American Electric Power - 10-Q quarterly report FY

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

FORM 10-Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For The Quarterly Period Ended June 30, 2010

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

GLOSSARY OF TERMS

 

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

FORWARD-LOOKING INFORMATION

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

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

Economic Conditions

Retail margins increased during the first six months of 2010 due to successful rate proceedings in various jurisdictions and higher residential and commercial demand for electricity as a result of favorable weather throughout AEP’s service territory.  In comparison to the recessionary lows of 2009, industrial sales increased 9% in the second quarter and 4% during the first six months of 2010.

Due to the continued slow recovery in the U.S. economy and a corresponding negative impact on energy consumption, we implemented cost reduction initiatives in the second quarter of 2010 to reduce our workforce by 11.5% and reduce other operation and maintenance spending.  Achieving these goals involved identifying process improvements, streamlining organizational designs and developing other efficiencies that will deliver additional sustainable savings.  In the second quarter of 2010, we recorded $293 million of expense related to these cost reduction initiatives.

 

Regulatory Activity

Our significant 2010 rate proceedings include:

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW coal 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 cost $1.3 billion, excluding AFUDC, plus an additional $131 million for transmission, excluding AFUDC.  The APSC, LPSC and PUCT approved SWEPCo’s original application to build the Turk Plant.  Various proceedings are pending that challenge the Turk Plant’s construction and its approved air and wetlands permits.  In July 2010, the Arkansas Court of Appeals issued a decision remanding all transmission line CECPN appeals to the APSC.  As a result, a stay was not ordered and construction co ntinues on the affected transmission lines.  

 

In June 2010, the Arkansas Supreme Court denied motions for rehearing filed by the APSC and SWEPCo related to the reversal of the APSC’s earlier grant of a CECPN for SWEPCo’s 88 MW Arkansas portion of the Turk Plant.  As a result, in June 2010, SWEPCo filed notice with the APSC of its intent to proceed with construction of the Turk Plant but that SWEPCo no longer intends to pursue a CECPN to seek recovery of its Arkansas portion of Turk Plant Costs in Arkansas retail rates.

 

In July 2010, the Hempstead County Hunting Club filed a complaint with the Federal District Court for the Western District of Arkansas against SWEPCo, the U.S. Army Corps of Engineers, the U.S. Department of Interior and the U.S. Fish and Wildlife Service seeking an injunction to stop construction of the Turk Plant asserting claims of violations of federal and state laws.

 

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

SEGMENTS

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

Utility Operations

AEP River Operations

Generation and Marketing

The table below presents our consolidated Income Before Extraordinary Loss by segment for the three and six months ended June 30, 2010 and 2009.

AEP CONSOLIDATED

Second Quarter of 2010 Compared to Second Quarter of 2009

Income Before Extraordinary Loss in 2010 decreased $185 million compared to 2009 due to $185 million of charges incurred (net of tax) in the second quarter of 2010 related to the cost reduction initiatives.

Average basic shares outstanding increased to 479 million in 2010 from 472 million in 2009.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Income Before Extraordinary Loss in 2010 decreased $202 million compared to 2009 primarily due to $185 million of charges incurred (net of tax) in the second quarter of 2010 related to the cost reduction initiatives.

Average basic shares outstanding increased to 479 million in 2010 from 440 million in 2009 primarily due to the April 2009 issuance of 69 million shares of AEP common stock.  Actual shares outstanding were 479 million as of June 30, 2010.

UTILITY OPERATIONS

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

AEP RIVER OPERATIONS

Second Quarter of 2010 Compared to Second Quarter of 2009

Income Before Extraordinary Loss from our AEP River Operations segment decreased from income of $1 million in 2009 to a loss of $1 million in 2010 primarily due to expenses related to the cost reduction initiatives, increased interest expense on new long-term debt and increased lease expense on new barge leases.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Income Before Extraordinary Loss from our AEP River Operations segment decreased from $12 million in 2009 to $2 million in 2010 primarily due to reduced grain loadings, higher fuel and other operating expenses, expenses related to the cost reduction initiatives, interest expense on increased long-term debt, increased lease expense on new barge leases and a gain on the sale of two older towboats in 2009.

GENERATION AND MARKETING

Second Quarter of 2010 Compared to Second Quarter of 2009

Income Before Extraordinary Loss from our Generation and Marketing segment increased from $4 million in 2009 to $7 million in 2010 primarily due to favorable marketing contracts in ERCOT and increased income from our wind farm operations.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Income Before Extraordinary Loss from our Generation and Marketing segment decreased from $28 million in 2009 to $17 million in 2010 primarily due to reduced inception gains from ERCOT marketing activities partially offset by improved plant performance, hedging activities on our generation assets and increased income from our wind farm operations.

ALL OTHER

Second Quarter of 2010 Compared to Second Quarter of 2009

Income Before Extraordinary Loss from All Other increased from a loss of $10 million in 2009 to a loss of $1 million in 2010 primarily due to $16 million in pretax gains ($10 million, net of tax) on the sale of our remaining 138,000 shares of Intercontinental Exchange, Inc. (ICE) in the second quarter of 2010.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Income Before Extraordinary Loss from All Other increased from a loss of $28 million in 2009 to a loss of $12 million in 2010 due to $16 million in pretax gains ($10 million, net of tax) on the sale of our remaining 138,000 shares of ICE in the second quarter of 2010.

AEP SYSTEM INCOME TAXES

Second Quarter of 2010 Compared to Second Quarter of 2009

Income Tax Expense decreased $83 million in comparison to 2009 primarily due to a decrease in pretax book income.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Income Tax Expense decreased $55 million in comparison to 2009 primarily due to a decrease in pretax book income, partially offset by the regulatory accounting treatment of state income taxes, other book/tax differences which are accounted for on a flow-through basis and the tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits.

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

DEBT AND EQUITY CAPITALIZATION

Our ratio of debt-to-total capital increased from 57.2% in 2009 to 58.5% in 2010 primarily due to an increase in short-term debt of $677 million as a result of a change in an accounting standard applicable to our sale of receivables agreement and an increase of $668 million in commercial paper outstanding.

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 June 30, 2010, we had $3.4 billion in aggregate credit facility commitments to support our operations.  Additional liquidity is available from cash from operations and a sale of receivables agreement.  We are committed to maintaining adequate liquidity.  We generally use short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged.  Sources of long-term funding include issuance of long-term debt, sale-leaseback or leasing agreements or common stock.

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments.  At June 30, 2010, our available liquidity was approximately $2.9 billion as illustrated in the table below:

We have credit facilities totaling $3.4 billion, of which two $1.5 billion credit facilities support our commercial paper program.  One of the $1.5 billion credit facilities allows for the issuance of up to $750 million as letters of credit.  In June 2010, we canceled a facility that was scheduled to mature in March 2011.  We also entered a new $1.5 billion credit facility in June 2010, which matures in 2013, that allows for the issuance of up to $600 million as letters of credit.  In June 2010, we reduced the credit facility that matures in April 2011 from $627 million to $478 million which can be utilized for letters of credit or draws.

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 2010 was $802 million.  The weighted-average interest rate for our commercial paper during 2010 was 0.42%.

Securitized Accounts Receivables

In July 2010, we renewed our receivables securitization agreement.  The agreement provides a commitment of $750 million from bank conduits to purchase receivables.  A commitment of $375 million expires in July 2011 and the remaining commitment of $375 million expires in July 2013.

Our revolving credit agreements contain certain covenants and require us to maintain our percentage of debt to total capitalization at a level that does not exceed 67.5%.  The method for calculating our outstanding debt and other capital is contractually defined in our revolving credit agreements. At June 30, 2010, this contractually-defined percentage was 54.8%.  Nonperformance under these covenants could result in an event of default under these credit agreements.  At June 30, 2010, we complied with all of the covenants contained in these credit agreements.  In addition, the acceleration of our payment obligations, or the obligations of certain of our major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under these credit agreements and in a majority of our non-exchange traded commodity contracts which would permit the lenders and counterparties to declare the outstanding amounts payable.  However, a default under our non-exchange traded commodity contracts does not cause an event of default under our revolving credit agreements.

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

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

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.42 per share in July 2010.  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.  Our income derives from our common stock equity in the earnings of our utility subsidiaries.  Various financing arrangements, charter provisions and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends. 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 per iod in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, our common stock.  We believe that these restrictions will not have a material effect on our cash flows or financial condition or limit any dividend payments in the foreseeable future.

Credit Ratings

Our 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.

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

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

Net Cash Flows from Operating Activities were $582 million in 2010 consisting primarily of Net Income of $483 million and $813 million of noncash Depreciation and Amortization.  Other includes a $656 million increase in securitized receivables under the application of new accounting guidance for “Transfers and Servicing” related to our sale of receivables agreement.  Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  Significant changes in other items include an increase in under-recovered fuel primarily due to the deferral of fuel under the FAC in Ohio and higher fuel costs in Oklahoma, accrued tax benefits a nd the favorable impact of a decrease in fuel inventory.  Deferred Income Taxes increased primarily due to the American Recovery and Reinvestment Act of 2009 extending bonus depreciation provisions, a change in tax accounting method and an increase in tax versus book temporary differences from operations.

Net Cash Flows from Operating Activities were $857 million in 2009 consisting primarily of Net Income of $680 million and $779 million of noncash Depreciation and Amortization.  Other represents items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  Significant changes in other items include the negative impact on cash of an increase in coal inventory reflecting decreased customer demand for electricity as the result of the economic slowdown and an increase in under-recovered fuel primarily due to the deferral of fuel costs in Ohio as a fuel clause was reactivated in 2009.

Net Cash Flows Used for Investing Activities were $992 million in 2010 primarily due to Construction Expenditures for new generation, environmental and distribution investments.  Proceeds from Sales of Assets in 2010 include $135 million for sales of Texas transmission assets to ETT.

Net Cash Flows Used for Investing Activities were $1.5 billion in 2009 primarily due to Construction Expenditures for our new generation, environmental and distribution investments.  Proceeds from Sales of Assets in 2009 include $104 million relating to the sale of a portion of Turk Plant to joint owners and $92 million for sales of transmission assets in Texas to ETT.

Net Cash Flows from Financing Activities in 2009 were $568 million.  Issuance of Common Stock, Net of $1.7 billion is comprised of our issuance of 69 million shares of common stock with net proceeds of $1.64 billion and additional shares through our dividend reinvestment, employee savings and incentive programs.  Our net debt retirements were $711 million. These retirements included a repayment of $1.75 billion outstanding under our credit facilities primarily from the proceeds of our common stock issuance and issuances of $955 million of senior unsecured notes and $135 million of pollution control bonds.

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

Effective January 1, 2010, we record the receivables and debt related to AEP Credit on our Condensed Consolidated Balance Sheet.  For complete information on each of these off-balance sheet arrangements see the “Off-balance Sheet Arrangements” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2009 Annual Report.

We continue to be involved in various matters described in the “Significant Factors” section of “Management’s Financial Discussion and Analysis of Results of Operations” in our 2009 Annual Report.  The 2009 Annual Report should be read in conjunction with this report in order to understand significant factors which have not materially changed in status since the issuance of our 2009 Annual Report, but may have a material impact on our future net income, cash flows and financial condition.

REGULATORY ISSUES

Ohio Electric Security Plan Filings

During 2009, the PUCO issued an order that modified and approved CSPCo’s and OPCo’s ESPs which established rates through 2011.  The order also limits rate increases for CSPCo to 7% in 2009, 6% in 2010 and 6% in 2011 and for OPCo to 8% in 2009, 7% in 2010 and 8% in 2011.  The order provides a FAC for the three-year period of the ESP.  Several notices of appeal are outstanding at the Supreme Court of Ohio relating to significant issues in the determination of the approved ESP rates.  CSPCo and OPCo will file their significantly excessive earnings test with the PUCO by their September 2010 deadline.  CSPCo and OPCo are unable to determine whether they will be required to return any of their ESP revenues to customers.  See “Ohio Electric Security Plan FilingsR 21; section of Note 3.

Cook Plant Unit 1 Fire and Shutdown

In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in a fire on the electric generator. Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $395 million.  Management believes that I&M should recover a significant portion of repair and replacement costs through the turbine vendor’s warranty, insurance and the regulatory process.  I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power.  The Unit 1 rotors were repaired and reinstalled due to the extensive lead time required to manufacture and install new turbine rotors.  As a result, the replacement of the repaired turbine rotors and other equipment is sched uled for the Unit 1 planned outage in the fall of 2011.  If the ultimate costs of the incident are not covered by warranty, insurance or through the related regulatory process or if any future regulatory proceedings are adverse, it could have an adverse impact on net income, cash flows and financial condition.  See “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.

Texas Restructuring Appeals

Pursuant to PUCT restructuring orders, TCC securitized net recoverable stranded generation costs of $2.5 billion and is recovering the principal and interest on the securitization bonds through the end of 2020.  TCC also refunded other net true-up regulatory liabilities of $375 million during the period October 2006 through June 2008 via a CTC credit rate rider under PUCT restructuring orders.  TCC and intervenors appealed the PUCT’s true-up related orders.  After rulings from the Texas District Court and the Texas Court of Appeals, TCC, the PUCT and intervenors filed petitions for review with the Texas Supreme Court.  Review is discretionary and the Texas Supreme Court has not yet determined if it will grant review.  See “Texas R estructuring Appeals” section of Note 3.

Mountaineer Carbon Capture and Storage Project

APCo and ALSTOM Power, Inc. (Alstom), an unrelated third party, jointly constructed a CO2 capture validation facility, which was placed into service in September 2009.  APCo also constructed and owns the necessary facilities to store the CO2.  In APCo’s July 2009 Virginia base rate filing and APCo’s May 2010 West Virginia base rate filing, APCo requested recovery of and a return on its estimated increased Virginia and West Virginia jurisdictional share of its project costs and recovery of the related asset retirement obligation regulatory asset amortization and accretion.  In July 2010, the Virginia SCC issued a base rate order that denied recovery of the Virginia share of the Mountaineer Carbon Capture and Storage Project costs, which resulted in a pretax write-off of approximately $54 million in the second quarter of 2010.  In response to the order, APCo filed with the Virginia SCC a petition for

reconsideration of the order as it relates to the Mountaineer Carbon Capture and Storage Project.  Through June 30, 2010, APCo has recorded a noncurrent regulatory asset of $58 million consisting of $38 million in project costs and $20 million in asset retirement costs.  If APCo cannot recover its remaining investments in and expenses related to the Mountaineer Carbon Capture and Storage project, it would reduce future net income and cash flows and impact financial condition.  See “Mountaineer Carbon Capture and Storage Project” section of Note 3.

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which is expected to be in-service in 2012.  SWEPCo owns 73% of the Turk Plant and will operate the completed facility.  The Turk Plant is currently estimated to cost $1.7 billion, excluding AFUDC, plus an additional $131 million for transmission, excluding AFUDC.  SWEPCo’s share is currently estimated to cost $1.3 billion, excluding AFUDC, plus an additional $131 million for transmission, excluding AFUDC.  Notices of appeal are outstanding at the Arkansas Court of Appeals and the Circuit Court of Hempstead County, Arkansas.  Matters are also outstanding at the LPSC, the Texas Court of Appeals and the Federal District Court for the Western Distri ct of Arkansas.  See “Turk Plant” section of Note 3.

LITIGATION

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual resolution will be or the timing and amount of any loss, fine or penalty may be.  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 of Results of Operations” in the 2009 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.

ENVIRONMENTAL ISSUES

We are implementing a substantial capital investment program and incurring additional operational costs to comply with new environmental control requirements.  We anticipate making additional investments and operational changes.  The most significant sources are the existing and anticipated CAA requirements to reduce emissions of SO2, NOx, PM and hazardous air pollutants from fossil fuel-fired power plants and new proposals governing the beneficial use and disposal of coal combustion products.

 

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 to reduce CO2 emissions to address concerns about global climate change.  See a complete discussion of these matters in the “Environmental Matters” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2009 Annual Report.

Clean Air Act Transport Rule (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 Transport Rule is assigned an allowance budget for SO2 and/or NOx.  Limited interstate trading is allowed on a sub-regional basis and intrastate trading is allowed among generating units.  Certain of our western st ates (Texas, Arkansas and Oklahoma) would be subject to only the seasonal NOx program, with new limits that are proposed to take effect in 2012.  The remainder of the states in which we operate would be subject to seasonal and annual NOx programs and an annual SO2 emissions reduction program that takes effect in two phases.  The first phase becomes effective in 2012 and requires approximately 1 million tons per year more SO2 emission reductions across the region than would have been required under CAIR.  The second phase takes effect in 2014 and reduces emissions by an additional 800,000 tons per year.  The SO2 font> 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 the CAIR rule.  The time frames for and

stringency of the additional 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, as these features could accelerate unit retirements, increase capital requirements, constrain operations and decrease reliability.  Comments on the proposed rule will be due within 60 days after publication in the Federal Register.

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 that would impose federal hazardous waste disposal and management standards on these materials and one that 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 initia te closure within five years of the issuance of a final rule.

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 are currently studying the potential costs associated with this proposal and expect that it will impose significant costs.  We will seek recovery of ex penditures for pollution control technologies and associated costs from customers through our regulated rates (in regulated jurisdictions).  We should be able to recover these expenditures through market prices in deregulated jurisdictions.  If not, these costs could adversely affect future net income, cash flows and possibly financial condition.

Global Warming

While comprehensive economy-wide regulation of CO2 emissions might be achieved 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 u nder the CAA beginning in January 2011 at the earliest 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.  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.

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 Ohio, Michigan, 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 2009 Form 10-K under the headings entitled “Business – General – Environmental and Other Matters – Global Warming” and “Management’s Financial Discussion and Analysis of Results of Operations.”

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

See the “Critical Accounting Policies and Estimates” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2009 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

New Accounting Pronouncements Adopted During 2010

We adopted ASU 2009-16 “Transfers and Servicing” effective January 1, 2010.  The adoption of this standard resulted in AEP Credit’s transfers of receivables being accounted for as financings with the receivables and short-term debt recorded on our balance sheet.

We adopted the prospective provisions of ASU 2009-17 “Consolidations” effective January 1, 2010.  We no longer consolidate DHLC effective with the adoption of this standard.

See Note 2 for further discussion of accounting pronouncements.

Future Accounting Changes

Market Risks

Our Utility Operations segment is exposed to certain market risks as a major power producer and marketer of wholesale electricity, coal and emission allowances.  These risks include commodity price risk, interest rate risk and credit risk.  In addition, we 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, transacts in wholesale energy trading and marketing contracts.  This segment is exposed to certain market risks as a marketer of wholesale electricity.  These risks include commodity price risk, interest rate risk and credit risk.  These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates.

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

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

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.

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 to assess the financial health of counterparties on an ongoing basis.  If an external rating is not available, an internal rating is generated utilizing a quantitative tool developed by Moody’s to estimate probability of default that corresponds to an implied external agency credit rating.

We have risk management contracts with numerous counterparties.  Since open risk management contracts are valued based on changes in market prices of the related commodities, our exposures change daily.  As of June 30, 2010, our credit exposure net of collateral to sub investment grade counterparties was approximately 8.0%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss).  As of June 30, 2010, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:

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 June 30, 2010, a near term typical change in commodity prices is not expected to have a material effect on our net income, cash flows or financial condition.

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

VaR Model

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 moves and market events that created the most significant exposure and report the findings to the Risk Executive Committee or the CORC as appropriate.

Interest Rate Risk

We utilize an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which AEP’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  As calculated on debt outstanding as of June 30, 2010 and December 31, 2009, the estimated EaR on our debt portfolio for the following twelve months was $3 million and $4 milli on, respectively.