10-Q 1 q311aep10q.htm AMERICAN ELECTRIC POWER 3Q2011 10-Q Unassociated Document
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, 2011
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from ____ to ____

Commission
 
Registrants; States of Incorporation;
 
I.R.S. Employer
File Number
 
Address and Telephone Number
 
Identification Nos.
         
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
   
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 the AEP 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 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 27, 2011
       
American Electric Power Company, Inc.
   
482,912,247
     
($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 OF QUARTERLY REPORTS ON FORM 10-Q
September 30, 2011

   
Page
Number
Glossary of Terms
    i
     
Forward-Looking Information
    iv
     
Part I. FINANCIAL INFORMATION
   
       
           Items 1, 2 and 3 - Financial Statements, Management’s Discussion and Analysis and Quantitative and Qualitative Disclosures About Market Risk:    
     
American Electric Power Company, Inc. and Subsidiary Companies:
   
 
Management’s Discussion and Analysis
    1
 
Quantitative and Qualitative Disclosures About Market Risk
    23
 
Condensed Consolidated Financial Statements
    27
 
Index of Condensed Notes to Condensed Consolidated Financial Statements
    32
       
Appalachian Power Company and Subsidiaries:
   
 
Management’s Discussion and Analysis
    84
 
Quantitative and Qualitative Disclosures About Market Risk
    91
 
Condensed Consolidated Financial Statements
    92
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
    97
       
Columbus Southern Power Company and Subsidiaries:
   
 
Management’s Narrative Discussion and Analysis
    99
 
Quantitative and Qualitative Disclosures About Market Risk
    105
 
Condensed Consolidated Financial Statements
    106
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
    111
       
Indiana Michigan Power Company and Subsidiaries:
   
 
Management’s Narrative Discussion and Analysis
    113
 
Quantitative and Qualitative Disclosures About Market Risk
    117
 
Condensed Consolidated Financial Statements
    118
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
    123
       
Ohio Power Company Consolidated:
   
 
Management’s Discussion and Analysis
    125
 
Quantitative and Qualitative Disclosures About Market Risk
    134
 
Condensed Consolidated Financial Statements
    135
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
    140
       
Public Service Company of Oklahoma:
   
 
Management’s Discussion and Analysis
    142
 
Quantitative and Qualitative Disclosures About Market Risk
    146
 
Condensed Financial Statements
    147
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
    152
       
Southwestern Electric Power Company Consolidated:
   
 
Management’s Discussion and Analysis
    154
 
Quantitative and Qualitative Disclosures About Market Risk
    159
 
Condensed Consolidated Financial Statements
    160
 
Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
    165

 
 

 

Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
    166
       
Combined Management’s Discussion and Analysis of Registrant Subsidiaries
    232
       
Controls and Procedures
    243
         
Part II.  OTHER INFORMATION
   
     
 
Item 1.
Legal Proceedings
    243
 
Item 1A.
Risk Factors
    243
 
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
    247
 
Item 5.
Other Information
    248
 
Item 6.
Exhibits:
    248
         
Exhibit 12
   
         
Exhibit 31(a)
   
         
Exhibit 31(b)
   
         
Exhibit 32(a)
   
         
Exhibit 32(b)
   
         
Exhibit 101.INS
   
         
Exhibit 101.SCH
   
         
Exhibit 101.CAL
   
         
Exhibit 101.DEF
   
         
Exhibit 101.LAB
   
         
Exhibit 101.PRE
   
               
SIGNATURE
      249

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., a holding company.
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 AEP Power Pool shares the generation, cost of generation and resultant wholesale off-system sales of the member companies.
AEP System or the System
 
American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEPEP
 
AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, asset management and commercial and industrial sales in the deregulated Texas market.
AEPSC
 
American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries.
AFUDC
 
Allowance for Funds Used During Construction.
AOCI
 
Accumulated Other Comprehensive Income.
APCo
 
Appalachian Power Company, an AEP electric utility subsidiary.
APSC
 
Arkansas Public Service Commission.
ASU
 
Accounting Standard Update.
BOA
 
Bank of America Corporation.
CAA
 
Clean Air Act.
CLECO
 
Central Louisiana Electric Company, a nonaffiliated utility company.
CO2
 
Carbon Dioxide and other greenhouse gases.
Cook Plant
 
Donald C. Cook Nuclear Plant, a two-unit, 2,191 MW nuclear plant owned by I&M.
CSPCo
 
Columbus Southern Power Company, an AEP electric utility subsidiary.
CTC
 
Competition Transition Charge, a transition charge applied to TCC’s transmission and distribution rates for stranded costs and other true-up amounts as required by the Texas Restructuring Legislation.
DCC Fuel
 
DCC Fuel LLC, DCC Fuel II LLC and DCC Fuel III LLC, variable interest entities formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
DHLC
 
Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo.
E&R
 
Environmental compliance and transmission and distribution system reliability.
EIS
 
Energy Insurance Services, Inc., a nonaffiliated captive insurance company.
ERCOT
 
Electric Reliability Council of Texas regional transmission organization.
ESP
 
Electric Security Plans, filed with the PUCO, pursuant to the Ohio Amendments.
ETT
 
Electric Transmission Texas, LLC, an equity interest joint venture between AEP Utilities, Inc. and MidAmerican Energy Holdings Company Texas Transco, LLC formed to own and operate electric transmission facilities in ERCOT.
FAC
 
Fuel Adjustment Clause.
FASB
 
Financial Accounting Standards Board.
Federal EPA
 
United States Environmental Protection Agency.
FERC
 
Federal Energy Regulatory Commission.
FGD
 
Flue Gas Desulfurization or Scrubbers.
FTR
 
Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.

 
i

 
Term
 
Meaning
     
GAAP
 
Accounting Principles Generally Accepted in the United States of America.
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.
KGPCo
 
Kingsport Power Company, an AEP electric utility subsidiary.
KPCo
 
Kentucky Power Company, an AEP electric utility subsidiary.
KWH
 
Kilowatthour.
LPSC
 
Louisiana Public Service Commission.
MISO
 
Midwest Independent Transmission System Operator.
MMBtu
 
Million British Thermal Units.
MPSC
 
Michigan Public Service Commission.
MTM
 
Mark-to-Market.
MW
 
Megawatt.
NEIL
 
Nuclear Electric Insurance Limited insures domestic and international nuclear utilities for the costs associated with interruptions, damages, decontaminations and related nuclear risks.
NOx
 
Nitrogen oxide.
Nonutility Money Pool
 
AEP’s Nonutility Money Pool is the centralized funding mechanism AEP uses to meet the short term cash requirements of pool participants.
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.
PJM
 
Pennsylvania – New Jersey – Maryland regional transmission organization.
PM
 
Particulate Matter.
POLR
 
Provider of Last Resort revenues.
PSO
 
Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO
 
Public Utilities Commission of Ohio.
PUCT
 
Public Utility Commission of Texas.
Registrant Subsidiaries
 
AEP subsidiaries which are SEC registrants; APCo, CSPCo, I&M, OPCo, PSO and SWEPCo.
Risk Management Contracts
 
Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant
 
A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana, owned by AEGCo and I&M.
RTO
 
Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine
 
Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity.
SEC
 
U.S. Securities and Exchange Commission.
SEET
 
Significantly Excessive Earnings Test.
SIA
 
System Integration Agreement, effective June 15, 2000, provides contractual basis for coordinated planning, operation and maintenance of the power supply sources of the combined AEP.
SNF
 
Spent Nuclear Fuel.

 
ii

 
Term
 
Meaning
     
SO2
 
Sulfur Dioxide.
SPP
 
Southwest Power Pool regional transmission organization.
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.
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.
     
Transition Funding
 
AEP Texas Central Transition Funding I LLC and AEP Texas Central Transition Funding II LLC, wholly-owned subsidiaries of TCC and consolidated variable interest entities formed for the purpose of issuing and servicing securitization bonds related to Texas restructuring law.
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 is the centralized funding mechanism AEP uses to meet the short term cash requirements of pool participants.
VIE
 
Variable Interest Entity.
Virginia SCC
 
Virginia State Corporation Commission.
WPCo
 
Wheeling Power Company, an AEP electric utility subsidiary.
WVPSC
 
Public Service Commission of West Virginia.

 
iii

 
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.  Many forward-looking statements appear in “Item 7 – Management’s Financial Discussion and Analysis” of the 2010 Annual Report, but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook.  These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected.  Forward-looking statements in this document are presented as of the date of this document.  Except to the extent required by applicable law, we undertake no obligation to update or revise any forward-looking statement.  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, customer growth and the impact of retail competition, particularly in Ohio.
·
Weather conditions, including storms, and our ability to recover significant storm restoration costs through applicable rate mechanisms.
·
Available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.
·
Availability of necessary generating capacity and the performance of our generating plants.
·
Our ability to resolve I&M’s Donald C. Cook Nuclear Plant Unit 1 restoration and outage-related issues through warranty, insurance and the regulatory process.
·
Our ability to recover regulatory assets and stranded costs in connection with deregulation.
·
Our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.
·
Our ability to build or acquire generating capacity, including the Turk Plant, and transmission lines and 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 oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances or additional regulation of fly ash and similar combustion products that could impact the continued operation and cost recovery of our plants and related assets.
·
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.
·
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 our 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 ESPs and the expected legal separation and transition to market for generation in Ohio and the allocation of costs within regional transmission organizations, including PJM and SPP.
 
 
iv

 
·
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, captive insurance entity 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.
·
Our ability to recover through rates or market prices any remaining unrecovered investment in generating units that may be retired before the end of their previously projected useful lives.
·
Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel.
·
Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events.

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

 
v

 
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS

EXECUTIVE OVERVIEW

Customer Demand

In comparison to 2010 for both the quarter-to-date and year-to-date periods, cooling degree days in 2011 were up 13% and 19%, respectively, in our western region and down 2% and 7%, respectively, in our eastern region.  While cooling degree days in our eastern region were down slightly in comparison to 2010, they were significantly higher than normal.  Our non-weather residential and commercial sales remained relatively flat in comparison to 2010.  Industrial sales are up just over 5% for the quarter-to-date and year-to-date periods, reflecting a significant increase in production from Ormet, a large aluminum company, and lesser increases from several other industrial customers, reflecting an increase in production at several of our metals and refinery customers.  Commercial margins decreased 5% for the year-to-date period primarily due to the loss of retail customers in Ohio.  See “Ohio Customer Choice” section below.

Texas Restructuring Appeals

In July 2011, the Supreme Court of Texas overturned a 2006 PUCT order that had denied recovery of capacity auction true-up amounts related to TCC securitized net recoverable stranded generation cost.  Based upon the Supreme Court of Texas’ opinion, TCC recorded $421 million of pretax income ($273 million, net of tax) in Extraordinary Item, Net of Tax on the condensed statements of income in the third quarter of 2011.

Also in the third quarter of 2011, TCC recorded $261 million in pretax Carrying Costs Income on the condensed statements of income related to the debt component of carrying costs for the period from January 2002 through September 2011.  This carrying costs income represents previously unrecorded earnings associated with restructuring in Texas since 2002.  The total regulatory asset related to the capacity auction true-up as of September 30, 2011 was $682 million.  In October 2011, TCC filed with the PUCT requesting a final determination of the amount to be securitized.  In its filing, TCC presented three alternative carrying cost calculations through March 2012, the anticipated securitization date, where the debt and equity component of carrying costs ranged from $396 million to $756 million, including $280 million to $444 million for the debt component of carrying costs.  The final amount of carrying costs will be determined by the PUCT and could vary from the calculations presented by TCC.  TCC plans to recognize debt carrying costs income prior to securitization and equity carrying costs income will be recognized as collected over the life of the securitization.  A PUCT hearing is scheduled for November 2011.  See “Texas Restructuring Appeals” section of Note 3.

Regulatory Activity

Ohio 2009 – 2011 ESPs

In April 2011, the Supreme Court of Ohio issued an opinion addressing the aspects of the PUCO's 2009 decision that were challenged and remanded certain issues back to the PUCO.  In October 2011, the PUCO issued an order in the remand proceeding.  The order required CSPCo and OPCo to refund POLR charges which were collected subject to refund since June 2011.  As a result, in the third quarter of 2011, CSPCo and OPCo recorded pretax refund provisions of $34 million and $9 million, respectively, on the condensed statements of income.

In July 2011, CSPCo and OPCo filed their 2010 SEET filings with the PUCO.  Based upon the approach in the PUCO 2009 order, management does not currently believe that CSPCo or OPCo will have any significantly excessive earnings.  In October 2011, the Ohio Consumers’ Counsel and the Ohio Energy Group filed testimony that recommended CSPCo refund up to $41 million of its 2010 earnings.  Also in October 2011, the PUCO staff filed testimony that recommended CSPCo refund $21 million of its 2010 earnings.  See “Ohio Electric Security Plan Filings” section of Note 3.
 
 
1

 
Ohio January 2012 – May 2016 ESP

In January 2011, CSPCo and OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing for generation.  In September 2011, a stipulation agreement was filed with the PUCO which involved various issues pending before the PUCO, including the approval of the CSPCo/OPCo merger and the recovery of deferred fuel until securitized.  Under the stipulation agreement, rates would be effective with the first billing cycle of January 2012 through the last billing cycle of May 2016.  Prior to June 2015, CSPCo’s and OPCo’s SSO customers continue to pay the tariff rate for non-fuel generation and the fuel adjustment clause.  Beginning in June 2015, CSPCo and OPCo will use results from a competitive bidding process performed prior to January 2015 to meet their SSO obligation through May 2016.  The stipulation agreement proposed a corporate separation plan of CSPCo’s and OPCo’s generation assets to complete the transition to a fully competitive generation market by June 2015.  In addition, to further develop customer choice and facilitate the transition to market generation pricing, CSPCo and OPCo will provide 21% of their generation capacity in 2012, 29% to 31% of their generation capacity in 2013 and 41% of their generation capacity beginning in 2014 through May 2015 to competitive retail suppliers at a charge based on the Reliability Pricing Model auction-clearing prices and the remainder at a discounted cost-based price.

The stipulation agreement also proposed a termination or modification of the Interconnection Agreement.  Finally, the stipulation agreement provides for certain CSPCo and OPCo contingent contributions and established a Distribution Investment Rider beginning January 2012 through May 2015 to recover post-2000 distribution investment with certain limitations.  See “Ohio Electric Security Plan Filings,” “Proposed CSPCo and OPCo Merger” and “Possible Termination of the Interconnection Agreement” sections of Note 3.

Ohio Distribution Base Rate Case

In February 2011, CSPCo and OPCo filed with the PUCO for annual increases in distribution rates of $34 million and $60 million, respectively.  The requested increase is based upon an 11.15% return on common equity to be effective January 2012.  In addition to the annual increases, CSPCo and OPCo requested recovery of the projected December 31, 2012 balances of certain distribution regulatory assets of $216 million and $159 million, respectively, including carrying costs, to be recovered in a requested distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013.  The PUCO staff filed testimony that recommended a rate reduction for CSPCo in the range of $2 million to $10 million and a rate increase for OPCo in the range of $23 million to $32 million.  In addition, the PUCO staff recommended recovery of the deferred distribution regulatory assets subject to a review of the carrying costs.  A decision from the PUCO is expected in the fourth quarter of 2011.  See “2011 Ohio Distribution Base Rate Case” section of Note 3.

Virginia Regulatory Activity

In March 2011, APCo filed a generation and distribution base rate request with the Virginia SCC to increase annual base rates by $126 million based upon an 11.65% return on common equity to be effective no later than February 2012.  The return on common equity includes a requested 0.5% renewable portfolio standards incentive as allowed by law. APCo proposed to mitigate the requested base rate increase by $51 million by maintaining current depreciation rates until the next biennial filing.  If approved, APCo’s net base rate increase would be $75 million.  In August 2011, the Virginia Attorney General and the Virginia SCC staff filed testimony recommending no increase in annual base rates and a $31 million increase in annual base rates, respectively.  Hearings were held in September 2011.  A decision from the Virginia SCC is pending.  See “2011 Virginia Biennial Base Rate Case” section of Note 3.

West Virginia Regulatory Activity

In March 2011, the WVPSC modified and approved a settlement agreement which increased annual base rates by approximately $51 million based upon a 10% return on common equity.  The approved settlement agreement also resulted in a pretax write-off of a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility in the first quarter of 2011.  In addition, the WVPSC allowed APCo to defer and amortize $18 million of previously expensed 2009 incremental storm expenses and allowed APCo and WPCo to defer and amortize $15 million of previously expensed costs related to the 2010 cost reduction initiatives, each over a period of seven years.   See “2010 West Virginia Base Rate Case” section of Note 3.

 
2

 
Michigan Base Rate Case

In July 2011, I&M filed a request with the MPSC for an annual increase in Michigan base rates of $25 million and a return on equity of 11.15%.  The request included an increase in depreciation rates that would result in a $6 million increase in annual depreciation expense.  I&M plans to request an interim rate increase, subject to refund, for the portion of the $25 million that, among other things, excludes the depreciation rate changes and other regulatory amortizations.  I&M plans to propose the interim rate increase be effective in January 2012.

Indiana Base Rate Case

In September 2011, I&M filed a request with the IURC for a net annual increase in Indiana base rates of $149 million based upon a return on equity of 11.15%.  The request included an increase in depreciation rates that would result in a $25 million increase in annual depreciation expense.

Ohio Customer Choice

In our Ohio service territory, various competitive retail electric service (CRES) providers are targeting retail customers by offering alternative generation service.  As a result, in comparison to the third quarter of 2010 and the first nine months of 2010, we lost approximately $41 million and $94 million, respectively, of generation and transmission related gross margin.  We are recovering a portion of lost margins through collection of transmission revenues from competitive CRES providers, off-system sales and new revenues from our CRES provider.  Our CRES provider targets retail customers in Ohio, both within and outside of our retail service territory.

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW coal generating unit in Arkansas, which is expected to be in service in 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility.  SWEPCo’s share of construction costs is currently estimated to be $1.3 billion, excluding AFUDC, plus an additional $129 million for transmission, excluding AFUDC.  The APSC, LPSC and PUCT approved SWEPCo’s original application to build the Turk Plant.  In June 2010, the APSC issued an order which reversed and set aside the previously granted Certificate of Environmental Compatibility and Public Need.  Various proceedings are pending that challenge the Turk Plant’s construction and its approved wetlands and air permits.  In 2010, the motions for preliminary injunction were partially granted by the Federal District Court for the Western District of Arkansas.  According to the preliminary injunction, all uncompleted construction work associated with wetlands, streams or rivers at the Turk Plant must immediately stop.  Mitigation measures required by the permit are authorized and may be completed.  The preliminary injunction affects portions of the water intake and portions of two transmission lines.  In July 2011, the U.S. Eighth Circuit Court of Appeals affirmed the preliminary injunction and remanded the case to the district court.  Management is unable to predict the timing or the outcome related to this remand proceeding.

In August 2011, a joint stipulation of dismissal was approved by the Federal District Court for the Western District of Arkansas that resolved all pending matters between SWEPCo, the Hempstead County Hunting Club (Hunting Club) and several other parties.  As a result, the Hunting Club’s challenge to the U.S. Army Corps of Engineers permit in the Federal District Court for the Western District of Arkansas was dismissed and the Hunting Club’s appeal of the air permit was withdrawn.  Additional judicial and administrative proceedings were terminated.  The Sierra Club and the Audubon Society challenges to the wetlands and air permits remain pending.

In October 2011, the Sierra Club, the National Audubon Society and Audubon Arkansas filed a complaint with the APSC requesting that construction of the Turk Plant be halted until SWEPCo or the Arkansas Electric Cooperative Corporation obtain either a Certificate of Environmental Compatibility and Public Need, or SWEPCo obtains a Certificate of Convenience and Necessity and performs an Environmental Impact Statement on associated gas facilities.  Management believes the complaint is without merit and intends to vigorously defend against the complaint.
 
 
3

 
Management expects that SWEPCo will ultimately be able to complete construction of the Turk Plant and related transmission facilities and place those facilities in service.  However, if SWEPCo is unable to complete the Turk Plant construction, including the related transmission facilities, and place the Turk Plant in service or if SWEPCo cannot recover all of its investment in and expenses related to the Turk Plant, it would materially reduce future net income and cash flows and materially impact financial condition.  See “Turk Plant” section of Note 3.

Cook Plant

In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in a fire on the electric generator.  Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $408 million.  Management believes that I&M should recover a significant portion of repair and replacement costs through the turbine vendor’s warranty, insurance and the regulatory process.  I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power.  The Unit 1 rotors were repaired and reinstalled due to the extensive lead time required to manufacture and install new turbine rotors.  The installation of the new turbine rotors and other equipment occurred as planned during the fall 2011 refueling outage of Unit 1.  If the ultimate costs of the incident are not covered by warranty, insurance or through the related regulatory process or if any future regulatory proceedings are adverse, it could reduce future net income and cash flows and impact financial condition.  See “Michigan 2009 and 2010 Power Supply Cost Recovery Reconciliations” section of Note 3 and “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.

As a result of the nuclear plant situation in Japan following a March 2011 earthquake, we expect the Nuclear Regulatory Commission and possibly Congress to review safety procedures and requirements for nuclear generating facilities.  This review could increase procedures and testing requirements, require physical modifications to the plant and increase future operating costs at the Cook Plant.  We are unable to predict the impact of potential future regulation of nuclear facilities.

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 predict the eventual resolution, timing or amount of any loss, fine or penalty.  We assess the probability of loss for each contingency and accrue a liability for cases that have a probable likelihood of loss if the loss 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” in the 2010 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, financial condition and cash flows.

ENVIRONMENTAL ISSUES

We are implementing a substantial capital investment program and incurring additional operational costs to comply with new environmental control requirements.  We will need to make additional investments and operational changes in response to existing and anticipated requirements such as CAA requirements to reduce emissions of SO2, NOx, PM and hazardous air pollutants from fossil fuel-fired power plants, new proposals governing the beneficial use and disposal of coal combustion products and proposed clean water rules.

We are engaged in litigation about environmental issues, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of SNF and future decommissioning of our nuclear units.  We are also engaged in the development of possible future requirements including the items discussed below and reductions of CO2 emissions to address concerns about global climate change.  AEP, various industry groups, affected states and other parties have urged the Federal EPA to conduct additional analysis and either postpone the effective date or extend the time frame for compliance with some of these future requirements.  The U.S. House of Representatives passed legislation called the Transparency in Regulatory Analysis of Impacts on the Nation (the TRAIN Act) that would delay implementation of certain Federal EPA rules to facilitate a comprehensive analysis of their impacts.  The Senate is considering similar legislation.  We believe that further analysis and better coordination of these future environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.
 
4

 
See a complete discussion of these matters in the “Environmental Issues” section of “Management’s Financial Discussion and Analysis” in the 2010 Annual Report.  We will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions.  We should be able to recover certain of these expenditures through market prices in deregulated jurisdictions.  If not, the costs of environmental compliance could adversely affect future net income, cash flows and possibly financial condition.

Update to Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System.  We continue to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of September 30, 2011, the AEP System had a total generating capacity of nearly 38,000 MWs, of which 23,900 MWs are coal-fired.  In the second quarter of 2011, we refined the cost estimates of complying with these rules and other impacts of the environmental proposals on our coal-fired generating facilities.  Based upon the updated estimates, investment to meet these proposed requirements ranges from approximately $6 billion to $8 billion between 2012 and 2020.  These amounts include investments to convert 1,070 MWs of coal generation to 932 MWs of natural gas capacity and build approximately 580 MWs of natural gas-fired generation.

The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in the final rules.  The cost estimates will also change based on: (a) the states’ implementation of these regulatory programs, including the potential for state implementation plans or federal implementation plans that impose standards more stringent than the proposed rules, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed on our units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors.

Subject to the factors listed above and based upon our continuing evaluation, we may retire the following plants or units of plants before 2015:

 
 
 
 
Generating
Company
 
Plant Name and Unit
 
Capacity
 
 
 
 
(in MWs)
KPCo
 
Big Sandy Plant, Unit 1
 
 
 278 
APCo
 
Clinch River Plant, Unit 3
 
 
 235 
CSPCo
 
Conesville Plant, Unit 3
 
 
 165 
APCo
 
Glen Lyn Plant
 
 
 335 
OPCo
 
Kammer Plant
 
 
 630 
APCo
 
Kanawha River Plant
 
 
 400 
OPCo
 
Muskingum River Plant, Units 1-4
 
 
 840 
APCo/OPCo
 
Philip Sporn Plant
 
 
 1,050 
CSPCo
 
Picway Plant
 
 
 100 
I&M
 
Tanners Creek Plant, Units 1-3
 
 
 495 
SWEPCo
 
Welsh Plant, Unit 2
 
 
 528 
 
 
Total
 
 
 5,056 

Duke Energy Corporation, the operator of W. C. Beckjord Generating Station, has announced its intent to close the facility in 2015.  CSPCo owns 12.5% (54 MWs) of one unit at that station.

Plans for and the timing of conversion of some of our coal units to natural gas, installing emission control equipment on other units and closure of existing units will be impacted by changes in emission requirements and demand for power.  We are completing construction of the Turk and Dresden Plants.  Recovery of the remaining investments in facilities that we may close and cost of new equipment and converted facilities will be subject to regulatory approval.
 
5

 
Cross-State Air Pollution Rule (formerly the Clean Air Act Transport Rule)

In July 2010, the Federal EPA issued a proposed rule to replace the Clean Air Interstate Rule (CAIR) that would impose new and more stringent requirements to control SO2 and NOx emissions from fossil fuel-fired electric generating units in 31 states and the District of Columbia.  Each state covered by the proposed Clean Air Act Transport Rule (Transport Rule) was assigned an allowance budget for SO2 and/or NOx.  Limited interstate trading was allowed on a sub-regional basis and intrastate trading was allowed among generating units.  Our western states (Arkansas, Oklahoma and Texas) would be subject to only the seasonal NOx program, with new limits that were proposed to take effect in 2012.  The remainder of the states in which we operate would have been subject to seasonal and annual NOx programs and an annual SO2 emissions reduction program that takes effect in two phases.  The first phase was to be effective in 2012 and more stringent SO2 emission reductions were proposed to take effect in 2014 in certain states.  The SO2 and NOx programs rely on newly-created allowances rather than relying on the CAIR NOx allowances or the Title IV Acid Rain Program allowances used in CAIR.

In July 2011, the Federal EPA released the final rule, renamed the Cross-State Air Pollution Rule (CSAP Rule).  Like the proposed Transport Rule, the CSAP Rule relies on newly-created SO2 and NOx allowances and individual state budgets to compel further emission reductions from electric utility generating units in 28 states.  Interstate trading of allowances is allowed on a restricted sub-regional basis beginning in 2012.  Arkansas and Louisiana are subject only to the seasonal NOx program in the final rule.  A proposed supplemental rule would include Oklahoma in the seasonal NOx program.  Texas is now subject to the annual programs for SO2 and NOx in addition to the seasonal NOx program.  The annual SO2 allowance budgets in Indiana, Ohio and West Virginia have been reduced significantly in the final rule.

In October 2011, the Federal EPA released a supplemental proposed rule revising portions of the final CSAP Rule.  The proposed rule would correct errors in unit-specific assumptions and make available additional allowances in ten states, including Louisiana and Texas, and provide additional allowances for the new unit set aside in Arkansas.  In addition, the proposed rule would make the allowance trading assurance provisions which restrict interstate trading of allowances effective January 1, 2014 instead of January 1, 2012.

The time frames and stringency of the required emission reductions, coupled with the lack of robust interstate trading and the elimination of historic allowance banks, pose significant concerns for the AEP System and our electric utility customers.  The compliance plan described above was based on the requirements of the proposed Transport Rule.  The more stringent requirements included in the final CSAP Rule could cause further unit curtailments, increase capital requirements, constrain operations, decrease reliability and unfavorably impact financial condition if the increased costs are not recovered in rates or market prices.

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

The Federal EPA issued the Clean Air Mercury Rule (CAMR) in 2005, setting mercury emission standards for new coal-fired power plants and requiring all states to issue new state implementation plans including mercury requirements for existing coal-fired power plants.  The CAMR was vacated by the D.C. Circuit Court of Appeals in 2008.  In response, the Federal EPA has been developing a rule addressing a broad range of HAPs from coal and oil-fired power plants.  The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of nonmercury metal) and hydrogen chloride (as a surrogate for acid gases) for units burning coal, on a site-wide 30-day rolling average basis.  In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans.  Compliance is required within three years of the effective date of the final rule, which is expected in December 2011 per the Federal EPA’s settlement agreement with several environmental groups.  A one-year extension may be available if the extension is necessary for the installation of controls.  In October 2011, various intervenors filed a motion to extend the deadline by which the Federal EPA is required to finalize the HAPs rule for one year, to November 2012.  The motion was supported by 25 states’ attorneys general.  A joint request of the Federal EPA and the plaintiffs to extend the deadline for finalizing the rule for 30 days, to December 16, 2011, was granted.
 
6

 
We submitted comments on the proposed rule and urged the Federal EPA to carefully consider all of the options available so that costly and inefficient control requirements are not imposed regardless of unit size, age or other operating characteristics.  We have older coal units for which it may be economically inefficient to install scrubbers or other environmental controls.  Several of these units are included in our current list of potential plant closures discussed above.

Regional Haze

In March 2011, the Federal EPA proposed to approve in part and disapprove in part the regional haze state implementation plan (SIP) submitted by the State of Oklahoma through the Department of Environmental Quality.  The Federal EPA is proposing to approve all of the NOx control measures in the SIP and disapprove the SO2 control measures for six electric generating units, including two units owned by PSO.  The Federal EPA is proposing a federal implementation plan (FIP) that would require these units to install technology capable of reducing SO2 emissions to 0.06 pounds per million British thermal units within three years of the effective date of the FIP.  The State of Oklahoma filed suit in Federal District Court in the Western District of Oklahoma seeking to enjoin the Federal EPA from taking final action on the FIP without allowing the state to first respond to the deficiencies identified for the first time in the proposed disapproval of the SIP.  Motions for preliminary relief are pending.  PSO submitted comments on the proposed action demonstrating that the cost-effectiveness calculations performed by the Federal EPA were unsound, challenging the period for compliance with the final rule and showing that the visibility improvements secured by the proposed SIP were significant and cost-effective.  Final action on the proposal is required to be taken by December 14, 2011 under a consent decree between the Federal EPA and certain environmental advocacy groups.

Coal Combustion Residual Rule

In June 2010, the Federal EPA published a proposed rule to regulate the disposal and beneficial re-use of coal combustion residuals, including fly ash and bottom ash generated at our coal-fired electric generating units.  The rule contains two alternative proposals.  One proposal would impose federal hazardous waste disposal and management standards on these materials and another would allow states to retain primary authority to regulate the beneficial re-use and disposal of these materials under state solid waste management standards, including minimum federal standards for disposal and management.  Both proposals would impose stringent requirements for the construction of new coal ash landfills and would require existing unlined surface impoundments to upgrade to the new standards or stop receiving coal ash and initiate closure within five years of the issuance of a final rule.  In October 2011, the Federal EPA issued a notice of data availability requesting comments on a number of technical reports and other data received during the comment period for the original proposal and requesting comments on potential modeling analyses to update its risk assessment.  Comments are due in November 2011.

Currently, approximately 40% of the coal ash and other residual products from our generating facilities are re-used in the production of cement and wallboard, as structural fill or soil amendments, as abrasives or road treatment materials and for other beneficial uses.  Certain of these uses would no longer be available and others are likely to significantly decline if coal ash and related materials are classified as hazardous wastes.  In addition, we currently use surface impoundments and landfills to manage these materials at our generating facilities and will incur significant costs to upgrade or close and replace these existing facilities.  We estimate that the potential compliance costs associated with the proposed solid waste management alternative could be as high as $3.9 billion including AFUDC for units across the AEP System.  Regulation of these materials as hazardous wastes would significantly increase these costs.

Clean Water Act Regulations

In April 2011, the Federal EPA issued a proposed rule setting forth standards for existing power plants that will reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water.  Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress.  The proposed standards affect all plants withdrawing more than two million gallons of cooling water per day and establish specific intake design and intake velocity standards meant to allow fish to avoid or escape impingement.  Compliance with this standard is required within eight years of the effective date of the final rule.  The proposed standard for entrainment for existing facilities requires a site-specific evaluation of the available measures for reducing entrainment.  The proposed entrainment
 
7

 
standard for new units at existing facilities requires either intake flows commensurate with closed cycle cooling or achieving entrainment reductions equivalent to 90% or greater of the reductions that could be achieved with closed cycle cooling.  Plants withdrawing more than 125 million gallons of cooling water per day must submit a detailed technology study to be reviewed by the state permitting authority.  We are evaluating the proposal and engaged in the collection of additional information regarding the feasibility of implementing this proposal at our facilities.  We submitted comments on the proposal in July and August 2011.

Global Warming

While comprehensive economy-wide regulation of CO2 emissions might be mandated through new legislation, Congress has yet to enact such legislation.  The Federal EPA continues to take action to regulate CO2 emissions under the existing requirements of the CAA.  The Federal EPA issued a final endangerment finding for CO2 emissions from new motor vehicles in December 2009 and final rules for new motor vehicles in May 2010.  The Federal EPA determined that CO2 emissions from stationary sources will be subject to regulation under the CAA and finalized its proposed scheme to streamline and phase in regulation of stationary source CO2 emissions through the NSR prevention of significant deterioration and Title V operating permit programs through the issuance of final federal rules, state implementation plan calls and federal implementation plans.  The Federal EPA is reconsidering whether to include CO2 emissions in a number of stationary source standards, including standards that apply to new and modified electric utility units and announced a settlement agreement to issue proposed new source performance standards for utility boilers that would be applicable for both new and existing utility boilers.  It is not possible at this time to estimate the costs of compliance with these new standards, but they may be material.

Our fossil fuel-fired generating units are very large sources of CO2 emissions.  If substantial CO2 emission reductions are required, there will be significant increases in capital expenditures and operating costs which would impact the ultimate retirement of older, less-efficient, coal-fired units.  To the extent we install additional controls on our generating plants to limit CO2 emissions and receive regulatory approvals to increase our rates, cost recovery could have a positive effect on future earnings.  Prudently incurred capital investments made by our subsidiaries in rate-regulated jurisdictions to comply with legal requirements and benefit customers are generally included in rate base for recovery and earn a return on investment.  We would expect these principles to apply to investments made to address new environmental requirements.  However, requests for rate increases reflecting these costs can affect us adversely because our regulators could limit the amount or timing of increased costs that we would recover through higher rates.  In addition, to the extent our costs are relatively higher than our competitors’ costs, such as operators of nuclear and natural gas based generation, it could reduce our off-system sales or cause us to lose customers in jurisdictions that permit customers to choose their supplier of generation service.

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

Certain groups have filed lawsuits alleging that emissions of CO2 are a “public nuisance” and seeking injunctive relief and/or damages from small groups of coal-fired electricity generators, petroleum refiners and marketers, coal companies and others.  We have been named in pending lawsuits, which we are vigorously defending.  It is not possible to predict the outcome of these lawsuits or their impact on our operations or financial condition.  See “Carbon Dioxide Public Nuisance Claims” and “Alaskan Villages’ Claims” sections of Note 4.

Future federal and state legislation or regulations that mandate limits on the emission of CO2 would result in significant increases in capital expenditures and operating costs, which in turn, could lead to increased liquidity needs and higher financing costs.  Excessive costs to comply with future legislation or regulations might force our utility subsidiaries to close some coal-fired facilities and could lead to possible impairment of assets.  As a result, mandatory limits could have a material adverse impact on our net income, cash flows and financial condition.

For detailed information on global warming and the actions we are taking to address potential impacts, see Part I of the 2010 Form 10-K under the headings entitled “Business – General – Environmental and Other Matters – Global Warming” and “Management’s Financial Discussion and Analysis.”
 
8

 
RESULTS OF OPERATIONS

SEGMENTS

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

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

AEP River Operations
 
·
Commercial barging operations that transport 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 and, to a lesser extent, Ohio in PJM and MISO.

The table below presents our consolidated Income Before Extraordinary Item by segment for the three and nine months ended September 30, 2011 and 2010.

 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2011 
 
2010 
 
2011 
 
2010 
 
 
(in millions)
Utility Operations
$
 642 
 
$
 541 
 
$
 1,376 
 
$
 1,017 
AEP River Operations
 
 17 
 
 
 14 
 
 
 23 
 
 
 16 
Generation and Marketing
 
 8 
 
 
 - 
 
 
 20 
 
 
 17 
All Other (a)
 
 (10)
 
 
 2 
 
 
 (54)
 
 
 (10)
Income Before Extraordinary Item
$
 657 
 
$
 557 
 
$
 1,365 
 
$
 1,040 

(a)
While not considered a business segment, All Other includes:
 
·
Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.
 
·
Forward natural gas contracts that were not sold with our natural gas pipeline and storage operations in 2004 and 2005.  These contracts are financial derivatives which settle and expire in the fourth quarter of 2011.
 
·
Revenue sharing related to the Plaquemine Cogeneration Facility which ends in the fourth quarter of 2011.

AEP CONSOLIDATED

Third Quarter of 2011 Compared to Third Quarter of 2010

Income Before Extraordinary Item increased from $557 million in 2010 to $657 million in 2011 primarily due to:

·
An increase in carrying costs income due to the third quarter 2011 recognition of a regulatory asset related to TCC capacity auction true-up amounts that were originally written off in 2005.
·
Successful rate proceedings in our various jurisdictions.
·
An increase in weather-related usage.

These increases were partially offset by:

·
Various Ohio adjustments in the third quarter of 2011, including the refund provision for POLR charges collected from customers, the impairments of Sporn Unit 5 and the FGD project at Muskingum River Unit 5 and the write-off of allocated Front-End Engineering and Design (FEED) study costs related to the Mountaineer Carbon Capture Project.
·
The loss of retail customers in Ohio to various competitive retail electric service providers.

Average basic shares outstanding increased from 480 million in 2010 to 482 million in 2011.
 
9

 
Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Income Before Extraordinary Item increased from $1,040 million in 2010 to $1,365 million in 2011 primarily due to the following:

·
A decrease in expenses as a result of the second quarter 2010 cost reduction initiatives.
·
An increase in carrying costs income due to the third quarter 2011 recognition of a regulatory asset related to TCC capacity auction true-up amounts that were originally written off in 2005.
·
Successful rate proceedings in our various jurisdictions.
·
The unfavorable 2010 tax treatment associated with future reimbursement of Medicare Part D prescription drug benefits.

These increases were partially offset by:

·
Various Ohio adjustments in the third quarter of 2011, including the refund provision for POLR charges collected from customers, the write-off of allocated FEED study costs related to the Mountaineer Carbon Capture Project and the impairments of Sporn Unit 5 and the FGD project at Muskingum River Unit 5.
·
A net-of-tax loss related to the first quarter of 2011 settlement of litigation with BOA and Enron.
·
The loss of retail customers in Ohio to various competitive retail electric service providers.

Average basic shares outstanding increased from 479 million in 2010 to 482 million in 2011.  Actual shares outstanding were 483 million as of September 30, 2011.

Our results of operations are discussed below by operating segment.

UTILITY OPERATIONS

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

 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2011 
 
2010 
 
2011 
 
2010 
 
 
(in millions)
Revenues
$
 4,074 
 
$
 3,907 
 
$
 10,987 
 
$
 10,544 
Fuel and Purchased Power
 
 1,609 
 
 
 1,427 
 
 
 4,136 
 
 
 3,784 
Gross Margin
 
 2,465 
 
 
 2,480 
 
 
 6,851 
 
 
 6,760 
Other Operation and Maintenance
 
 882 
 
 
 849 
 
 
 2,587 
 
 
 2,798 
Asset Impairments and Other Related Charges
 
 90 
 
 
 - 
 
 
 90 
 
 
 - 
Depreciation and Amortization
 
 435 
 
 
 413 
 
 
 1,226 
 
 
 1,205 
Taxes Other Than Income Taxes
 
 210 
 
 
 208 
 
 
 618 
 
 
 613 
Operating Income
 
 848 
 
 
 1,010 
 
 
 2,330 
 
 
 2,144 
Interest and Investment Income
 
 18 
 
 
 2 
 
 
 21 
 
 
 6 
Carrying Costs Income
 
 290 
 
 
 17 
 
 
 323 
 
 
 51 
Allowance for Equity Funds Used During Construction
 
 26 
 
 
 17 
 
 
 69 
 
 
 60 
Interest Expense
 
 (223)
 
 
 (238)
 
 
 (682)
 
 
 (710)
Income Before Income Tax Expense and Equity
 
 
 
 
 
 
 
 
 
 
 
 
Earnings
 
 959 
 
 
 808 
 
 
 2,061 
 
 
 1,551 
Equity Earnings of Unconsolidated Subsidiaries
 
 7 
 
 
 3 
 
 
 19 
 
 
 7 
Income Tax Expense
 
 324 
 
 
 270 
 
 
 704 
 
 
 541 
Income Before Extraordinary Item
$
 642 
 
$
 541 
 
$
 1,376 
 
$
 1,017 
 
 
10

 
Summary of KWH Energy Sales for Utility Operations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
2011 
 
2010 
 
2011 
 
2010 
 
 
(in millions of KWHs)
Retail:
 
 
 
 
 
 
 
 
 
 
 
 
Residential
 
 18,238 
 
 
 17,817 
 
 
 48,690 
 
 
 48,250 
 
Commercial
 
 14,274 
 
 
 14,032 
 
 
 38,833 
 
 
 38,508 
 
Industrial
 
 15,206 
 
 
 14,460 
 
 
 44,688 
 
 
 42,503 
 
Miscellaneous
 
 854 
 
 
 832 
 
 
 2,354 
 
 
 2,328 
Total Retail (a)
 
 48,572 
 
 
 47,141 
 
 
 134,565 
 
 
 131,589 
 
 
 
 
 
 
 
 
 
 
 
 
Wholesale
 
 13,164 
 
 
 10,689 
 
 
 32,532 
 
 
 25,846 
 
 
 
 
 
 
 
 
 
 
 
 
Total KWHs
 
 61,736 
 
 
 57,830 
 
 
 167,097 
 
 
 157,435 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)  Includes 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 number of customers within each region.

Summary of Heating and Cooling Degree Days for Utility Operations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
September 30,
 
 
2011 
 
2010 
 
2011 
 
2010 
 
 
(in degree days)
Eastern Region
 
 
 
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 6 
 
 
 1 
 
 
 1,995 
 
 
 1,976 
Normal - Heating (b)
 
 7 
 
 
 7 
 
 
 1,914 
 
 
 1,918 
 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 838 
 
 
 859 
 
 
 1,209 
 
 
 1,294 
Normal - Cooling (b)
 
 700 
 
 
 691 
 
 
 999 
 
 
 984 
 
 
 
 
 
 
 
 
 
 
 
 
 
Western Region
 
 
 
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 - 
 
 
 - 
 
 
 702 
 
 
 764 
Normal - Heating (b)
 
 1 
 
 
 1 
 
 
 601 
 
 
 596 
 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (d)
 
 1,669 
 
 
 1,471 
 
 
 2,813 
 
 
 2,357 
Normal - Cooling (b)
 
 1,359 
 
 
 1,353 
 
 
 2,179 
 
 
 2,168 
 
 
 
 
 
 
 
 
 
 
 
 
 
(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 cooling degree days are calculated on a 65 degree temperature base.
(d)
Western Region cooling degree days are calculated on a 65 degree temperature base for PSO/SWEPCo and a 70 degree temperature base for TCC/TNC.

 
11

 
Third Quarter of 2011 Compared to Third Quarter of 2010
 
Reconciliation of Third Quarter of 2010 to Third Quarter of 2011
 
Income from Utility Operations before Extraordinary Item
 
(in millions)
 
 
 
 
 
Third Quarter of 2010
  $ 541  
 
       
Changes in Gross Margin:
       
Retail Margins
    (19 )
Off-system Sales
    (1 )
Transmission Revenues
    14  
Other Revenues
    (9 )
Total Change in Gross Margin
    (15 )
 
       
Changes in Expenses and Other:
       
Other Operation and Maintenance
    (33 )
Asset Impairments and Other Related Charges
    (90 )
Depreciation and Amortization
    (22 )
Taxes Other Than Income Taxes
    (2 )
Interest and Investment Income
    16  
Carrying Costs Income
    273  
Allowance for Equity Funds Used During Construction
    9  
Interest Expense
    15  
Equity Earnings of Unconsolidated Subsidiaries
    4  
Total Change in Expenses and Other
    170  
 
       
Income Tax Expense
    (54 )
 
       
Third Quarter of 2011
  $ 642  

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

·
Retail Margins decreased $19 million primarily due to the following:
 
·
A $41 million decrease attributable to Ohio customers switching to alternative competitive retail electric service (CRES) providers.
 
·
A $33 million refund provision for CSPCo POLR charges as a result of the October 2011 PUCO remand order.
 
·
A $29 million increase in other variable electric generation expenses.
 
·
A $23 million decrease in rate related margins for APCo due to the expiration of E&R cost recovery in Virginia.
 
These decreases were partially offset by:
 
·
Successful rate proceedings in our service territories which include:
   
·
A $57 million rate increase in Ohio.
   
·
A $22 million rate increase for APCo.
   
·
A $10 million rate increase for I&M.
   
·
A $3 million rate increase for SWEPCo.
   
·
For the rate increases described above, $41 million of these increases relate to riders/trackers which have corresponding increases in other expense items below.
 
·
A $14 million increase in weather-related usage primarily due to a 13% increase in cooling degree days in our western region.
 
·
A $5 million increase in revenues related to TCC’s securitization.  This increase is offset by an increase in Depreciation and Amortization expenses.
·
Transmission Revenues increased $14 million primarily due to net rate increases in PJM and increased transmission revenues for Ohio customers who have switched to alternative CRES providers.  The increase in transmission revenues related to CRES providers offsets lost revenues included in Retail Margins above.
·
Other Revenues decreased $9 million primarily due to lower amortization of deferred gains.

 
12

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

·
Other Operation and Maintenance expenses increased $33 million primarily due to:
 
·
A $9 million increase due to the third quarter 2011 write-off of Ohio allocated FEED study costs related to the Mountaineer Carbon Capture Project.
 
·
A $9 million increase in plant outage expenses and other plant operating and maintenance expenses.
 
·
An $8 million increase in storm-related expenses.
 
·
An $8 million increase in transmission-related expenses.
 
·
A $4 million increase in demand side management expenses, energy efficiency program expenses and other expenses currently recovered dollar-for-dollar in rate recovery riders/trackers within Gross Margin.
 
These increases were partially offset by:
 
·
A $6 million decrease associated with the favorable resolution of an I&M contingency.
·
Asset Impairments and Other Related Charges includes the third quarter 2011 plant impairments of Sporn Unit 5 ($48 million) and the FGD project at Muskingum River Unit 5 ($42 million).
·
Depreciation and Amortization expenses increased $22 million primarily due to the following:
 
·
A $19 million increase for OPCo due to the amortization of debt and equity carrying costs on deferred fuel as a result of the October 2011 PUCO remand order which required the POLR refund to be applied against deferred fuel balances.  The equity amortization was partially offset by amounts recognized in Carrying Costs Income.
 
·
A $10 million increase in depreciation and amortization for TCC primarily due to increased amortization of TCC’s Securitized Transition Asset.  This increase is offset by an increase in revenues within Gross Margin.
 
·
Overall higher depreciable property balances.
 
These increases were partially offset by:
 
·
An $8 million decrease in depreciation and amortization for APCo primarily due to the expiration of E&R amortization of deferred carrying costs in Virginia.
·
Interest and Investment Income increased $16 million primarily due to interest income recorded in the third quarter of 2011 for favorable adjustments related to the 2001-2006 federal income tax audit.
·
Carrying Costs Income increased $273 million primarily due to the following:
 
·
A $261 million increase in carrying costs income due to the third quarter 2011 recognition of a regulatory asset related to TCC capacity auction true-up amounts that were originally written off in 2005.
 
·
A $10 million increase due to the recognition of equity carrying costs on deferred fuel as a result of the October 2011 PUCO remand order which required the POLR refund to be applied against any deferred fuel balances.  The equity carrying costs income was offset by amounts in Depreciation and Amortization discussed above.
·
Allowance for Equity Funds Used During Construction increased $9 million primarily due to construction of the Turk and Dresden Plants and various environmental upgrades.
·
Interest Expense decreased $15 million primarily due to lower outstanding debt balances.
·
Equity Earnings of Unconsolidated Subsidiaries increased $4 million primarily due to an increase in transmission investments by ETT.
·
Income Tax Expense increased $54 million primarily due to an increase in pre-tax book income.

 
13

 

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010
 
Reconciliation of Nine Months Ended September 30, 2010 to Nine Months Ended September 30, 2011
Income from Utility Operations before Extraordinary Item
(in millions)
 
 
 
 
 
Nine Months Ended September 30, 2010
 
$
 1,017 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
Retail Margins
 
 
 8 
 
Off-system Sales
 
 
 49 
 
Transmission Revenues
 
 
 34 
 
Total Change in Gross Margin
 
 
 91 
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
Other Operation and Maintenance
 
 
 211 
 
Asset Impairments and Other Related Charges
 
 
 (90)
 
Depreciation and Amortization
 
 
 (21)
 
Taxes Other Than Income Taxes
 
 
 (5)
 
Interest and Investment Income
 
 
 15 
 
Carrying Costs Income
 
 
 272 
 
Allowance for Equity Funds Used During Construction
 
 
 9 
 
Interest Expense
 
 
 28 
 
Equity Earnings of Unconsolidated Subsidiaries
 
 
 12 
 
Total Change in Expenses and Other
 
 
 431 
 
 
 
 
 
 
Income Tax Expense
 
 
 (163)
 
 
 
 
 
 
Nine Months Ended September 30, 2011
 
$
 1,376 
 

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 $8 million primarily due to the following:
 
·
Successful rate proceedings in our service territories which include:
   
·
A $90 million rate increase in Ohio.
   
·
A $49 million rate increase for APCo.
   
·
A $32 million rate increase for KPCo.
   
·
A $25 million rate increase for I&M.
   
·
A $23 million rate increase for SWEPCo.
   
·
For the rate increases described above, $54 million of these increases relate to riders/trackers which have corresponding increases in other expense items below.
 
·
A $32 million increase in weather-related usage in our western region primarily due to a 19% increase in cooling degree days.
 
·
A $5 million increase related to TCC’s Securitized Transition Asset.  This increase is offset by an increase in Depreciation and Amortization expenses.
 
These increases were partially offset by:
 
·
A $94 million decrease attributable to Ohio customers switching to alternative CRES providers.
 
·
A $60 million decrease in rate related margins for APCo due to the expiration of E&R cost recovery in Virginia.
 
·
A $37 million increase in other variable electric generation expenses.
 
·
A $33 million refund provision for CSPCo POLR charges as a result of the October 2011 PUCO remand order.
 
·
A $32 million decrease in weather-related usage in our eastern region primarily due to a 7% decrease in cooling degree days.
·
Margins from Off-system Sales increased $49 million primarily due to an increase in PJM capacity revenues and higher physical sales volumes, partially offset by lower trading and marketing margins.
 
 
14

 
·
Transmission Revenues increased $34 million primarily due to net rate increases in PJM and increased transmission revenues for Ohio customers who have switched to alternative CRES providers.  The increase in transmission revenues related to CRES providers offsets lost revenues included in Retail Margins above.

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

·
Other Operation and Maintenance expenses decreased $211 million primarily due to the following:
 
·
A $275 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
 
·
A $54 million decrease due to the second quarter 2010 write-off of APCo’s Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the Virginia SCC.
 
·
A $33 million decrease due to the first quarter 2011 deferral of 2010 costs related to storms and our cost reduction initiatives as allowed by the WVPSC.
 
·
A $31 million decrease in administrative and general expenses primarily due to a decrease in fringe benefit expenses.
 
·
An $11 million gain on the sale of land.
 
These decreases were partially offset by:
 
·
A $49 million increase in demand side management, energy efficiency programs and other expenses currently recovered dollar-for-dollar in rate recovery riders/trackers within Gross Margin.
 
·
A $41 million increase due to the first quarter 2011 write-off of a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the WVPSC.
 
·
A $36 million increase in storm-related expenses.
 
·
A $36 million increase in plant outage and other plant operating and maintenance expenses.
 
·
A $25 million increase due to the second quarter 2010 deferral of 2009 storm costs as allowed by the Virginia SCC.
 
·
A $9 million increase due to the third quarter 2011 write-off of Ohio allocated FEED study costs related to the Mountaineer Carbon Capture Project.
·
Asset Impairments and Other Related Charges includes the third quarter 2011 plant impairments of Sporn Unit 5 ($48 million) and the FGD project at Muskingum River Unit 5 ($42 million).
·
Depreciation and Amortization expenses increased $21 million primarily due to the following:
 
·
A $19 million increase for OPCo due to the amortization of debt and equity carrying costs on deferred fuel as a result of the October 2011 PUCO remand order which required the POLR refund to be applied against deferred fuel balances.  The equity amortization was partially offset by amounts recognized in Carrying Costs Income as discussed below.
 
·
A $15 million increase in depreciation and amortization for TCC primarily due to increased amortization of TCC’s Securitized Transition Asset.  This increase is offset by an increase in revenues within Gross Margin.
 
·
Overall higher depreciable property balances.
 
These increases were partially offset by:
 
·
A $22 million decrease in depreciation and amortization for APCo primarily due to the expiration of E&R amortization of deferred carrying costs in Virginia.
·
Interest and Investment Income increased $15 million primarily due to interest income recorded in the third quarter of 2011 for favorable adjustments related to the 2001-2006 federal income tax audit.
·
Carrying Costs Income increased $272 million primarily due to the following:
 
·
A $261 million increase in carrying costs income due to the third quarter 2011 recognition of a regulatory asset related to TCC capacity auction true-up amounts that were originally written off in 2005.
 
·
A $10 million increase due to the recognition of equity carrying costs on deferred fuel as a result of the October 2011 PUCO remand order which required the POLR refund to be applied against any deferred fuel balances.  The equity carrying costs income was offset by amounts in Depreciation and Amortization discussed above.
·
Allowance for Equity Funds Used During Construction increased $9 million primarily due to construction of the Turk and Dresden Plants and various environmental upgrades, partially offset by a decrease due to the completion of the Stall Unit in June 2010.
 
 
15

 
·
Interest Expense decreased $28 million primarily due to lower outstanding debt balances.
·
Equity Earnings of Unconsolidated Subsidiaries increased $12 million primarily due to an increase in transmission investments by ETT.
·
Income Tax Expense increased $163 million primarily due to an increase in pretax book income, partially offset by the 2010 tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits.

AEP RIVER OPERATIONS

Third Quarter of 2011 Compared to Third Quarter of 2010

Net Income from our AEP River Operations segment increased from $14 million in 2010 to $17 million in 2011.  AEP River had increases in revenues related to higher coal exports and increased barge fleet size partially offset by increases in expenses related to higher fuel, maintenance and flood-related costs.

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Net Income from our AEP River Operations segment increased from $16 million in 2010 to $23 million in 2011 primarily due to higher grain shipping rates, increased coal exports, increased barge fleet size and the cost reduction initiatives recorded in the second quarter of 2010, partially offset by higher fuel, maintenance and flood-related costs.

GENERATION AND MARKETING

Third Quarter of 2011 Compared to Third Quarter of 2010

Net Income from our Generation and Marketing segment increased from $0 in 2010 to $8 million in 2011 primarily due to increased inception gains from ERCOT marketing activities and increased gross margins at the Oklaunion Plant.

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Net Income from our Generation and Marketing segment increased from $17 million in 2010 to $20 million in 2011 primarily due to increased inception gains from ERCOT marketing activities and increased income from our wind farm operations partially offset by lower gross margins at the Oklaunion Plant.

ALL OTHER

Third Quarter of 2011 Compared to Third Quarter of 2010

Net Income from All Other decreased from a gain of $2 million in 2010 to a loss of $10 million in 2011 primarily due to favorable federal income tax adjustments in the third quarter of 2010.

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Net Income from All Other decreased from a loss of $10 million in 2010 to a loss of $54 million in 2011 due to a $22 million net-of-tax loss incurred in the first quarter of 2011 related to the settlement of litigation with BOA and Enron and a $10 million net-of-tax gain on the sale of our remaining 138,000 shares of ICE in the second quarter of 2010.

 
16

 
AEP SYSTEM INCOME TAXES

Third Quarter of 2011 Compared to Third Quarter of 2010

Income Tax Expense increased $76 million primarily due to an increase in pretax book income.

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Income Tax Expense increased $256 million primarily due to an increase in pretax book income and the unrealized capital loss valuation allowance related to a deferred tax asset associated with the settlement of litigation with BOA and Enron, offset in part by the 2010 tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits.

FINANCIAL CONDITION

We measure our financial condition by the strength of our balance sheet and the liquidity provided by our cash flows.  Target debt to equity ratios are included in our credit arrangements as covenants that must be met for borrowing to continue.

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization

 
 
September 30, 2011
 
December 31, 2010
 
 
(dollars in millions)
Long-term Debt, including amounts due within one year
$
 16,450 
 
 50.7 
%
 
$
 16,811 
 
 52.8 
%
Short-term Debt
 
 1,279 
 
 3.9 
 
 
 
 1,346 
 
 4.2 
 
Total Debt
 
 17,729 
 
 54.6 
 
 
 
 18,157 
 
 57.0 
 
Preferred Stock of Subsidiaries
 
 60 
 
 0.2 
 
 
 
 60 
 
 0.2 
 
AEP Common Equity
 
 14,653 
 
 45.2 
 
 
 
 13,622 
 
 42.8 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Debt and Equity Capitalization
$
 32,442 
 
 100.0 
%
 
$
 31,839 
 
 100.0 
%

Our ratio of debt-to-total capital decreased from 57% at December 31, 2010 to 54.6% at September 30, 2011.  The decrease is due to increased equity, as a result of the third quarter 2011 recognition of a regulatory asset related to TCC capacity auction true-up amounts written off in 2005, and reduced debt.

In October 2011, we announced our intent to redeem all of the outstanding preferred stock of our subsidiaries in December 2011.

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, 2011, we had $3.25 billion in aggregate credit facility commitments to support our operations.  Additional liquidity is available from cash from operations and a receivables securitization 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.

 
17

 
Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments.  At September 30, 2011, our available liquidity was approximately $3.2 billion as illustrated in the table below:

 
 
 
Amount
 
 
Maturity
 
 
 
(in millions)
 
 
 
Commercial Paper Backup:
 
 
 
 
 
 
 
Revolving Credit Facility
 
$
 1,500 
 
 
June 2015
 
Revolving Credit Facility
 
 
 1,750 
 
 
July 2016
Total
 
 
 3,250 
 
 
 
Cash and Cash Equivalents
 
 
 546 
 
 
 
Total Liquidity Sources
 
 
 3,796 
 
 
 
Less:
AEP Commercial Paper Outstanding
 
 
 529 
 
 
 
 
Letters of Credit Issued
 
 
 103 
 
 
 
 
 
 
 
 
 
 
 
Net Available Liquidity
 
$
 3,164 
 
 
 
 
 
 
 
 
 
 
 

We have credit facilities totaling $3.25 billion to support our commercial paper program.  The credit facilities allow us to issue letters of credit in an amount up to $1.35 billion.  In July 2011, we replaced the $1.5 billion facility due in 2012 with a new $1.75 billion facility maturing in July 2016 and extended the $1.5 billion facility due in 2013 to expire in June 2015.

In March 2011, we terminated a $478 million credit facility, used for letters of credit to support variable rate debt, that was scheduled to mature in April 2011.  In March 2011, we issued bilateral letters of credit to support the remarketing of $357 million of the variable rate debt and reacquired the remaining $115 million which are held by a trustee on our behalf.

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.  The maximum amount of commercial paper outstanding during the first nine months of 2011 was $1.2 billion.  The weighted-average interest rate for our commercial paper during 2011 was 0.38%.

Securitized Accounts Receivables

In July 2011, we renewed our receivables securitization agreement.  The agreement provides a commitment of $750 million from bank conduits to purchase receivables with an increase to $800 million for the months of July, August and September to accommodate seasonal demand.  A commitment of $375 million with the seasonal increase to $425 million for the months of July, August and September expires in June 2012 and the remaining commitment of $375 million expires in June 2014.

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 capitalization is contractually defined in our revolving credit agreements.  Debt as defined in the revolving credit agreements excludes junior subordinated debentures, securitization bonds and debt of AEP Credit.  At September 30, 2011, this contractually-defined percentage was 50.3%.  Nonperformance under these covenants could result in an event of default under these credit agreements.  At September 30, 2011, 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.

 
18

 
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, 2011, we had not exceeded those authorized limits.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.47 per share in October 2011.  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.  AEP’s income derives from our common stock equity in the earnings of our utility subsidiaries.  Various charter provisions and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends.

We have the option to defer interest payments on the AEP Junior Subordinated Debentures 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 do not believe restrictions related to our various charter provisions and regulatory requirements will have any significant impact on Parent’s ability to access cash to meet the payment of dividends on its common stock.

Credit Ratings

We do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit downgrade, but our access to the commercial paper market may depend on our credit ratings.  In addition, downgrades in our credit ratings by one of the rating agencies could increase our borrowing costs.  Counterparty concerns about the credit quality of AEP or its utility subsidiaries could subject us to additional collateral demands under adequate assurance clauses under our derivative and non-derivative energy contracts.

CASH FLOW

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

 
 
 
Nine Months Ended
 
 
 
September 30,
 
 
 
2011 
 
2010 
 
 
 
(in millions)
Cash and Cash Equivalents at Beginning of Period
 
$
 294 
 
$
 490 
Net Cash Flows from Operating Activities
 
 
 3,338 
 
 
 1,702 
Net Cash Flows Used for Investing Activities
 
 
 (1,967)
 
 
 (1,575)
Net Cash Flows from (Used for) Financing Activities
 
 
 (1,119)
 
 
 473 
Net Increase in Cash and Cash Equivalents
 
 
 252 
 
 
 600 
Cash and Cash Equivalents at End of Period
 
$
 546 
 
$
 1,090 
 
 
19

 
Cash from operations and short-term borrowings provides working capital and allows us to meet other short-term cash needs.

Operating Activities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended
 
 
 
September 30,
 
 
 
2011 
 
2010 
 
 
 
(in millions)
Net Income
 
$
 1,638 
 
$
 1,040 
Depreciation and Amortization
 
 
 1,258 
 
 
 1,237 
Other
 
 
 442 
 
 
 (575)
Net Cash Flows from Operating Activities
 
$
 3,338 
 
$
 1,702 

Net Cash Flows from Operating Activities were $3.3 billion in 2011 consisting primarily of Net Income of $1.6 billion and $1.3 billion of noncash Depreciation and Amortization.  Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  Following a Supreme Court of Texas opinion, we recorded an Extraordinary Item, Net of Tax of $273 million for the third quarter 2011 recognition of a regulatory asset related to TCC capacity auction true-up amounts that were originally written off in 2005.  We also recorded $261 million in Carrying Costs Income related to the TCC extraordinary item.  A significant change in other items includes the favorable impact of a decrease in fuel inventory.  Deferred Income Taxes increased primarily due to provisions in the Small Business Jobs Act and the Tax Relief, Unemployment Insurance Reauthorization and Jobs Creation Act, the settlement with BOA and Enron and an increase in tax versus book temporary differences from operations.  In February 2011, we paid $425 million to BOA of which $211 million was used to settle litigation with BOA and Enron. The remaining $214 million was used to acquire cushion gas as discussed in Investing Activities below.  We also contributed $150 million to our qualified pension trust.

Net Cash Flows from Operating Activities were $1.7 billion in 2010 consisting primarily of Net Income of $1 billion and $1.2 billion of noncash Depreciation and Amortization.  Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  Other includes a $656 million increase in securitized receivables under the application of new accounting guidance for “Transfers and Servicing” related to our sale of receivables agreement.  Significant changes in other items include an increase in under-recovered fuel primarily due to the deferral of fuel under the FAC in Ohio and higher fuel costs in Oklahoma and the favorable impact of a decrease in fuel inventory.  Deferred Income Taxes increased primarily due to bonus depreciation provisions in the American Recovery and Reinvestment Act of 2009, a change in tax accounting method and an increase in tax versus book temporary differences from operations.  Due to these tax changes, Accrued Taxes, Net also increased primarily as a result of the receipt of a federal income tax refund of $419 million related to a net operating loss in 2009 that was carried back to 2007 and 2008.  We also contributed $463 million to our qualified pension trust in 2010.
 
 
Investing Activities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended
 
 
 
September 30,
 
 
 
2011 
 
2010 
 
 
 
(in millions)
Construction Expenditures
 
$
 (1,849)
 
$
 (1,629)
Acquisitions of Nuclear Fuel
 
 
 (104)
 
 
 (69)
Acquisition of Cushion Gas from BOA
 
 
 (214)
 
 
 - 
Proceeds from Sales of Assets
 
 
 116 
 
 
 160 
Other
 
 
 84 
 
 
 (37)
Net Cash Flows Used for Investing Activities
 
$
 (1,967)
 
$
 (1,575)

 
20

 
Net Cash Flows Used for Investing Activities were $2 billion in 2011 primarily due to Construction Expenditures for new generation, environmental, distribution and transmission investments.  We paid $214 million to BOA for cushion gas as part of a litigation settlement.

Net Cash Flows Used for Investing Activities were $1.6 billion in 2010 primarily due to Construction Expenditures for new generation, environmental, distribution and transmission investments.  Proceeds from Sales of Assets in 2010 include $139 million for sales of Texas transmission assets to ETT.

Financing Activities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended
 
 
 
September 30,
 
 
 
2011 
 
2010 
 
 
 
(in millions)
Issuance of Common Stock, Net
 
$
 70 
 
$
 65 
Issuance (Retirement) of Debt, Net
 
 
 (469)
 
 
 1,087 
Dividends Paid on Common Stock
 
 
 (668)
 
 
 (602)
Other
 
 
 (52)
 
 
 (77)
Net Cash Flows from (Used for) Financing Activities
 
$
 (1,119)
 
$
 473 

Net Cash Flows Used for Financing Activities in 2011 were $1.1 billion.  Our net debt retirements were $469 million. The net retirements included retirements of $683 million of senior unsecured and other debt notes, $678 million of pollution control bonds, $159 million of securitization bonds and a decrease in short-term borrowing of $67 million offset by issuances of $600 million of senior unsecured notes and $526 million of pollution control bonds.  We paid common stock dividends of $668 million.  See Note 11 – Financing Activities for a complete discussion of long-term debt issuances and retirements.

Net Cash Flows from Financing Activities were $473 million in 2010.  Our net debt issuances were $1.1 billion.  The net issuances included issuances of $884 million of notes and $326 million of pollution control bonds, a $594 million increase in commercial paper outstanding and retirements of $1 billion of senior unsecured notes, $148 million of securitization bonds and $222 million of pollution control bonds.  Our short-term debt securitized by receivables increased $656 million under the application of new accounting guidance for “Transfers and Servicing” related to our sale of receivables agreement.  We paid common stock dividends of $602 million.

In October 2011, APCo remarketed $100 million of 2% Pollution Control Bonds due in 2014.

In October 2011, I&M retired $29 million of Notes Payable related to DCC Fuel.

OFF-BALANCE SHEET ARRANGEMENTS

In prior periods, under a limited set of circumstances, we entered into off-balance sheet arrangements for various reasons including reducing operational expenses and spreading risk of loss to third parties.  Our current policy restricts the use of off-balance sheet financing entities or structures to traditional operating lease arrangements that we enter in the normal course of business.  The following identifies significant off-balance sheet arrangements:

 
 
 
September 30,
 
December 31,
 
 
 
2011 
 
2010 
 
 
 
(in millions)
Rockport Plant Unit 2 Future Minimum Lease Payments
 
$
 1,700 
 
$
 1,774 
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” in the 2010 Annual Report.

 
21

 
CONTRACTUAL OBLIGATION INFORMATION

A summary of our contractual obligations is included in our 2010 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” section above.

MINE SAFETY INFORMATION

The Federal Mine Safety and Health Act of 1977 (Mine Act) imposes stringent health and safety standards on various mining operations.  The Mine Act and its related regulations affect numerous aspects of mining operations, including training of mine personnel, mining procedures, equipment used in mine emergency procedures, mine plans and other matters.  SWEPCo, through its ownership of DHLC, CSPCo, through its ownership of Conesville Coal Preparation Company (CCPC), and OPCo, through its use of the Conner Run fly ash impoundment, are subject to the provisions of the Mine Act.

The Dodd-Frank Wall Street Reform and Consumer Protection Act requires companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act.  DHLC, CCPC and Conner Run received the following notices of violation and proposed assessments under the Mine Act for the quarter ended September 30, 2011:

 
 
 
DHLC
 
CCPC
 
Conner Run
Number of Citations for Violations of Mandatory Health or
 
 
 
 
 
 
 
 
 
 
Safety Standards under 104 *
 
 
 2 
 
 
 - 
 
 
 1 
Number of Orders Issued under 104(b) *
 
 
 - 
 
 
 - 
 
 
 - 
Number of Citations and Orders for Unwarrantable Failure
 
 
 
 
 
 
 
 
 
 
to Comply with Mandatory Health or Safety Standards under
 
 
 
 
 
 
 
 
 
 
104(d) *
 
 
 - 
 
 
 - 
 
 
 - 
Number of Flagrant Violations under 110(b)(2) *
 
 
 - 
 
 
 - 
 
 
 - 
Number of Imminent Danger Orders Issued under 107(a) *
 
 
 - 
 
 
 - 
 
 
 - 
Total Dollar Value of Proposed Assessments
 
$
Not assessed
 
$
 - 
 
$
Not assessed
Number of Mining-related Fatalities
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 
 
 
 
 
 
 
 
* References to sections under the Mine Act
 
 
 
 
 
 
 
 
 

DHLC currently has three legal actions pending before the Federal Mine Safety and Health Review Commission. Two are related to actions challenging four violations issued by Mine Safety and Health Administration following an employee fatality in March 2009 and the third legal action is challenging a citation issued in August 2010 related to a dragline boom issue.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

See the “Critical Accounting Policies and Estimates” section of “Management’s Financial Discussion and Analysis” in the 2010 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.

NEW ACCOUNTING PRONOUNCEMENTS

Pronouncements Effective in the Future

The FASB issued ASU 2011-05 “Presentation of Comprehensive Income” eliminating the option to present the components of other comprehensive income as a part of the statement of shareholders’ equity.  The standard requires other comprehensive income be presented as part of a single continuous statement of comprehensive income or in a statement of other comprehensive income immediately following the statement of net income.  This standard will change the presentation of our financial statements but will not affect the calculation of net income, comprehensive income or earnings per share.  The new accounting guidance is effective for interim and annual
 
 
22

 
periods beginning after December 15, 2011.  Early adoption is permitted.  The FASB is currently considering deferral of reclassification adjustment presentation provisions of ASU 2011-05.  Absent a deferral of this accounting guidance in its entirety, we expect to adopt ASU 2011-05 for the 2011 Annual Report.

Future Accounting Changes

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

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks

Our Utility Operations segment is exposed to certain market risks as a major power producer and through its transactions in wholesale electricity, coal and emission allowance trading and marketing contracts.  These risks include commodity price risk, interest rate risk and credit risk.  In addition, we are 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 and, to a lesser extent, Ohio in PJM and MISO, primarily transacts in wholesale energy 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 settle and expire in the fourth quarter of 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 power, coal and natural gas and, to a lesser degree, heating oil and gasoline, emission allowance and other commodity contracts to manage the risk associated with our energy business.  As a result, we are subject to price risk.  The amount of risk taken is determined by the commercial operations group in accordance with the market risk policy approved by the Finance Committee of our Board of Directors.  Our market risk oversight staff independently monitors our risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures.  The CORC consists of our President, 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.

 
23

 
The following table summarizes the reasons for changes in total mark-to-market (MTM) value as compared to December 31, 2010:

 
MTM Risk Management Contract Net Assets (Liabilities)
 
Nine Months Ended September 30, 2011
 
 
 
 
 
 
Generation
 
 
 
 
 
 
Utility
and
 
 
 
 
Operations
Marketing
All Other
Total
 
 
(in millions)
Total MTM Risk Management Contract Net Assets
 
 
 
 
 
 
 
 
 
 
 
 
at December 31, 2010
$
 91 
 
$
 140 
 
$
 2 
 
$
 233 
(Gain) Loss from Contracts Realized/Settled During the Period and
 
 
 
 
 
 
 
 
 
 
 
 
Entered in a Prior Period
 
 (23)
 
 
 (17)
 
 
 (2)
 
 
 (42)
Fair Value of New Contracts at Inception When Entered During the
 
 
 
 
 
 
 
 
 
 
 
 
Period (a)
 
 3 
 
 
 14 
 
 
 - 
 
 
 17 
Net Option Premiums Received for Unexercised or Unexpired
 
 
 
 
 
 
 
 
 
 
 
 
Option Contracts Entered During the Period
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Changes in Fair Value Due to Market Fluctuations During the
 
 
 
 
 
 
 
 
 
 
 
 
Period (b)
 
 5 
 
 
 4 
 
 
 - 
 
 
 9 
Changes in Fair Value Allocated to Regulated Jurisdictions (c)
 
 2 
 
 
 - 
 
 
 - 
 
 
 2 
Total MTM Risk Management Contract Net Assets
 
 
 
 
 
 
 
 
 
 
 
 
at September 30, 2011
$
 78 
 
$
 141 
 
$
 - 
 
 
 219 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Cash Flow Hedge Contracts
 
 
 
 
 
 
 
 
 
 
 19 
Interest Rate and Foreign Currency Cash Flow Hedge Contracts
 
 
 
 
 
 
 
 
 
 
 (34)
Fair Value Hedge Contracts
 
 
 
 
 
 
 
 
 
 
 - 
Collateral Deposits
 
 
 
 
 
 
 
 
 
 
 30 
Total MTM Derivative Contract Net Assets at September 30, 2011
 
 
 
 
 
 
 
 
 
$
 234 

(a)
Reflects fair value on primarily 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)
Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income.  These net gains (losses) are recorded as regulatory liabilities/assets.

See Note 8 – Derivatives and Hedging and Note 9 – Fair Value Measurements for additional information related to our risk management contracts.  The following tables and discussion provide information on our credit risk and market volatility risk.

Credit Risk

We limit credit risk in our wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis.  We use Moody’s Investors Service, Standard & Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.
 
 
24

 
We have risk management contracts with numerous counterparties.  Since open risk management contracts are valued based on changes in market prices of the related commodities, our exposures change daily.  As of September 30, 2011, our credit exposure net of collateral to sub investment grade counterparties was approximately 5.5%, 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, 2011, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:

 
 
 
Exposure
 
 
 
 
 
Number of
 
Net Exposure
 
 
Before
 
 
Counterparties
of
 
 
Credit
Credit
Net
>10% of
Counterparties
Counterparty Credit Quality
Collateral
Collateral
Exposure
Net Exposure
>10%
 
 
 
(in millions, except number of counterparties)
Investment Grade
 
$
 534 
 
$
 1 
 
$
 533 
 
 
 1 
 
$
 158 
Split Rating
 
 
 1 
 
 
 - 
 
 
 1 
 
 
 1 
 
 
 1 
Noninvestment Grade
 
 
 2 
 
 
 2 
 
 
 - 
 
 
 1 
 
 
 - 
No External Ratings:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Internal Investment Grade
 
 
 192 
 
 
 - 
 
 
 192 
 
 
 1 
 
 
 76 
 
Internal Noninvestment Grade
 
 
 52 
 
 
 10 
 
 
 42 
 
 
 1 
 
 
 36 
Total as of September 30, 2011
 
$
 781 
 
$
 13 
 
$
 768 
 
 
 5 
 
$
 271 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total as of December 31, 2010
 
$
 946 
 
$
 33 
 
$
 913 
 
 
 7 
 
$
 347 

Value at Risk (VaR) Associated with Risk Management Contracts

We use a risk measurement model, which calculates VaR, to measure our commodity price risk in the risk management portfolio.  The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period.  Based on this VaR analysis, as of September 30, 2011, a near term typical change in commodity prices is not expected to have a material effect on our net income, cash flows or financial condition.

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

VaR Model

Nine Months Ended
 
Twelve Months Ended
September 30, 2011
 
December 31, 2010
End
 
High
 
Average
 
Low
 
End
 
High
 
Average
 
Low
(in millions)
 
(in millions)
$
 
$
 
$
 
$
 
$
 
$
 
$
 
$

We back-test our VaR results against performance due to actual price movements.  Based on the assumed 95% confidence interval, the performance due to actual price movements would be expected to exceed the VaR at least once every 20 trading days.

As our VaR calculation captures recent price movements, we also perform regular stress testing of the portfolio to understand our exposure to extreme price movements.  We employ a historical-based method whereby the current portfolio is subjected to actual, observed price movements from the last four years in order to ascertain which historical price movements translated into the largest potential MTM loss.  We then research the underlying positions, price movements and market events that created the most significant exposure and report the findings to the Risk Executive Committee or the CORC as appropriate.
 
 
25

 
Interest Rate Risk

We utilize an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which our interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  As calculated on debt outstanding as of September 30, 2011 and December 31, 2010, the estimated EaR on our debt portfolio for the following twelve months was $23 million and $5 million, respectively.

 
26

 


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2011 and 2010
 (in millions, except per-share and share amounts)
(Unaudited)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Nine Months Ended
 
 
 
2011 
 
2010 
 
2011 
 
2010 
REVENUES
 
 
 
 
 
 
 
 
 
 
 
 
Utility Operations
 
$
 4,044 
 
$
 3,876 
 
$
 10,901 
 
$
 10,468 
Other Revenues
 
 
 289 
 
 
 188 
 
 
 771 
 
 
 525 
TOTAL REVENUES
 
 
 4,333 
 
 
 4,064 
 
 
 11,672 
 
 
 10,993 
EXPENSES
 
 
 
 
 
 
 
 
 
 
 
 
Fuel and Other Consumables Used for Electric Generation
 
 
 1,371 
 
 
 1,189 
 
 
 3,407 
 
 
 3,098 
Purchased Electricity for Resale
 
 
 294 
 
 
 247 
 
 
 856 
 
 
 712 
Other Operation
 
 
 747 
 
 
 707 
 
 
 2,130 
 
 
 2,374 
Maintenance
 
 
 283 
 
 
 262 
 
 
 864 
 
 
 776 
Asset Impairments and Other Related Charges
 
 
 90 
 
 
 - 
 
 
 90 
 
 
 - 
Depreciation and Amortization
 
 
 445 
 
 
 424 
 
 
 1,258 
 
 
 1,237 
Taxes Other Than Income Taxes
 
 
 213 
 
 
 210 
 
 
 628 
 
 
 619 
TOTAL EXPENSES
 
 
 3,443 
 
 
 3,039 
 
 
 9,233 
 
 
 8,816 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
OPERATING INCOME
 
 
 890 
 
 
 1,025 
 
 
 2,439 
 
 
 2,177 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Income (Expense):
 
 
 
 
 
 
 
 
 
 
 
 
Interest and Investment Income
 
 
 19 
 
 
 3 
 
 
 24 
 
 
 24 
Carrying Costs Income
 
 
 291 
 
 
 18 
 
 
 323 
 
 
 51 
Allowance for Equity Funds Used During Construction
 
 
 26 
 
 
 17 
 
 
 69 
 
 
 60 
Interest Expense