American Electric Power - 10-Q quarterly report FY

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For The Quarterly Period Ended June 30, 2007

OR

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

OF THE SECURITIES EXCHANGE ACT OF 1934

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

The status of base rate filings ongoing or finalized this quarter with implemented rates are:

In Virginia, APCo filed the following non-base rate requests in July 2007 with the Virginia SCC:

In June 2007, APCo filed testimony with the WVPSC supporting construction of a 629 MW IGCC plant adjacent to APCo’s existing Mountaineer Generating Station in Mason County, WV.   APCo requested pre-approval of a surcharge rate mechanism to provide for the timely recovery of both the ongoing finance costs of the project during the construction period as well as the capital and operating costs and a return on equity once the facility is placed into commercial operation.  In July 2007, APCo filed a request with the Virginia SCC to recover an estimated $45 million in financing costs on projected IGCC construction work in progress including pre-construction development design and planning costs from July 1, 2007 through December 31, 2009.  If APCo receives all necessary approvals, the plant could be completed as early as mid-2012 for an estimated cost of $2.2 billion.

In June 2007, the IURC approved a settlement agreement allowing I&M to implement reduced book depreciation rates upon the filing by I&M of a general rate petition.  On June 19, 2007, I&M filed its rate petition to be effective on July 1, 2007.  The settlement agreement will result in a reduction of book depreciation expense of $37 million primarily related to the Cook Plant license extension for the period from June 19, 2007 to December 31, 2007, which was offset by a $5 million regulatory liability, recorded in June 2007, to provide for an agreed-upon fuel credit.  I&M expects new base rates including the reduced depreciation to become effective in late 2008 or early 2009.

Effective July 1, 2007, I&M’s rate cap ended for both base and fuel rates.  I&M’s fuel factor increased effective with July 2007 billings to recover the full projected cost of fuel.  I&M will resume deferring through revenues any under/over-recovered fuel costs for future recovery/refund.

In June 2007, an ALJ issued a Proposal for Decision recommending a $17 million disallowance in SWEPCo's Texas fuel reconciliation proceeding.  Results of operations for the second quarter were adversely affected by $25 million as a result of reflecting the ALJ’s decision.  In July 2007, the PUCT orally affirmed the ALJ report.  A final order is expected in the third quarter of 2007.

In April 2007, the Virginia legislature re-regulated electric utilities’ generation/supply rates on a cost basis effective July 1, 2007.  We recorded an extraordinary pretax reduction in APCo’s earnings of $118 million ($79 million, net of tax) from reapplication of SFAS 71 regulatory accounting in the second quarter of 2007 as a result of the new re-regulation legislation.

In the second quarter of 2007, we completed the purchase of the 480 MW Darby Electric Generation Station for $102 million and the purchase of the 1,096 MW Lawrenceburg Generating Station for $325 million.

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 for the three and six months ended June 30, 2007 and 2006.  We reclassified prior year amounts to conform to the current year’s segment presentation.

Income Before Discontinued Operations and Extraordinary Loss in 2007 increased $85 million compared to 2006 primarily due to an increase in Utility Operations segment earnings of $79 million.  The increase in Utility Operations segment earnings primarily relates to higher retail margins mostly due to rate increases and favorable weather and increased margins from off-system sales.

Average basic shares outstanding increased to 399 million in 2007 from 394 million in 2006 primarily due to the issuance of shares under our incentive compensation plans.  Actual shares outstanding were 399 million as of June 30, 2007.

Income Before Discontinued Operations and Extraordinary Loss in 2007 decreased $22 million compared to 2006 primarily due to a decrease in Utility Operations segment earnings of $33 million.  The decrease in Utility Operations segment earnings primarily relates to higher operation and maintenance expenses, higher regulatory amortization expense and lower earnings-sharing payments from Centrica received in March 2007 representing the last payment of the earnings-sharing agreement.  These decreases in earnings were partially offset by rate increases and favorable weather.

Average basic shares outstanding increased to 398 million in 2007 from 394 million in 2006 primarily due to the issuance of shares under our incentive compensation plans.  Actual shares outstanding were 399 million as of June 30, 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.

Income from Utility Operations Before Discontinued Operations and Extraordinary Loss increased $79 million to $238 million in 2007.  The key drivers of the increase were a $172 million increase in Gross Margin partially offset by a $56 million increase in Operating Expenses and Other and a $37 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 from Utility Operations Before Discontinued Operations and Extraordinary Loss decreased $33 million to $491 million in 2007.  The key driver of the decrease was a $302 million increase in Operating Expenses and Other, offset by a $246 million increase in Gross Margin and a $23 million decrease 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 from $14 million in 2006 to $7 million in 2007.  While MEMCO operated 15% more barges in the second quarter of 2007 than the same period in 2006, freight revenues remained flat as spot market freight demand remained weaker than in 2006, primarily related to reduced steel and cement imports.  Operating expenses were up 11% over the same period in 2006 mainly due to the increased fleet size, increased fuel costs and wage increases for towboat crews.

Income Before Discontinued Operations and Extraordinary Loss from our MEMCO Operations segment decreased from $35 million in 2006 to $22 million in 2007.  MEMCO operated approximately 16% more barges in the first six months of 2007 than 2006, however, revenue remained flat as reduced imports, primarily steel and cement continued to depress freight rates and reduce northbound loadings.  Operating expenses were up for the first six months of 2007 compared to 2006 primarily due to the cost of the increased fleet size, fuel and wage increases.

Income Before Discontinued Operations and Extraordinary Loss from our Generation and Marketing segment increased from $2 million in 2006 to $15 million in 2007.  The increase primarily relates to favorable marketing contracts with municipalities and cooperatives in ERCOT.  Net revenues for our Generation and Marketing segment increased primarily due to certain existing ERCOT energy contracts which were transferred from our Utility Operations segment on January 1, 2007.

Income Before Discontinued Operations and Extraordinary Loss from our Generation and Marketing segment increased from $6 million in 2006 to $14 million in 2007.  The increase primarily relates to favorable marketing contracts with municipalities and cooperatives in ERCOT.  Net revenues for our Generation and Marketing segment increased primarily due to certain existing ERCOT energy contracts which were transferred from our Utility Operations segment on January 1, 2007.

Loss Before Discontinued Operations and Extraordinary Loss from All Other was essentially flat at $3 million.

Income Before Discontinued Operations and Extraordinary Loss from All Other increased from a $15 million loss in 2006 to income of $1 million in 2007.  In 2006, we had after-tax losses of $8 million from operation of the Plaquemine Cogeneration Facility which was sold in the fourth quarter of 2006.  In 2007, we had an after-tax gain of $10 million on the sale of investment securities.

Income Tax Expense increased $36 million in the second quarter of 2007 compared to the second quarter of 2006 primarily due to an increase in pretax book income.

Income Tax Expense decreased $23 million for the six-month period ended June 30, 2007 compared to the six-month period ended June 30, 2006 primarily due to a decrease in pretax book income and changes in certain book/tax differences accounted for on a flow-through basis.

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 increased, as planned, from 59.1% to 60.8% in 2007 due to our increased borrowings.

Liquidity, or access to cash, is an important factor in determining our financial stability.  We are committed to maintaining adequate liquidity.

We manage our liquidity by maintaining adequate external financing commitments.  At June 30, 2007, our available liquidity was approximately $2.7 billion as illustrated in the table below:

In 2007, we amended the terms and extended the maturity of our two credit facilities by one year to March 2011 and April 2012, respectively.  The facilities are structured as two $1.5 billion credit facilities of which $300 million may be issued under each credit facility as letters of credit.

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, 2007, this contractually-defined percentage was 56.1%.  Nonperformance of these covenants could result in an event of default under these credit agreements.  At June 30, 2007, 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.

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

Under a regulatory order, our utility subsidiaries, other than TCC, cannot incur additional indebtedness if the issuer’s common equity would constitute less than 30% of its capital.  In addition, this order restricts those utility subsidiaries from issuing long-term debt unless that debt will be rated investment grade by at least one nationally recognized statistical rating organization.  At June 30, 2007, all applicable utility subsidiaries complied with this order.

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders.  At June 30, 2007, we had not exceeded those authorized limits.

AEP’s ratings have not been adjusted by any rating agency during 2007 and AEP is currently on a stable outlook by the rating agencies.  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.  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, 2007, we had credit facilities totaling $3 billion to support our commercial paper program.  The maximum amount of commercial paper outstanding during 2007 was $833 million.  The weighted-average interest rate of our commercial paper for the six months ended June 30, 2007 was 5.40%.  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 common stock or long-term debt and sale-leaseback or leasing agreements.  Utility Money Pool borrowings and external borrowings may not exceed authorized limits under regulatory orders.  See the discussion below for further detail related to the components of our cash flows.

Net Cash Flows From Operating Activities decreased in 2007 primarily due to lower fuel costs recovery.

Net Cash Flows From Operating Activities were $1 billion in 2007. We produced Income Before Discontinued Operations of $449 million adjusted for noncash expense items, primarily depreciation and amortization.  Other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The current period activity in these asset and liability accounts relates to a number of items, the most significant of which relates primarily to the Texas CTC refund of fuel over-recovery.

Net Cash Flows From Operating Activities were $1.1 billion in 2006.  We produced Income Before Discontinued Operations of $550 million adjusted for noncash expense items, primarily depreciation and amortization.  In 2005, we initiated fuel proceedings in Oklahoma, Texas, Virginia and Arkansas seeking recovery of our increased fuel costs.  Under-recovered fuel costs decreased due to recovery of higher cost of fuel, especially natural gas.  Other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The current period activity in these asset and liability accounts relates to a number of items; the most significant are a $185 million cash increase from net Accounts Receivable/Accounts Payable due to a lower balance of Customer Accounts Receivable at June 30, 2006 and a $189 million decrease in cash related to customer deposits held for trading activities.

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.  In our normal course of business, we purchase investment securities including auction rate securities and variable rate demand notes with cash available for short-term investments.  Also included in Purchases/Sales of Investment Securities, Net are purchases and sales of securities within our nuclear trusts.

Net Cash Flows Used For Investing Activities were $1.6 billion in 2006 primarily due to Construction Expenditures.  Construction Expenditures increased due to our environmental investment plan.

We forecast approximately $1.7 billion of construction expenditures for the remainder of 2007.  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.

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.  See Note 9 for a complete discussion of long-term debt issuances and retirements.

Net Cash Flows From Financing Activities in 2006 were $297 million.  During 2006, we issued $115 million of obligations relating to pollution control bonds, issued $850 million of notes and retired $396 million of notes for a net increase in notes outstanding of $454 million and increased our short-term commercial paper outstanding by $144 million.  The Other amount of $30 million in the above table includes $68 million received from a coal supplier, net of an $8 million repayment, related to a long-term coal purchase contract amended in March 2006.

Our capital investment plans for the remainder of 2007 will require additional funding of approximately $1.5 billion 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 only allow 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 2006 Annual Report.

A summary of our contractual obligations is included in our 2006 Annual Report and has not changed significantly from year-end other than the debt issuances discussed in “Cash Flow” and “Financing Activities” above.

As part of the purchase-and-sale agreement related to the sale of our Texas REPs in 2002, we retained the right to share in earnings with Centrica from the two REPs above a threshold amount through 2006 if the Texas retail market developed increased earnings opportunities.  We received $20 million and $70 million payments in 2007 and 2006, respectively, for our share in earnings.  The payment we received in 2007 was the final payment under the earnings sharing agreement.

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 2006 Annual Report.  The 2006 Annual Report should be read in conjunction with this report in order to understand significant factors without material changes in status since the issuance of our 2006 Annual Report, but may have a material impact on our future results of operations, cash flows and financial condition.

CSPCo and OPCo are involved in discussions with various stakeholders in Ohio about potential legislation to address the period following the expiration of the RSPs on December 31, 2008.  At this time, management is unable to predict whether CSPCo and OPCo will transition to market pricing, as permitted by the current Ohio restructuring legislation, extend their RSP rates, with or without modification, or become subject to a legislative reinstatement of some form of cost-based regulation for their generation supply business on January 1, 2009 when the RSP period ends.

TCC recovered its net recoverable stranded generation costs through a securitization financing and is refunding its net other true-up items through a CTC rate rider credit under 2006 PUCT orders.  TCC appealed the PUCT stranded costs true-up 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, federal law and fail to fully compensate TCC for its net stranded cost and other true-up items.  The significant items appealed by TCC are:

Municipal customers and other intervenors also appealed the PUCT true-up orders seeking to further reduce TCC’s true-up recoveries.  In March 2007, the Texas District Court judge hearing the various appeals affirmed the PUCT’s April 4, 2006 final true-up order for TCC with two significant exceptions.  The judge determined that the PUCT erred by applying an invalidated rule to determine the carrying cost rate for the true-up of stranded costs.  However, the District Court did not rule that the carrying cost rate was inappropriate.  If the District Court’s ruling on the carrying cost rate is ultimately upheld on appeal and remanded to the PUCT for reconsideration, the PUCT could either confirm the existing weighted average carrying cost (WACC) rate or determine a new rate.  If the PUCT reduces the rate, it could result in a material adverse change to TCC’s recoverable carrying costs, results of operations, cash flows and financial condition.

The District Court judge also determined the PUCT improperly reduced TCC’s net stranded plant costs for commercial unreasonableness.  If upheld on appeal, this ruling could have a materially favorable effect on TCC’s results of operations and cash flows.

TCC, the PUCT and intervenors appealed the District Court rulings to the Court of Appeals.  Management cannot predict the outcome of these proceedings.  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, or if TCC has a tax normalization violation, it could have a substantial adverse effect on future results of operations, cash flows and financial condition.

The AEP East companies ceased collecting T&O revenues in accordance with FERC orders, and collected SECA rates to mitigate the loss of T&O revenues from December 1, 2004 through March 31, 2006, when SECA rates expired.  Intervenors objected to the SECA rates, raising various issues.  As a result, the FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund or surcharge.  The AEP East companies paid SECA rates to other utilities at considerably lesser amounts than collected.  If a refund is ordered, the AEP East companies would also receive refunds related to the SECA rates they paid to third parties.  The AEP East companies recognized gross SECA revenues of $220 million. Approximately $19 million of these recorded SECA revenues billed by PJM were not collected.  The AEP East companies filed a motion with the FERC to force payment of these uncollected SECA billings.

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

In September 2006, AEP, together with Exelon Corporation and The Dayton Power and Light Company, filed an extensive post-hearing brief and reply brief noting exceptions to the ALJ’s initial decision and asking the FERC to reverse the decision in large part.  Management believes that the FERC should reject the initial decision because it contradicts prior related FERC decisions, which are presently subject to rehearing.  Furthermore, management believes the ALJ’s findings on key issues are largely without merit.  As directed by the FERC, management is working to settle the remaining $115 million of unsettled revenues within the remaining reserve balance.  Although management believes it has meritorious arguments and can settle with the remaining customers within the amount provided, management cannot predict the ultimate outcome of ongoing settlement talks and, if necessary, any future FERC proceedings or court appeals.  If the FERC adopts the ALJ’s decision and/or AEP cannot settle a significant portion of the remaining unsettled claims within the amount provided, it will have an adverse effect on future results of operations and cash flows.

In April 2004, Virginia enacted legislation that amended the Virginia Electric Utility Restructuring Act extending the transition period to market rates for the generation and supply of electricity, including the extension of capped rates, through December 31, 2010.  The legislation provided APCo with specified cost recovery opportunities during the extended capped rate period, including two optional bundled general base rate changes and an opportunity for timely recovery, through a separate rate mechanism, of certain unrecovered incremental environmental and reliability costs incurred on and after July 1, 2004.  Under the amended restructuring law, APCo continues to have an active fuel clause recovery mechanism in Virginia and continues to practice deferred fuel accounting.  Also, under the amended restructuring law, APCo has the right to defer incremental environmental compliance costs and incremental E&R costs for future recovery, to the extent such costs are not being recovered, and amortizes a portion of such deferrals commensurate with their recovery.

In April 2007, the Virginia legislature adopted a comprehensive law providing for the re-regulation of electric utilities’ generation and supply rates.  These amendments shorten the transition period by two years (from 2010 to 2008) after which rates for retail generation and supply will return to a form of cost-based regulation in lieu of market-based rates.  The legislation provides for, among other things, biennial rate reviews beginning in 2009; rate adjustment clauses for the recovery of the costs of (a) transmission services and new transmission investments, (b) demand side management, load management, and energy efficiency programs, (c) renewable energy programs, and (d) environmental retrofit and new generation investments; significant return on equity enhancements for investments in new generation and, subject to Virginia SCC approval, certain environmental retrofits, and a floor on the allowed return on equity based on the average earned return on equities’ of regional vertically integrated electric utilities.  Effective July 1, 2007, the amendments allow utilities to retain a minimum of 25% of the margins from off-system sales with the remaining margins from such sales credited against fuel factor expenses with a true-up to actual.  The legislation also allows APCo to continue to defer and recover incremental environmental and reliability costs incurred through December 31, 2008.  The new re-regulation legislation should result in significant positive effects on APCo’s future earnings and cash flows from the mandated enhanced future returns on equity, the reduction of regulatory lag from the opportunities to adjust base rates on a biennial basis and the new opportunities to request timely recovery of certain new costs not included in base rates.

With the new re-regulation legislation, APCo’s generation business again meets the criteria for application of regulatory accounting principles under SFAS 71.  The extraordinary pretax reduction in APCo’s earnings and shareholder’s equity from reapplication of SFAS 71 regulatory accounting of $118 million ($79 million, net of tax) was recorded in the second quarter of 2007.  This extraordinary net loss primarily relates to the reestablishment of $139 million in net generation-related customer-provided removal costs as a regulatory liability, offset by the restoration of $21 million of deferred state income taxes as a regulatory asset.  In addition, APCo established a regulatory asset of $17 million for qualifying SFAS 158 pension costs of the generation operations that, for ratemaking purposes, are deferred for future recovery under the new law.  AOCI and Deferred Income Taxes increased by $11 million and $6 million, respectively.

In March 2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority to recover costs related to building and operating a 629 MW IGCC power plant using clean-coal technology.  The application proposed three phases of cost recovery associated with the IGCC plant:  Phase 1, recovery of $24 million in pre-construction costs during 2006; Phase 2, concurrent recovery of construction-financing costs; and Phase 3, recovery or refund in distribution rates of any difference between the market-based standard service offer price for generation and the cost of operating and maintaining the plant, including a return on and return of the ultimate cost to construct the plant, originally projected to be $1.2 billion, along with fuel, consumables and replacement power costs.  The proposed recoveries in Phases 1 and 2 would be applied against the 4% limit on additional generation rate increases CSPCo and OPCo could request under their RSPs.

In April 2006, the PUCO issued an order authorizing CSPCo and OPCo to implement Phase 1 of the cost recovery proposal.  In June 2006, the PUCO issued another order approving a tariff to recover Phase 1 pre-construction costs over a period of no more than twelve months effective July 1, 2006.  Through June 30, 2007, CSPCo and OPCo each recorded pre-construction IGCC regulatory assets of $10 million and each collected the entire $12 million approved by the PUCO.  CSPCo and OPCo expect to incur additional pre-construction costs equal to or greater than the $12 million each recovered.  As of June 30, 2007, CSPCo and OPCo have recorded a liability of $2 million each for the over-recovered portion.  The PUCO indicated that if CSPCo and OPCo have not commenced a continuous course of construction of the IGCC plant within five years of the June 2006 PUCO order, all amounts collected for pre-construction costs, associated with items that may be utilized in IGCC projects to be built by AEP at other sites, must be refunded to Ohio ratepayers with interest.  The PUCO deferred ruling on cost recovery for Phases 2 and 3 until further hearings are held.  A date for further rehearings has not been set.

In August 2006, the Ohio Industrial Energy Users, Ohio Consumers’ Counsel, FirstEnergy Solutions and Ohio Energy Group filed four separate appeals of the PUCO’s order in the IGCC proceeding.  The Ohio Supreme Court has scheduled oral arguments for these appeals in October 2007.  Management believes that the PUCO’s authorization to begin collection of Phase 1 rates is lawful.  Management, however, cannot predict the outcome of these appeals.  If the PUCO’s order is found to be unlawful, CSPCo and OPCo could be required to refund Phase 1 cost-related recoveries.

Pending the outcome of the Supreme Court litigation, CSPCo and OPCo announced they may delay the start of construction of the IGCC plant.  Recent estimates of the cost to build an IGCC plant are $2.2 billion.  CSPCo and OPCo may need to request an extension to the 5 year start of construction requirement if the commencement of construction is delayed beyond 2011.  In July 2007, CSPCo and OPCo filed a status report with the PUCO referencing APCo’s IGCC West Virginia filing.

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

In June 2007, APCo filed testimony with the WVPSC supporting the requests for a CCN and for pre-approval of a surcharge rate mechanism to provide for the timely recovery of both the ongoing finance costs of the project during the construction period as well as the capital costs, operating costs and a return of equity once the facility is placed into commercial operation.  If APCo receives all necessary approvals, the plant could be completed by mid-2012 at the earliest and currently is expected to cost an estimated $2.2 billion.  In July 2007, the WVPSC staff and intervenors filed to delay the procedural schedule by 90 days.  APCo supported the changes to the procedural schedule.  The statutory decision deadline was revised to March 2008.  In July 2007, the WVPSC approved the revised procedural schedule.  Through June 30, 2007, APCo deferred pre-construction IGCC costs totaling $11 million.  If the plant is not built and these costs are not recoverable, future results of operations and cash flows would be adversely affected.

In July 2007, APCo filed a request with the Virginia SCC to recover, over the twelve months beginning January 1, 2009, a return on projected construction work in progress including development, design and planning costs from July 1, 2007 through December 31, 2009 estimated to be $45 million associated with the IGCC plant to be constructed in West Virginia.  APCo is requesting authorization to defer a return on actual pre-construction costs incurred beginning July 1, 2007 until such costs are recovered, starting January 1, 2009 as required by the new re-regulation legislation.

In December 2005, SWEPCo sought proposals for new peaking, intermediate and base load generation to be online between 2008 and 2011.  In May 2006, SWEPCo announced plans to construct new generation to satisfy the demands of its customers.  Plans include the construction of up to 480 MW of simple-cycle natural gas combustion turbine peaking generation in Tontitown, Arkansas and a 480 MW combined-cycle natural gas fired intermediate plant at its existing Arsenal Hill Power Plant in Shreveport, Louisiana.  SWEPCo also plans to build the Turk plant, a new 600 MW base load coal plant, with a 73% ownership share, in Hempstead County, Arkansas by 2011 to meet the long-term generation needs of its customers.  Preliminary cost estimates for SWEPCo’s share of these new facilities are approximately $1.4 billion (this total includes all three plants, but excludes the related transmission investment and AFUDC).  Expenditures related to construction of all of these facilities are expected to total $349 million in 2007.  These new facilities are subject to regulatory approvals from SWEPCo’s three state commissions.  Mattison plant, the peaking generation facility in Tontitown, Arkansas has been approved by all three state commissions.  Mattison plant Units 3 and 4 began commercial operation in July 2007, with the remaining two units scheduled for completion in December 2007.  All four units of the Mattison plant are expected to be completed in advance of the originally planned 2008 commercial operation date.  Construction is expected to begin in the second half of 2007 on the base load facility and in 2008 on the intermediate facility, both upon approval from SWEPCo’s three state commissions.

In September 2005, PSO sought proposals for new peaking generation to be online in 2008, and in December 2005 PSO sought proposals for base load generation to be online in 2011.  PSO received proposals and evaluated those proposals meeting the Request for Proposal criteria with oversight from a neutral third party.  In March 2006, PSO announced plans to add 170 MW of peaking generation to its Riverside Station plant in Jenks, Oklahoma where PSO will construct and operate two 85 MW simple-cycle natural gas combustion turbines.   Also in March 2006, PSO announced plans to add 170 MW of peaking generation to its Southwestern Station plant in Anadarko, Oklahoma where they will construct and operate two 85 MW simple-cycle natural gas combustion turbines.  Construction of all four peaking units began in the second quarter of 2007.  Combined preliminary cost estimates for these additions are approximately $120 million.  In April 2007, the OCC approved a settlement agreement in a matter involving a proposed cogeneration facility, which included a provision regarding these new peaking units.  The settlement agreement provides for recovery of a purchase fee of $35 million, which PSO paid to Lawton Cogeneration, LLC (Lawton) in the second quarter of 2007 to settle the proceeding and for all rights to Lawton’s permits, options and engineering studies for the cogeneration facility.  In April 2007, PSO recorded with OCC approval, the purchase fee as a regulatory asset and will recover it through a rider over a three-year period with a carrying charge of 8.25% beginning in September 2007.  In addition, PSO will recover the traditional costs associated with plant in service of these new peaking units.  Such costs will be recovered through the rider until cost recovery occurs through base rates or formula rates in a subsequent proceeding.  PSO must file a rate case within eighteen months of the beginning of recovery through the rider unless the OCC approves a formula-based rate mechanism that provides for recovery of the peaking units.

In July 2006, PSO announced plans to enter a joint ownership agreement with Oklahoma Gas and Electric Company (OG&E) and Oklahoma Municipal Power Authority (OMPA) where OG&E will construct and operate a new 950 MW coal-fueled electricity generating unit near Red Rock, Oklahoma.  PSO will own 50% of the new unit.  PSO, OG&E and OMPA signed an agreement in February 2007 with Red Rock Power Partners to begin the first phase of the project.  Preliminary cost estimates for 100% of the new facility are approximately $1.8 billion, and the unit is expected to be online no later than the first half of 2012.  This new facility is subject to regulatory approval from the OCC, which is expected later in 2007.  Construction is expected to begin in the second half of 2007.  The Oklahoma Supreme Court is addressing whether the upfront approval process is constitutional.  PSO estimates construction expenditures for all of the new generation projects to be $167 million in 2007.

In November 2006, CSPCo agreed to purchase Darby Electric Generating Station (Darby) from DPL Energy, LLC, a subsidiary of The Dayton Power and Light Company, for $102 million and the assumption of liabilities of $2 million.  CSPCo completed the purchase in April 2007.  The Darby plant is located near Mount Sterling, Ohio and is a natural gas, simple cycle power plant with a generating capacity of 480 MW.  The purchase of Darby is an economically efficient way to provide peaking generation to our customers at a cost below that of building a new, comparable plant.

In January 2007, AEGCo agreed to purchase Lawrenceburg Generating Station (Lawrenceburg) from Public Service Enterprise Group (PSEG) for $325 million and the assumption of liabilities of $3 million.  The transaction closed in May 2007.  The Lawrenceburg plant is located in Lawrenceburg, Indiana, adjacent to I&M’s Tanners Creek Plant, and is a natural gas, combined cycle power plant with a generating capacity of 1,096 MW.  AEGCo sells the power to CSPCo under a FERC-approved purchase power contract.

In January 2007, we signed a participation agreement with MidAmerican Energy Holdings Company (MidAmerican) to form a joint venture company, Electric Transmission Texas LLC (ETT), to fund, own and operate electric transmission assets in ERCOT.  ETT filed with the PUCT in January 2007 requesting regulatory approval to operate as an electric transmission utility in Texas, to transfer from TCC to ETT approximately $76 million of transmission assets under construction and to establish a wholesale transmission tariff for ETT.  ETT also requested PUCT approval of initial rates based on an 11.25% return on equity.  A hearing was held in July 2007.  We expect a final order from the PUCT in October 2007.

TCC also made a regulatory filing at the FERC in February 2007 regarding the transfer of certain transmission assets from TCC to ETT.  In April 2007, the FERC authorized the transfer.

Upon receipt of all required regulatory approvals, AEP Utilities, Inc., a subsidiary of AEP, and MEHC Texas Transco LLC, a subsidiary of MidAmerican, each will acquire a 50 percent equity ownership in ETT.  AEP and MidAmerican plan for ETT to invest in additional transmission projects in ERCOT.  The joint venture partners anticipate investments in excess of $1 billion of joint investment in Texas ERCOT Transmission projects that could be constructed by ETT during the next several years.  The joint venture is anticipated to be formed and begin operations in the fourth quarter of 2007, subject to certain closing conditions such as necessary regulatory approvals.

In February 2007, ETT filed a proposal with the PUCT that addresses the Competitive Renewable Energy Zone (CREZ) initiative of the Texas Legislature, which outlines opportunities for additional significant investment in transmission assets in Texas. A CREZ hearing was held in June 2007.  We expect an order in August 2007 on the designation of zones and amount of wind generation for each zone, subsequent studies by ERCOT on specific transmission recommendations in late 2007 or early 2008 and selection of transmission construction designees by the PUCT in early 2008.

We believe Texas can provide a high degree of regulatory certainty for transmission investment due to the predetermination of ERCOT’s need based on reliability requirements and significant Texas economic growth as well as public policy that supports “green generation” initiatives, which require substantial transmission improvements.  In addition, a streamlined annual interim transmission cost of service review process is available in ERCOT, which reduces regulatory lag.  The use of a joint venture structure will allow us to share the significant capital requirements for the investments, and also allow us to participate in more transmission projects than previously anticipated.

In January 2006, we filed a proposal with the FERC and PJM to build a new 765 kV 550-mile transmission line from West Virginia to New Jersey.  The 765 kV line is designed to reduce PJM congestion costs by substantially improving west-east transfer capability by approximately 5,000 MW during peak loading conditions and reducing transmission line losses by up to 280 MW.  The project would also enhance reliability of the Eastern transmission grid.  The projected cost for the project, as originally proposed to PJM, is approximately $3 billion.  The project is subject to PJM and state approvals, and FERC approvals of incentive cost recovery mechanisms.

We were the first entity to file with the Department of Energy (DOE) seeking to have the route of a proposed transmission project designated as a National Interest Electric Transmission Corridor (NIETC).  The Energy Policy Act of 2005 provides for NIETC designation for areas experiencing electric energy transmission capacity constraints or congestion that adversely affects consumers.  In August 2006, the DOE issued the “National Interest Electric Transmission Congestion Study.”  In this study, DOE indicated that the mid-Atlantic Coastal area, which the AEP Interstate Project is designed to reinforce, is one of the two most critical congestion areas in the nation.  In April 2007, the DOE included in its draft report the mid-Atlantic Coastal area NIETC which contains the entire proposed 765 kV transmission line.  The DOE expects to issue its final report by the end of 2007.

In July 2006, pursuant to our request, the FERC clarified that the project qualifies for incentive rate treatment, provided that the new line is included in PJM’s 2007 Regional Transmission Expansion Plan.  The conditionally- approved incentives include (a) a return on equity set at the high end of the “zone of reasonableness”; (b) the timely recovery of the cost of capital during the construction period; and (c) the ability to defer and recover costs incurred during the pre-construction and pre-operating period.  Since the FERC has clarified that the project qualifies for these rate incentives, we expect to propose rates that will capture the incentives in a future FERC rate filing.

In April 2007, we signed a memorandum of understanding (MOU) with Allegheny Energy Inc. (AYE) to form a joint venture company to build and own certain electric transmission assets within PJM including the first half of the West Virginia – New Jersey line proposed by AEP in January 2006.  Under the terms of the MOU, the joint venture company will build and own approximately 300 miles of transmission lines from AEP’s Amos station to the Maryland border.  The MOU does not include any provisions for the remainder of the AEP Interstate Project proposal from AYE’s Kemptown station to New Jersey.

On June 22, 2007, PJM’s Board authorized the construction of such a major new transmission line to address the reliability and efficiency needs of the PJM system.  PJM has identified a need for a new line as early as 2012.  The line would be 765kV for most of its length and would run approximately 250 miles from AEP’s Amos substation in West Virginia to AYE’s Kemptown station in north central Maryland. AEP and AYE continue to work on finalizing the definitive agreements necessary to construct the line through a joint venture.  The new line has been named the “Potomac-Appalachian Transmission Highline” (PATH) by AEP and AYE and represents the “first leg” of the AEP Interstate Project.  The “second leg”, which would extend the line to New Jersey, is currently under evaluation by PJM.  We expect to execute definitive agreements for the joint venture with AYE in the third quarter of 2007 and anticipate the joint venture will begin activities in the second half of 2007.  The total PATH project is estimated to cost approximately $1.8 billion and AEP’s estimated share will be approximately $600 million.

In the ordinary course of business, we and 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 of these proceedings 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 the loss amount can be estimated.  For details on regulatory proceedings and our 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 2006 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 the results of operations, cash flows and financial condition of AEP and its subsidiaries.

See discussion of the “Environmental Litigation” within the “Environmental Matters” section of “Significant Factors.”

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 monitoring possible future requirements to reduce carbon dioxide (CO₂) 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 2006 Annual Report.

New Source Review (NSR) Litigation:  In 1999, 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 the Tennessee Valley Authority, Alabama Power Company, Cincinnati Gas & Electric Company, Ohio Edison Company, Southern Indiana Gas & Electric Company, Illinois Power Company, Tampa Electric Company, Virginia Electric Power Company and Duke Energy,  modified certain units at coal-fired generating plants in violation of the NSR requirements of the CAA.  Several similar complaints were filed in 1999 and thereafter against nonaffiliated utilities including Allegheny Energy, Eastern Kentucky Electric Cooperative, Public Service Enterprise Group, Santee Cooper, Wisconsin Electric Power Company, Mirant, NRG Energy and Niagara Mohawk.  Several of these cases were resolved through consent decrees.  The alleged modifications at our power plants occurred over a 20-year period.  A bench trial on the liability issues was held during 2005.  In 2006, the judge stayed the liability decision pending the issuance of a decision by the U.S. Supreme Court in the Duke Energy case.

Under the CAA, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology.  This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components, or other repairs needed for the reliable, safe and efficient operation of the plant.

Courts that considered whether the activities at issue in these cases are routine maintenance, repair, or replacement, and therefore are excluded from NSR, reached different conclusions.  Similarly, courts that considered whether the activities at issue increased emissions from the power plants reached different results.  Appeals on these and other issues were filed in certain appellate courts, including a petition to appeal to the U.S. Supreme Court that was granted in the Duke Energy case.

In April 2007, the U.S. Supreme Court reversed the Fourth Circuit Court of Appeals’ decision that had supported the statutory construction argument of Duke Energy in its NSR proceeding.  In a unanimous decision, the Court ruled that the Federal EPA was not obligated to define “major modification” in two different CAA provisions in the same way.  The Court also found that the Fourth Circuit’s interpretation of “major modification” as applying only to projects that increased hourly emission rates amounted to an invalidation of the relevant Federal EPA regulations, which under the CAA can only be challenged in the Court of Appeals within 60 days of the Federal EPA rulemaking.  The U.S. Supreme Court did acknowledge, however, that Duke Energy may argue on remand that the Federal EPA has been inconsistent in its interpretations of the CAA and the regulations and may not retroactively change 20 years of accepted practice.

In addition to providing guidance on the merits of arguments in our NSR proceedings, the U.S. Supreme Court’s issuance of a ruling in the Duke Energy cases has an impact on the timing of our NSR proceedings.  The court indicated an intent to issue a decision on liability issues in the third quarter of 2007.  A bench trial on remedy issues, if necessary, is likely to begin in the second half of 2007.

We are unable to estimate the loss or range of loss related to any contingent liability, if any, we might have for civil penalties under the CAA proceedings.  We are also unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues to be determined by the court.  If we do not prevail, we believe we can recover any capital and operating costs of additional pollution control equipment that may be required through regulated rates and 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, cash flows and possibly financial condition.

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.

The rule was challenged in the courts by states, advocacy organizations and industry.  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 may seek further review or relief from the schedules included in our permits.

See the “Critical Accounting Estimates” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2006 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.

FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements by prescribing a recognition threshold (whether a tax position is more likely than not to be sustained) without which, the benefit of that position is not recognized in the financial statements.  It requires a measurement determination for recognized tax positions based on the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement.  FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.  FIN 48 requires that the cumulative effect of applying this interpretation be reported and disclosed as an adjustment to the opening balance of retained earnings for that fiscal year and presented separately.  We adopted FIN 48 effective January 1, 2007.  The effect of this interpretation on our financial statements was an unfavorable adjustment to retained earnings of $17 million.  See “FIN  48 “Accounting for Uncertainty in Income Taxes” and FASB Staff Position FIN 48-1 “Definition of Settlement in FASB Interpretation No. 48”” section of Note 2 and Note 8 – Income Taxes.

As a major power producer and marketer of wholesale electricity, coal and emission allowances, our Utility Operations segment is exposed to certain market risks.  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.

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 primarily financial derivatives, along with physical contracts, which will gradually liquidate and completely expire in 2011.  Our risk objective is to keep these positions generally risk neutral through maturity.

Our Generation and Marketing segment holds power sale contracts to commercial and industrial customers and wholesale power trading and marketing contracts within ERCOT.

We employ risk management contracts including physical forward purchase and sale contracts, exchange futures and options, over-the-counter options, swaps and other derivative contracts to offset price risk where appropriate.  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 management 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 Treasurer.  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, 2007 and the reasons for changes in our total MTM value included on our condensed consolidated balance sheet as compared to December 31, 2006.

The following table presents:

The determination of the point at which a market is no longer supported by independent quotes and therefore considered in the modeled category in the preceding table varies by market.  The following table generally 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 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 forward contracts and collars as cash flow hedges to lock in prices on certain transactions denominated in foreign currencies where deemed necessary.  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, 2006 to June 30, 2007.  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.  Only after an entity meets our internal credit rating criteria will we extend unsecured credit.  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.  We use our analysis, in conjunction with the rating agencies’ information, to determine appropriate risk parameters.  We also require cash deposits, letters of credit and parent/affiliate guarantees as security from counterparties depending upon credit quality in our normal course of business.

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, 2007, our credit exposure net of credit collateral to sub investment grade counterparties was approximately 4.9%, 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, 2007, 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, 2009.  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, 2007, 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:

The High VaR for 2006 occurred in mid-August during a period of high gas and power volatility.  The following day, positions were flattened and the VaR was significantly reduced.

We utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period.  The volatilities and correlations were based on three years of daily prices. The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $912 million at June 30, 2007 and $870 million at December 31, 2006.  We would not expect to liquidate our entire debt portfolio in a one-year holding period.  Therefore, a near term change in interest rates should not materially affect our results of operations, cash flows or financial position.