ITEM 1.     BUSINESS

GENERAL

OVERVIEW AND DESCRIPTION OF SUBSIDIARIES

AEP was incorporated under the laws of the State of New York in 1906 and reorganized in 1925. It is a public utility holding company that owns, directly or indirectly, all of the outstanding common stock of its public utility subsidiaries and varying percentages of other subsidiaries.

The service areas of AEP’s public utility subsidiaries cover portions of the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. The generating and transmission facilities of AEP’s public utility subsidiaries are interconnected and their operations are coordinated. Transmission networks are interconnected with extensive distribution facilities in the territories served. The public utility subsidiaries of AEP have traditionally provided electric service, consisting of generation, transmission and distribution, on an integrated basis to their retail customers. Restructuring legislation in Michigan, Ohio, the ERCOT area of Texas and, through 2008, Virginia has caused AEP public utility subsidiaries in those states to unbundle previously integrated regulated rates for their retail customers.

The AEP System is an integrated electric utility system. As a result, the member companies of the AEP System have contractual, financial and other business relationships with the other member companies, such as participation in the AEP System savings and retirement plans and tax returns, sales of electricity and transportation and handling of fuel. The companies of the AEP System also obtain certain accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost from a common provider, AEPSC.

At December 31, 2007, the subsidiaries of AEP had a total of 20,861 employees. Because it is a holding company rather than an operating company, AEP has no employees. The public utility subsidiaries of AEP are:

APCo   (organized in Virginia in 1926) is engaged in the generation, transmission and distribution of electric power to approximately 956,000 retail customers in the southwestern portion of Virginia and southern West Virginia, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. At December 31, 2007, APCo and its wholly owned subsidiaries had 2,497 employees.  Among the principal industries served by APCo are coal mining, primary metals, chemicals and textile mill products. In addition to its AEP System interconnections, APCo is interconnected with the following unaffiliated utility companies: Carolina Power & Light Company, Duke Carolina and Virginia Electric and Power Company. APCo has several points of interconnection with TVA and has entered into agreements with TVA under which APCo and TVA interchange and transfer electric power over portions of their respective systems.  APCo is a member of PJM.

CSPCo   (organized in Ohio in 1937, the earliest direct predecessor company having been organized in 1883) is engaged in the generation, transmission and distribution of electric power to approximately 746,000 retail customers in Ohio, and in supplying and marketing electric power at wholesale to other electric utilities, municipalities and other market participants. At December 31, 2007, CSPCo had 1,265 employees. CSPCo’s service area is comprised of two areas in Ohio, which include portions of twenty-five counties. One area includes the City of Columbus and the other is a predominantly rural area in south central Ohio. Among the principal industries served are food processing, chemicals, primary metals, electronic machinery and paper products. In addition to its AEP System interconnections, CSPCo is interconnected with the following unaffiliated utility companies: Duke Ohio, DP&L and Ohio Edison Company.  CSPCo is a member of PJM.

I&M   (organized in Indiana in 1925) is engaged in the generation, transmission and distribution of electric power to approximately 583,000 retail customers in northern and eastern Indiana and southwestern Michigan, and in supplying and marketing electric power at wholesale to other electric utility companies, rural electric cooperatives, municipalities and other market participants.  At December 31, 2007, I&M had 2,687 employees. Among the principal industries served are primary metals, transportation equipment, electrical and electronic machinery, fabricated metal products, rubber and miscellaneous plastic products and chemicals and allied products. Since 1975, I&M has leased and operated the assets of the municipal system of the City of Fort Wayne, Indiana. This lease currently extends through February 2010.  In addition to its AEP System interconnections, I&M is interconnected with the following unaffiliated utility companies: Central Illinois Public Service Company, Duke Ohio, Commonwealth Edison Company, Consumers Energy Company, Illinois Power Company, Indianapolis Power & Light Company, Louisville Gas and Electric Company, Northern Indiana Public Service Company, Duke Indiana and Richmond Power & Light Company.  I&M is a member of PJM.

KPCo   (organized in Kentucky in 1919) is engaged in the generation, transmission and distribution of electric power to approximately 176,000 retail customers in an area in eastern Kentucky, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants.  At December 31, 2007, KPCo had 471 employees. In addition to its AEP System interconnections, KPCo is interconnected with the following unaffiliated utility companies: Kentucky Utilities Company and East Kentucky Power Cooperative Inc. KPCo is also interconnected with TVA.  KPCo is a member of PJM.

Kingsport Power Company   (organized in Virginia in 1917) provides electric service to approximately 47,000 retail customers in Kingsport and eight neighboring communities in northeastern Tennessee. Kingsport Power Company does not own any generating facilities and is a member of PJM. It purchases electric power from APCo for distribution to its customers. At December 31, 2007, Kingsport Power Company had 57 employees.

OPCo   (organized in Ohio in 1907 and re-incorporated in 1924) is engaged in the generation, transmission and distribution of electric power to approximately 712,000 retail customers in the northwestern, east central, eastern and southern sections of Ohio, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. At December 31, 2007, OPCo had 2,351 employees. Among the principal industries served by OPCo are primary metals, rubber and plastic products, stone, clay, glass and concrete products, petroleum refining and chemicals. In addition to its AEP System interconnections, OPCo is interconnected with the following unaffiliated utility companies: Duke Ohio, The Cleveland Electric Illuminating Company, DP&L, Duquesne Light Company, Kentucky Utilities Company, Monongahela Power Company, Ohio Edison Company, The Toledo Edison Company and West Penn Power Company.  OPCo is a member of PJM.

PSO   (organized in Oklahoma in 1913) is engaged in the generation, transmission and distribution of electric power to approximately 525,000 retail customers in eastern and southwestern Oklahoma, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. At December 31, 2007, PSO had 1,255 employees. Among the principal industries served by PSO are natural gas and oil production, oil refining, steel processing, aircraft maintenance, paper manufacturing and timber products, glass, chemicals, cement, plastics, aerospace manufacturing, telecommunications, and rubber goods. In addition to its AEP System interconnections, PSO is interconnected with Ameren Corporation, Empire District Electric Company, Oklahoma Gas and Electric Company, Southwestern Public Service Company and Westar Energy, Inc.  PSO is a member of SPP.

SWEPCo   (organized in Delaware in 1912) is engaged in the generation, transmission and distribution of electric power to approximately 467,000 retail customers in northeastern Texas, northwestern Louisiana and western Arkansas, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. At December 31, 2007, SWEPCo had 1,578 employees. Among the principal industries served by SWEPCo are natural gas and oil production, petroleum refining, manufacturing of pulp and paper, chemicals, food processing, and metal refining. The territory served by SWEPCo also includes several military installations, colleges, and universities. SWEPCO also owns and operates a lignite coal mining operation.  In addition to its AEP System interconnections, SWEPCo is interconnected with CLECO Corp., Empire District Electric Co., Entergy Corp. and Oklahoma Gas & Electric Co.  SWEPCo is a member of SPP.

TCC (organized in Texas in 1945) is engaged in the transmission and distribution of electric power to approximately 753,000 retail customers through REPs in southern Texas. Under the Texas Act, TCC has completed the final stage of exiting the generation business and has sold all of its generation assets.  At December 31, 2007, TCC had 1,195 employees. Among the principal industries served by TCC are oil and gas extraction, food processing, apparel, metal refining, chemical and petroleum refining, plastics, and machinery equipment. In addition to its AEP System interconnections, TCC is a member of ERCOT.

TNC   (organized in Texas in 1927) is engaged in the transmission and distribution of electric power to approximately 184,000 retail customers through REPs in west and central Texas. TNC’s remaining generating capacity that is not deactivated has been transferred to an affiliate at TNC’s cost pursuant to a 20-year agreement.  At December 31, 2007, TNC had 373 employees. Among the principal industries served by TNC are agriculture and the manufacturing or processing of cotton seed products, oil products, precision and consumer metal products, meat products and gypsum products. The territory served by TNC also includes several military installations and correctional facilities. In addition to its AEP System interconnections, TNC is a member of ERCOT.

WPCo (organized in West Virginia in 1883 and reincorporated in 1911) provides electric service to approximately 41,000 retail customers in northern West Virginia. WPCo does not own any generating facilities.  WPCo is a member of PJM. It purchases electric power from OPCo for distribution to its customers. At December 31, 2007, WPCo had 61 employees.

AEGCo   (organized in Ohio in 1982) is an electric generating company. AEGCo sells power at wholesale to I&M, CSPCo and KPCo. AEGCo has no employees.

SERVICE COMPANY SUBSIDIARY

AEP also owns a service company subsidiary, AEPSC.  AEPSC provides accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost to the AEP affiliated companies.  The executive officers of AEP and certain of its public utility subsidiaries are employees of AEPSC.  At December 31, 2007, AEPSC had 6,151 employees.

(a)	Includes revenues of other subsidiaries not shown. Intercompany transactions have been eliminated for the year ended December 31, 2007.

FINANCING

General

Companies within the AEP System generally use short-term debt to finance working capital needs.  Short-term debt is also used to finance acquisitions, construction and redemption or repurchase of outstanding securities until such needs can be financed with long-term debt. In recent history, short-term funding needs have been provided for by cash on hand and AEP’s commercial paper program.  Funds are made available to subsidiaries under the AEP corporate borrowing program. Certain public utility subsidiaries of AEP also sell accounts receivable to provide liquidity.

AEP’s revolving credit agreements (which backstop the commercial paper program) include covenants and events of default typical for this type of facility, including a maximum debt/capital test and a $50 million cross-acceleration provision. At December 31, 2007, AEP was in compliance with its debt covenants. With the exception of a voluntary bankruptcy or insolvency, any event of default has either or both a cure period or notice requirement before termination of the agreements. A voluntary bankruptcy or insolvency would be considered an immediate termination event.  See Management’s Financial Discussion and Analysis of Results of Operations , included in the 2007 Annual Reports, under the heading entitled Financial Condition for additional information with respect to AEP’s credit agreements.

AEP’s subsidiaries have also utilized, and expect to continue to utilize, additional financing arrangements, such as leasing arrangements, including the leasing of coal transportation equipment and facilities.

Credit Ratings

AEP’s senior unsecured debt is rated Baa2 by Moody’s and BBB by S&P and Fitch.  AEP’s commercial paper is rated Prime-2 by Moody’s, A2 by S&P and F2 by Fitch.  There were no changes in the ratings or rating outlook for AEP by Moody’s, S&P or Fitch during 2007.  In February 2008 Fitch downgraded the senior unsecured debt rating of PSO to BBB+ with stable outlook.  Fitch downgraded the senior unsecured debt rating of TCC (to BBB+) in April 2007 and placed it on negative outlook until November 2007, when Fitch restored its stable outlook.  Fitch revised TNC’s outlook from negative to stable in April 2007.  Moody’s placed the senior unsecured debt rating of APCo, OPCo, SWEPCo and TCC on negative outlook in January 2008.  Moody’s assigns the following ratings to the senior unsecured debt of these companies:  APCo Baa2, OPCo A3, SWEPCo Baa1 and TCC Baa2.  See Management’s Financial Discussion and Analysis of Results of Operations , included in the 2007 Annual Reports, under the heading entitled Financial Condition for additional information with respect to the credit ratings of the registrants.

ENVIRONMENTAL AND OTHER MATTERS

General

AEP’s subsidiaries are currently subject to regulation by federal, state and local authorities with regard to air and water-quality control and other environmental matters, and are subject to zoning and other regulation by local authorities. The environmental issues that are potentially material to the AEP system include:

·	Global climate change and legislative responses to it, including limitations on CO 2 emissions.  See Management’s Financial Discussion and Analysis of Results of Operations under the headings entitled Environmental Matters – Potential Regulation of CO 2 and GHG Emissions.

·

The CAA and CAAA and state laws and regulations (including State Implementation Plans) that require compliance, obtaining permits and reporting as to air emissions. See Management’s Financial Discussion and Analysis of Results of Operations under the headings entitled Environmental Matters - Clean Air Act Requirements and Estimated Air Quality Environmental Investments .

·

Litigation with the federal and certain state governments and certain special interest groups regarding regulated air emissions and/or whether emissions from coal-fired generating plants cause or contribute to global climate changes. See Management’s Financial Discussion and Analysis of Results of Operations under the heading entitled Environmental Matters - Environmental Litigation and Note 6 to the consolidated financial statements entitled Commitments, Guarantees and Contingencies , included in the 2007 Annual Reports, for further information.

·

Rules issued by the EPA and certain states that require substantial reductions in SO 2 , mercury and NOx emissions, which have compliance dates that take effect periodically through as late as 2018. AEP is installing (and has installed) emission control technology and is taking other measures to comply with required reductions. See Management’s Financial Discussion and Analysis of Results of Operations under the headings entitled Environmental Matters - Clean Air Act Requirements and Estimated Air Quality Environmental Investments included in the 2007 Annual Reports for further information.

·

CERCLA, which imposes costs for environmental remediation upon owners and previous owners of sites, as well as transporters and generators of hazardous material disposed of at such sites.  See Note 6 to the consolidated financial statements entitled Commitments, Guarantees and Contingencies , included in the 2007 Annual Reports, under the heading entitled The Comprehensive Environmental Response Compensation and Liability Act ( Superfund) and State Remediation for further information .

·

The Federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits. See Management’s Financial Discussion and Analysis of Results of Operations , included in the 2007 Annual Reports, under the heading entitled Environmental Matters - Clean Water Act Regulations for additional information.

·

Solid and hazardous waste laws and regulations, which govern the management and disposal of certain wastes. The majority of solid waste created from the combustion of coal and fossil fuels is fly ash and other coal combustion byproducts, which the EPA has determined are not hazardous waste subject to RCRA.

In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. See Management’s Financial Discussion and Analysis of Results of Operations under the heading entitled Environmental Matters , included in the 2007 Annual Reports,   for further information with respect to environmental issues .

While we expect to recover our expenditures for pollution control technologies, replacement generation and associated operating costs from customers through regulated rates (in regulated jurisdictions) or market prices (in Ohio and Texas), without such recovery those costs could adversely affect future results of operations and cash flows, and possibly financial condition.  The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the AEP System.  In October 2007, we settled the New Source Review litigation with the EPA, the United States Department of Justice, various states and special interest groups.  The litigation challenged whether modifications to or maintenance of certain coal-fired generating plants required additional permitting or pollution control technology.  In settling, we agreed to invest in additional environmental controls for our plants before 2019.  We also paid a $15 million civil penalty and will provide $36 million for environmental projects coordinated with the federal government and $24 million to the states for environmental mitigation.  See Management’s Financial Discussion and Analysis of Results of Operations under the heading entitled Environmental Matters and Note 6 to the consolidated financial statements entitled Commitments, Guarantees and Contingencies, included in the 2007 Annual Reports, for more information regarding the settled litigation and other environmental matters.

Environmental Investments

Investments related to improving AEP System plants’ environmental performance and compliance with air and water quality standards during 2005, 2006 and 2007 and the current estimates for 2008, 2009 and 2010 are shown below, in each case excluding AFUDC or capitalized interest. AEP expects to make substantial investments in addition to the amounts set forth below in future years in connection with the modification and addition of facilities at generating plants for environmental quality controls.  Such future investments are needed in order to comply with air and water quality standards which have been adopted and have deadlines for compliance after 2010 or have been proposed and may be adopted.  Future investments could be significantly greater if emissions reduction requirements are accelerated or otherwise become more onerous or if CO 2 becomes regulated. See Management’s Financial Discussion and Analysis of Results of Operations under the heading entitled Environmental Matters and   Note 6 to the consolidated financial statements, entitled Commitments, Guarantees and Contingencies, included in the 2007 Annual Reports, for more information regarding environmental expenditures in general.

*	Includes expenditures of both the subsidiaries shown below and other subsidiaries not shown. The figures reflect  construction expenditures, not investments in subsidiary companies.  Excludes discontinued operations.

Electric and Magnetic Fields

EMF are found everywhere there is electricity. Electric fields are created by the presence of electric charges. Magnetic fields are produced by the flow of those charges. This means that EMF are created by electricity flowing in transmission and distribution lines, electrical equipment, household wiring, and appliances.  A number of studies in the past several years have examined the possibility of adverse health effects from EMF. While some of the epidemiological studies have indicated some association between exposure to EMF and health effects, none has produced any conclusive evidence that EMF does or does not cause adverse health effects.

Management cannot predict the ultimate impact of the question of EMF exposure and adverse health effects. If further research shows that EMF exposure contributes to increased risk of cancer or other health problems, or if the courts conclude that EMF exposure harms individuals and that utilities are liable for damages, or if states limit the strength of magnetic fields to such a level that the current electricity delivery system must be significantly changed, then the results of operations and financial condition of AEP and its operating subsidiaries could be materially adversely affected unless these costs can be recovered from customers.

 

UTILITY OPERATIONS

GENERAL

Utility operations constitute most of AEP’s business operations.  Utility operations include (i) the generation, transmission and distribution of electric power to retail customers and (ii) the supplying and marketing of electric power at wholesale (through the electric generation function) to other electric utility companies, municipalities and other market participants.  AEPSC, as agent for AEP’s public utility subsidiaries, performs marketing, generation dispatch, fuel procurement and power-related risk management and trading activities.

ELECTRIC GENERATION

Facilities

AEP’s public utility subsidiaries own or lease approximately 37,000 MW of domestic generation. See Item 2 — Properties for more information regarding AEP’s generation capacity.

AEP Power Pool and CSW Operating Agreement

APCo, CSPCo, I&M, KPCo and OPCo are parties to the Interconnection Agreement defining how they share the costs and benefits associated with their generating plants. This sharing is based upon each company’s “member-load-ratio.” The Interconnection Agreement has been approved by the FERC.  The member-load-ratio is calculated monthly by dividing such company’s highest monthly peak demand for the last twelve months by the aggregate of the highest monthly peak demand for the last twelve months for all AEP East companies. As of December 31, 2007, the member-load-ratios were as follows:

Ohio’s electric restructuring law, the Ohio Act, was enacted in 2001.  To comply with that law CSPCo and OPCo functionally separated their generation business from their remaining operations.  They plan to remain functionally separated through at least December 31, 2008 as authorized by their rate stabilization plans approved by the PUCO. As permitted by the Ohio Act, CSPCo and OPCo can implement market-based rates effective January 2009, following the expiration of their RSPs on December 31, 2008.  CSPCo and OPCo have been involved in discussions with various stakeholders in Ohio about proposed legislation to address the period following the expiration of the rate stabilization plans.  See Note 4 to the consolidated financial statements, entitled Rate Matters , included in the 2007 Annual Reports, for more information.

Since 1995, APCo, CSPCo, I&M, KPCo and OPCo have been parties to the AEP System Interim Allowance Agreement (Allowance Agreement), which provides, among other things, for the transfer of emission allowances associated with transactions under the Interconnection Agreement.  The following table shows the net (credits) or charges allocated among the parties under the Interconnection Agreement during the years ended December 31, 2005, 2006 and 2007:

PSO, SWEPCo and AEPSC are parties to a Restated and Amended Operating Agreement originally dated as of January 1, 1997 (CSW Operating Agreement), which has been approved by the FERC. The CSW Operating Agreement requires these public utility subsidiaries to maintain adequate annual planning reserve margins and requires the subsidiaries that have capacity in excess of the required margins to make such capacity available for sale to other public utility subsidiary parties as capacity commitments. Parties are compensated for energy delivered to the recipients based upon the deliverer’s incremental cost plus a portion of the recipient’s savings realized by the purchaser that avoids the use of more costly alternatives.  Revenues and costs arising from third party sales in their region are generally shared based on the amount of energy each west zone public utility subsidiary contributes that is sold to third parties.  The separation of the generation business undertaken by TCC and TNC to comply with the Texas Act has made their business operations incompatible with the CSW Operating Agreement.  As a result, with FERC approval, these companies are no longer parties to, and no longer supply generating capacity under, the CSW Operating Agreement.

The following table shows the net (credits) or charges allocated among the parties under the CSW Operating Agreement during the years ended December 31, 2005, 2006 and 2007:

	2005	2006	2007
	(in thousands)
PSO	$27,600	$(15,300)	$(17,500)
SWEPCo	(27,500)	9,900	16,800
TCC	0	0	0
TNC	(100)	5,400	700

Power generated by or allocated or provided under the Interconnection Agreement or CSW Operating Agreement to any public utility subsidiary is primarily sold to customers by such public utility subsidiary at rates approved by the public utility commission in the jurisdiction of sale. In Ohio and Virginia, such rates are based on a statutory formula as Ohio considers continuing to transition to the use of market rates for generation and as Virginia completes it final year of transition before returning to a form of cost-based regulation. See Regulation — Rates under Item 1, Utility Operations .

Under both the Interconnection Agreement and CSW Operating Agreement, power that is not needed to serve the native load of our public utility subsidiaries is sold in the wholesale market by AEPSC on behalf of those subsidiaries.  See Risk Management and Trading , below , for a discussion of the trading and marketing of such power.

AEP’s System Integration Agreement, which has been approved by the FERC, provides for the integration and coordination of AEP’s East companies, PSO and SWEPCO. This includes joint dispatch of generation within the AEP System and the distribution, between the two zones, of costs and benefits associated with the transfers of power between the two zones (including sales to third parties and risk management and trading activities). It is designed to function as an umbrella agreement in addition to the Interconnection Agreement and the CSW Operating Agreement, each of which controls the distribution of costs and benefits for activities within each zone.  Because TCC and TNC have exited the generation business, these two companies are no longer parties to the System Integration Agreement.

Risk Management and Trading

As agent for AEP’s public utility subsidiaries, AEPSC sells excess power into the market and engages in power, natural gas, coal and emissions allowances risk management and trading activities focused in regions in which AEP traditionally operates. These activities primarily involve the purchase and sale of electricity (and to a lesser extent, natural gas, coal and emissions allowances) under physical forward contracts at fixed and variable prices. These contracts include physical transactions, over-the-counter swaps and exchange-traded futures and options. The majority of physical forward contracts are typically settled by entering into offsetting contracts.   These transactions are executed with numerous counterparties or on exchanges. Counterparties and exchanges may require cash or cash related instruments to be deposited on these transactions as margin against open positions. As of December 31, 2007, counterparties and exchanges have posted approximately $43 million in cash, cash equivalents or letters of credit with AEPSC for the benefit of AEP’s public utility subsidiaries (while, as of that date, AEP’s public utility subsidiaries had posted approximately $77 million with counterparties and exchanges).  Since open trading contracts are valued based on market power prices, exposures change daily.

Variations in the generation of nuclear power are primarily related to refueling and maintenance outages.  Price increases in one or more fuel sources relative to other fuels generally result in increased use of other fuels.

Coal and Lignite : AEP’s public utility subsidiaries procure coal and lignite under a combination of purchasing arrangements including long-term contracts, affiliate operations and spot agreements with various producers and coal trading firms.  The price for most solid fuels generally has been increasing. Management has responded to increases in the price of coal by rebalancing the coal used in its generating facilities with coal from different coal regions and sources that have different heat and sulfur contents.  This rebalancing is an ongoing process that is expected to continue, significantly enabled by the installation of scrubbers at a number of our generating facilities. Management believes that AEP’s public utility subsidiaries will be able to secure and transport coal and lignite of adequate quality and in adequate quantities to operate their coal and lignite-fired units.  Through subsidiaries, AEP owns, leases or controls more than 8,400 railcars, 692 barges, 16 towboats and a coal handling terminal with 20 million tons of annual capacity to move and store coal for use in its generating facilities.  See MEMCO Operations for a discussion of AEP’s for-profit coal and other dry-bulk commodity transportation operations that are not part of AEP’s Utility Operations segment.

The following table shows the amount of coal and lignite delivered to the AEP System plants during the past three years and the average delivered price of coal purchased by System companies:

	2005	2006	2007
Total coal delivered to AEP System plants (thousands of tons)	72,321	76,045	72,644
Average price per ton of purchased coal	$32.84	$35.27	$36.65

The coal supplies at AEP System plants vary from time to time depending on various factors, including, but not limited to, demand for electric power, unit outages, transportation infrastructure limitations, space limitations, plant coal consumption rates, labor issues and weather conditions which may interrupt production or deliveries. At December 31, 2007, the System’s coal inventory was approximately 29 - 33 days of normal usage.  This estimate assumes that the total supply would be utilized through the operation of plants that use coal most efficiently.

In cases of emergency or shortage, System companies have developed programs to conserve coal supplies at their plants. Such programs have been filed and reviewed with officials of federal and state agencies and, in some cases, the relevant state regulatory agency has prescribed actions to be taken under specified circumstances by System companies, subject to the jurisdiction of such agency.

The FERC has adopted regulations relating, among other things, to the circumstances under which, in the event of fuel emergencies or shortages, it might order electric utilities to generate and transmit electric power to other regions or systems experiencing fuel shortages, and to ratemaking principles by which such electric utilities would be compensated. In addition, the federal government is authorized, under prescribed conditions, to reallocate coal and to require the transportation thereof, for the use at power plants or major fuel-burning installations experiencing fuel shortages.

Natural Gas : Through its public utility subsidiaries, AEP consumed over 108 billion cubic feet of natural gas during 2007 for generating power. A portfolio of long-term, monthly, seasonal firm and daily peaking purchase and transportation agreements (that are entered into on a competitive basis and based on market prices) supplies natural gas requirements for each plant.

Nuclear:   I&M has made commitments to meet the current nuclear fuel requirements of the Cook Plant. I&M has made and will make purchases of uranium in various forms in the spot, short-term, and mid-term markets. I&M also leases nuclear fuel.

For purposes of the storage of high-level radioactive waste in the form of spent nuclear fuel, I&M completed modifications to its spent nuclear fuel storage pool more than 10 years ago. I&M anticipates that the Cook Plant has sufficient storage capacity for its spent nuclear fuel to permit normal operations through 2013.  I&M has entered into an agreement to provide for onsite dry cask storage.

Nuclear Waste and Decommissioning

As the owner of the Cook Plant, I&M has a significant future financial commitment to dispose of spent nuclear fuel and decommission and decontaminate the plant safely. The cost to decommission a nuclear plant is affected by NRC regulations and the spent nuclear fuel disposal program.  In 2006, when the most recent study was done, the estimated cost of decommissioning and disposal of low-level radioactive waste for the Cook Plant ranged from $733 million to $1.3 billion in 2006 non-discounted dollars.  At December 31, 2007, the total decommissioning trust fund balance for the Cook Plant was $1.057 billion.  The ultimate cost of retiring the Cook Plant may be materially different from estimates and funding targets as a result of the:

·	Type of decommissioning plan selected;

·	Escalation of various cost elements (including, but not limited to, general inflation and the cost of energy);

·	Further development of regulatory requirements governing decommissioning;

·	Technology available at the time of decommissioning differing significantly from that assumed in studies;

·	Availability of nuclear waste disposal facilities; and

·	Availability of a DOE facility for permanent storage of spent nuclear fuel.

Accordingly, management is unable to provide assurance that the ultimate cost of decommissioning the Cook Plant will not be significantly different than current projections.  We will seek recovery from customers through our regulated rates if actual decommissioning costs exceed our projections.  See Note 10 to the consolidated financial statements, entitled Nuclear , included in the 2007 Annual Reports, for information with respect to nuclear waste and decommissioning.

Low-Level Radioactive Waste : The LLWPA mandates that the responsibility for the disposal of low-level radioactive waste rests with the individual states. Low-level radioactive waste consists largely of ordinary refuse and other items that have come in contact with radioactive materials. Michigan does not currently have a disposal site for such waste available. I&M cannot predict when such a site may be available, but South Carolina and Utah license low-level radioactive waste disposal sites which currently accept low-level radioactive waste from Michigan.  I&M’s access to the Barnwell, South Carolina facility is currently allowed through the end of fiscal year 2008.  With some modifications to existing facilities, I&M will have capacity for onsite storage of that waste currently shipped to Barnwell, South Carolina for the duration of its licensed operation of Cook Plant.  There is currently no set date limiting I&M’s access to the Utah facility; however this facility does not accept all classifications of low level waste.

Structured Arrangements Involving Capacity, Energy, and Ancillary Services

In January 2000, OPCo and NPC, an affiliate of Buckeye, entered into an agreement relating to the construction and operation of a 510 MW gas-fired electric generating peaking facility to be owned by NPC and called the Mone Plant.  OPCo is entitled to 100% of the power generated by the Mone Plant, and is responsible for the fuel and other costs of the facility through May 2012, as extended. Following that, NPC and OPCo will be entitled to 80% and 20%, respectively, of the power of the Mone Plant, and both parties will generally be responsible for their allocable portion of the fuel and other costs of the facility.

Certain Power Agreements

I&M : The Unit Power Agreement between AEGCo and I&M, dated March 31, 1982, provides for the sale by AEGCo to I&M of all the capacity (and the energy associated therewith) available to AEGCo at the Rockport Plant. Whether or not power is available from AEGCo, I&M is obligated to pay a demand charge for the right to receive such power (and an energy charge for any associated energy taken by I&M).  The agreement will continue in effect until the last of the lease terms of Unit 2 of the Rockport Plant has expired (currently December 2022) unless extended in specified circumstances.

Pursuant to an assignment between I&M and KPCo, and a unit power agreement between KPCo and AEGCo, AEGCo sells KPCo 30% of the capacity (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo has agreed to pay to AEGCo the amounts that I&M would have paid AEGCo under the terms of the Unit Power Agreement between AEGCo and I&M for such entitlement. The KPCo unit power agreement expires in December 2022.

CSPCo : The Unit Power Agreement between AEGCo and CSPCo, dated March 15, 2007, provides for the sale by AEGCo to CSPCo of all the capacity and associated unit contingent energy and ancillary services available to AEGCo at the Lawrenceburg Plant that are scheduled and dispatched by CSPCo.  CSPCo is obligated to pay a capacity charge (whether or not power is available from the Lawrenceburg Plant), the fuel, operating and maintenance charges associated with the energy dispatched by CSPCo, and to reimburse AEGCo for other costs associated with the operation and ownership of the Lawrenceburg Plant.  The agreement will continue in effect until December 31, 2017 unless extended as set forth in the agreement.

OVEC:   AEP and several unaffiliated utility companies jointly own OVEC. The aggregate equity participation of AEP in OVEC is 43.47%.  Until September 1, 2001, OVEC supplied from its generating capacity the power requirements of a uranium enrichment plant near Portsmouth, Ohio owned by the DOE.  The sponsoring companies are now entitled to receive and obligated to pay for all OVEC capacity (approximately 2,200 MW) in proportion to their respective power participation ratios.  The aggregate power participation ratio of APCo, CSPCo, I&M and OPCo is 43.47%. The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs and to provide a return on its equity capital.  The Amended and Restated Inter-Company Power Agreement, which defines the rights of the owners and sets the power participation ratio of each, will expire by its terms on March 12, 2026.  AEP and the other owners have been evaluating the need for environmental investments related to their ownership interests, which are material.  In December 2006, OVEC’s Board of Directors authorized interim capital expenditures totaling $366 million in order to complete detailed engineering and began construction of flue gas desulfurization (sulfur dioxide scrubber) projects and the associated scrubber waste disposal landfills.  In November 2007, OVEC’s Board of Directors authorized additional interim capital expenditures of up to $82.8 million for completion of the associated scrubber waste disposal landfills.  If approved, the estimated total cost to complete the scrubber and landfill projects would be in excess of $1 billion, which OVEC would expect to finance through issuing debt.

ELECTRIC TRANSMISSION AND DISTRIBUTION

General

AEP’s public utility subsidiaries (other than AEGCo) own and operate transmission and distribution lines and other facilities to deliver electric power. See Item 2—Properties for more information regarding the transmission and distribution lines. Most of the transmission and distribution services are sold, in combination with electric power, to retail customers of AEP’s public utility subsidiaries in their service territories. These sales are made at rates established and approved by the state utility commissions of the states in which they operate, and in some instances, approved by the FERC. See Regulation—Rates . The FERC regulates and approves the rates for wholesale transmission transactions. See Item 1 –Utility Operations - Regulation—FERC . As discussed below, some transmission services also are separately sold to non-affiliated companies.

AEP’s public utility subsidiaries (other than AEGCo) hold franchises or other rights to provide electric service in various municipalities and regions in their service areas. In some cases, these franchises provide the utility with the exclusive right to provide electric service. These franchises have varying provisions and expiration dates. In general, the operating companies consider their franchises to be adequate for the conduct of their business. For a discussion of competition in the sale of power, see Item 1 –Utility Operations - Competition .

AEP Transmission Pool

Transmission Equalization Agreement:   APCo, CSPCo, I&M, KPCo and OPCo operate their transmission lines as a single interconnected and coordinated system and are parties to the TEA, defining how they share the costs and benefits associated with their relative ownership of the extra-high-voltage transmission system (facilities rated 345kV and above) and certain facilities operated at lower voltages (138kV up to 345kV). The TEA has been approved by the FERC. Sharing under the TEA is based upon each company’s “member-load-ratio.” The member-load-ratio is calculated monthly by dividing such company’s highest monthly peak demand for the last twelve months by the aggregate of the highest monthly peak demand for the last twelve months for all east zone operating companies.  The respective peak demands and member-load-ratios as of December 31, 2007 are set forth above in the section titled ELECTRIC GENERATION – AEP Power Pool and CSW Operating Agreement.

 

The following table shows the net (credits) or charges allocated among the parties to the TEA during the years ended December 31, 2005, 2006 and 2007:

Transmission Coordination Agreement:   PSO, SWEPCo, TCC, TNC and AEPSC are parties to the TCA, which has been approved by the FERC.  Under the TCA, a coordinating committee is charged with the responsibility of (i) overseeing the coordinated planning of the transmission facilities of the AEP West companies, including the performance of transmission planning studies, (ii) the interaction of such subsidiaries with independent system operators and other regional bodies interested in transmission planning and (iii) compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such tariff.  Pursuant to the TCA, the AEP West companies have delegated to AEPSC responsibility for monitoring the reliability of their transmission systems and administering the AEP OATT on their behalf. Prior to September 2005, the TCA also provided for the allocation among the AEP West companies of revenues collected for transmission and ancillary services provided under the AEP OATT.  Since then, these allocations have been determined by the FERC-approved OATT for the SPP (with respect to PSO and SWEPCo) and PUCT-approved protocols for ERCOT (with respect to TCC and TNC).

The following table shows the net (credits) or charges allocated among the parties to the TCA prior to September 2005, and pursuant to the SPP OATT and ERCOT protocols as described above during the years ended December 31, 2005, 2006 and 2007:

Transmission Services for Non-Affiliates:   In addition to providing transmission services in connection with their own power sales, AEP’s public utility subsidiaries through RTOs also provide transmission services for non-affiliated companies. See Item 1 –Utility Operations - Regional Transmission Organizations, below . Transmission of electric power by AEP’s public utility subsidiaries is regulated by the FERC.

Coordination of East and West Zone Transmission:   AEP’s System Transmission Integration Agreement provides for the integration and coordination of the planning, operation and maintenance of the transmission facilities of AEP East and AEP West companies. The System Transmission Integration Agreement functions as an umbrella agreement in addition to the TEA and the TCA. The System Transmission Integration Agreement contains two service schedules that govern:

·	The allocation of transmission costs and revenues and

·	The allocation of third-party transmission costs and revenues and System dispatch costs.

The System Transmission Integration Agreement contemplates that additional service schedules may be added as circumstances warrant.

Regional Transmission Organizations

The AEP East Companies are members of PJM (a FERC-approved RTO).  SWEPCo and PSO are members of the SPP (another FERC-approved RTO).  RTOs operate, plan and control utility transmission assets in a manner designed to provide open access to such assets in a way that prevents discrimination between participants owning transmission assets and those that do not. The remaining AEP West companies (TCC and TNC) are members of ERCOT. See Note 4 to the consolidated financial statements, entitled Rate Matters , included in the 2007 Annual Reports under the heading entitled RTO Formation/Integration Costs and Transmission Rate Proceedings at the FERC for a discussion of public utility subsidiary participation in RTOs.

REGULATION

General

Except for transmission and/or retail generation sales in certain of its jurisdictions, AEP’s public utility subsidiaries’ retail rates and certain other matters are subject to traditional regulation by the state utility commissions.  See Item 1 – Utility Operations - Electric Restructuring and Customer Choice Legislation and Rates, below. AEP’s subsidiaries are also subject to regulation by the FERC under the FPA.  I&M is subject to regulation by the NRC under the Atomic Energy Act of 1954, as amended, with respect to the operation of the Cook Plant.  AEP and its public utility subsidiaries are also subject to the regulatory provisions of EPACT, much of which is administered by the FERC.  EPACT contains key provisions affecting the electric power industry such as giving the FERC “backstop” transmission siting authority as well as increased utility merger oversight.  The law also provides incentives and funding for clean coal technologies and initiatives to voluntarily reduce greenhouse gases.

Rates

Historically, state utility commissions have established electric service rates on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its cost of providing service and to earn a reasonable return on its investment used in providing that service. A utility’s cost of service generally reflects its operating expenses, including operation and maintenance expense, depreciation expense and taxes. State utility commissions periodically adjust rates pursuant to a review of (i) a utility’s revenues and expenses during a defined test period and (ii) such utility’s level of investment. Absent a legal limitation, such as a law limiting the frequency of rate changes or capping rates for a period of time, a state utility commission can review and change rates on its own initiative. Some states may initiate reviews at the request of a utility, customer, governmental or other representative of a group of customers. Such parties may, however, agree with one another not to request reviews of or changes to rates for a specified period of time.

In many jurisdictions, the rates of AEP’s public utility subsidiaries are generally based on the cost of providing traditional bundled electric service (i.e., generation, transmission and distribution service). In the ERCOT area of Texas, our utilities have exited the generation business and they currently charge unbundled cost-based rates for transmission and distribution service.  In Ohio, rates for electric service are unbundled for generation, transmission and distribution service.  Historically, the state regulatory frameworks in the service area of the AEP System reflected specified fuel costs as part of bundled (or, more recently, unbundled) rates or incorporated fuel adjustment clauses in a utility’s rates and tariffs. Fuel adjustment clauses permit periodic adjustments to fuel cost recovery from customers and therefore provide protection against exposure to fuel cost changes. While the historical framework remains in a portion of AEP’s service territory, recovery of increased fuel costs through a fuel adjustment clause is no longer provided for in Ohio.

The following state-by-state analysis summarizes the regulatory environment of certain major jurisdictions in which AEP operates. Several public utility subsidiaries operate in more than one jurisdiction.

Indiana :  I&M provides retail electric service in Indiana at bundled rates approved by the IURC, with rates set on a cost-of-service basis.  In January 2008, I&M filed for an increase in its Indiana base rates of $82 million based on a return on equity of 11.5% and a September 30, 2007 test year.  The base rate increase includes a $69 million reduction in depreciation. The filing requests trackers for certain variable components of the cost of service including additional PJM costs, reliability enhancement costs, demand side management/energy efficiency costs, off-system sales margins and net environmental compliance costs.  The trackers would increase annual revenues by $46 million.  I&M proposes to share 50% of an estimated $96 million of off-system sales margins with ratepayers with a guaranteed minimum of $20 million.  A decision is expected from the IURC in early 2009.

Ohio : CSPCo and OPCo each operated as a functionally separated utility and provided “default” retail electric service to customers at unbundled rates pursuant to the Ohio Act through December 31, 2007. The PUCO approved the rate stabilization plans filed by CSPCo and OPCo (which, among other things, address default retail generation service rates from January 1, 2006 through December 31, 2008).  Retail generation rates are determined consistent with the rate stabilization plan until December 31, 2008. CSPCo and OPCo are providing and will continue to provide distribution services to retail customers at rates approved by the PUCO. These rates are frozen from their levels as of December 31, 2005 through December 31, 2008. Transmission services will continue to be provided at rates based on rates established by the FERC. CSPCo and OPCo have been involved in discussions with various stakeholders in Ohio about pending legislation to address the period following the expiration of the rate stabilization plans.  See Note 4 to the consolidated financial statements, entitled Rate Matters , included in the 2007 Annual Reports, for more information.

Oklahoma : PSO provides retail electric service in Oklahoma at bundled rates approved by the OCC.  PSO’s rates are set on a cost-of-service basis. Fuel and purchased energy costs above the amount included in base rates are recovered by applying a fuel adjustment factor to retail kilowatt-hour sales. The factor is generally adjusted annually and is based upon forecasted fuel and purchased energy costs. Over or under collections of fuel costs for prior periods are returned to or recovered from customers in the year following when new annual factors are established.  In November 2006, PSO filed a request with the OCC seeking an increase in base rates and other rate relief and the OCC issued a final order in October 2007.  See Note 4 to the consolidated financial statements, entitled Rate Matters , included in the 2007 Annual Reports, for additional information.

Texas:   TCC has sold all of its generation assets.  TNC has one active generation unit, however, all of the output from that unit is sold to a non-utility affiliate pursuant to a 20-year agreement.  Most retail customers in TCC’s and TNC’s ERCOT service area of Texas are served through non-affiliated Retail Electric Providers (“REPs”).  TCC and TNC provide retail transmission and distribution service on a cost-of-service basis at rates approved by the PUCT and wholesale transmission service under tariffs approved by the FERC consistent with PUCT rules.  In November 2006, TCC and TNC filed requests with the PUCT seeking increases in the rates charged to REPs for delivering electricity over their transmission and distribution lines.  The PUCT granted increases during 2007.  See Note 4 to the consolidated financial statements, entitled Rate Matters included in the 2007 Annual Reports, for additional information.  In August 2006, the PUCT delayed competition in the SPP area of Texas until at least January 1, 2011. As such, the PUCT continues to approve base and fuel rates for SWEPCo’s Texas operations.

Virginia:   APCo currently provides retail electric service in Virginia at unbundled rates.  In April 2007, the Virginia legislature adopted a comprehensive law providing for the re-regulation of electric utilities’ generation and supply rates after the December 31, 2008 expiration of capped rates.    The law provides for, among other things, biennial rate reviews beginning in 2009; rate adjustment clauses for the recovery of a variety of costs and a minimum allowed return on equity which will be based on the average earned return on equity of regional vertically integrated electric utilities.  The law also provides that utilities may 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.

In May 2007, the VSCC approved an overall annual increase in base rates.  In December 2007, the VSCC approved recovery of certain recurring environmental and reliability costs (the first of several anticipated requests for costs expected to be incurred).  In February 2008, the VSCC approved an adjustment in APCO’s fuel factor and the submission of PJM-related costs in fuel factor review and recovery, and authorized APCo to retain a share of margins from its off-system sales. For a more complete discussion of these matters, see Note 4 to the consolidated financial statements, entitled Rate Matters , included in the 2007 Annual Reports.

West Virginia : APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC. West Virginia generally allows for timely recovery of fuel costs.  In June 2007, the WVPSC approved a settlement agreement that provided for recovery of additional costs effective July 1, 2007.  See Note 4 to the consolidated financial statements, entitled Rate Matters , included in the 2007 Annual Reports, for additional information on current rate proceedings.

Other Jurisdictions : The public utility subsidiaries of AEP also provide service at regulated bundled rates in Arkansas, Kentucky, Louisiana and Tennessee and regulated unbundled rates in Michigan.

The following table illustrates the current rate regulation status of the states in which the public utility subsidiaries of AEP operate:

 

FERC

Under the FPA, the FERC regulates rates for interstate sales at wholesale, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects. The FERC regulations require AEP to provide open access transmission service at FERC-approved rates. The FERC also regulates unbundled transmission service to retail customers.  The FERC also regulates the sale of power for resale in interstate commerce by (i) approving contracts for wholesale sales to municipal and cooperative utilities and (ii) granting authority to public utilities to sell power at wholesale at market-based rates upon a showing that the seller lacks the ability to improperly influence market prices.  Except for wholesale power that AEP delivers within its control area of the SPP, AEP has market-rate authority from the FERC, under which much of its wholesale marketing activity takes place.  The FERC requires each public utility that owns or controls interstate transmission facilities to file an open access network and point-to-point transmission tariff that offers services comparable to the utility’s own uses of its transmission system. The FERC also requires all transmitting utilities to establish an OASIS, which electronically posts transmission information such as available capacity and prices, and require utilities to comply with Standards of Conduct that prohibit utilities’ system operators from providing non-public transmission information to the utility’s merchant energy employees. Utilities are permitted to seek recovery of certain prudently incurred stranded costs that result from unbundled transmission services.

The FERC oversees the voluntary formation of RTOs, entities created to operate, plan and control utility transmission assets. Order 2000 also prescribes certain characteristics and functions of acceptable RTO proposals.  As a condition of the FERC’s approval in 2000 of AEP’s merger with CSW, AEP was required to transfer functional control of its transmission facilities to one or more RTOs. The AEP East Companies are members of PJM. SWEPCo and PSO are members of SPP.

The FERC has jurisdiction over the issuances of securities of our public utility subsidiaries, the acquisition of securities of utilities, the acquisition or sale of certain utility assets, and mergers with another electric utility or holding company.  In addition, both the FERC and state regulators are permitted to review the books and records of any company within a holding company system.  EPACT gives the FERC “backstop” transmission siting authority as well as increased utility merger oversight.

ELECTRIC RESTRUCTURING AND CUSTOMER CHOICE LEGISLATION

Certain states in AEP’s service area have adopted restructuring or customer choice legislation. In general, this legislation provides for a transition from bundled cost-based rate regulated electric service to unbundled cost-based rates for transmission and distribution service and market pricing for the supply of electricity with customer choice of supplier. At a minimum, this legislation allows retail customers to select alternative generation suppliers. Electric restructuring and/or customer choice began on January 1, 2001 in Ohio and on January 1, 2002 in Michigan and the ERCOT area of Texas. Electric restructuring in the SPP area of Texas has been delayed by the PUCT until at least 2011. AEP’s public utility subsidiaries operate in both the ERCOT and SPP areas of Texas.  Customer Choice also began in Virginia on January 1, 2002, but will end beginning in 2009 pursuant to the passage of legislation providing for the re-regulation of electric utilities’ generation and supply rates.

Ohio Restructuring

Currently, the Ohio Act requires vertically integrated electric utility companies that are in the business of providing competitive retail electric service in Ohio to separate their generating functions from their transmission and distribution functions. Following the market development period (which ended December 31, 2005), retail customers receive distribution and, where applicable, transmission service from the incumbent utility whose distribution rates are approved by the PUCO and whose transmission rates are based on rates established by the FERC. The PUCO approved CSPCo’s and OPCo’s RSPs that, among other things, addressed default generation service rates from January 1, 2006 through December 31, 2008. See Item 1 – Utility Operations - Regulation—FERC for a discussion of FERC regulation of transmission rates, Regulation—Rates—Ohio and Note 4 to the consolidated financial statements entitled Rate Matters , included in the 2007 Annual Reports , for a discussion of the impact of restructuring on distribution rates. The PUCO authorized CSPCo and OPCo to remain functionally separated through 2008.

The Ohio Act requires CSPCo and OPCo to begin implementing market-based rates on January 1, 2009, following the expiration of their RSPs.  However, in August 2007, legislation was introduced that would significantly reduce the likelihood of CSPCo’s and OPCo’s ability to charge market-based rates for generation at the expiration of their RSPs.  The legislation has been passed by the Ohio Senate and is being considered by the Ohio House of Representatives.  AEP management is working closely with various stakeholders to achieve a principled, fair and well-considered approach to electric supply pricing.

Texas Restructuring

Signed into law in June of 1999, the Texas Act substantially amended the regulatory structure governing electric utilities in Texas in order to allow retail electric competition for customers.  Among other things, the Texas Act:

·

gave Texas customers the opportunity to choose their REP beginning January 1, 2002 (delayed until at least 2011 in the SPP portion of Texas),

·

required each utility to legally separate into a REP, a power generation company and a transmission and distribution utility, and

·

required that REPs provide electricity at generally unregulated rates, except that until January 1, 2007 the prices that could be charged to residential and small commercial customers by REPs affiliated with a utility within the affiliated utility’s service area were set by the PUCT, until certain conditions in the Texas Act were met.

The Texas Act provides each affected utility an opportunity to recover its generation-related regulatory assets and stranded costs resulting from the legal separation of the transmission and distribution utility from the generation facilities and the related introduction of retail electric competition.  Regulatory assets consist of the Texas jurisdictional amount of generation-related regulatory assets and liabilities in the audited financial statements as of December 31, 1998.  Stranded costs consist of the positive excess of the net regulated book value of generation assets (as of December 31, 2001) over the market value of those assets, taking specified factors into account, as ultimately determined in a PUCT true-up proceeding.

In May 2005, TCC filed its stranded cost quantification application, or true-up proceeding, with the PUCT seeking recovery of $2.4 billion of net stranded generation costs and other recoverable true-up items.  A final order was issued in April 2006.  In the final order, the PUCT determined TCC’s net stranded generation costs and other recoverable true-up items to be approximately $1.475 billion.  Other parties have appealed the PUCT’s final order as unwarranted or too large; TCC has appealed seeking additional recovery consistent with the Texas Act and related rules.  TCC intends to appeal any final adverse rulings regarding the PUCT’s order in the true-up proceedings.

After PUCT approval, in October 2006 TCC issued $1.74 billion of securitization bonds, including additional issuance and carrying costs through the date of issuance.  The PUCT authorized negative competition transition charges in the amount of $356 million in October 2006.  TCC is required to refund this amount to its ratepayers.  For a discussion of (i) regulatory assets and stranded costs subject to recovery by TCC and (ii) rate adjustments made after implementation of restructuring to allow recovery of certain costs by or with respect to TCC and TNC, see Note 4 to the consolidated financial statements entitled Rate Matters included in the 2007 Annual Reports .

Michigan Customer Choice

Customer choice commenced for I&M’s Michigan customers on January 1, 2002. Rates for retail electric service for I&M’s Michigan customers were unbundled (though they continue to be regulated) to allow customers the ability to evaluate the cost of generation service for comparison with other suppliers. At December 31, 2007, none of I&M’s Michigan customers have elected to change suppliers and no alternative electric suppliers are registered to compete in I&M’s Michigan service territory.

Virginia Re-regulation

In April 2007, the Virginia legislature adopted a comprehensive law providing for the re-regulation of electric utilities’ generation and supply rates after the December 31, 2008 expiration of capped rates.    The law provides for, among other things, biennial rate reviews beginning in 2009; rate adjustment clauses for the recovery of a variety of costs and a minimum allowed return on equity which will be based on the average earned return on equity of regional vertically integrated electric utilities.  The law also provides that utilities may 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.

COMPETITION

The public utility subsidiaries of AEP, like the electric industry generally, face competition in the sale of available power on a wholesale basis, primarily to other public utilities and power marketers. The Energy Policy Act of 1992 was designed, among other things, to foster competition in the wholesale market by creating a generation market with fewer barriers to entry and mandating that all generators have equal access to transmission services. As a result, there are more generators able to participate in this market. The principal factors in competing for wholesale sales are price (including fuel costs), availability of capacity and power and reliability of service.

AEP’s public utility subsidiaries also compete with self-generation and with distributors of other energy sources, such as natural gas, fuel oil and coal, within their service areas. The primary factors in such competition are price, reliability of service and the capability of customers to utilize sources of energy other than electric power. With respect to competing generators and self-generation, the public utility subsidiaries of AEP believe that they generally maintain a favorable competitive position. With respect to alternative sources of energy, the public utility subsidiaries of AEP believe that the reliability of their service and the limited ability of customers to substitute other cost-effective sources for electric power place them in a favorable competitive position, even though their prices may be higher than the costs of some other sources of energy.

Significant changes in the global economy have led to increased price competition for industrial customers in the United States, including those served by the AEP System. Some of these industrial customers have requested price reductions from their suppliers of electric power. In addition, industrial customers that are downsizing or reorganizing often close a facility based upon its costs, which may include, among other things, the cost of electric power. The public utility subsidiaries of AEP cooperate with such customers to meet their business needs through, for example, providing various off-peak or interruptible supply options pursuant to tariffs filed with, and approved by, the various state commissions. Occasionally, these rates are negotiated with the customer, and then filed with the state commissions for approval. The public utility subsidiaries of AEP believe that they are unlikely to be materially affected by this competition in an adverse manner.

SEASONALITY

The sale of electric power is generally a seasonal business. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. The pattern of this fluctuation may change due to the nature and location of AEP’s facilities and the terms of power sale contracts into which AEP enters. In addition, AEP has historically sold less power, and consequently earned less income, when weather conditions are milder. Unusually mild weather in the future could diminish AEP’s results of operations and may impact its financial condition.  Conversely, unusually extreme weather conditions could increase AEP’s results of operations.

MEMCO OPERATIONS

Our MEMCO Operations Segment transports coal and dry bulk commodities primarily on the Ohio, Illinois, and lower Mississippi rivers.  Almost all of our customers are nonaffiliated third parties who obtain the transport of coal and dry bulk commodities for various uses.  We charge these customers market rates for the purpose of making a profit.  Depending on market conditions and other factors, including barge availability, we have also served AEP utility subsidiary affiliates.   Our affiliated utility customers procure the transport of coal for use as fuel in their respective generating plants.  We charged affiliated customers rates that reflected our costs.  The MEMCO operations include approximately 1,992 barges, 38 towboats and 14 harbor boats that we own or lease.

Competition within the barging industry for major commodity contracts is intense, with a number of companies offering transportation services in the waterways we serve. We compete with other carriers primarily on the basis of commodity shipping rates, but also with respect to   customer service, available routes, value-added services (including scheduling convenience and flexibility), information timeliness and equipment. The industry continues to experience consolidation.   The resulting companies increasingly offer the widespread geographic reach necessary to support major national customers.  Demand for barging services can be seasonal, particularly with respect to the movement of harvested agricultural commodities (beginning in the late summer and extending through the fall).  Cold winter weather may also limit our operations when certain of the waterways we serve are closed.

Gas Operations

In January 2005, we sold a 98% controlling interest in HPL and related assets with the remaining 2% interest being sold to the buyer in November 2005.  See Note 8 to the consolidated financial statements entitled Acquisitions, Dispositions, Discontinued Operations, Impairments, and Assets Held for Sale , included in the 2007 Annual Reports for more information.  As a result, management anticipates that our gas marketing operations will be limited to managing our obligations with respect to the gas transactions entered into before these sales.

Plaquemine Cogeneration Facility

Pursuant to an agreement with Dow, AEP constructed an 880 MW cogeneration facility (“Facility”) at Dow’s chemical facility in Plaquemine, Louisiana that achieved commercial operation status in 2004.  Dow used a portion of the energy produced by the Facility and sold the excess power to us.  We agreed to sell up to all of the excess 800 MW to Tractebel.  Litigation in connection with that power agreement has been settled.  For more information, see Note 6 to the consolidated financial statements entitled Commitments, Guarantees and Contingencies .  In November 2006, we sold our interest in the Facility to Dow.  Negotiations for the sale resulted in an after-tax impairment of approximately $136 million.  See Note 8 to the consolidated financial statements entitled Acquisitions, Dispositions, Discontinued Operations, Impairments and Assets Held for Sale.

For information regarding other non-core investments, see Note 8 to the consolidated financial statements entitled Acquisitions, Dispositions, Discontinued Operations, Impairments and Assets Held for Sale, included in the 2007 Annual Reports.