
53 
   
37 
   
19 
   
27 
   
42 
   
202 
Level 3 (c) (d)
 
19 
   
40 
   
   
   
   
30 
   
104 
Total
 
40 
   
94 
   
44 
   
24 
   
30 
   
72 
   
304 
Dedesignated Risk Management Contracts (e)
 
   
14 
   
   
   
   
   
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 Risk

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

   
Exposure Before Credit Collateral
   
Credit Collateral
   
Net Exposure
   
Number of Counterparties >10% of
Net Exposure
   
Net Exposure
of Counterparties >10%
 
Counterparty Credit Quality
 
(in millions, except number of counterparties)
 
Investment Grade
  $ 775     $ 69     $ 706       2     $ 228  
Split Rating
    7       -       7       2       7  
Noninvestment Grade
    4       2       2       2       1  
No External Ratings:
                                       
Internal Investment Grade
    75       4       71       4       56  
Internal Noninvestment Grade
    112       12       100       3