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PART I

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.  Virginia has returned to integrated regulated rates.

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, 2008, the subsidiaries of AEP had a total of 21,912 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 962,000 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, 2008, APCo and its wholly owned subsidiaries had 2,575 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 749,000 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, 2008, CSPCo had 1,323 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 582,000 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, 2008, I&M had 2,879 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, 2008, KPCo had 480 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, 2008, Kingsport Power Company had 58 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, 2008, OPCo had 2,434 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 527,000 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, 2008, PSO had 1,279 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 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 471,000 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, 2008, SWEPCo had 1,641 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 761,000 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, 2008, TCC had 1,201 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 185,000 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 an agreement effective through 2027.  At December 31, 2008, TNC had 370 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, 2008, WPCo had 62 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, 2008, AEPSC had 6,351 employees.

CLASSES OF SERVICE

The principal classes of service from which AEP and the registrant subsidiaries of AEP derive revenues and the amount of such revenues during the year ended December 31, 2008 are as follows:

Description	AEP System(a)	APCo	CSPCo	I&M
	(in thousands)
UTILITY OPERATIONS:
Retail Sales
Residential Sales	$4,267,000	$ 891,159	$ 720,761	$427,877
Commercial Sales	3,116,000	426,277	684,277	333,575
Industrial Sales	2,954,000	601,166	328,010	364,670
PJM Net Charges	(214,000)	(72,898)	(40,249)	(38,782)
Provision for Rate Refund	(105,000)	(52,910)	(30,359)	(33,279)
Other Retail Sales	210,000	55,359	5,873	6,044
Total Retail	10,228,000	1,848,153	1,668,313	1,060,105
Wholesale
Off-System Sales	2,690,000	720,574	430,093	675,205
Transmission	58,000	(52,740)	(30,419)	(16,235)
Total Wholesale	2,748,000	667,834	399,674	658,970
Other Electric Revenues	244,000	26,235	11,623	8,694
Other Operating Revenues	106,000	18,199	5,542	19,102
Sales To Affiliates	-	328,735	122,949	419,488
Total Utility Operating Revenues	13,326,000	2,889,156	2,208,101	2,166,359
OTHER	1,114,000	-	-	-
TOTAL REVENUES	$14,440,000	$ 2,889,156	$ 2,208,101	$2,166,359

Description	OPCo	PSO	SWEPCo
	(in thousands)
UTILITY OPERATIONS:
Retail Sales
Residential Sales	$ 602,770	$ 557,195	$440,826
Commercial Sales	402,149	407,052	382,984
Industrial Sales	694,890	357,884	280,082
PJM Net Charges	(47,705)	-	-
Provision for Rate Refund	(42,435)	13,811	21,417
Other Retail Sales	9,439	99,158	7,906
Total Retail	1,619,108	1,435,100	1,133,215
Wholesale
Off-System Sales	511,961	62,980	267,689
Transmission	(38,529)	27,234	39,966
Total Wholesale	473,432	90,214	307,655
Other Electric Revenues	24,257	24,176	17,157
Other Operating Revenues	18,937	4,853	45,893
Sales to Affiliates	961,200	101,602	50,842
Total Utility Operating Revenues	3,096,934	1,655,945	1,554,762
OTHER	-	-	-
TOTAL REVENUES	$ 3,096,934	$ 1,655,945	$1,554,762

 

(a)	Includes revenues of other subsidiaries not shown. Intercompany transactions have been eliminated for the year ended December 31, 2008.

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, borrowing under AEP's revolving credit agreements 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. See Management’s Financial Discussion and Analysis of Results of Operations, included in the 2008 Annual Reports, under the heading entitled Financial Condition for additional information concerning short-term funding and our access to bank lines of credit, commercial paper and capital markets.

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, 2008, 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 of AEP would be considered an immediate termination event.  See Management’s Financial Discussion and Analysis of Results of Operations, included in the 2008 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

The credit ratings of AEP and its registrant subsidiaries as of February 18, 2009 are set forth below.  Over the first two months of 2009, Moody’s placed the senior unsecured debt rating of AEP on negative outlook, the senior unsecured debt rating of OPCo, SWEPCo, TCC and TNC on review for possible downgrade and changed the outlook of APCo from negative to stable.  In February 2008 Fitch downgraded the senior unsecured debt rating of PSO to BBB+ with stable outlook.  Fitch placed the senior unsecured debt rating of APCo and TCC on negative outlook in May 2008 and February 2009, respectively.  See Management’s Financial Discussion and Analysis of Results of Operations, included in the 2008 Annual Reports, under the heading entitled Financial Condition for additional information with respect to the credit ratings of the registrants.

	Moody’s		S&P		Fitch
Company	Senior Unsecured	Outlook*	Senior Unsecured	Outlook*	Senior Unsecured	Outlook*
AEP	Baa2	N	BBB	S	BBB	S
AEP Short Term Rating	P2	S	A2	S	F2	S
APCo	Baa2	S	BBB	S	BBB+	N
CSPCo	A3	S	BBB	S	A-	S
I&M	Baa2	S	BBB	S	BBB	S
OPCo	A3	R	BBB	S	BBB+	S
PSO	Baa1	S	BBB	S	BBB+	S
SWEPCo	Baa1	R	BBB	S	BBB+	S

* S=Stable Outlook;  N=Negative Outlook; R=Under Review for Possible Downgrade

 

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 and regulatory responses to it, including limitations on CO2 emissions.  See Management’s Financial Discussion and Analysis of Results of Operations under the headings entitled Environmental Matters – Potential Regulation of CO2 and Other 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/or 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 Litigation - Environmental Litigation and Note 6 to the consolidated financial statements entitled Commitments, Guarantees and Contingencies, included in the 2008 Annual Reports, for further information.

·

Rules issued by the EPA and certain states that require substantial reductions in SO2 and NOx emissions and future rules for mercury emission reductions, 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 2008 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 2008 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, and regulates systems that withdraw surface water for use in our power plants.  See Management’s Financial Discussion and Analysis of Results of Operations, included in the 2008 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, and other laws governing the use of ash impoundments, including containment dams. 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 2008 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, 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. 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 2008 Annual Reports, for more information regarding environmental matters.

Environmental Investments

Investments related to improving AEP System plants’ environmental performance and compliance with air and water quality standards during 2006, 2007 and 2008 and the current estimates for 2009, 2010 and 2011 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 CO2 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 2008 Annual Reports, for more information regarding environmental expenditures in general.

Historical and Projected Environmental Investments
	2006	2007	2008	2009	2010	2011
	Actual	Actual	Actual	Estimate	Estimate	Estimate
(in thousands)
Total AEP System*	$1,366,200	$994,100	$886,800	$436,100	$581,900	$892,400
APCo	532,800	351,900	361,200	99,400	183,900	71,400
CSPCo	138,900	130,000	162,800	69,700	54,600	57,900
I&M	23,200	9,300	22,400	40,600	3,600	2,000
OPCo	660,800	481,700	311,800	179,800	49,200	116,400
PSO	500	1,500	5,000	1,000	22,200	265,100
SWEPCo	21,000	14,300	12,000	22,300	170,400	243,600

* Includes expenditures of the subsidiaries shown 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 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, 2008, the member-load-ratios were as follows:

	Peak Demand (MW)	Member-Load Ratio (%)
APCo	7,848	33.2
CSPCo	4,406	18.6
I&M	4,264	18.0
KPCo	1,678	7.1
OPCo	5,458	23.1

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 remained functionally separated through December 31, 2008 as authorized by their rate stabilization plans approved by the PUCO.  Pursuant to rules recently adopted by the PUCO, CSPCo and OPCo expect to file corporate separation plans with the PUCO.  See Note 4 to the consolidated financial statements, entitled Rate Matters, included in the 2008 Annual Reports, for more information.

APCo, CSPCo, I&M, KPCo and OPCo are 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, 2006, 2007 and 2008:

	2006	2007	2008
	(in thousands)
APCo	$319,500	$454,800	$575,300
CSPCo	281,700	173,000	233,200
I&M	(146,100)	(93,200)	(153,000)
KPCo	38,800	41,200	65,000
OPCo	(493,900)	(575,800)	(720,500)

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 as of May 1, 2006, 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, 2006, 2007 and 2008:

	2006	2007	2008
	(in thousands)
PSO	$(15,300)	$(17,500)	$(57,000)
SWEPCo	9,900	16,800	59,900
TCC	0	0	0
TNC	5,400	700	(2,900)

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 its 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 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.  In an order issued November 26, 2008, the FERC ruled that AEP should reallocate pre-tax trading margins from off-system sales between the AEP East Companies and the AEP West Companies during the period from June 2000 to March 2006 governed by the previous system integration agreement.   See Note 4 to the consolidated financial statements, entitled Rate Matters, included in the 2008 Annual Reports under the heading entitled FERC Rate Matters for additional information.

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 and in adjacent regions. 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, 2008, counterparties have posted approximately $29 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 $100 million with counterparties and exchanges).  Since open trading contracts are valued based on market power prices, exposures change daily. See Management’s Financial Discussion and Analysis of Results of Operations, included in the 2008 Annual Reports, under the heading entitled Quantitative and Qualitative Disclosures About Risk Management Activities for additional information.

Fuel Supply

The following table shows the sources of fuel used by the AEP System:

	2006	2007	2008
Coal and Lignite	85%	85%	86%
Natural Gas	6%	6%	6%
Nuclear	9%	9%	8%
Hydroelectric and other	<1%	<1%	<1%

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 has been increasing due to increased mining costs (including labor, diesel fuel, mining equipment, implementation of new safety regulations, and permitting difficulties) in addition to higher international demand for eastern U.S. coals.  To the extent practical, management has responded to increases in the price of coal by rebalancing the coal used in its generating facilities with products 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 9,000 railcars, 726 barges, 18 towboats and a coal handling terminal with 18 million tons of annual capacity to move and store coal for use in our generating facilities.  See AEP River 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 price of coal in the various spot markets remains volatile.  During the first half of 2008, spot market prices for coal generally rose; in the second half of 2008, spot market prices for coal generally decreased.  Most of the coal we purchase is procured through long-term contracts.  The prices we pay under these contracts is usually lower than the spot market price of coal.  As these long-term contracts expire they are replaced with new agreements, often at higher prices.  The price we paid for coal in 2008 rose from the prior year as a result of this.  We expect this trend to continue in 2009.

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 AEP System companies:

	2006	2007	2008
Total coal delivered to AEP System plants (thousands of tons)	76,045	72,644	77,054
Average price per ton of purchased coal	$35.27	$36.65	$47.14

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, availability of acceptable coals, labor issues and weather conditions which may interrupt production or deliveries. At December 31, 2008, the System’s coal inventory was approximately 32 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, AEP has developed programs to conserve coal supplies at its plants. Such programs have been filed and reviewed with federally approved electric reliability organizations.  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 nearly 103 billion cubic feet of natural gas during 2008 for generating power. This represents a slight decrease from 2007 due to reduced demand in AEP’s eastern jurisdictions.  Many of the natural gas-fired power plants are connected to at least two pipelines, which allows greater access to competitive supplies and improves delivery reliability. 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, as needed.

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 continues to lease a portion of its nuclear fuel requirements.

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.  Initial loading of spent nuclear fuel into the dry casks is tentatively scheduled to begin in 2011, which should permit normal operations through 2037, its current licensing period.

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, 2008, the total decommissioning trust fund balance for the Cook Plant was $959 million.  The balance of funds available to decommission Cook Plant will differ based on contributions and investment returns.  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 9 to the consolidated financial statements, entitled Nuclear, included in the 2008 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 Utah licenses a low-level radioactive waste disposal sites which currently accepts low-level radioactive waste from Michigan.  I&M’s access to the Barnwell, South Carolina facility ended in 2008.  With some modifications to existing facilities, I&M will have capacity for onsite storage of that waste previously 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), and 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 authorized environmental investments related to their ownership interests.  As of December 2008, OVEC’s Board of Directors has authorized capital expenditures totaling $981.6 million in connection with the engineering and construction of flue gas desulfurization (sulfur dioxide scrubber) projects and the associated scrubber waste disposal landfills at its two generating plants.  OVEC’s Board of Directors has delayed for at least eighteen months final completion of construction on one of the plants.  If approved and fully funded, the estimated total cost to complete the scrubber and landfill projects would be in excess of $1.2 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 approved by the state utility commissions of the states in which they operate, and in some instances, approved by the FERC.  See Item 1 –Utility Operations - 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 Agreement: APCo, CSPCo, I&M, KPCo and OPCo operate their transmission lines as a single interconnected and coordinated system in AEP East transmission zone 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, 2008 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, 2006, 2007 and 2008:

	2006	2007	2008
	(in thousands)
APCo	$(16,000)	$(25,000)	$(29,000)
CSPCo	46,000	51,900	55,000
I&M	(37,000)	(34,600)	(37,000)
KPCo	(2,000)	(800)	(2,000)
OPCo	9,000	8,500	13,000

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 in the AEP West transmission zone, 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 pursuant to the SPP OATT and ERCOT protocols as described above during the years ended December 31, 2006, 2007 and 2008:

	2006	2007	2008
	(in thousands)
PSO	$1,800	$500	$8,200
SWEPCo	(1,900)	(500)	(8,200)
TCC	1,100	1,100	1,500
TNC	(1,000)	(1,100)	(1,500)

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 – Electric Transmission and Distribution - 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 2008 Annual Reports under the heading entitled Regional Transmission Rate Proceedings at the FERC for additional information regarding 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 cost-based 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 with respect to wholesale power and transmission service transactions as well as certain unbundled retail transmission rates mainly in Ohio.  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 adjusted 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.

Public utilities have traditionally financed capital investments until the new asset was placed in service.  Provided the asset was found to be a prudent investment, it was then added to rate base and entitled to a return through rate recovery.  Given long lead times in construction, the high costs of plant and equipment and difficult capital markets, we are actively pursuing strategies to accelerate rate recognition of investments and cash flow.  AEP representatives are leading the dialogue with our state commissioners and legislators on alternative ratemaking options to reduce regulatory lag and enhance certainty in the process.   These options include pre-approvals, a return on construction work in progress, rider/trackers, securitization, formula rates and the inclusion of future test-year projections into rates.

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 only.  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, CSPCo and OPCo did not have a fuel adjustment clause to recover increased fuel costs in Ohio through 2008.  CSPCo and OPCo are seeking to implement a fuel cost recovery mechanism.

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.  See Note 4 to the consolidated financial statements, entitled Rate Matters, included in the 2008 Annual Reports, for more information regarding pending rate matters.

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.  Indiana provides for timely fuel and purchased power cost recovery through a fuel cost recovery mechanism.

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.  Pursuant to rate stabilization plans approved by the PUCO, CSPCo and OPCo provide retail generation service at rates approved by the PUCO.   CSPCo and OPCo are providing and will continue to provide distribution services to retail customers at cost based rates approved by the PUCO.  Transmission services will continue to be provided at OATT rates based on rates established by the FERC.  CSPCo and OPCo’s generation/supply rates are no longer cost based regulated. Pursuant to the Ohio Amendments, CSPCo and OPCo have filed their ESP with PUCO, each requesting an annual rate increase for 2009 through 2011 that would not exceed approximately 15% per year.  A significant portion of the requested increases results from the implementation of a fuel cost recovery mechanism that primarily includes fuel costs, purchased power costs including mandated renewable energy, consumables such as urea, other variable production costs and gains and losses on sales of emission allowances.  CSPCo and OPCo have not had a fuel adjustment clause since 1999.

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.

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 an agreement effective through 2027.  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 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 on a cost of service basis.

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 a fuel adjustment clause factor with a true-up to actual.

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 through an expanded net energy clause which trues up to actual expenses.

Other Jurisdictions: The public utility subsidiaries of AEP also provide service at cost based regulated bundled rates in Arkansas, Kentucky, Louisiana and Tennessee and regulated unbundled rates in Michigan.  These jurisdictions provide for the timely recovery of fuel costs through fuel adjustment clauses that true-up to actual expenses.

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

 

						Fuel Clause Rates(1)
								Off-System Sales Profits		Percentage of AEP System
		Status of Base Rates for						Shared with		Retail
Jurisdiction		Power Supply		Energy Delivery		Status		Ratepayers		Revenues(2)
Ohio		See footnote 3		See footnote 3		See footnote 3		Not applicable		32%
Oklahoma		Not capped or frozen		Not capped or frozen		Active		Yes		14%
Texas ERCOT		Not applicable (4)		Not capped or frozen		Not applicable		Not applicable		8%
Texas SPP		Not capped or frozen (4)		Not capped or frozen		Active		Yes		4%
West Virginia		Not capped or frozen		Not capped or frozen		Active		Yes		10%
Indiana		Not capped or frozen		Not capped or frozen		Active		No		9%
Virginia		Not capped or frozen (5)		Not capped or frozen (5)		Active		Yes		9%
Louisiana		Not capped or frozen		Not capped or frozen		Active		Yes, above base levels		4%
Kentucky		Not capped or frozen		Not capped or frozen		Active		Yes, above and below base levels(6)		4%
Arkansas		Not capped or frozen		Not capped or frozen		Active		Yes, above base levels		3%
Michigan		Not capped or frozen		Not capped or frozen		Active		Yes, in some areas		2%
Tennessee		See footnote 7		Not capped or frozen		Active		Not applicable		1%

 

(1)	Includes, where applicable, fuel and fuel portion of purchased power.

(2)	Represents the percentage of revenues from sales to retail customers from AEP utility companies operating in each state to the total AEP System revenues from sales to retail customers for the year ended December 31, 2008.

(3)

The PUCO approved rate stabilization plans (RSP) filed by CSPCo and OPCo that began after the market development period and extended through December 31, 2008 during which OPCo’s retail generation rates increased 7% annually and CSPCo’s retail generation rates increased 3% annually.  Distribution rates were frozen, with certain exceptions, through December 31, 2008.  Pursuant to the Ohio Amendments, in July 2008, CSPCo and OPCo filed ESP with the PUCO to establish rates for 2009 through 2011.  CSPCo and OPCo have requested retroactive application of the new rates, including the fuel cost recovery mechanism, back to January 1, 2009 upon approval of the ESP.  In December 2008, the PUCO ordered that CSPCo and OPCo continue using their current RSP rates until the PUCO issues a ruling on the ESP or the end of the February 2009 billing cycle, whichever comes first.  In January 2009, CSPCo and OPCo filed an application with the PUCO requesting the PUCO to authorize deferred fuel accounting beginning January 1, 2009.  See Note 4 to the consolidated financial statements, entitled Rate Matters.

(4)	TCC and TNC are no longer in the retail generation supply business.  TCC and TNC provide only regulated delivery services in ERCOT.  SWEPCo is vertically integrated utility that provides retail electric service in the SPP area of Texas.

(5)	Rates in Virginia were capped, subject to adjustment, through 2008.  Beginning January 1, 2009, rates are neither capped nor frozen.

(6)

If the monthly off-system sales profits do not meet the monthly level built into base rates, ratepayers reimburse KPCo for a portion of the shortfall.  If the monthly off-system sales profits exceed the monthly base amount built into base rates, KPCo reimburses ratepayers for a portion of the excess.

(7)

Prior to January 1, 2009, base rates for power supply were not capped or frozen.  Effective January 1, 2009, base rates for power supply will phase-in increases of $24 million, $3 million and $9 million for the years beginning January 1, 2009, 2010 and 2011, respectively.  Any filing to increase the amount Kingsport pays for the non-fuel component of its purchase power, other than as discussed above, cannot be made prior to January 1, 2012.

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, directly or through an RTO, 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, directly or through an RTO, 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’ transmission employees from providing non-public transmission information to the utility’s marketing employees.

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, including OASIS and tariff responsibilities, to one or more RTOs.  As a result, 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 ended in 2009 for residential customers (except those seeking green power) pursuant to a new law 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 cost-based distribution rates are approved by the PUCO and whose cost-based transmission rates are based on rates established by the FERC.  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 2008 Annual Reports, for a discussion of the impact of restructuring on distribution rates. The PUCO has authorized CSPCo and OPCo to remain functionally separated.

Pursuant to the Ohio Amendments, CSPCo and OPCo have filed ESP with the PUCO, each requesting an annual rate increase for 2009 through 2011 that would not exceed approximately 15% per year.  A significant portion of the requested increases results from the implementation of a fuel cost recovery mechanism that primarily includes fuel costs, purchased power costs including mandated renewable energy, consumables such as urea, other variable production costs and gains and losses on sales of emission allowances.  See Note 4 to the consolidated financial statements, entitled Rate Matters, included in the 2008 Annual Reports, for more information.

Texas Restructuring

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 also 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 at non-cost based rates for generation/supply of electricity.  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 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.

TCC elected to sell its generating facilities to establish its recoverable stranded costs.  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.  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 2008 Annual Reports.

Michigan Customer Choice

Customer choice commenced for I&M’s Michigan customers on January 1, 2002.  In October 2008, the Governor of Michigan signed legislation to limit customer choice load to no more than 10% of the annual retail load for the preceding calendar year. Rates for retail electric service for I&M’s Michigan customers were unbundled (though they continue to be cost based regulated) to allow customers the ability to evaluate the cost of generation service for comparison with other suppliers. At December 31, 2008, 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 adjusted 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 APCo’s fuel adjustment clause factor 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.

AEP RIVER OPERATIONS

Our AEP River 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 permit AEP utility subsidiary affiliates to use certain of our equipment at rates that reflect our cost.  Our affiliated utility customers procure the transport of coal for use as fuel in their respective generating plants.  We charge affiliated customers rates that reflect our costs.  AEP River Operations includes approximately 2,252 barges, 42 towboats and 22 harbor boats that we own or lease. These assets are separate from the barges and towboats dedicated exclusively to transporting coal for use as fuel in our own generating facilities discussed under the prior segment.  See Item 1 – Utility Operations - Electric Generation —Fuel Supply—Coal and Lignite.

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.

 

Our transportation operations are subject to regulation by the U.S. Coast Guard, federal laws, state laws and certain international conventions.  Legislation has been proposed that could make our towboats subject to inspection by the U.S. Coast Guard.

 

GENERATION AND MARKETING

 

Our Generation and Marketing Segment consists of non-utility generating assets and a competitive power supply and energy trading and marketing business.  We enter into short and long-term transactions to buy or sell capacity, energy and ancillary services primarily in the ERCOT market.  As of December 31, 2008, the assets utilized in this segment included approximately 310 MW of company-owned domestic wind power facilities, 75MW of domestic wind power from a long-term purchase power agreement and 377 MW of coal-fired capacity which was obtained through an agreement effective through 2027 that transfers TNC’s interest in the Oklaunion power station to AEP Energy Partners, Inc.  During first quarter of 2009, one of our non-utility affiliates, AEP Energy Partners, Inc., entered into a purchase power agreement effective through 2029 that entitles us to the output of a wind farm of approximately 100MW capacity.  TNC’s transfer of coal-fired generation capacity is in order to comply with the separation requirements of the Texas Act.  The power obtained from the Oklaunion power station is marketed and sold in ERCOT.  We are regulated by the PUCT for transactions inside ERCOT and by the FERC for transactions outside of ERCOT.  While peak load in ERCOT typically occurs in the summer, we do not necessarily expect seasonal variation in our operations.

 

OTHER

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 was settled in August, 2005.  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 7 to the consolidated financial statements entitled Acquisitions, Dispositions, Discontinued Operations and Impairments.

For information regarding other non-core investments, see Note 7 to the consolidated financial statements entitled Acquisitions, Dispositions, Discontinued Operations and Impairments, included in the 2008 Annual Reports.

ITEM 1A.                            RISK FACTORS

General Risks of Our Regulated Operations

We may not be able to recover the costs of our substantial planned investment in capital improvements and additions. (Applies to each registrant.)

Our business plan calls for extensive investment in capital improvements and additions, including the installation of environmental upgrades and retrofits, construction and/or acquisition of additional generation units and transmission facilities, modernizing existing infrastructure as well as other initiatives. Our public utility subsidiaries currently provide service at rates approved by one or more regulatory commissions.  If these regulatory commissions do not approve adjustments to the rates we charge, we would not be able to recover the costs associated with our planned extensive investment.  This would cause our financial results to be diminished.  While we may seek to limit the impact of any denied recovery by attempting to reduce the scope of our capital investment, there can be no assurance as to the effectiveness of any such mitigation efforts, particularly with respect to previously incurred costs and commitments.

Our planned capital investment program coincides with a material increase in the price of the fuels used to generate electricity.  Most of our jurisdictions have fuel clauses that permit us to recover these increased fuel costs through rates without a general rate case.  While prudent capital investment and variable fuel costs each generally warrant recovery, in practical terms our regulators could limit the amount or timing of increased costs that we would recover through higher rates.  Any such limitation could cause our financial results to be diminished.

While Indiana permits the recovery of prudently incurred costs, our request for rate recovery may not be approved in its entirety. (Applies to AEP and I&M.)

     In January 2008, I&M filed a request to increase base rates in its Indiana jurisdiction by approximately $80 million. The request included a return on equity of 11.5% and the ability to introduce additional riders.  The requested increase is attributable to additional costs relating to operating in the PJM, reliability enhancement, demand side management, additional off-system sales margin sharing and environmental compliance costs.  While regulation in Indiana provides for a return on costs prudently incurred, there can be no assurance that the IURC will approve all of the costs included in our filing or that this process will result in rates providing full recovery in a timely manner.  If the IURC denies the requested rate recovery, it could adversely impact future results of operations, cash flows and financial conditions.

Our request for rate recovery in Ohio may not be approved in its entirety.  (Applies to AEP, OPCo and CSPCo)

In July 2008, within the parameters of the ESP, CSPCo and OPCo filed with the PUCO to establish rates for 2009 through 2011.  CSPCo and OPCo each requested an annual rate increase for 2009 through 2011 that would not exceed approximately 15% per year.  A significant portion of the requested increases results from the implementation of a fuel cost recovery mechanism that primarily includes fuel costs, purchased power costs including renewable energy, consumables such as urea, other variable production costs and gains and losses on sales of emission allowances.  Management expects a PUCO decision on the ESP filings in the first quarter of 2009. CSPCo and OPCo have requested retroactive application of the new rates back to January 1, 2009 upon approval.  If the PUCO denies all or part of the requested rate recovery, it could have an adverse effect on future net income, cash flows and financial condition.

We may not recover costs incurred to begin constructing generating plants that are canceled. (Applies to each registrant)

Our business plan for the construction of new generating units involves a number of risks, including construction delays, nonperformance by equipment suppliers, and increases in equipment and labor costs. To limit the risks of these construction projects, we enter into equipment purchase orders and construction contracts and incur engineering and design service costs in advance of receiving necessary regulatory approvals and/or siting or environmental permits. If any of these projects is canceled for any reason, including our failure to receive necessary regulatory approvals and/or siting or environmental permits, we could incur significant cancellation penalties under the equipment purchase orders and construction contracts. In addition, if we have recorded any construction work or investments as a regulatory asset we may need to impair that asset in the event the project is canceled.

Rate regulation may delay or deny full recovery of capital improvements, additions and other costs. (Applies to each registrant.)

Our public utility subsidiaries currently provide service at rates approved by one or more regulatory commissions.  These rates are generally regulated based on an analysis of the applicable utility’s expenses incurred in a test year.  Thus, the rates a utility is allowed to charge may or may not match its expenses at any given time.  There may also be a delay between the timing of when these costs are incurred and when these costs are recovered.  Traditionally, we have financed capital investments and improvements until the new asset was placed in service.  Provided the asset was found to be a prudent investment, the asset was then added to rate base and entitled to a return through rate recovery.  Long lead times in construction, the high costs of plant and equipment and difficult capital markets has heightened the risks involved in our capital investments and improvements. While we are actively pursuing strategies to accelerate rate recognition of investments and cash flow, including pre-approvals, a return on construction work in progress, rider/trackers, securitization, formula rates and the inclusion of future test-year projections into rates, there can be no assurance that these will be adopted, that the applicable regulatory commission will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs in a timely manner.

Certain of our revenues and results of operations are subject to risks that are beyond our control.  (Applies to each registrant.)

Our operations are structured to comply with all applicable federal and state laws and regulations and we take measures to minimize the risk of significant disruptions.  Material disruptions at one or more of our operational facilities, however, could negatively impact our revenues, operating and capital expenditures and results of operations.  Such events may also create additional risks related to the supply and/or cost of equipment and materials.  We could experience unexpected but significant interruption due to several events, including:

·	major facility or equipment failure;

·	an environmental event such as a serious spill or release;

·	fires, floods, droughts, earthquakes, hurricanes or other natural disasters;

·	wars, terrorist acts or threats and other catastrophic events;

·	significant health impairments or disease events, and;

·	other serious operational problems.

We are exposed to nuclear generation risk. (Applies to AEP and I&M.)

Through I&M, we own the Cook Plant.  It consists of two nuclear generating units for a rated capacity of 2,191 MW, or 8-9% of the electricity we generate.  We are, therefore, subject to the risks of nuclear generation, which include the following:

·	the potential harmful effects on the environment and human health resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials such as spent nuclear fuel;

·	limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with our nuclear operations;

·	uncertainties with respect to contingencies and assessment amounts if insurance coverage is inadequate (federal law requires owners of nuclear units to purchase the maximum available amount of nuclear liability insurance and potentially contribute to the losses of others); and,

·	uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.

There can be no assurance that I&M’s preparations or risk mitigation measures will be adequate if and when these risks are triggered.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities.  In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved.  Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants such as ours.  In addition, although we have no reason to anticipate a serious nuclear incident at our plants, if an incident did occur, it could harm our results of operations or financial condition.  A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit.  Moreover, a major incident at any nuclear facility in the U.S. could require us to make material contributory payments.

The different regional power markets in which we compete or will compete in the future have changing transmission regulatory structures, which could affect our performance in these regions.  (Applies to each registrant.)

Our results are likely to be affected by differences in the market and transmission regulatory structures in various regional power markets.  The rules governing the various regional power markets, including SPP and PJM, may also change from time to time which could affect our costs or revenues.  Because the manner in which RTOs will evolve remains unclear, we are unable to assess fully the impact that changes in these power markets may have on our business.

The amount we charged third parties for using our transmission facilities has been reduced and is subject to refund. (Applies to AEP, APCo, CSPCo, I&M and OPCo.)

In July 2003, the FERC issued an order directing PJM and MISO to make compliance filings for their respective tariffs to eliminate the transaction-based charges for through and out (T&O) transmission service on transactions where the energy is delivered within those RTOs.  The elimination of the T&O rates reduced the transmission service revenues collected by the RTOs and thereby reduced the revenues received by transmission owners under the RTOs’ revenue distribution protocols. To mitigate the impact of lost T&O revenues, the FERC approved temporary replacement seams elimination cost allocation (SECA) transition rates beginning in December 2004 and extending through March 2006.  Because intervenors objected to this decision, the SECA fees we collected ($220 million) are subject to refund.  

A hearing was held in May 2006 to determine whether any of the SECA revenues should be refunded. In August 2006, the ALJ ruled that the rate design for the recovery of SECA charges was flawed and that a large portion 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 unpaid SECA rates must be paid in the recommended reduced amount.  The FERC has not ruled on the matter.  If the FERC upholds the decision of the ALJ, it would disallow $90 million of the AEP East companies’ remaining unsettled $108 million of unsettled gross SECA revenues.  AEP has settled $112 million of SECA revenues for $10 million. We have recorded a provision for estimated settlement refunds.   After completed and in-process settlements, the AEP East companies have a remaining reserve balance of $34 million to settle the remaining $108 million in unsettled gross SECA revenues. Based on this settlement history, the $34 million reserve balance should be adequate to absorb the potential refund of the remaining contested SECA rates, assuming that the claims are settled.  Payments in excess of the reserve balance could harm our results of operations and financial position.

An increase in the amount PJM charges us for transmitting power over its network may not be fully recoverable. (Applies to AEP and I&M.)

On June 1, 2007, in response to a 2006 FERC order, PJM revised its methodology for calculating the effect of transmission line losses in generation dispatch when determining locational marginal prices.   The new method is designed to recognize the varying delivery costs of transmitting electricity from individual generator locations to the places where customers consume the energy.  Due to the implementation of the new methodology, we experienced an increase in the cost of transmitting energy to customer load zones in the PJM.  AEP has initiated discussions with PJM regarding the impact of the new methodology and will pursue a modification through the appropriate stakeholder processes.  Management believes these additional costs should be recoverable through retail and/or cost-based wholesale rates.  Recovery has been authorized by the PUCO, KPSC, VSCC and WVPSC.  The adjudication of the filing with the IURC is pending.  In the interim, such costs in these jurisdictions will have an adverse effect on future results of operations and cash flows.  Management is unable to predict whether full recovery will ultimately be approved.

We could be subject to higher costs and/or penalties related to mandatory reliability standards. (Applies to each registrant.)

As a result of EPACT, owners and operators of the bulk power transmission system are subject to mandatory reliability standards promulgated by the North American Electric Reliability Corporation and enforced by the FERC. These standards, which previously were being applied on a voluntary basis, became mandatory in June 2007. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and is guided by reliability and market interface principles. Compliance with new reliability standards may subject us to higher operating costs and/or increased capital expenditures. While we expect to recover costs and expenditures from customers through regulated rates, there can be no assurance that the applicable commissions will approve full recovery in a timely manner.  If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties, which likely would not be recoverable from customers through regulated rates.

At times, demand for power could exceed our supply capacity.  (Applies to each registrant.)

We are currently obligated to supply power in parts of eleven states.  From time to time, because of unforeseen circumstances, the demand for power required to meet these obligations could exceed our available generation capacity.  If this occurs, we would have to buy power from the market.  This would increase the pressure on our short-term debt financing capacity in times of tight liquidity.  We may not always have the ability to pass these costs on to our customers, and the time lag between incurring costs and recovery can be long.  Since these situations most often occur during periods of peak demand, it is possible that the market price for power at that time would be very high. Even if a supply shortage were brief, we could suffer substantial losses that could reduce our results of operations.

Risks Related to Market, Economic or Financial Volatility

If we are unable to access capital markets on reasonable terms, it could have an adverse impact on our net income, cash flows and financial condition.  (Applies to each registrant)

We rely on access to capital markets as a significant source of liquidity for capital requirements not satisfied by operating cash flows.  The recent volatility and reduced liquidity in the financial markets could affect our ability to raise capital and fund our capital needs, including construction costs and refinancing maturing indebtedness.  In addition, if capital is available only on less than reasonable terms or to borrowers whose creditworthiness is better than ours, capital costs could increase materially.  Restricted access to capital markets and/or increased borrowing costs could have an adverse impact on net income, cash flows and financial condition.

Downgrades in our credit ratings could negatively affect our ability to access capital and/or to operate our power trading businesses.  (Applies to each registrant.)

The credit ratings agencies periodically review our capital structure and the quality and stability of our earnings.  Any negative ratings actions could constrain the capital available to our industry and could limit our access to funding for our operations.  Our business is capital intensive, and we are dependent upon our ability to access capital at rates and on terms we determine to be attractive.  In the current period of market turmoil, access to capital is difficult for all borrowers.  If our ability to access capital becomes significantly constrained, our costs of capital will likely increase and our financial condition could be harmed and future results of operations could be adversely affected.

If Moody’s or S&P were to downgrade the long-term rating of any of the securities of the registrants, particularly below investment grade, the borrowing costs of that registrant would increase, which would diminish its financial results.  In addition, the registrant’s potential pool of investors and funding sources could decrease.  Over the first two months of 2009, Moody’s placed the senior unsecured debt rating of AEP on negative outlook, the senior unsecured debt rating of OPCo, SWEPCo, TCC and TNC on review for possible downgrade and changed the outlook of APCo from negative to stable.  In February 2008 Fitch downgraded the senior unsecured debt rating of PSO to BBB+ with stable outlook.  Fitch placed the senior unsecured debt rating of APCo and TCC on negative outlook in May 2008 and February 2009, respectively.

Our power trading business relies on the investment grade ratings of our individual public utility subsidiaries’ senior unsecured long-term debt.  Most of our counterparties require the creditworthiness of an investment grade entity to stand behind transactions.  If those ratings were to decline below investment grade, our ability to operate our power trading business profitably would be diminished because we would likely have to deposit cash or cash-related instruments which would reduce our profits.

Our retirement plans may require additional significant contributions. (Applies to each registrant.)

The performance of the capital markets affects the value of the assets that are held in trust to satisfy future obligations under our defined benefit pension plans. The recent deterioration of the capital markets has led to a decline in the market value of these assets and a reduction in the benchmark discount rate with respect to a return on these assets. Accordingly, we expect that our future funding requirements of the obligations under our defined benefit plans to significantly increase.

AEP has no income or cash flow apart from dividends paid or other obligations due it from its subsidiaries.  (Applies to AEP.)

AEP is a holding company and has no operations of its own.  Its ability to meet its financial obligations associated with its indebtedness and to pay dividends on its common stock is primarily dependent on the earnings and cash flows of its operating subsidiaries, primarily its regulated utilities, and the ability of its subsidiaries to pay dividends to, or repay loans from, AEP.  Its subsidiaries are separate and distinct legal entities that have no obligation (apart from loans from AEP) to provide AEP with funds for its payment obligations, whether by dividends, distributions or other payments. Payments to AEP by its subsidiaries are also contingent upon their earnings and business considerations. In addition, any payment of dividends, distributions or advances by the utility subsidiaries to AEP would be subject to regulatory or contractual restrictions.  AEP indebtedness and common stock dividends are effectively subordinated to all subsidiary indebtedness and preferred stock obligations.

Our operating results may fluctuate on a seasonal or quarterly basis and with general economic conditions.  (Applies to each registrant.)

Electric power generation 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.  As a result, our overall operating results in the future may fluctuate substantially on a seasonal basis.  The pattern of this fluctuation may change depending on the terms of power sale contracts that we enter into.  In addition, we have historically sold less power, and consequently earned less income, when weather conditions are milder.  Unusually mild weather in the future could diminish our results of operations and harm our financial condition.  Conversely, unusually extreme weather conditions could increase AEP’s results of operations in a manner that would not likely be sustainable.  Further, deteriorating economic conditions generally result in reduced consumption by our customers, particularly industrial customers who may curtail operations or cease production entirely, while an expanding economic environment generally results in increased revenues.  As a result, our overall operating results in the future may fluctuate on the basis of prevailing economic conditions.  For example, a leading customer of APCO, Century Aluminum in West Virginia, announced in February 2009 that it was ceasing operations.

Failure to attract and retain an appropriately qualified workforce could harm our results of operations. (Applies to each registrant.)

 

Certain events, such as an aging workforce without appropriate replacements, mismatch of skillset or complement to future needs, or unavailability of contract resources may lead to operating challenges and increased costs. The challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development. In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate our business.  If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations could be negatively affected.

Parties we have engaged to provide construction materials or services may fail to perform their obligations, which could harm our results of operations.  (Applies to each registrant.)

Our business plan calls for extensive investment in capital improvements and additions, including the installation of environmental upgrades, construction of additional generation units and transmission facilities as well as other initiatives.   We are exposed to the risk of substantial price increases in the costs of materials used in construction.  We have engaged numerous contractors and entered into a large number of agreements to acquire the necessary materials and/or obtain the required construction related services.  As a result, we are also exposed to the risk that these contractors and other counterparties could breach their obligations to us.  Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices and almost certainly cause delays in that and related projects.   Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than these mitigation provisions. This would cause our financial results to be diminished, and we might incur losses or delays in completing construction.

Changes in commodity prices and the costs of transport may increase our cost of producing power or decrease the amount we receive from selling power, harming our financial performance.  (Applies to each registrant.)

We are exposed to changes in the price and availability of coal and the price and availability to transport coal because most of our generating capacity is coal-fired.  We have contracts of varying durations for the supply of coal for most of our existing generation capacity, but as these contracts end or otherwise are not honored, we may not be able to purchase coal on terms as favorable as the current contracts.   Similarly, we are exposed to changes in the price and availability of emission allowances.   We use emission allowances based on the amount of coal we use as fuel and the reductions achieved through emission controls and other measures.   According to our estimates, we have procured sufficient emission allowances to cover our projected needs for the next two years and for much of the projected needs for periods beyond that.   At some point, however, we may have to obtain additional allowances and those purchases may not be on as favorable terms as those currently obtained.

We also own natural gas-fired facilities, which increases our exposure to market prices of natural gas. Natural gas prices tend to be more volatile than prices for other fuel sources. Our ability to make off-system sales at a profit is highly dependent on the price of natural gas.  As the price of natural gas falls, other market participants that utilize natural gas-fired generation will be able to offer electricity at increasingly competitive prices relative to our off-system sales prices, so the margins we realize from sales will be lower and, on occasion, we may need to curtail operation of marginal plants.

The price trends for coal, natural gas and emission allowances have shown material increases in the recent past.   Changes in the cost of coal, emission allowances or natural gas and changes in the relationship between such costs and the market prices of power will affect our financial results.  Since the prices we obtain for power may not change at the same rate as the change in coal, emission allowances or natural gas costs, we may be unable to pass on the changes in costs to our customers.

In addition, actual power prices and fuel costs will differ from those assumed in financial projections used to value our trading and marketing transactions, and those differences may be material.  As a result, our financial results may be diminished in the future as those transactions are marked to market.

In Ohio, we have limited ability to pass on our fuel costs to our customers.  (Applies to AEP, CSPCo and OPCo.)

Because generation is no longer regulated in Ohio, we are exposed to risk from changes in the market prices of coal, natural gas, and emissions allowances used to generate power.  The prices of coal, natural gas and emissions allowances have increased materially in the recent past.  The protection afforded by retail fuel clause recovery mechanisms has been eliminated by the implementation of customer choice in Ohio, which represents approximately 20% of our fuel costs.  As long as generating costs cannot be passed through to customers as a matter of right in Ohio, we retain these risks.  If we cannot recover an amount sufficient to cover our actual fuel costs, our results of operations and cash flows would be adversely affected.

Risks Relating to State Restructuring

There is uncertainty as to our recovery of stranded costs resulting from industry restructuring in Texas.  (Applies to AEP.)

Restructuring legislation in Texas required utilities with stranded costs to use market-based methods to value certain generating assets for determining stranded costs.  We elected to use the sale of assets method to determine the market value of TCC’s generation assets for stranded cost purposes.  In general terms, the amount of stranded costs under this market valuation methodology is the amount by which the book value of generating assets, including regulatory assets and liabilities that were not securitized, exceeds the market value of the generation assets, as measured by the net proceeds from the sale of the assets. In May 2005, TCC filed its stranded cost quantification application 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.  We have appealed the PUCT’s final order seeking additional recovery consistent with the Texas Restructuring Legislation and related rules, other parties have appealed the PUCT’s final order as unwarranted or too large. Management cannot predict the ultimate outcome of any future court appeals or any future remanded PUCT proceeding.

Collection of our revenues in Texas is concentrated in a limited number of REPs. (Applies to AEP.)

Our revenues from the distribution of electricity in the ERCOT area of Texas are collected from REPs that supply the electricity we distribute to their customers.  Currently, we do business with approximately seventy REPs.  In 2008, TCC’s largest customer accounted for 28% of its operating revenues; TNC’s largest customer (a non-utility affiliate) accounted for 28% of its operating revenues and its second largest customer accounted for 12% of its operating revenues.  Adverse economic conditions, structural problems in the Texas market or financial difficulties of one or more REPs could impair the ability of these REPs to pay for our services or could cause them to delay such payments.  We depend on these REPs for timely remittance of payments.  Any delay or default in payment could adversely affect the timing and receipt of our cash flows and thereby have an adverse effect on our liquidity.

Risks Related to Owning and Operating Generation Assets and Selling Power

Our costs of compliance with environmental laws are significant and the cost of compliance with future environmental laws could harm our cash flow and profitability or cause some of our electric generating units to be uneconomical to maintain or operate. (Applies to each registrant)

Our operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources and health and safety.  Approximately 90% of the electricity generated by the AEP system is produced by the combustion of fossil fuels.  Emissions of nitrogen and sulfur oxides, mercury and particulates from fossil fueled generating plants are potentially subject to increased regulations, controls and mitigation expenses.  Compliance with these legal requirements requires us to commit significant capital toward environmental monitoring, installation of pollution control equipment, emission fees and permits at all of our facilities.  These expenditures have been significant in the past, and we expect that they will increase in the future.  Further, environmental advocacy groups, other organizations and some agencies in the United States are focusing considerable attention on CO2 emissions from power generation facilities and their potential role in climate change.  Although several bills have been introduced in Congress that would compel CO2 emission reductions, none have advanced through the legislature.  In April 2007 the U.S. Supreme Court determined that CO2 is an “air pollutant” and that the Federal EPA has authority to regulate CO2 emissions under the CAA.  In July 2008 the Federal EPA issued an advance notice of proposed rulemaking (ANPR) that requests comments on a wide variety of issues in response to the U.S. Supreme Court’s decision.  The ANPR could lead to regulations limiting the emissions of CO2 from our generating plants.  In addition, the Obama administration has indicated that it intends to focus on reducing CO2 emissions.

Costs of compliance with environmental regulations could adversely affect our net income and financial position, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and types of assets we operate increase.  All of our estimates are subject to significant uncertainties about the outcome of several interrelated assumptions and variables, including timing of implementation, required levels of reductions, allocation requirements of the new rules and our selected compliance alternatives.  As a result, we cannot estimate our compliance costs with certainty.  The actual costs to comply could differ significantly from our estimates.  All of the costs are incremental to our current investment base and operating cost structure.  In addition, any legal obligation that would require us to substantially reduce our emissions beyond present levels could require extensive mitigation efforts and, in the case of CO2 legislation, would raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities.  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, without such recovery those costs could adversely affect future net income and cash flows, and possibly financial condition.

Governmental authorities may assess penalties on us if it is determined that we have not complied with environmental laws and regulations. (Applies to each registrant.)

If we fail to comply with environmental laws and regulations, even if caused by factors beyond our control, that failure may result in the assessment of civil or criminal penalties and fines against us.  In July 2004 attorneys general of eight states and others sued AEP and other utilities alleging that CO2 emissions from power generating facilities constitute a public nuisance under federal common law.  The trial court dismissed the suits and plaintiffs have appealed the dismissal.  While we believe the claims are without merit, the costs associated with reducing CO2 emissions could harm our business and our results of operations and financial position.

If these or other future actions are resolved against us, substantial modifications of our existing coal-fired power plants could be required.  In addition, we could be required to invest significantly in additional emission control equipment, accelerate the timing of capital expenditures, pay penalties and/or halt operations.  Moreover, our results of operations and financial position could be reduced due to the timing of recovery of these investments and the expense of ongoing litigation.

Our financial performance may be impaired if Cook Plant Unit 1 is not returned to service in a reasonable period of time or in a cost-efficient manner.  (Applies to AEP and I&M)

Cook Plant Unit 1 is a 1,055 MW nuclear generating unit located in Bridgman, Michigan. In September 2008, I&M shut down Unit 1 due to turbine vibrations, likely caused by blade failure, which resulted in a fire on the electric generator.  I&M is working with its insurance company and turbine vendor to evaluate the extent of the damage resulting from the incident and the costs to return the unit to service.  Repair and replacement of the turbine rotors is estimated to cost up to approximately $330 million.  Management believes that I&M should recover a significant portion of these costs through the turbine vendor’s warranty, insurance and the regulatory process.  If any of these costs are not covered by warranty, insurance or recovered through the regulatory process, or if the unit is not returned to service in a reasonable period of time, it could have an adverse impact on net income, cash flows and financial condition.

Our revenues and results of operations from selling power are subject to market risks that are beyond our control.  (Applies to each registrant.)

We sell power from our generation facilities into the spot market or other competitive power markets or on a contractual basis.  We also enter into contracts to purchase and sell electricity, natural gas, emission allowances and coal as part of our power marketing and energy trading operations.  With respect to such transactions, the rate of return on our capital investments is not determined through mandated rates, and our revenues and results of operations are likely to depend, in large part, upon prevailing market prices for power in our regional markets and other competitive markets.  These market prices can fluctuate substantially over relatively short periods of time.  Trading margins may erode as markets mature and there may be diminished opportunities for gain should volatility decline.  In addition, the FERC, which has jurisdiction over wholesale power rates, as well as RTOs that oversee some of these markets, may impose price limitations, bidding rules and other mechanisms to address some of the volatility in these markets.  Power supply and other similar agreements entered into during extreme market conditions may subsequently be held to be unenforceable by a reviewing court or the FERC.  Fuel and emissions prices may also be volatile, and the price we can obtain for power sales may not change at the same rate as changes in fuel and/or emissions costs.  These factors could reduce our margins and therefore diminish our revenues and results of operations.

Volatility in market prices for fuel and power may result from:

·	weather conditions;

·	seasonality;

·	power usage;

·	illiquid markets;

·	transmission or transportation constraints or inefficiencies;

·	availability of competitively priced alternative energy sources;

·	demand for energy commodities;

·	natural gas, crude oil and refined products, and coal production levels;

·	natural disasters, wars, embargoes and other catastrophic events; and

·	federal, state and foreign energy and environmental regulation and legislation.

Our power trading (including coal, gas and emission allowances trading and power marketing) and risk management policies cannot eliminate the risk associated with these activities.  (Applies to each registrant.)

Our power trading (including coal, gas and emission allowances trading and power marketing) activities expose us to risks of commodity price movements.  We attempt to manage our exposure by establishing and enforcing risk limits and risk management procedures.  These risk limits and risk management procedures may not work as planned and cannot eliminate the risks associated with these activities.  As a result, we cannot predict the impact that our energy trading and risk management decisions may have on our business, operating results or financial position.

We routinely have open trading positions in the market, within guidelines we set, resulting from the management of our trading portfolio.  To the extent open trading positions exist, fluctuating commodity prices can improve or diminish our financial results and financial position.

Our power trading and risk management activities, including our power sales agreements with counterparties, rely on projections that depend heavily on judgments and assumptions by management of factors such as the future market prices and demand for power and other energy-related commodities.  These factors become more difficult to predict and the calculations become less reliable the further into the future these estimates are made.  Even when our policies and procedures are followed and decisions are made based on these estimates, results of operations may be diminished if the judgments and assumptions underlying those calculations prove to be inaccurate.

Our financial performance may be adversely affected if we are unable to operate our pooled electric generating facilities successfully.  (Applies to each registrant.)

Our performance is highly dependent on the successful operation of our electric generating facilities.  Operating electric generating facilities involves many risks, including:

·	operator error and breakdown or failure of equipment or processes;

·	operating limitations that may be imposed by environmental or other regulatory requirements;

·	labor disputes;

·	fuel supply interruptions caused by transportation constraints, adverse weather, non-performance by our suppliers and other factors; and

·	catastrophic events such as fires, earthquakes, explosions, hurricanes, terrorism, floods or other similar occurrences.

A decrease or elimination of revenues from power produced by our electric generating facilities or an increase in the cost of operating the facilities would adversely affect our results of operations.

Parties with whom we have contracts may fail to perform their obligations, which could harm our results of operations.  (Applies to each registrant.)

We are exposed to the risk that counterparties that owe us money or power could breach their obligations.  Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative hedging arrangements or honor underlying commitments at then-current market prices that may exceed our contractual prices, which would cause our financial results to be diminished and we might incur losses. Although our estimates take into account the expected probability of default by a counterparty, our actual exposure to a default by a counterparty may be greater than the estimates predict.

We rely on electric transmission facilities that we do not own or control.  If these facilities do not provide us with adequate transmission capacity, we may not be able to deliver our wholesale electric power to the purchasers of our power.  (Applies to each registrant.)

We depend on transmission facilities owned and operated by other unaffiliated power companies to deliver the power we sell at wholesale.  This dependence exposes us to a variety of risks.  If transmission is disrupted, or transmission capacity is inadequate, we may not be able to sell and deliver our wholesale power.  If a region’s power transmission infrastructure is inadequate, our recovery of wholesale costs and profits may be limited.  If restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in expansion of transmission infrastructure.

The FERC has issued electric transmission initiatives that require electric transmission services to be offered unbundled from commodity sales.  Although these initiatives are designed to encourage wholesale market transactions for electricity and gas, access to transmission systems may in fact not be available if transmission capacity is insufficient because of physical constraints or because it is contractually unavailable.  We also cannot predict whether transmission facilities will be expanded in specific markets to accommodate competitive access to those markets.

We do not fully hedge against price changes in commodities.  (Applies to each registrant.)

We routinely enter into contracts to purchase and sell electricity, natural gas, coal and emission allowances as part of our power marketing and energy and emission allowances trading operations.  In connection with these trading activities, we routinely enter into financial contracts, including futures and options, over-the counter options, financially-settled swaps and other derivative contracts.  These activities expose us to risks from price movements.  If the values of the financial contracts change in a manner we do not anticipate, it could harm our financial position or reduce the financial contribution of our trading operations.

We manage our exposure by establishing risk limits and entering into contracts to offset some of our positions (i.e., to hedge our exposure to demand, market effects of weather and other changes in commodity prices).  However, we do not always hedge the entire exposure of our operations from commodity price volatility.  To the extent we do not hedge against commodity price volatility, our results of operations and financial position may be improved or diminished based upon our success in the market.

 

ITEM 1B.        UNRESOLVED STAFF COMMENTS

None.

ITEM 2.                                PROPERTIES

GENERATION FACILITIES

UTILITY OPERATIONS

At December 31, 2008, the AEP System owned (or leased where indicated) generating plants with net power capabilities (winter rating) shown in the following table:

 

Company		Stations			Coal MW		Natural Gas MW		Nuclear MW		Lignite MW		Hydro MW		Oil MW		Total MW
AEGCo		2	(a)		1,310		1,146										2,456
APCo		17	(b)(c)		5,093		516						681				6,290
CSPCo		7	(d)		2,341		1,357								3		3,701
I&M		9	(a)		2,305				2,191				15				4,511
KPCo		1			1,060												1,060
OPCo		8	(b)(c)(e)		8,452								26				8,478
PSO		8	(f)(g)		1,026		3,552								25		4,603
SWEPCo		10	(h)		1,848		2,152				850						4,850
TNC		6	(f) (i)(j)		377		262								8		647
System Totals		62			23,812		8,985		2,191		850		722		36		36,596
Percentage of System Totals					65.1		24.5		6.0		2.3		2.0		0.1

 

(a)	Unit 1 of the Rockport Plant is owned one-half by AEGCo and one-half by I&M. Unit 2 of the Rockport Plant is leased one-half by AEGCo and one-half by I&M. The leases terminate in 2022 unless extended.

(b)	Unit 3 of the John E. Amos Plant is owned one-third by APCo and two-thirds by OPCo.

(c)	APCo owns Units 1 and 3 and OPCo owns Units 2, 4 and 5 of Philip Sporn Plant, respectively.

(d)	CSPCo owns generating units in common with Duke Ohio and DP&L. Its percentage ownership interest is reflected in this table.

(e)	The scrubber facilities at the General James M. Gavin Plant are leased.  OPCo is permitted to terminate the lease as early as 2010.

(f)	As of December 31, 2008, PSO and TNC, along with Oklahoma Municipal Power Authority and The Public Utilities Board of the City of Brownsville, Texas, jointly owned the Oklaunion power station. PSO and TNC’s ownership interest is reflected in this portion of the table.

(g)	PSO began commercial operation of Units 4 and 5, of 85 MW each (winter rating), at its gas-fired Southwestern Plant in February 2008. Also, commercial operation of PSO’s Units 3 and 4, of 85 MW each (winter rating), at the gas-fired Riverside Plant began in April 2008.

(h)	SWEPCo owns generating units in common with Cleco Corporation and other unaffiliated parties. Only its ownership interest is reflected in this table.

(i)

TNC sold the four inactive plants of Fort Phantom, Lake Pauline, San Angelo, and Rio Pecos to Eagle Construction and Environmental Services, LP for a total of 667 MW (winter rating) in February 2008. A fifth inactive plant owned by TNC, the Oak Creek Plant (85 MW, winter rating), was conveyed to the City of Sweetwater under terms related to a settlement agreement executed by the parties in 2005.

(j)	TNC’s gas-fired and oil-fired generation has been deactivated.

Cook Nuclear Plant

The following table provides operating information relating to the Cook Plant.

	Cook Plant
	Unit 1		Unit 2
Year Placed in Operation	1975		1978
Year of Expiration of NRC License	2034		2037
Nominal Net Electrical Rating in Kilowatts	1,084,000		1,107,000
Net Capacity Factors (a)
2008	59.2%(b)		96.6%
2007	97.4%		83.8%
2006	80.4%		86.5%
2005	88.8%		97.1%

(a)

Net Capacity Factor values for Unit 1 in 2007 and 2008 reflect Nominal Net Electrical Rating in Kilowatts of 1,084,000.  The Net Capacity Factor values for Unit 1 in 2005 and 2006 reflect the previous Nominal Net Electrical Rating in Kilowatts of 1,036,000.  The Net Electrical Rating changed due to low pressure turbine replacement.

(b)	Unit 1 Net Capacity Factor for 2008 was impacted by a forced outage caused by low pressure turbine blade failures.

Costs associated with the operation (including fuel), maintenance and retirement of nuclear plants continue to be more significant and less predictable than costs associated with other sources of generation, in large part due to changing regulatory requirements and safety standards, availability of nuclear waste disposal facilities and experience gained in the operation of nuclear facilities.  The ability of I&M to obtain adequate and timely recovery of costs associated with the Cook Plant is not assured.  Such costs may include replacement power, any unamortized investment at the end of the useful life of the Cook Plant (whether scheduled or premature), the carrying costs of that investment and retirement costs.

GENERATION AND MARKETING

In addition to the generating facilities described above, AEP has ownership interests in other electrical generating facilities. Information concerning these facilities at December 31, 2008 is listed below.

Facility	Fuel	Location	Capacity Total MW	Owner-ship Interest	Status
Desert Sky Wind Farm	Wind	Texas	161	100%	Exempt Wholesale Generator(a)
Trent Wind Farm	Wind	Texas	150	100%	Exempt Wholesale Generator(a)
Total			311

(a)     As defined under rules issued pursuant to EPACT.

 

 See Note 7 to the consolidated financial statements entitled Acquisitions, Dispositions, Discontinued Operations and Impairments, included in the 2008 Annual Reports, for a discussion of AEP’s disposition of independent power producer and foreign generation assets.

TRANSMISSION AND DISTRIBUTION FACILITIES

The following table sets forth the total overhead circuit miles of transmission and distribution lines of the AEP System and its operating companies and that portion of the total representing 765kV lines:

	Total Overhead Circuit Miles of Transmission and Distribution Lines			Circuit Miles of 765kV Lines
AEP System  (a)	224,095	(b)		2,116
APCo	52,022			734
CSPCo (a)	15,519			—
I&M	22,023			615
Kingsport Power Company	1,358			—
KPCo	11,020			258
OPCo	30,762			509
PSO	21,193			—
SWEPCo	21,453			—
TCC	29,564			—
TNC	17,476			—
WPCo	1,705			—

(a)	Includes 766 miles of 345,000-volt jointly owned lines.

(b)	Includes 73 miles of overhead transmission lines not identified with an operating company.

TITLES

The AEP System’s generating facilities are generally located on lands owned in fee simple. The greater portion of the transmission and distribution lines of the System has been constructed over lands of private owners pursuant to easements or along public highways and streets pursuant to appropriate statutory authority. The rights of AEP’s public utility subsidiaries in the realty on which their facilities are located are considered adequate for use in the conduct of their business. Minor defects and irregularities customarily found in title to properties of like size and character may exist, but such defects and irregularities do not materially impair the use of the properties affected thereby. AEP’s public utility subsidiaries generally have the right of eminent domain which permits them, if necessary, to acquire, perfect or secure titles to or easements on privately held lands used or to be used in their utility operations.  Recent legislation in Ohio and Virginia has restricted the right of eminent domain previously granted for power generation purposes.

SYSTEM TRANSMISSION LINES AND FACILITY SITING

Laws in the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Texas, Tennessee, Virginia, and West Virginia require prior approval of sites of generating facilities and/or routes of high-voltage transmission lines. We have experienced delays and additional costs in constructing facilities as a result of proceedings conducted pursuant to such statutes, and in proceedings in which our operating companies have sought to acquire rights-of-way through condemnation.  These proceedings may result in additional delays and costs in future years.  See Management’s Financial Discussion and Analysis of Results of Operations included in the 2008 Annual Reports, for more information on current siting proceedings.

CONSTRUCTION PROGRAM

GENERAL

With input from its state utility commissions, the AEP System continuously assesses the adequacy of its generation, transmission, distribution and other facilities to plan and provide for the reliable supply of electric power and energy to its customers. In this assessment process, assumptions are continually being reviewed as new information becomes available, and assessments and plans are modified, as appropriate.  AEP forecasts $2.6 billion of construction expenditures, excluding AFUDC, for 2009, which is a significant reduction from the original 2009 capital forecast set in 2008.  Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, and the ability to access capital.  Due to recent credit market instability, we reviewed our projections for capital expenditures for 2009 and 2010.  We identified reductions of approximately $750 million for 2009.  We are evaluating possible additional capital reductions for 2010.

PROPOSED TRANSMISSION FACILITIES

Joint Venture in PJM

In June 2007, PJM authorized the construction of a major new transmission line to address the reliability and efficiency needs of the PJM system.  The line would be 765kV and would run approximately 275 miles from APCo’s Amos substation in West Virginia to Allegheny Energy Inc.’s (“AYE”) proposed Kemptown station in north central Maryland.  In September 2007, AEP and AYE entered into a joint venture to construct, own and operate transmission facilities in the PJM region, including the Amos-to-Kemptown transmission line. In December 2007, the joint venture filed an application with the FERC for approval of a return on equity and formula rate for the Amos-to-Kemptown transmission line.  FERC approval of the settlement among the participants is pending.  In addition to the rate recovery sought through the FERC, the joint venture will seek appropriate regulatory approvals from the appropriate state utility commissions for siting and Certificates of Public Convenience and Necessity.  The total cost of the Amos-to-Kemptown line is estimated to be approximately $1.8 billion, and AEP’s estimated share will be approximately $600 million.  The joint venture is not consolidated with AEP for financial or tax reporting purposes.  See Management’s Financial Discussion and Analysis of Results of Operations included in the 2008 Annual Reports for more information.

Joint Venture in ERCOT

In January 2007, TCC entered into an agreement to establish a joint venture with MidAmerican Energy Holdings Company (“MidAmerican”) to fund, own and operate electric transmission assets in ERCOT.  In January 2007, a filing was made with the PUCT seeking regulatory approval to operate as an electric transmission utility in Texas, to transfer transmission assets from TCC to the joint venture and to establish a wholesale transmission tariff.  In December 2007, the PUCT issued an order authorizing the transaction, the initial tariffs and a certificate of convenience and necessity to operate in the ERCOT region. A Texas district court reversed the PUCT’s order granting a certificate of convenience.  Both the PUCT and ETT have appealed this decision.  The PUCT’s appeal suspends enforceability of the court’s judgment pending final appellate review.  Subsidiaries of AEP and MidAmerican each hold a 50 percent equity interest in the joint venture.  The joint venture is not consolidated with AEP for financial or tax reporting purposes.  See Management’s Financial Discussion and Analysis of Results of Operations, Note 4 and Note 7 to the consolidated financial statements, entitled Rate Matter and Acquisitions, Dispositions, Discontinued Operations and Impairments, respectively, included in the 2008 Annual Reports, for more information.

 

PROPOSED GENERATION FACILITIES

 

SWEPCo Projects

In 2008, SWEPCo began construction of a 508 MW combined-cycle natural gas fired plant at its existing Arsenal Hill Power Plant in Shreveport, Louisiana (the “Stall Unit”).  PUCT and LPSC have approved construction of the Stall Unit and filing has been made with the APSC seeking approval to construct the Stall Unit.  The Stall Unit is estimated to cost $384 million, excluding AFUDC, and is expected to be operational in mid-2010.  See Note 4 to the consolidated financial statements, entitled Rate Matters, included in the 2008 Annual Reports, for more information.

In August 2006, SWEPCo announced plans to build a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas named the John W. Turk, Jr. Power Plant (the “Turk Plant”).  In 2008, SWEPCo received various regulatory approvals, including the issuance of an air permit from the Arkansas Department of Environmental Quality, to construct the Turk Plant and actual construction commenced in November 2008.  SWEPCo anticipates owning 73% of the Turk Plant and will be the operator.  During 2007, SWEPCO signed joint ownership, construction and operations agreements with Oklahoma Municipal Power Authority, AECC and ETEC for the remaining 27% of the Turk Plant.  ETEC’s participation in the Turk Plant is contingent on obtaining certain regulatory approvals that are pending.  The Turk Plant is estimated to cost $1.6 billion with SWEPCo’s 73% portion estimated to cost $1.2 billion, excluding AFUDC.  The Turk Plant is expected to be operational in 2013.  See Note 4 to the consolidated financial statements, entitled Rate Matters, included in the 2008 Annual Reports, for more information.

 

Ohio IGCC Plant

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.  In June 2006, the PUCO issued an order approving a tariff to recover pre-construction costs, subject to refund.  In March 2008, the Ohio Supreme Court remanded the matter back to the PUCO after review.    Pending the outcome of the remand, neither CSPCo nor OPCo are engaged in a continuous course of construction on the IGCC plant.  In December 2007 we estimated that its construction would cost $2.7 billion.  Since then costs to construct generation facilities have continued to increase significantly.  Management continues to pursue the ultimate construction of the IGCC plant.  However, CSPCo and OPCo will not start construction of the IGCC plant until sufficient assurance of regulatory cost recovery exists.See Management’s Financial Discussion and Analysis of Results of Operations and Note 4 to the consolidated financial statements, entitled Rate Matters, included in the 2008 Annual Reports, for more information.

 

West Virginia IGCC

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 proposed 629 MW IGCC plant.  The plant is to be built adjacent to APCo’s existing Mountaineer Generating Station in Mason County, WV for an estimated cost of $2.2 billion.  In March 2008, the WVPSC granted APCo the CCN to build the plant and approved the requested cost recovery.  In July 2007, APCo filed a request with the VSCC for a rate adjustment clause to recover initial costs associated with a proposed IGCC plant.  The VSCC issued an order in April 2008 denying APCo’s requests, in part, upon its finding that the estimated cost of the plant was uncertain and may escalate.  In July 2008, based on the unfavorable order received in Virginia, the WVPSC issued a notice seeking comments from parties on how the WVPSC should proceed.  Comments were filed by various parties, including APCo, but the WVPSC has not taken any action.  See Management’s Financial Discussion and Analysis of Results of Operations and Note 4 to the consolidated financial statements, entitled Rate Matters, included in the 2008 Annual Reports, for more information.

Mountaineer Carbon Capture Project

In January 2008, APCo and ALSTOM Power Inc. (Alstom), an unrelated third party, entered into an agreement to jointly construct a 20 MW CO2 capture demonstration facility at APCo’s Mountaineer 1320 MW generating unit.  APCo and Alstom will each own part of the CO2 capture facility.  APCo will also construct and own the necessary facilities to store the CO2.  RWE AG, a German electric power and natural gas public utility, is participating in the evaluation of the commercial and technical feasibility of taking captured CO2 from the flue gas stream and storing it in deep geologic formations.  APCo’s estimated cost for its share of the facilities is $76 million.  Through December 31, 2008, APCo incurred $29 million in capitalized project costs that are included in regulatory assets.  APCo is earning a return on the capitalized project costs incurred through June 30, 2008, as a result of the base rate case settlement approved by the VSCC in November 2008. See Note 4 to the consolidated financial statements, entitled Rate Matters, included in the 2008 Annual Reports, for more information.

 

Other

Our significant planned environmental investments in emission control installations at existing coal-fired plants and our commitment to IGCC and ultra-supercritical technology reinforce our belief that coal will be a lower-emission domestic energy source of the future and further signals our commitment to invest in clean, environmentally safe technology.   For additional information regarding anticipated environmental expenditures, see Management’s Financial Discussion and Analysis of Results of Operations under the heading entitled Environmental Matters.

CONSTRUCTION EXPENDITURES

The following table shows construction expenditures (including environmental expenditures) during 2006, 2007 and 2008 and a current estimate of 2009 construction expenditures, in each case excluding AFUDC, capitalized interest and assets acquired under leases.

	2006 Actual (b)		2007 Actual (c)		2008 Actual (d)		2009 Estimate
	(in thousands)
Total AEP System (a)	$3,551,000		$3,414,000		$3,981,200		$2,584,000
APCo	922,700		715,700		755,800		367,500
CSPCo	325,000		330,800		435,700		269,600
I&M	306,900		282,400		372,400		361,600
OPCo	978,600		806,000		675,200		439,400
PSO	245,200		302,600		274,200		187,700
SWEPCo	339,400		516,800		689,300		457,400

(a)	Includes expenditures of other subsidiaries not shown. The figures reflect construction expenditures, not investments in subsidiary companies.  Excludes discontinued operations.

(b)	Excludes Cash Flow Statement Adjustments (Statement of Cash Flow Including AFUDC Debt Equals $3,528,000).

(c)	Excludes $512 million for the purchase of Lawrenceburg, Dresden (AEGCo) and Darby (CSPCo) and Cash Flow Statement Adjustments (Statement of Cash Flow Including AFUDC Debt Equals $3,556,000).

(d)	Excludes Cash Flow Statement Adjustments (Statement of Cash Flow Including AFUDC Debt Equals $3,799,600).

The System construction program is reviewed continuously and is revised from time to time in response to changes in estimates of customer demand, business and economic conditions, the cost and availability of capital, environmental requirements and other factors. Changes in construction schedules and costs, and in estimates and projections of needs for additional facilities, as well as variations from currently anticipated levels of net earnings, Federal income and other taxes, and other factors affecting cash requirements, may increase or decrease the estimated capital requirements for the System’s construction program.  Due to recent credit market instability, we reviewed our projections for capital expenditures for 2009 and 2010.  We identified reductions of approximately $750 million for 2009.  We are evaluating possible additional capital reductions for 2010.  

POTENTIAL UNINSURED LOSSES

Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including liabilities relating to damage to our generating plants and costs of replacement power. Unless allowed to be recovered through rates, future losses or liabilities which are not completely insured could have a material adverse effect on results of operations and the financial condition of AEP and other AEP System companies. For risks related to owning a nuclear generating unit, see Note 9 to the consolidated financial statements entitled Nuclear for information with respect to nuclear incident liability insurance.

ITEM 3.                                LEGAL PROCEEDINGS

For a discussion of material legal proceedings, see Note 6 to the consolidated financial statements, entitled Commitments, Guarantees and Contingencies, incorporated by reference in Item 8.

ITEM 4.                                SUBMISSION OF MATTERS TO A VOTE

            OF SECURITY HOLDERS

AEP, APCo, OPCo, PSO and SWEPCo. None.

CSPCo and I&M. Omitted pursuant to Instruction I(2)(c).

EXECUTIVE OFFICERS OF THE REGISTRANTS

AEP.  The following persons are, or may be deemed, executive officers of AEP.  Their ages are given as of February 1, 2009.

Name		Age		Office (a)
Michael G. Morris		62		Chairman of the Board, President and Chief Executive Officer
Nicholas K. Akins		48		Executive Vice President
Carl L. English		62		Chief Operating Officer
John B. Keane		62		Executive Vice President, General Counsel and Secretary
Holly Keller Koeppel		50		Executive Vice President and Chief Financial Officer
Venita McCellon-Allen		49		Executive Vice President
Richard E. Munczinski		56		Senior Vice President
Robert P. Powers		54		President-AEP Utilities
Brian X. Tierney		41		Executive Vice President
Susan Tomasky		55		President – AEP Transmission

(a)

Messrs. Morris, Akins, Munczinski, Powers and Tierney and Ms. Koeppel and Ms. Tomasky have been employed by AEPSC or System companies in various capacities (AEP, as such, has no employees) for the past five years.  Messrs.  Akins, Munczinski, Powers and Tierney, Ms. Koeppel and Ms. Tomasky became executive officers of AEP effective with their promotions on August 15, 2006, June 1, 2008, October 24, 2001, January 1, 2008, November 18, 2002 and January 26, 2000, respectively.  Mr. Keane became an executive officer of AEP in July 2004.  Before joining AEPSC in July 2004, Mr. Keane was President of Bainbridge Crossing Advisors.  Mr. English became an executive officer of AEP on August 1, 2004.  Before joining AEPSC in August 2004, Mr. English was President and Chief Executive Officer of Consumers Energy gas division.  Ms. McCellon-Allen became an executive officer of AEP in July 2008.  From August 2006 to June 2008, Ms. McCellon-Allen was President and Chief Operating Officer of SWEPCO.  Before joining AEPSC in 2004, Ms. McCellon-Allen was SVP-Human Resources for Baylor Heath Care Systems.  All of the above officers are appointed annually for a one-year term by the board of directors of AEP.

APCo, OPCo, PSO and SWEPCo.  The names of the executive officers of APCo, OPCo, PSO and SWEPCo, the positions they hold with these companies, their ages as of February 1, 2009, and a brief account of their business experience during the past five years appear below. The directors and executive officers of APCo, OPCo, PSO and SWEPCo are elected annually to serve a one-year term.

Name		Age		Position		Period
Michael G. Morris (a)(b)		62		Chairman of the Board, President, Chief Executive Officer and Director of AEP		2004-Present
				Chairman of the Board, Chief Executive Officer and Director of APCo, OPCo, PSO and SWEPCo		2004-Present
Nicholas K. Akins (a)		48		Executive Vice President of AEP		2006-Present
				Vice President and Director of APCo, OPCo, PSO		2006-Present
				and SWEPCo
				President and Chief Operating Officer of SWEPCo		2004-2006
Carl L. English (a)		62		Chief Operating Officer		2008-Present
				President-AEP Utilities of AEP		2004-2007
				Director and Vice President of APCo, OPCo, PSO and SWEPCo		2004-Present
				President and Chief Executive Officer of Consumers Energy gas division		1999-2004
John B. Keane (c)		62		Executive Vice President, General Counsel and Secretary of AEP		2004-Present
				Director of APCo, OPCo , PSO and SWEPCo		2004-Present
				President of Bainbridge Crossing Advisors		2003-2004
Holly Keller Koeppel (a)(d)		50		Executive Vice President and Chief Financial Officer of AEP		2006-Present
				Executive Vice President-AEP Utilities-East of AEPSC		2004-2006
				Vice President of APCo and OPCo		2003-Present
				Director of APCo and OPCo		2004-Present
				Chief Financial Officer of APCo, OPCo, PSO and SWEPCo		2006-Present
				Vice President and Director of PSO and SWEPCo		2006-Present
				Executive Vice President-Commercial Operations of AEPSC		2002-2004
Venita McCellon-Allen		49		Executive Vice President		2008-Present
				Director and Vice President of PSO and SWEPCo		2008-Present
				President and Chief Operating Officer of SWEPCo		2006-2008
				Director and Senior Vice President-Shared Services of AEPSC		2004-2006
				Director of APCo, I&M, OPCo and SWEPCo		2004-2006
				Senior Vice President-Human Resources for Baylor Health Care Systems		2000-2004
Richard E. Munczinski (c)		56		Senior Vice President-Shared Services		2008-Present
				Senior Vice President-Corporate Planning & Budgeting of AEPSC		1998-2008
Robert P. Powers (a)		54		President-AEP Utilities of AEP		2008-Present
				Executive Vice President of AEP		2004-2007
				Director and Vice President of APCo and OPCo		2001-Present
				Director and Vice President of PSO and SWEPCo		2008-Present
Brian X. Tierney (a)		41		Executive Vice President		2008-Present
				Director and Vice President of APCo and OPCo		2008-Present
				Senior Vice President—Commercial Operations of AEPSC		2005-2007
				Senior Vice President— Energy Marketing of AEPSC		2003-2005
Susan Tomasky (a)		55		President-AEP Transmission		2008-Present
				Executive Vice President of AEP		2004-Present
				Chief Financial Officer of AEP		2001-2006
				Vice President and Director of APCo, OPCo, PSO and SWEPCo		2000-Present

(a)	Messrs. Morris, Akins, English, Powers and Tierney and Ms. Koeppel and Ms. Tomasky are directors of CSPCo and I&M.
(b)	Mr. Morris is a director of Alcoa, Inc. and The Hartford Financial Services Group, Inc.
(c)	Mr. Keane and Mr. Munczinski are directors of CSPCo.
(d)	Ms. Koeppel is a director of Reynolds American Inc.

APCo:

Name		Age		Position		Period
Dana E. Waldo		57		President and Chief Operating Officer of APCo		2004-Present
				President and Chief Executive Officer of West Virginia Roundtable		1999-2004

OPCo:

Name		Age		Position		Period
Joseph Hamrock		45		President and Chief Operating Officer of CSPCo and OPCo		2008-Present
				Senior Vice President and Chief Information Officer of AEPSC		2003-2007

PSO:

Name		Age		Position		Period
Stuart Solomon		47		President and Chief Operating Officer of PSO		2004-Present
				Vice President-Public Policy & Regulatory Services of AEPSC		2001-2004

SWEPCo:

Name		Age		Position		Period
Paul Chodak, III		45		President and Chief Operating Officer of SWEPCo		2008-Present
				Director-New Generation of AEPSC		2007-2008
				Director-Environmental Programs of AEPSC		2004-2007
				Director-Environmental Programs of AEPSC		2004-2007

 

 

PART II

ITEM 5.                  MARKET FOR REGISTRANTS’ COMMON EQUITY,

         RELATED STOCKHOLDER MATTERS

             AND ISSUER PURCHASES OF EQUITY SECURITIES

AEP. The information required by this item is incorporated herein by reference to the material under AEP Common Stock and Dividend Information in the 2008 Annual Report.

APCo, CSPCo, I&M, OPCo, PSO and SWEPCo. The common stock of these companies is held solely by AEP. The amounts of cash dividends on common stock paid by these companies to AEP during 2008, 2007 and 2006 are incorporated by reference to the material under Statements of Changes in Common Shareholder’s Equity and Comprehensive Income (Loss) in the 2008 Annual Reports.

The following table provides information about purchases by AEP (or its publicly-traded subsidiaries) during the quarter ended December 31, 2008 of equity securities that are registered by AEP (or its publicly-traded subsidiaries) pursuant to Section 12 of the Exchange Act:

 ISSUER PURCHASES OF EQUITY SECURITIES

Period

Total Number of Shares Purchased

Average Price Paid per Share

Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs

Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs

10/01/08 – 10/31/08

-

$

-

-

$

-

11/01/08 – 11/30/08

-

-

-

-

12/01/08 – 12/31/08

-

-

-

-

Total

-

$

-

-

$

-

ITEM 6.                                SELECTED FINANCIAL DATA

CSPCo and I&M.  Omitted pursuant to Instruction I(2)(a).

AEP, APCo, OPCo, PSO and SWEPCo.  The information required by this item is incorporated herein by reference to the material under Selected Consolidated Financial Data in the 2008 Annual Reports.

ITEM 7.            MANAGEMENT’S DISCUSSION AND ANALYSIS

        OF FINANCIAL CONDITION

        AND RESULTS OF OPERATION

CSPCo and I&M.  Omitted pursuant to Instruction I(2)(a). Management’s narrative analysis of the results of operations and other information required by Instruction I(2)(a) is incorporated herein by reference to the material under Management’s Financial Discussion and Analysis of Results of Operations in the 2008 Annual Reports.

AEP, APCo, OPCo, PSO and SWEPCo.  The information required by this item is incorporated herein by reference to the material under Management’s Financial Discussion and Analysis of Results of Operations in the 2008 Annual Reports.

ITEM 7A.                 QUANTITATIVE AND QUALITATIVE

            DISCLOSURES ABOUT MARKET RISK

AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo. The information required by this item is incorporated herein by reference to the material under Management’s Financial Discussion and Analysis of Results of Operations in the 2008 Annual Reports.

ITEM 8.                   FINANCIAL STATEMENTS

            AND SUPPLEMENTARY DATA

AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo. The information required by this item is incorporated herein by reference to the financial statements and financial statement schedules described under Item 15 herein.

ITEM 9.                       CHANGES IN AND DISAGREEMENTS WITH

        ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo.                                None.

ITEM 9A.            CONTROLS AND PROCEDURES

During 2008, management, including the principal ex