American Electric Power - 10-Q quarterly report FY

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.

 

INDEX TO QUARTERLY REPORTS ON FORM 10-Q

June 30, 2008

 

Base Rate Filings

Our significant base rate filings include:

Ohio Electric Security Plan Filings

In April 2008, the Ohio legislature passed Senate Bill 221, which amends the restructuring law effective July 31, 2008 and requires electric utilities to adjust their rates by filing an Electric Security Plan (ESP).  In July 2008, within the parameters of the ESPs, CSPCo and OPCo each requested an annual rate increase for 2009 through 2011 that would not exceed approximately 15% per year.  A significant portion of the requested increases results from the implementation of a fuel cost recovery mechanism.

Turk Plant

In July 2008, the PUCT approved a certificate of convenience and necessity for construction of the plant.  We expect a written order in August 2008 which will also provide for the conditions of the PUCT’s approval.  SWEPCo has received approvals from all of the state commissions that regulate its retail rates and services.  However, the APSC approval has been appealed to the Arkansas State Court of Appeals.  SWEPCo is working with the Arkansas Department of Environmental Quality and the U.S. Army Corps of Engineers for approval later this year.  Through June 30, 2008, SWEPCo capitalized $407 million in expenditures related to the Turk Plant.

IGCC Plants

We have delayed construction of the West Virginia and Ohio IGCC plants.  In May 2008, the Virginia SCC denied APCo’s request to reconsider the Virginia SCC's previous denial of APCo’s request to recover initial costs associated with a proposed IGCC plant in West Virginia.  In July 2008, the WVPSC issued a notice seeking comments from parties on how the WVPSC should proceed regarding its earlier approval of the IGCC plant.  In Ohio, CSPCo and OPCo await the result of an Ohio Supreme Court remand to the PUCO regarding recovery of IGCC pre-construction costs.

 

Fuel Costs

We currently estimate 2008 coal prices to increase by about 20% due to escalating domestic prices and increased needs, primarily in the east.  We had expected coal costs to increase by 13% in 2008.    We continue to see increases in prices due to expiring lower priced coal and transportation contracts being replaced with higher priced contracts.  Prices for fuel oil are at record highs and remain volatile.  We have limited exposure to price risk related to our open positions for coal, natural gas and fuel oil especially since we do not currently have an active fuel cost recovery adjustment mechanism in Ohio, which represents approximately 20% of our fuel costs.  However, under Ohio’s amended restructuring law, we have requested the PUCO to reinstate a fuel cost recovery mechanism effective January 1, 2009.  Fuel cost adjustment rate clauses in our other jurisdictions will help offset future negative impacts of fuel price increases on our gross margins.

Capital Expenditures

We reduced our projections for capital expenditures to approximately $6.75 billion from $7.35 billion for 2009 through 2010.

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

The table below presents our consolidated Income Before Discontinued Operations and Extraordinary Loss by segment for the three and six months ended June 30, 2008 and 2007.

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

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

Reconciliation of Second Quarter of 2007 to Second Quarter of 2008

Income from Utility Operations Before Discontinued Operations and Extraordinary Loss

(in millions)

Income from Utility Operations Before Discontinued Operations and Extraordinary Loss increased $25 million to $263 million in 2008.  The key drivers of the increase were a $94 million increase in Gross Margin offset by a $60 million increase in Operating Expenses and Other and a $9 million increase in Income Tax Expense.

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

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

Reconciliation of Six Months Ended June 30, 2007 to Six Months Ended June 30, 2008

Income from Utility Operations Before Discontinued Operations and Extraordinary Loss

(in millions)

Income from Utility Operations Before Discontinued Operations and Extraordinary Loss increased $182 million to $673 million in 2008.  The key drivers of the increase were a $261 million increase in Gross Margin and an $11 million decrease in Operating Expenses and Other offset by a $90 million increase in Income Tax Expense.

 

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

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

 

Income Before Discontinued Operations and Extraordinary Loss from our MEMCO Operations segment decreased to $3 million in 2008 from $7 million in 2007 primarily due to high water conditions and reduced northbound loadings.  Fuel consumption and other operating costs were higher due to the sustained high water conditions on all major rivers on which we operate.  Northbound loadings continue to be depressed as a result of reduced imports through the Gulf of Mexico.

Income Before Discontinued Operations and Extraordinary Loss from our MEMCO Operations segment decreased to $10 million in 2008 from $22 million in 2007 primarily due to high water conditions and reduced northbound loadings.  Fuel consumption and other operating costs were higher due to the sustained high water conditions on all major rivers on which we operate.  Northbound loadings continue to be depressed as a result of reduced imports through the Gulf of Mexico.

Income Before Discontinued Operations and Extraordinary Loss from our Generation and Marketing segment increased to $26 million in 2008 from $15 million in 2007 primarily due to favorable marketing contracts in ERCOT, higher gross margins at the Oklaunion plant from optimization activities and an increase in income from wind farm operations.

Income Before Discontinued Operations and Extraordinary Loss from our Generation and Marketing segment increased to $27 million in 2008 from $14 million in 2007 primarily due to favorable marketing contracts in ERCOT, higher gross margins at the Oklaunion plant from optimization activities  and an increase in income from wind farm operations.

Loss Before Discontinued Operations and Extraordinary Loss from All Other increased to $12 million in 2008 from $3 million in 2007.  The increase in the loss primarily relates to lower cash balances yielding lower interest income and higher interest expense due to the AEP Junior Subordinated Debentures issued in March 2008 and increased short-term borrowings.

Income Before Discontinued Operations and Extraordinary Loss from All Other increased to $143 million in 2008 from $1 million in 2007.  In 2008, we had after-tax income of $163 million from a litigation settlement of a power purchase and sale agreement with TEM related to the Plaquemine Cogeneration Facility which was sold in the fourth quarter of 2006.  The settlement was recorded as a pretax credit to Asset Impairments and Other Related Items of $255 million in the accompanying Condensed Consolidated Statements of Income.  In 2007, we had a $16 million pretax gain ($10 million, net of tax) on the sale of a portion of our investment in Intercontinental Exchange, Inc. (ICE).

 

Income Tax Expense increased $15 million in the second quarter of 2008 compared to the second quarter of 2007 primarily due to an increase in pretax income.

Income Tax Expense increased $178 million in the six-month period ended June 30, 2008 compared to the six-month period ended June 30, 2007 primarily due to an increase in pretax income.

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

Our ratio of debt to total capital decreased from 60.7% to 60.6% in 2008 due to our net earnings and increased common equity from stock issuances through stock compensation and dividend reinvestment plans.

Liquidity, or access to cash, is an important factor in determining our financial stability.  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 and common stock.

Credit Markets

We believe we have adequate liquidity under our credit facilities and the ability to issue long-term debt in the current credit markets.  As of June 30, 2008, we had $313 million outstanding of tax-exempt long-term debt sold at auction rates that reset every 35 days.  This debt is insured by bond insurers previously AAA-rated, namely Ambac Assurance Corporation and Financial Guaranty Insurance Co.  Due to the exposure that these bond insurers have in connection with developments in the subprime credit market, the credit ratings of these insurers have been downgraded or placed on negative outlook.  These market factors have contributed to higher interest rates in successful auctions and increasing occurrences of failed auctions, including many of the auctions of our tax-exempt long-term debt.  The instruments under which the bonds are issued allow us to convert to other short-term variable-rate structures, term-put structures and fixed-rate structures.  Through June 30, 2008, we reduced our outstanding auction rate securities by $1.2 billion.  We plan to continue the conversion and refunding process for the remaining $313 million to other permitted modes, including term-put structures, variable-rate and fixed-rate structures, during the second half of 2008 to lower our interest rates as such opportunities arise.

As of June 30, 2008, $367 million of the prior auction rate debt was issued in a weekly variable rate mode supported by letters of credit at variable rates ranging from 1.45% to 1.68% and $384 million was issued at fixed rates ranging from 4.85% to 5.625%.  As of June 30, 2008, trustees held, on our behalf, approximately $400 million of our reacquired auction rate tax-exempt long-term debt which we plan to reissue to the public as market conditions permit.

 

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments.  At June 30, 2008, our available liquidity was approximately $3.1 billion as illustrated in the table below:

 

The revolving credit facilities for commercial paper backup are structured as two $1.5 billion credit facilities.  In March 2008, the credit facilities were amended so that $750 million may be issued under each credit facility as letters of credit.

We use our corporate borrowing program to meet the short-term borrowing needs of our subsidiaries.  The corporate borrowing program includes a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility subsidiaries.  In addition, we also fund, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons.  As of June 30, 2008, we had credit facilities totaling $3 billion to support our commercial paper program.  The maximum amount of commercial paper outstanding during the first six months of 2008 was $1.2 billion.  The weighted-average interest rate of our commercial paper during the first six months of 2008 was 3.22%.

In April 2008, we entered into a $650 million 3-year credit agreement and a $350 million 364-day credit agreement.  Under the facilities, we may issue letters of credit.  As of June 30, 2008, $371 million of letters of credit were issued under the 3-year credit agreement to support variable rate demand notes.

Investments in Auction-Rate Securities

During the first six months of 2008, we sold all of our investment in auction-rate securities at par.

Debt Covenants and Borrowing Limitations

Our revolving credit agreements, including the new agreements entered into in April 2008, contain certain covenants and require us to maintain our percentage of debt to total capitalization at a level that does not exceed 67.5%.  The method for calculating our outstanding debt and other capital is contractually defined. At June 30, 2008, this contractually-defined percentage was 55.9%.  Nonperformance of these covenants could result in an event of default under these credit agreements.  At June 30, 2008, we complied with all of the covenants contained in these credit agreements.  In addition, the acceleration of our payment obligations, or the obligations of certain of our major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under these credit agreements and permit the lenders to declare the outstanding amounts payable.

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders.  At June 30, 2008, we had not exceeded those authorized limits.

Dividend Policy and Restrictions

We have declared common stock dividends payable in cash in each quarter since July 1910.  The Board of Directors declared a quarterly dividend of $0.41 per share in July 2008.  Future dividends may vary depending upon our profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time.  We have the option to defer interest payments on the $315 million of AEP Junior Subordinated Debentures issued in March 2008 for one or more periods of up to 10 consecutive years per period.  During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, our common stock.  We believe that these restrictions will not have a material effect on our results of operations, cash flows, financial condition or limit any dividend payments in the foreseeable future.

Credit Ratings

In the first quarter of 2008, Moody’s changed its outlook from stable to negative for APCo, SWEPCo, OPCo and TCC and affirmed its stable outlook for AEP and our other subsidiaries.  Also in the first quarter, Fitch downgraded PSO and SWEPCo from A- to BBB+ for senior unsecured debt.  In May 2008, Fitch revised APCo’s outlook from stable to negative.  Our current credit ratings are as follows:

If we or any of our rated subsidiaries receive an upgrade from any of the rating agencies listed above, our borrowing costs could decrease.  If we receive a downgrade in our credit ratings by one of the rating agencies listed above, our borrowing costs could increase and access to borrowed funds could be negatively affected.

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

 

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

Operating Activities

Net Cash Flows from Operating Activities increased in 2008 primarily due to the TEM settlement.

Net Cash Flows from Operating Activities were $1.2 billion in 2008 consisting primarily of Income Before Discontinued Operations of $853 million and $736 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 an increase in under-recovered fuel reflecting higher natural gas prices.

Net Cash Flows from Operating Activities were $1 billion in 2007 consisting primarily of Income Before Discontinued Operations of $449 million and $763 million of noncash depreciation and amortization.  Other represents items that had a prior 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 resulted in lower cash from operations due to a number of items, the most significant of which relates primarily to the Texas CTC refund of fuel over-recovery.

Investing Activities

 

Net Cash Flows Used for Investing Activities were $1.6 billion in 2008 primarily due to Construction Expenditures for our environmental, distribution and new generation investment plan.  Construction expenditures decreased compared to 2007 due to a decline in environmental, fossil, hydro and nuclear projects partially offset by increased expenditures for new generation and transmission projects.

Net Cash Flows Used for Investing Activities were $2.1 billion in 2007 primarily due to Construction Expenditures for our environmental, distribution and new generation investment plan.  We paid $427 million to purchase gas-fired generating units to acquire capacity at a cost below that of building a new, comparable plant.

In our normal course of business, we purchase and sell investment securities with cash available for short-term investments.  We also purchase and sell investment securities within our nuclear trusts.  The net amount of these activities is included in Other.

We forecast approximately $2.2 billion of construction expenditures for the remainder of 2008.  Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather, legal reviews and the ability to access capital.  These construction expenditures will be funded through results of operations and financing activities.

Financing Activities

 

Net Cash Flows from Financing Activities in 2008 were $488 million primarily due to the issuance of additional debt including $315 million of junior subordinated debentures and a net increase of $1 billion in outstanding senior unsecured notes partially offset by the reacquisition of a net $440 million of pollution control bonds and retirements of $53 million of mortgage notes and $75 million of securitization bonds.  See Note 9 – Financing Activities for a complete discussion of long-term debt issuances and retirements.

Net Cash Flows from Financing Activities in 2007 were $1 billion primarily due to issuing $1.1 billion of debt securities including $1 billion of new debt for plant acquisitions and construction and increasing short-term commercial paper borrowings.  We paid common stock dividends of $311 million.

Our capital investment plans for 2008 will require additional funding from the capital markets.

Under a limited set of circumstances, we enter into off-balance sheet arrangements to accelerate cash collections, reduce operational expenses and spread risk of loss to third parties.  Our current guidelines restrict the use of off-balance sheet financing entities or structures to traditional operating lease arrangements and sales of customer accounts receivable that we enter in the normal course of business.  Our significant off-balance sheet arrangements  are as follows:

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 2007 Annual Report.

A summary of our contractual obligations is included in our 2007 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in “Cash Flow” above and standby letters of credit discussed in “Liquidity” above.

 

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 2007 Annual Report.  The 2007 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 2007 Annual Report, but may have a material impact on our future results of operations, cash flows and financial condition.

In April 2008, the Ohio legislature passed Senate Bill 221, which amends the restructuring law effective July 31, 2008 and requires electric utilities to adjust their rates by filing an Electric Security Plan (ESP).  Electric utilities may file an ESP with a fuel cost recovery mechanism.  Electric utilities also have an option to file a Market Rate Offer (MRO) for generation pricing.  A MRO, from the date of its commencement, could transition CSPCo and OPCo to full market rates no sooner than six years and no later than ten years.  The PUCO has the authority to approve or modify the utilities’ ESP request.  The PUCO is required to approve an ESP if, in the aggregate, the ESP is more favorable to ratepayers than the MRO.  Both alternatives involve a “substantially excessive earnings” test based on what public companies, including other utilities with similar risk profiles, earn on equity.  Management has preliminarily concluded, pending the issuance of final rules by the PUCO and the outcome of the ESP proceeding, that CSPCo’s and OPCo’s generation/supply operations are not subject to cost-based rate regulation accounting.  However, if a fuel cost recovery mechanism is implemented within the ESP, CSPCo’s and OPCo’s fuel operations would be subject to cost-based rate regulation accounting.  Management is unable to predict the financial statement impact of the restructuring legislation until the PUCO acts on specific proposals made by CSPCo and OPCo in their ESPs.

In July 2008, within the parameters of the ESPs, CSPCo and OPCo filed with the PUCO to establish rates for 2009 through 2011.  CSPCo and OPCo did not file MROs.  CSPCo and OPCo each requested an annual rate increase for 2009 through 2011 that would not exceed approximately 15% per year.  A significant portion of the requested increases results from the implementation of a fuel cost recovery mechanism that primarily includes fuel costs, purchased power costs including mandated renewable energy, consumables such as urea, other variable production costs and gains and losses on sales of emission allowances.  The increases in customer bills related to the fuel cost recovery mechanism would be phased-in over the three year period from 2009 through 2011.  Effective January 1, 2009, CSPCo and OPCo will defer the fuel cost under-recoveries and related carrying costs for future recovery over seven years from 2012 through 2018.  In addition to the fuel cost recovery mechanisms, the requested increases would also recover incremental carrying costs associated with environmental costs, Provider of Last Resort (POLR) charges to compensate for the risk of customers changing electric suppliers, automatic increases for unexpected costs and reliability costs. The filings also include programs for smart metering initiatives and economic development and mandated energy efficiency and peak demand reduction programs.  Management expects a PUCO decision on the ESP filings in the fourth quarter of 2008.

Within the ESPs, CSPCo and OPCo would also recover existing regulatory assets of $45 million and $36 million, respectively, for customer choice implementation and line extension carrying costs.  In addition, CSPCo and OPCo would recover related unrecorded equity carrying costs of $28 million and $19 million, respectively.   Such costs would be recovered over an 8 year period beginning January 2011.  Failure of the PUCO to ultimately approve the recovery of the regulatory assets would have an adverse effect on future results of operations and cash flows.

Pursuant to PUCT orders, TCC securitized its net recoverable stranded generation costs of $2.5 billion and is recovering such costs over a period ending in 2020.  TCC has refunded its net other true-up items of $375 million during the period October 2006 through June 2008 via a CTC credit rate rider.  Cash paid for CTC refunds for the six months ended June 30, 2008 and 2007 was $68 million and $170 million, respectively. TCC appealed the PUCT stranded costs true-up and related orders seeking relief in both state and federal court on the grounds that certain aspects of the orders are contrary to the Texas Restructuring Legislation, PUCT rulemakings and federal law and fail to fully compensate TCC for its net stranded cost and other true-up items.  Municipal customers and other intervenors also appealed the PUCT true-up and related orders seeking to further reduce TCC’s true-up recoveries. In March 2007, the Texas District Court judge hearing the appeal of the true-up order affirmed the PUCT’s April 2006 final true-up order for TCC with two significant exceptions.  The judge determined that the PUCT erred by applying an invalid rule to determine the carrying cost rate for the true-up of stranded costs and remanded this matter to the PUCT for further consideration.  The District Court judge also determined that the PUCT improperly reduced TCC’s net stranded plant costs for commercial unreasonableness.

TCC, the PUCT and intervenors appealed the District Court decision to the Texas Court of Appeals.  In May 2008, the Texas Court of Appeals affirmed the District Court decision in all but one major respect.  It reversed the District Court’s decision finding that the PUCT erred by applying an invalid rule to determine the carrying cost rate.  The Texas Court of Appeals denied intervenors’ motion for rehearing.  Management expects intervenors to appeal the decision to the Texas Supreme Court.  If upheld on appeal, this ruling could have a favorable effect on TCC’s results of operations and cash flows.

Management cannot predict the outcome of these court proceedings and PUCT remand decisions.  If TCC ultimately succeeds in its appeals, it could have a favorable effect on future results of operations, cash flows and financial condition.  If municipal customers and other intervenors succeed in their appeals it could have a substantial adverse effect on future results of operations, cash flows and financial condition.

FERC allows utilities to sell wholesale power at market-based rates if they can demonstrate that they lack market power in the markets in which they participate.  Sellers with market rate authority must, at least every three years, update their studies demonstrating lack of market power.  In December 2007, AEP filed its most recent triennial update.  In March and May 2008, the PUCO filed comments suggesting that FERC should further investigate whether AEP continues to pass FERC’s indicative screens for the lack of market power in PJM.  Certain industrial retail customers also urged FERC to further investigate this matter.  AEP responded that its market power studies were performed in accordance with FERC’s guidelines, and continue to demonstrate lack of market power. Management is unable to predict the outcome of this proceeding; however, if a further investigation by the FERC limits AEP’s ability to sell power at market based rates in PJM, it would result in an adverse effect on future off-system sales margins, results of operations and cash flows.

In 2008, AEP completed or is in various stages of construction of the following generation facilities:

Turk Plant

In November 2007, the APSC granted approval to build the Turk Plant.  Certain landowners filed a notice of appeal to the Arkansas State Court of Appeals.  In March 2008, the LPSC approved the application to construct the Turk Plant.  In July 2008, the PUCT approved a certificate of convenience and necessity for construction of the plant.  We expect a written order in August 2008 which will also provide for the conditions of the PUCT’s approval.

SWEPCo is working with the Arkansas Department of Environmental Quality and the U.S. Army Corps of Engineers for approval later this year.  A request to stop pre-construction activities at the site was filed in Federal court by the same Arkansas landowners who appealed the APSC decision to the Arkansas State Court of Appeals.  In July 2008, the Federal court denied the request and the Arkansas landowners appealed the denial to the U.S. Court of Appeals.

If SWEPCo does not receive appropriate authorizations and permits to build the Turk Plant, SWEPCo could incur significant cancellation fees to terminate its commitments and would be responsible to reimburse the joint owners for their share of paid costs.  If that occurred, SWEPCo would seek recovery of its capitalized costs including any cancellation fees and joint owner reimbursements.  As of June 30, 2008, including the joint owners’ share, SWEPCo has capitalized approximately $407 million of expenditures and has significant contractual construction commitments for an additional $815 million.  As of June 30, 2008, if the plant had been canceled, cancellation fees of $60 million would have been required in order to terminate these construction commitments.  If SWEPCo cannot recover its costs, it would have an adverse effect on future results of operations, cash flows and possibly financial condition.

IGCC Plants

We have delayed construction of the West Virginia and Ohio IGCC plants.  In May 2008, the Virginia SCC denied APCo’s request to reconsider the Virginia SCC's previous denial of APCo’s request to recover initial costs associated with a proposed IGCC plant in West Virginia.  In July 2008, the WVPSC issued a notice seeking comments from parties on how the WVPSC should proceed regarding its earlier approval of the IGCC plant.  In July 2008, the IRS awarded $134 million in future tax credits for the IGCC plant.  Management continues to pursue the ultimate construction of the IGCC plant.  If the West Virginia IGCC plant is canceled, APCo plans to seek recovery of its prudently incurred deferred pre-construction costs of $19 million.  If the plant is canceled and the deferred costs are not recoverable, it would have an adverse effect on future results of operations and cash flows.

In Ohio, CSPCo and OPCo continue to pursue the ultimate construction of the IGCC plant, but await the result of an Ohio Supreme Court remand to the PUCO regarding recovery of IGCC pre-construction costs.  If CSPCo and OPCo were required to refund $24 million collected for IGCC pre-construction costs and those costs were not recoverable in another jurisdiction in connection with the construction of an IGCC plant, it would have an adverse effect on future results of operations and cash flows.

In the ordinary course of business, we, along with our subsidiaries, are involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcome will be, or what the timing of the amount of any loss, fine or penalty may be.  Management does, however, assess the probability of loss for such contingencies and accrues a liability for cases that have a probable likelihood of loss and if the loss amount can be estimated.  For details on our regulatory proceedings and pending litigation see Note 4 – Rate Matters, Note 6 – Commitments, Guarantees and Contingencies and the “Litigation” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2007 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 results of operations.

 

Environmental Litigation

New Source Review (NSR) Litigation:  The Federal EPA, a number of states and certain special interest groups filed complaints alleging that APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities, including Cincinnati Gas & Electric Company, Dayton Power and Light Company (DP&L) and Duke Energy Ohio, Inc. (Duke), modified certain units at coal-fired generating plants in violation of the NSR requirements of the CAA.

In 2007, the AEP System settled their complaints under a consent decree.  CSPCo jointly-owns Beckjord and Stuart Stations with Duke and DP&L.  A jury trial in May 2008 returned a verdict of no liability at the jointly-owned Beckjord unit.  Settlement discussions are ongoing in the citizen suit action filed by Sierra Club against the jointly-owned units at Stuart Station.  We believe we can recover any capital and operating costs of additional pollution control equipment that may be required through future regulated rates or market prices for electricity.  If we are unable to recover such costs or if material penalties are imposed, it would adversely affect future results of operations and cash flows.

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

In addition, we are engaged in litigation with respect to certain environmental matters, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of spent nuclear fuel and future decommissioning of our nuclear units.  We are also engaged in the development of possible future requirements to reduce CO2 and other greenhouse gases (GHG) emissions to address concerns about global climate change.  All of these matters are discussed in the “Environmental Matters” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2007 Annual Report.

Clean Air Act Requirements

As discussed in the 2007 Annual Report under “Clean Air Act Requirements,” various states and environmental organizations challenged the Clean Air Mercury Rule (CAMR) in the D. C. Circuit Court of Appeals.  The Court ruled that the Federal EPA’s action delisting fossil fuel-fired power plants did not conform to the procedures specified in the CAA.  The Court vacated and remanded the model federal rules for both new and existing coal-fired power plants to the Federal EPA.  We are unable to predict how the Federal EPA will respond to the remand.  In addition, in 2005, the Federal EPA issued a final rule, the Clean Air Interstate Rule (CAIR), that requires further reductions in SO2 and NOxemissions and assists states developing new state implementation plans to meet 1997 national ambient air quality standards (NAAQS).  CAIR reduces regional emissions of SO2 and NOx(which can be transformed into PM and ozone) from power plants in the Eastern U.S. (29 states and the District of Columbia).  CAIR requires power plants within these states to reduce emissions of SO2 by 50 percent by 2010, and by 65 percent by 2015.  NOx emissions will be subject to additional limits beginning in 2009, and will be reduced by a total of 70 percent from current levels by 2015.  Reduction of both SO2and NOx would be achieved through a cap-and-trade program.  In July 2008, the D.C. Circuit Court of Appeals vacated the CAIR and remanded the rule to the Federal EPA.  We are unable to predict how the Federal EPA will respond to the remand which could be stayed or appealed to the U.S. Supreme Court.  The Federal EPA also issued revised NAAQS for both ozone and PM 2.5that are more stringent than the 1997 standards used to establish CAIR, which could increase the levels of SO2 and NOxreductions required from our facilities.

 

In anticipation of compliance with CAIR in 2009, I&M purchased $8 million of annual CAIR NOx  allowances which are included in inventory as of June 30, 2008.  The market value of annual CAIR NOx allowances decreased in the weeks following this court decision.  Management intends to seek recovery of the cost of purchased allowances.  If the recovery is denied, it would have an adverse effect on future results of operations and cash flows.  None of AEP’s other subsidiaries purchased any significant number of CAIR allowances.  SO2 and seasonal NOx allowances allocated to our facilities under the Acid Rain Program and the NOx SIP Call will still be required to comply with existing CAA programs that were not affected by the court’s decision.

It is too early to determine the full implication of these decisions on our environmental compliance strategy.  However, independent obligations under the CAA, including obligations under future state implementation plan submittals, and actions taken pursuant to our recent settlement of the NSR enforcement action, are consistent with the actions included in our least-cost CAIR compliance plan.   Consequently, we do not anticipate making any immediate changes in our near-term compliance plans as a result of these court decisions.

Global Climate Change

In July 2008, the Federal EPA issued an advance notice of proposed rulemaking (ANPR) that requests comments on a wide variety of issues the agency is considering in formulating its response to the U.S. Supreme Court’s decision in Massachusetts v. EPA.  In that case, the Court determined that CO2 is an “air pollutant” and that the Federal EPA has authority to regulate mobile sources of CO2emissions under the CAA if appropriate findings are made.  The Federal EPA has identified a number of issues that could affect stationary sources, such as electric generating plants, if the necessary findings are made for mobile sources, including the potential regulation of CO2 emissions for both new and existing stationary sources under the NSR programs of the CAA.  We plan to submit comments and participate in any subsequent regulatory development processes, but are unable to predict the outcome of the Federal EPA’s administrative process or its impact on our business.  Also, additional legislative measures to address CO2 and other GHGs have been introduced in Congress, and such legislative actions could impact future decisions by the Federal EPA on CO2regulation.

In addition, the Federal EPA issued a proposed rule for the underground injection and storage of CO2 captured from industrial processes, including electric generating facilities, under the Safe Drinking Water Act’s Underground Injection Control (UIC) program.  The proposed rules provide a comprehensive set of well siting, design, construction, operation, closure and post-closure care requirements.  We plan to submit comments and participate in any subsequent regulatory development process, but are unable to predict the outcome of the Federal EPA’s administrative process or its impact on our business.  Permitting for our demonstration project at the Mountaineer Plant will proceed under the existing UIC rules.

Clean Water Act Regulations

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

In January 2007, the Second Circuit Court of Appeals issued a decision remanding significant portions of the rule to the Federal EPA.  In July 2007, the Federal EPA suspended the 2004 rule, except for the requirement that permitting agencies develop best professional judgment (BPJ) controls for existing facility cooling water intake structures that reflect the best technology available for minimizing adverse environmental impact.  The result is that the BPJ control standard for cooling water intake structures in effect prior to the 2004 rule is the applicable standard for permitting agencies pending finalization of revised rules by the Federal EPA.  We cannot predict further action of the Federal EPA or what effect it may have on similar requirements adopted by the states.  We sought further review and filed for relief from the schedules included in our permits.

In April 2008, the U.S. Supreme Court agreed to review decisions from the Second Circuit Court of Appeals that limit the Federal EPA’s ability to weigh the retrofitting costs against environmental benefits.  Management is unable to predict the outcome of this appeal.

See the “Critical Accounting Estimates” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2007 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.

In September 2006, the FASB issued SFAS 157 “Fair Value Measurements” (SFAS 157), enhancing existing guidance for fair value measurement of assets and liabilities and instruments measured at fair value that are classified in shareholders’ equity.  The statement defines fair value, establishes a fair value measurement framework and expands fair value disclosures.  It emphasizes that fair value is market-based with the highest measurement hierarchy level being market prices in active markets.  The standard requires fair value measurements be disclosed by hierarchy level, an entity includes its own credit standing in the measurement of its liabilities and modifies the transaction price presumption.  The standard also nullifies the consensus reached in EITF Issue No. 02-3 “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3) that prohibited the recognition of trading gains or losses at the inception of a derivative contract, unless the fair value of such derivative is supported by observable market data.  In February 2008, the FASB issued FSP FAS 157-1 “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13” which amends SFAS 157 to exclude SFAS 13 “Accounting for Leases” and other accounting pronouncements that address fair value measurements for purposes of lease classification or measurement under SFAS 13.  In February 2008, the FASB issued FSP FAS 157-2 “Effective Date of FASB Statement No. 157” which delays the effective date of SFAS 157 to fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The provisions of SFAS 157 are applied prospectively, except for a) changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price under EITF 02-3, b) existing hybrid financial instruments measured initially at fair value using the transaction price and c) blockage discount factors.  Although the statement is applied prospectively upon adoption, in accordance with the provisions of SFAS 157 related to EITF 02-3, we recorded an immaterial transition adjustment to beginning retained earnings.  The impact of considering our own credit risk when measuring the fair value of liabilities, including derivatives, had an immaterial impact on fair value measurements upon adoption.  We partially adopted SFAS 157 effective January 1, 2008.  We will fully adopt SFAS 157 effective January 1, 2009 for items within the scope of FSP FAS 157-2.  See “SFAS 157 “Fair Value Measurements” (SFAS 157)” section of Note 2.

In February 2007, the FASB issued SFAS 159 “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159), permitting entities to choose to measure many financial instruments and certain other items at fair value.  The standard also establishes presentation and disclosure requirements designed to facilitate comparison between entities that choose different measurement attributes for similar types of assets and liabilities.  If the fair value option is elected, the effect of the first remeasurement to fair value is reported as a cumulative effect adjustment to the opening balance of retained earnings.  The statement is applied prospectively upon adoption.  We adopted SFAS 159 effective January 1, 2008.  At adoption, we did not elect the fair value option for any assets or liabilities.

In June 2007, the FASB ratified the EITF Issue No. 06-11 “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards” (EITF 06-11), consensus on the treatment of income tax benefits of dividends on employee share-based compensation.  The issue is how a company should recognize the income tax benefit received on dividends that are paid to employees holding equity-classified nonvested shares, equity-classified nonvested share units or equity-classified outstanding share options and charged to retained earnings under SFAS 123R, “Share-Based Payments.”  Under EITF 06-11, a realized income tax benefit from dividends or dividend equivalents that are charged to retained earnings and are paid to employees for equity-classified nonvested equity shares, nonvested equity share units and outstanding equity share options should be recognized as an increase to additional paid-in capital. We adopted EITF 06-11 effective January 1, 2008.  EITF 06-11 is applied prospectively to the income tax benefits of dividends on equity-classified employee share-based payment awards that are declared in fiscal years after December 15, 2007.  The adoption of this standard had an immaterial impact on our financial statements.

In April 2007, the FASB issued FSP FIN 39-1 “Amendment of FASB Interpretation No. 39” (FIN 39-1).  It amends FASB Interpretation No. 39 “Offsetting of Amounts Related to Certain Contracts” by replacing the interpretation’s definition of contracts with the definition of derivative instruments per SFAS 133.  It also requires entities that offset fair values of derivatives with the same party under a netting agreement to net the fair values (or approximate fair values) of related cash collateral.  The entities must disclose whether or not they offset fair values of derivatives and related cash collateral and amounts recognized for cash collateral payables and receivables at the end of each reporting period. We adopted FIN 39-1 effective January 1, 2008.  This standard changed our method of netting certain balance sheet amounts and reduced assets and liabilities.  It requires retrospective application as a change in accounting principle.  Consequently, we reduced total assets and liabilities on the December 31, 2007 balance sheet by $47 million each.  See “FSP FIN 39-1 “Amendment of FASB Interpretation No. 39” (FIN 39-1)” section of Note 2.

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

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

All Other includes natural gas operations which holds forward natural gas contracts that were not sold with the natural gas pipeline and storage assets.  These contracts are financial derivatives, which will gradually liquidate 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, natural gas, coal, and emissions and to a lesser degree other commodities associated with our energy business.  As a result, we are subject to price risk.  The amount of risk taken is determined by the commercial operations group in accordance with the market risk policy approved by the Finance Committee of our Board of Directors.  Our market risk 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 – AEP Utilities, 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.

We actively participate in the Committee of Chief Risk Officers (CCRO) to develop standard disclosures for risk management activities around risk management contracts.  The CCRO adopted disclosure standards for risk management contracts to improve clarity, understanding and consistency of information reported.  We support the work of the CCRO and embrace the disclosure standards applicable to our business activities.  The following tables provide information on our risk management activities.

The following two tables summarize the various mark-to-market (MTM) positions included on our Condensed Consolidated Balance Sheet as of June 30, 2008 and the reasons for changes in our total MTM value included on our Condensed Consolidated Balance Sheet as compared to December 31, 2007.

 

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

 

 

The following table reports an estimate of the maximum tenors (contract maturities) of the liquid portion of each energy market.

 

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

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

We use foreign currency derivatives to lock in prices on certain forecasted transactions denominated in foreign currencies where deemed necessary, and designate qualifying instruments as cash flow hedges.  We do not hedge all foreign currency exposure.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Condensed Consolidated Balance Sheets and the reasons for changes in cash flow hedges from December 31, 2007 to June 30, 2008.  The following table also indicates what portion of designated, effective hedges are expected to be reclassified into net income in the next 12 months.  Only contracts designated as cash flow hedges are recorded in AOCI.  Therefore, economic hedge contracts which are not designated as effective cash flow hedges are marked-to-market and are included in the previous risk management tables.

We limit credit risk in our wholesale marketing and trading activities by assessing creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness after transactions have been initiated.  We use Moody’s Investors Service, Standard & Poor’s and qualitative and quantitative data to assess the financial health of counterparties on an ongoing basis.  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.  Based on our analysis, we set appropriate risk parameters for each internally-graded counterparty.  We may also require cash deposits, letters of credit and parental/affiliate guarantees as security from counterparties in order to mitigate credit risk.

We have risk management contracts with numerous counterparties.  Since open risk management contracts are valued based on changes in market prices of the related commodities, our exposures change daily.  At June 30, 2008, our credit exposure net of collateral to sub investment grade counterparties was approximately 20.1%, 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).  The increase from 5.4% at December 31, 2007 is primarily related to an increase in exposure with coal counterparties due to escalating coal prices.  Approximately 55% of our credit exposure net of collateral to sub investment grade counterparties is short-term exposure of less than one year.  As of June 30, 2008, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable (in millions, except number of counterparties):

This table provides information on operating measures regarding the proportion of output of our generation facilities (based on economic availability projections) economically hedged, including both contracts designated as cash flow hedges under SFAS 133 and contracts not designated as cash flow hedges.  This information is forward-looking and provided on a prospective basis through December 31, 2010.  This table is a point-in-time estimate, subject to changes in market conditions and our decisions on how to manage operations and risk.  “Estimated Plant Output Hedged” represents the portion of MWHs of future generation/production, taking into consideration scheduled plant outages, for which we have sales commitments or estimated requirement obligations to customers.

We use a risk measurement model, which calculates Value at Risk (VaR) to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period.  Based on this VaR analysis, at June 30, 2008, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

 

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

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

As our VaR calculation captures recent price moves, we also perform regular stress testing of the portfolio to understand our exposure to extreme price moves.  We employ a historically-based method whereby the current portfolio is subjected to actual, observed price moves from the last three years in order to ascertain which historical price moves translates into the largest potential mark-to-market loss.  We then research the underlying positions, price moves and market events that created the most significant exposure.

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.  The estimated EaR on our debt portfolio was $32 million.