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 decreased $112and Extraordinary Loss increased $79 million to $253$238 million in 2007.  The key driverdrivers of the decrease wasincrease were a $246$172 million increase in Gross Margin partially offset by a $56 million increase in Operating Expenses and Other offset by a $74 million increase in Gross Margin and a $60$37 million decreaseincrease 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 $21$14 million in 2006 to $15$7 million in 2007.  The decrease wasWhile 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 a returnreduced steel and cement imports.  Operating expenses were up 11% over the same period in 2006 mainly due to normal winter river operating conditionsthe 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 milder and more favorable weather in 2006 and lower spot market ratesprimarily due to decreased barging demand caused by lower backhaul imports.the cost of the increased fleet size, fuel and wage increases.

LossIncome Before Discontinued Operations and Extraordinary Loss from our Generation and Marketing segment was $1increased from $2 million in 2007 compared2006 to income of $4$15 million in 2006.2007.  The decreaseincrease primarily relates to plannedfavorable marketing contracts with municipalities and forced outages atcooperatives in ERCOT.  Net revenues for our Oklaunion plantGeneration 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 2007 that limited the availability of power under lease.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.

Income Before Discontinued Operations and Extraordinary Loss from All Other increased from a $12$15 million loss in 2006 to income of $4$1 million in 2007.  In 2006, we had after-tax losses of $8 million in 2006 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 $59$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.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 59.4%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 March 31,June 30, 2007, our available liquidity was approximately $3.1$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.defined in our revolving credit agreements. At March 31,June 30, 2007, this contractually-defined percentage was 54.5%56.1%.  Nonperformance of these covenants could result in an event of default under these credit agreements.  At March 31,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 March 31,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 March 31,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 March 31,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 $150$833 million.  The weighted-average interest rate of our commercial paper duringfor the six months ended June 30, 2007 was 5.43%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 $351 million$1 billion in 2007 consisting primarily of2007. We produced Income Before Discontinued Operations of $271 million. Income Before Discontinued Operations included$449 million adjusted for noncash expense items, primarily for depreciation amortization, deferred taxes and deferred investment tax credits.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, nonethe most significant of which were significant.relates primarily to the Texas CTC refund of fuel over-recovery.

Net Cash Flows From Operating Activities were $583 million$1.1 billion in 2006.  We produced Income Before Discontinued Operations of $378 million. Income Before Discontinued Operations included$550 million adjusted for noncash expense items, primarily for depreciation amortization, deferred taxes and deferred investment tax credits.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 $99$185 million cash increase from net Accounts Receivable/Accounts Payable due to a lower balance of Customer Accounts Receivable at March 31,June 30, 2006 and an increasea $189 million decrease in Accrued Taxes of $176 million. We did not make a federal income tax payment during the first quarter of 2006.cash related to customer deposits held for trading activities.

Net Cash Flows Used For Investing Activities were $628 million$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 $750 million$1.6 billion in 2006 primarily due to Construction Expenditures.  Construction Expenditures increased due to our environmental investment plan.

We forecast approximately $2.6$1.7 billion of construction expenditures for the remainder of 2007 plus $427 million for announced purchases of gas-fired generating units.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 $235 million$1 billion primarily due to $150 millionissuing $1.1 billion of debt securities including $1 billion of new debt for plant acquisitions and construction and increasing short-term commercial paper borrowings under our credit facilities and issuing $250 million of debt securities.borrowings.  We paid common stock dividends of $155$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 $42$297 million.  During the first quarter of 2006, we issued $50$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.outstanding by $144 million.  The Other amount of $54$30 million in the above table primarily consists ofincludes $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.

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.

In January 2007, we signed a participation agreementCSPCo and OPCo are involved in discussions with MidAmerican Energy Holdings Company (MidAmerican)various stakeholders in Ohio about potential legislation to form a joint venture company, Electric Transmission Texas LLC (ETT),address the period following the expiration of the RSPs on December 31, 2008.  At this time, management is unable to fund, ownpredict whether CSPCo and operate electric transmission assets in ERCOT. ETT filedOPCo will transition to market pricing, as permitted by the current Ohio restructuring legislation, extend their RSP rates, 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 currently under construction and to establish a wholesale transmission tariff for ETT. ETT also requested approval from the PUCT of initial rates based on an 11.25% return on equity. A procedural schedule has been established in the case, with a hearing scheduled for June. We expect a final order from the PUCT in the third quarter.

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.  On February 1,In March 2007, the Texas District Court judge hearing the various appeals issued a letter containing his preliminary determinations. He generally affirmed the PUCT’s April 4, 2006 final true-up order for TCC with two significant exceptions.  The judge determined that the PUCT erred when it determined TCC’s stranded cost using the sale of assets method instead of the Excess Cost Over Market (ECOM) methodby applying an invalidated rule to value TCC’s nuclear plant. The judge also determined that the PUCT erred when it concluded it was required to usedetermine the carrying cost rate specified infor the true-up order.of stranded costs.  However, the District Court did not rule that the carrying cost rate was inappropriate.  He directed that these matters should be remanded to the PUCT to determine their specific impact on TCC’s future true-up revenues.

TCC, the PUCT and intervenors appealed the District Court rulingrulings to the Court of Appeals.  Management cannot predict what actions, if any, the PUCT will take regarding the carrying costs.

WeThe AEP East companies ceased collecting through-and-out transmission service (T&O)T&O revenues in accordance with FERC orders, and implementedcollected 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, thea 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 theThe Dayton Power and Light Company, filed an extensive post hearingpost-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 is contrary tocontradicts 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 they haveit 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 extendedamended the Virginia Electric Utility Restructuring Act extending the transition period to market rates for the generation and supply of electricity, restructuring, including the extension of capped rates, through December 31, 2010.  The legislation providesprovided 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 defershas the right to defer incremental environmental generationcompliance costs and incremental T&D reliabilityE&R costs for future recovery, to the extent such costs are not being recovered, when incurred, 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/generation and supply rates.  TheThese amendments shorten the transition period by two years (from 2010 to 2008) after which rates for retail generation/generation and supply will return to a form of cost-based regulation.regulation in lieu of market-based rates.  The legislation provides for, among other things, biennial rate reviews beginning in 2009,2009; rate adjustment clauses for the recovery of the costs of (a) transmission services and new transmission investment,investments, (b) Demand Side Management,demand side management, load management, and energy efficiency programs, (c) renewable energy programs, and (d) environmental retrofit and new generation investments,investments; significant return on equity enhancements for large 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 willto retain a minimum of 25% of the margins from off-system sales with the remaining margins from such sales credited against the fuel factor.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.  APCo expects thisThe new form of cost-based ratemakingre-regulation legislation should improve its annual returnresult 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 cash flow from operations whenthe new ratemaking beginsopportunities to request timely recovery of certain new costs not included in 2009. However, withbase rates.

With the return of cost-based regulation,new re-regulation legislation, APCo’s generation business will again meetmeets the criteria for application of regulatory accounting principles under SFAS 71.  Results of operationsThe extraordinary pretax reduction in APCo’s earnings and financial condition could be adversely affected when APCo is required to re-establish certain net regulatory liabilities applicable to its generation/supply business. The timing and earnings effectshareholder’s equity from such 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 APCo’s Virginia generation/supply businessqualifying SFAS 158 pension costs of the generation operations that, for ratemaking purposes, are uncertain at this time.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 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.  CSPCo and OPCo believeThe 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 I1 cost-related recoveries.

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 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.  SWEPCo will buildPlans include the construction of up to 480 MW of simple-cycle natural gas combustion turbine peaking generation in Tontitown, Arkansas and will build 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, of which SWEPCo’s investment will bewith 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 thethese 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.  TheMattison plant, the peaking generation facility in Tontitown, Arkansas has been approved by all three state commissions andcommissions.  Mattison plant Units 3 and 4 are projected to be onlinebegan commercial operation in July 2007, andwith the remaining two units by 2008.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 intermediate and base load facilitiesfacility and in 2008 on the intermediate facility, both upon approval from theSWEPCo’s three state regulatory commissions. Expenditures related to construction of these facilities are expected to total $349 million in 2007.

In July 2006, PSO announced plans to enter a joint ventureownership 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.  TheseThis new facilities arefacility is subject to regulatory approval from the OCC.OCC, which is expected later in 2007.  Construction of all of these additions is expected to begin in the second half of 2007.  Expenditures relatedThe Oklahoma Supreme Court is addressing whether the upfront approval process is constitutional.  PSO estimates construction expenditures for all of the new generation projects to construction of these facilities are expected to total $125be $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 an affiliate of Public Service Enterprise Group (PSEG) for approximately $325 million and the assumption of liabilities of approximately $2$3 million.  The transaction is expected to closeclosed 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 plans to sellsells the power to CSPCo throughunder a FERC-approved purchase power contract.

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:

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. The Federal EPA issued a final rule that would exclude activities similar to those challenged in these cases from NSR as “routine replacements.” In March 2006, the Court of Appeals for the District of Columbia Circuit issued a decision vacating the rule. The Court denied the Federal EPA’s request for rehearing, and the Federal EPA and other parties filed a petition for review by the U.S. Supreme Court. In April 2007, the Supreme Court denied the petition for review. The Federal EPA also proposed a rule that would define “emissions increases” in a way that would exclude most of the challenged activities from NSR.

OnIn April 2, 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 certain of the merits of thearguments in our NSR proceedings, brought against APCo, CSPCo, I&M and OPCo in U.S. District Court for the Southern District of Ohio, 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.  First, theThe court in the case for which a trial on liability issues has been conducted has indicated an intent to issue a decision on liability. Second,liability issues in the third quarter of 2007.  A bench trial on remedy issues, if necessary, is likely to be scheduled to begin in the third quartersecond 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.

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.

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 March 31,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.