UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(MARK ONE)

x ANNUAL REPORT PURSUANT TO SECTION 13, 15(d), OR 37 OF THE

 SECURITIES EXCHANGE ACT OF 1934

 For the fiscal year ended September 30, 2010

 OR

 o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

 THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____ to _____

Commission file number 000-52313

TENNESSEE VALLEY AUTHORITY

(Exact name of registrant as specified in its charter)

A corporate agency of the United States created by an act of Congress  (State or other jurisdiction of incorporation or organization)	62-0474417  (IRS Employer Identification No.)
400 W. Summit Hill Drive Knoxville, Tennessee  (Address of principal executive offices)	37902  (Zip Code)

(865) 632-2101

Registrant’s telephone number, including area code

Securities registered pursuant to Section 12(b) of the Act:  None

Securities registered pursuant to Section 12(g) of the Act:  None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes o  No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13, Section 15(d), or Section 37 of the Securities Exchange Act.  Yes o  No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13, 15(d), or 37 of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x  No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes o  No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.  (Check one):

Large accelerated filer o                                                Accelerated filer o

Non-accelerated filer   x                                                Smaller reporting company  o

(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act).  Yes o  No x

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Table of Contents
FORWARD-LOOKING INFORMATION	5
GENERAL INFORMATION	6
PART I
ITEM1. BUSINESS	7
The Corporation	7
Service Area	7
Customers	8
Rates	10
Current Power Supply	12
Fuel Supply	18
Transmission	20
Weather and Seasonality	20
Competition	21
Integrated Resource Plan and Future Power Supply	21
Research and Development	24
Environmental Stewardship Activities	24
Economic Development Activities	25
Governance	25
Regulation	25
Taxation and Tax Equivalents	27
Environmental Matters	27
Employee Relations	36
ITEM 1A. RISK FACTORS	36
ITEM 1B. UNRESOLVED STAFF COMMENTS	44
ITEM 2. PROPERTIES	44
Generating Properties	44
Transmission Properties	44
Natural Resource Stewardship Properties	44
Buildings	44
Disposal of Property	45
ITEM 3. LEGAL PROCEEDINGS	45
ITEM 4. RESERVED	45
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED TO STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	46
ITEM 6. SELECTED FINANCIAL DATA	46
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	47
Business Overview	47
Executive Summary	47
2010 Highlights	47
2010 Challenges	48
Future Challenges	50
Liquidity and Capital Resources	52
Results of Operations	58
Off-Balance Sheet Arrangements	62
Critical Accounting Policies and Estimates	62
Changes in Ratemaking Impacting Accounting	67
Fair Value Measurements	68
New Accounting Standards and Interpretations	70
Legislative and Regulatory Matters	71
Environmental Matters	71
Legal Proceedings	71
Risk Management Activities	72
Subsequent Event	76
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	76
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	77
Statements of Operations	77
Balance Sheets	78
Statements of Cash Flows	79
Statements of Changes in Proprietary Capital	80
Notes to Financial Statements	81
Report of Independent Registered Public Accounting Firm	134
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	135
ITEM 9A. CONTROLS AND PROCEDURES	135
Disclosure Controls and Procedures	135
Internal Control over Financial Reporting	135
Report of Independent Registered Public Accounting Firm	136
ITEM 9B. OTHER INFORMATION	137

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PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE	138
Directors	138
Executive Officers	139
Disclosure and Financial Code of Ethics	141
Committees of the TVA Board	141
ITEM 11. EXECUTIVE COMPENSATION	142
Compensation Discussion and Analysis	142
Executive Compensation Tables and Narrative Disclosures	153
Retirement and Pension Plans	158
Potential Payments on Account of Retirement/Resignation, Termination without Cause, Termination with Cause, or Death/Disability	161
Other Agreements	164
Director Compensation	164
Compensation Committee Interlocks and Insider Participation	166
Compensation Committee Report	166
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	166
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	166
Director Independence	166
Related Party Transactions	167
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES	168
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES	170
SIGNATURES	175
EXHIBIT INDEX	177

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GLOSSARY OF COMMON ACRONYMS
Following are definitions of terms or acronyms frequently used in this Annual Report on Form 10-K for the fiscal year ended September 30, 2010 (the “Annual Report”):
Term or Acronym	Definition
AFUDC	Allowance for funds used during construction
ARO	Asset retirement obligation
ART	Asset Retirement Trust
ASLB	Atomic Safety and Licensing Board
BEST	Bellefonte Efficiency and Sustainability Team
BREDL	Blue Ridge Environmental Defense League
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CCP	Coal combustion products
CERCLA	Comprehensive Environmental Response, Compensation, and Liability Act
CME	Chicago Mercantile Exchange
CO2	Carbon dioxide
COLA	Cost of living adjustment
CVA	Credit valuation adjustment
CY	Calendar year
DOE	Department of Energy
EPA	Environmental Protection Agency
FASB	Financial Accounting Standards Board
FCA	Fuel cost adjustment
FERC	Federal Energy Regulatory Commission
FPA	Federal Power Act
FTP	Financial Trading Program
GAAP	Accounting principles generally accepted in the United States of America
GHGs	Greenhouse gas
GWh	Gigawatt hours(s)
kWh	Kilowatt hour(s)
LIBOR	London Interbank Offered Rate
MACT	Maximum achievable control technology
mmBtu	Million British thermal unit(s)
MtM	Mark-to-market
MW	Megawatt
NDT	Nuclear Decommissioning Trust
NEPA	National Environmental Policy Act
NOx	Nitrogen oxides
NRC	Nuclear Regulatory Commission
NSR	New Source Review
PCBs	Polychlorinated biphenyls
REIT	Real estate investment trust
SACE	Southern Alliance for Clean Energy
SCRs	Selective catalytic reduction systems
SEIS	Supplemental Environmental Impact Statement
SERP	Supplemental executive retirement plan
Seven States	Seven States Power Corporation
SO2	Sulfur dioxide
SSSL	Seven States Southaven, LLC
TDEC	Tennessee Department of Environment and Conservation
TVARS	Tennessee Valley Authority Retirement System

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FORWARD-LOOKING INFORMATION

This Annual Report contains forward-looking statements relating to future events and future performance.  All statements other than those that are purely historical may be forward-looking statements.  In certain cases, forward-looking statements can be identified by the use of words such as “may,” “will,” “should,” “expect,” “anticipate,” “believe,” “intend,” “project,” “plan,” “predict,” “assume,” “forecast,” “estimate,” “objective,” “possible,” “probably,” “likely,” “potential,” or other similar expressions.

Although the Tennessee Valley Authority (“TVA”) believes that the assumptions underlying the forward-looking statements are reasonable, TVA does not guarantee the accuracy of these statements.  Numerous factors could cause actual results to differ materially from those in the forward-looking statements.  These factors include, among other things:

• New or changed laws, regulations, and administrative orders, including those related to environmental matters, and the costs of complying with these new or changed laws, regulations, and administrative orders, as well as complying with existing laws, regulations, and administrative orders;

• The requirement or decision to make additional contributions to TVA’s pension or other post-retirement benefit plans or to TVA’s nuclear decommissioning trust (“NDT”);

• Significant delays, cost increases, or cost overruns associated with the construction of generation or transmission assets or the cleanup and recovery activities associated with the ash spill at TVA’s Kingston Fossil Plant (“Kingston”);

• Fines, penalties, natural resource damages, and settlements associated with the Kingston ash spill;

• The outcome of legal and administrative proceedings, including, but not limited to, proceedings involving the Kingston ash spill and the North Carolina public nuisance case;

• Significant changes in demand for electricity;

• Addition or loss of customers;

• The continued operation, performance, or failure of TVA’s generation, transmission, and related assets, including coal combustion product (“CCP”) facilities;

• The economics of modernizing aging coal-fired generating units and installing emission control equipment to meet anticipated emission reduction requirements, which could make continued operation of certain coal-fired units uneconomical and lead to their removal from service, perhaps permanently;

• Disruption of fuel supplies, which may result from, among other things, weather conditions, production or transportation difficulties, labor challenges, or environmental laws or regulations affecting TVA’s fuel suppliers or transporters;

• Purchased power price volatility and disruption of purchased power supplies;

• Events involving transmission lines, dams, and other facilities not operated by TVA, including those that affect the reliability of the interstate transmission grid of which TVA’s transmission system is a part as well as the supply of water to TVA’s generation facilities;

• Inability to obtain regulatory approval for the construction or operation of assets;

• Weather conditions;

• Events at a nuclear facility, even one that is not operated by or licensed to TVA;

• Catastrophic events such as fires, earthquakes, solar events, floods, tornadoes, pandemics, wars, national emergencies, terrorist activities, and other similar events, especially if these events occur in or near TVA’s service area;

• Reliability and creditworthiness of counterparties;

• Changes in the market price of commodities such as coal, uranium, natural gas, fuel oil, crude oil, construction materials, electricity, and emission allowances;

• Changes in the market price of equity securities, debt securities, and other investments;

• Changes in interest rates, currency exchange rates, and inflation rates;

•       Rising pension and health care costs;

• Increases in TVA’s financial liability for decommissioning its nuclear facilities and retiring other assets;

• Changes in the market for TVA’s debt, changes in TVA’s debt ceiling, changes in TVA’s credit rating, or limitations on TVA’s ability to borrow money which may result from, among other things, TVA’s approaching or reaching its debt ceiling;

• Changes in the economy and volatility in financial markets;

• Inability to eliminate identified deficiencies in TVA’s systems, standards, controls, and corporate culture;

• Ineffectiveness of TVA’s disclosure controls and procedures and its internal control over financial reporting;

• Problems attracting and retaining a qualified workforce;

• Changes in technology;

• Failure of TVA’s information technology assets to operate as planned;

• Differences between estimates of revenues and expenses and actual revenues and expenses incurred; and

• Unforeseeable events.

See also Item 1A, Risk Factors, and Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.  New factors emerge from time to time, and it is not possible for management to predict all such factors or to assess the extent to which any factor or combination of factors may impact TVA’s business or cause results to

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differ materially from those contained in any forward-looking statement.  TVA undertakes no obligation to update any forward-looking statement to reflect developments that occur after the statement is made.

GENERAL INFORMATION

Fiscal Year

References to years (2010, 2009, etc.) in this Annual Report are to TVA’s fiscal years ending September 30 except for references to years in the biographical information about directors and executive officers in Item 10, Directors, Executive Officers and Corporate Governance, as well as to years that are preceded by “CY,” which references are to calendar years.

Notes

References to “Notes” are to the Notes to Financial Statements contained in Item 8, Financial Statements and Supplementary Data in this Annual Report.

Property

TVA does not own real property.  TVA acquires real property in the name of the United States, and such legal title in real property is entrusted to TVA as the agent of the United States to accomplish the purposes of the Tennessee Valley Authority Act of 1933, as amended, 16 U.S.C. §§ 831-831ee (as amended, the “TVA Act”).  TVA acquires personal property in the name of TVA.  Accordingly, unless the context indicates the reference is to TVA’s personal property, any statement in this Annual Report referring to TVA property shall be read as referring to the real property of the United States which has been entrusted to TVA as its agent.

Available Information

TVA's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports are available on TVA's web site, free of charge, as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission (“SEC”).  TVA's web site is www.tva.gov.  Information contained on TVA’s web site shall not be deemed to be incorporated into, or to be a part of, this Annual Report.  TVA's SEC reports are also available to the public without charge from the web site maintained by the SEC at www.sec.gov.  In addition, the public may read and copy any reports or other information that TVA files with or furnishes to the SEC at the SEC’s Public Reference Room at 100 F Street N.E., Washington, D.C. 20549.  The public may obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.

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PART I

ITEM 1.  BUSINESS

The Corporation

In response to a request by President Franklin D. Roosevelt, the U.S. Congress in 1933 enacted legislation that created the Tennessee Valley Authority (“TVA”), a government corporation.  TVA was created as a government corporation to, among other things, improve navigation on the Tennessee River, reduce the damage from destructive flood waters within the Tennessee River system and downstream on the lower Ohio and Mississippi Rivers, further the economic development of TVA’s service area in the southeastern United States, and sell the electricity generated at the facilities TVA operates.

Today, TVA operates the nation’s largest public power system and supplies power in most of Tennessee, northern Alabama, northeastern Mississippi, and southwestern Kentucky and in portions of northern Georgia, western North Carolina, and southwestern Virginia to a population of over nine million people.  In 2010, the revenues generated from TVA’s electricity sales were $10.7 billion and accounted for virtually all of TVA’s revenues.

TVA also manages the Tennessee River and certain shoreline to protect natural resources, to enhance economic development, and to provide recreational opportunities, adequate water supply, and improved water quality.  TVA’s stewardship responsibilities are conducted within the Tennessee Valley watershed, whose boundaries are similar to, though not exactly the same as, the TVA service area.  TVA’s management of the Tennessee River and its tributaries will sometimes be referred to as TVA’s “stewardship” program in this Annual Report.

Initially, all TVA operations were funded by federal appropriations.  Direct appropriations for the TVA power program ended in 1959, and appropriations for TVA’s stewardship, economic development, and multipurpose activities ended in 1999.  Since 1999, TVA has funded all of its operations almost entirely from the sale of electricity and power system financings.  TVA’s power system financings consist primarily of the sale of debt securities.  TVA is owned by the United States and is not authorized to issue equity securities.

Service Area

The area in which TVA sells power, its service area, is defined by the TVA Act.  Under the TVA Act, subject to certain minor exceptions, TVA may not, without specific authorization from the U.S. Congress, enter into contracts that would have the effect of making it, or the distributor customers of its power, a source of power supply outside the area for which TVA or its distributor customers were the primary source of power supply on July 1, 1957.  This provision is referred to as the “fence” because it bounds TVA’s sales activities, essentially limiting TVA to power sales within a defined service area.

In addition, an amendment to the Federal Power Act (“FPA”) includes a provision that helps protect TVA’s ability to sell power within its service area.  This provision, called the anti-cherrypicking provision, prevents the Federal Energy Regulatory Commission (“FERC”) from ordering TVA to provide access to its transmission lines to others for the purpose of using TVA’s transmission lines to deliver power to customers within substantially all of TVA’s defined service area.  As a result, the anti-cherrypicking provision reduces TVA’s exposure to loss of customers.

Sales of electricity account for substantially all of TVA’s operating revenues.  TVA’s revenues by state for each of the last three years are detailed in the table below.

Operating Revenues For the years ended September 30 (in millions)
	2010		2009		2008
Electricity sales by state
Alabama	$	1,495	$	1,526	$	1,410
Georgia		253		264		238
Kentucky		1,195		1,252		1,192
Mississippi		974		1,017		923
North Carolina		53		58		50
Tennessee		6,693		6,970		6,389
Virginia		48		51		37
Subtotal		10,711		11,138		10,239
Sale for resale and other		2		4		13
Subtotal		10,713		11,142		10,252
Other revenues		161		113		130
Operating revenues	$	10,874	$	11,255	$	10,382

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TVA SERVICE AREA

Customers

TVA is primarily a wholesaler of power.  It sells power to distributor customers, consisting of municipalities and cooperatives that then resell the power to their customers at retail rates.  TVA also sells power to directly served customers, consisting primarily of federal agencies and customers with large or unusual loads.  In addition, power that is excess to the needs of the TVA system may, where consistent with the provisions of the TVA Act, be sold under exchange power arrangements with other electric systems.

Operating revenues by customer type for each of the last three years are set forth in the table below.  In this table, sales to industries directly served are included in Industries directly served, and sales to federal agencies directly served and to exchange power customers are included in Federal agencies and other.

Operating Revenues by Customer Type For the years ended September 30 (in millions)
	2010		2009		2008
Municipalities and cooperatives	$	9,275	$	9,644	$	8,659
Industries directly served		1,321		1,367		1,472
Federal agencies and other
Federal agencies directly served		115		127		108
Off-system sales and other		2		4		13
Subtotal		10,713		11,142		10,252
Other revenues		161		113		130
Operating revenues	$	10,874	$	11,255	$	10,382

Municipalities and Cooperatives

Revenues from distributor customers accounted for 85 percent of TVA’s total operating revenues in 2010.  At September 30, 2010, TVA had wholesale power contracts with 155 municipalities and cooperatives.  Each of these contracts requires distributor customers to purchase from TVA all of their electric power and energy used within the TVA service area.

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All distributor customers purchase power under one of three basic termination notice arrangements:

• Contracts that require five years’ notice to terminate;

• Contracts that require 10 years’ notice to terminate; and

• Contracts that require 15 years’ notice to terminate.

The number of distributor customers with the contract arrangements described above, the revenues derived from such arrangements in 2010, and the percentage of TVA’s 2010 total operating revenues represented by these revenues are summarized in the table below.

TVA Distributor Customer Contracts As of September 30, 2010
Contract Arrangements(1)	Number of Distributor Customers		Sales to Distributor Customers in 2010			Percentage of Total Operating Revenues in 2010
	(in millions)
15-year termination notice		5	$	102			0.9	%
10-year termination notice		47		3,078			28.4	%
5-year termination notice		103		6,084			55.6	%
Total		155	$	9,264	(2)		84.9	%
Notes (1)  Ordinarily the distributor customer and TVA have the same termination notice period; however, in contracts with six of the distributor customers with five-year termination notices, TVA has a 10-year termination notice (which becomes a five-year termination notice if TVA loses its discretionary wholesale rate-setting authority). Also, under TVA’s contract with Bristol Virginia Utilities, a five-year termination notice may not be given until January 2018. (2)  Sales to distributor customers in 2010 for contracts terminated during the year totaled an additional $11 million.

TVA’s two largest distributor customers — Memphis Light, Gas and Water Division (“MLGW”) and Nashville Electric Service (“NES”) — have contracts with five-year and 10-year termination notice periods, respectively.  Although no single customer accounted for 10 percent or more of TVA’s total operating revenues in 2010, sales to MLGW and NES accounted for nine percent and eight percent, respectively.

The power contracts between TVA and the distributor customers provide for purchase of power by the distributor customers at the wholesale rates established by the TVA Board.  These contracts include a fuel cost adjustment (“FCA”) formula under which rates are periodically adjusted to reflect the changing costs of fuel, purchased power, and emission allowances.  The FCA mechanism also includes tax equivalent payments related to FCA amounts.  Beginning October 1, 2007, rates were automatically adjusted quarterly under the FCA formula.  Beginning October 1, 2009, the FCA rate adjustment became effective on a monthly rather than a quarterly basis.  The TVA Board, at its August 20, 2010 meeting, approved a rate structure change that revises the wholesale base rate structure to implement wholesale demand and energy rates in place of the end-use rates currently in effect.  See Item 1, Business — Rates — Rate Structure.

Under section 10 of the TVA Act, the TVA Board is authorized to regulate the municipal and cooperative distributors of TVA power to carry out the purposes of the TVA Act through contract terms and conditions as well as through rules and regulations.  The TVA Board regulates distributor customers primarily through the provisions of TVA’s wholesale power contracts.  All of the power contracts between TVA and the distributor customers require that power purchased from TVA be sold and distributed to the ultimate consumer without discrimination among consumers of the same class, and prohibit direct or indirect discriminatory rates, rebates, or other special concessions.  In addition, there are a number of wholesale power contract provisions through which TVA seeks to ensure that the electric system revenues of the distributor customers are used only for electric system purposes.  Furthermore, almost all of these contracts specify the specific resale rates and charges at which the distributor customers must resell TVA power to their customers.  These rates are revised from time to time, subject to TVA approval, to reflect changes in costs, including changes in the wholesale cost of power.  The regulatory provisions in TVA’s wholesale power contracts help carry out the objectives of the TVA Act, including providing for an adequate supply of power at the lowest feasible rates.

Other Customers

Revenues from industrial customers directly served accounted for 12 percent of TVA’s total operating revenues in 2010.  In 2010, contracts for customers directly served were generally for terms ranging from five to 10 years.  These contracts are subject to termination by TVA or the customer upon a minimum notice period that varies according to the customer’s contract demand and the period of time service has been provided.

The United States Enrichment Corporation (“USEC”) is TVA’s largest directly served industrial customer.  Sales to USEC for its Paducah, Kentucky facility represented five percent of TVA’s total operating revenues in 2010.  TVA’s current power supply contract with USEC expires on May 31, 2012.  See Item 7, Management's Discussion and Analysis of

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Financial Condition and Results of Operations — Risk Management Activities — Credit Risk.  In January 2004, USEC announced its decision to construct a new commercial centrifuge facility in Piketon, Ohio, which is outside TVA’s service area, and in July 2010, USEC submitted its loan guarantee application for the facility to the Department of Energy (“DOE”).  TVA believes that if the facility is constructed, USEC would reduce its electricity purchases at the Paducah, Kentucky facility from about 2,000 megawatts (“MW”) at its peak to less than 50 MW.  USEC and TVA are involved in contract discussions which may result in a contract modification to reflect USEC’s potential need for power beyond May 31, 2012.  The effect of these discussions is not yet known.  Any termination of the USEC contract would result in a loss of revenue, but the lower demand could result in a more economical dispatch of power to remaining customers if some modifications were made to the transmission system.

Rates

Rate Authority

The TVA Act gives the TVA Board sole responsibility for establishing the rates TVA charges for power.  These rates are not subject to judicial review or to review or approval by any state or federal regulatory body.

Under the TVA Act, TVA is required to charge rates for power which will produce gross revenues sufficient to provide funds for:

• Operation, maintenance, and administration of its power system;

• Payments to states and counties in lieu of taxes (“tax equivalents”);

• Debt service on outstanding indebtedness;

• Payments to the U.S. Treasury in repayment of and as a return on the government’s appropriation investment in TVA’s power facilities (the “Power Program Appropriation Investment”); and

• Such additional margin as the TVA Board may consider desirable for investment in power system assets, retirement of outstanding bonds, notes, or other evidences of indebtedness (“Bonds”) in advance of maturity, additional reduction of the Power Program Appropriation Investment, and other purposes connected with TVA’s power business.

In setting TVA’s rates, the TVA Board is charged by the TVA Act to have due regard for the primary objectives of the TVA Act, including the objective that power shall be sold at rates as low as are feasible.

Rate Methodology

In setting rates to cover the costs set out in the TVA Act, TVA uses a debt-service coverage (“DSC”) methodology to derive annual revenue requirements in a manner similar to that used by other public power entities that also use the DSC rate methodology.  Under the DSC methodology, rates are calculated so that an entity will be able to cover its operating costs and to satisfy its obligations to pay principal and interest on debt.  This ratemaking approach is particularly suitable for use by entities financed primarily, if not entirely, by debt capital, such as TVA.

TVA’s revenue requirements (or projected costs) are calculated under the DSC methodology as the sum of the following components:

• Fuel and purchased power costs;

• Operating and maintenance costs;

• Tax equivalents; and

• Debt service coverage.

This methodology reflects the cause-and-effect relationship between a regulated entity’s costs and the corresponding rates the entity charges for its regulated products and services.  Once the revenue requirements (or projected costs) are determined, they are compared to the projected revenues for the year in question, at existing rates, to arrive at the shortfall or surplus of revenues as compared to the projected costs.  Subject to TVA Board approval, power rates would be adjusted to a level sufficient to produce revenues approximately equal to projected costs.  In addition, as discussed above, the rates established under the DSC methodology are adjusted by the FCA.

The TVA Board is authorized by the TVA Act to set rates for power sold to its customers.  Additionally, TVA’s regulated rates are designed to recover its costs of providing electricity.  In view of demand for electricity and the level of competition, it is reasonable to assume that the rates, set at levels that will recover TVA’s costs, can be charged and collected.  Further, the TVA Board has the discretion to determine when costs will be recovered in rates.  As a result of these factors, TVA must record certain assets and liabilities that result from the regulated ratemaking process that would not be recorded under accounting principles generally accepted in the United States of America (“GAAP”) for non-regulated entities.  Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates.  Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that are not likely to be incurred or deferral of gains that will be credited to customers in

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future periods.  TVA assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes, potential legislation, and changes in technology.  This determination reflects the current regulatory and political environment and is subject to change in the future.  If future recovery of regulatory assets ceases to be probable or any of the other factors described above cease to be applicable, TVA would be required to write off these regulatory assets or liabilities.  Most regulatory asset or liability write-offs would be required to be recognized in earnings in the period in which future recovery ceases to be probable.

Rate Structure

The rate structure for electricity sales is comprised of a base rate and the FCA.  On August 20, 2009, the TVA Board approved (1) a nine percent increase to the base rate portion of TVA’s firm electricity sales rates, effective in the October 2009 billing period, and (2) a revised FCA formula that converted the FCA from quarterly operation to monthly operation effective October 2009.  Also, as of October 2009, TVA started amortizing over a nine-month period ended June 30, 2010, the $822 million deferred balance that was in the FCA liability account as of September 30, 2009.  The table below identifies the monthly FCA amounts during 2010 and the first three months of 2011 as well as the impact of the FCA changes from prior month total rates for end-use customers:

Month	FCA (¢/kWh)	Impact of FCA Changes from Prior Month  Total Rate
October 2009	(0.210)	(11.0%)
November 2009	(0.309)	(1.5%)
December 2009	(0.662)	(5.5%)
January 2010	(0.799)	(2.3%)
February 2010	(0.861)	(1.1%)
March 2010	(0.552)	5.3%
April 2010	(0.193)	5.9%
May 2010	(0.131)	1.0%
June 2010	0.198	5.0%
July 2010	0.403	3.0%
August 2010	0.508	1.5%
September 2010	0.659	2.1%
October 2010	1.127	6.4%
November 2010	0.735	(5.0%)
December 2010	0.476	(3.5%)

The TVA Board did not adjust the base rate portion of firm wholesale rates for 2011 but revised its FCA formula in October 2010 to adjust for seasonal fuel costs within the FCA formula.

TVA’s existing base rate structure with its distributor customers is based on end-use customer demand and/or energy consumption.  Under this rate structure, wholesale charges are specified for each customer classification, and each distributor customer’s wholesale bill reflects the application of these charges to actual end-use customers’ volumes within each classification.  A demand and energy base rate structure applies to TVA’s directly served customers.

On July 8, 2009, in accordance with the rate change provisions of its wholesale power contracts, TVA issued a letter to its distributor customers proposing the implementation of a new rate structure.  This letter initiated a required negotiation period during which TVA sought to reach agreement with distributors on the proposed changes to wholesale and retail rates.  At its August 20, 2010 meeting, the TVA Board approved the terms and conditions of the rate change to become effective April 2011.

The changed rate structures provide price signals intended to incentivize distributor and end-use customers to shift energy usage from high-cost periods to less expensive periods and are not intended to provide additional revenue for TVA (although individual distributor and end-use customers may see some effects on their bills).

For distributor customers, the default rate structure is a time-of-use rate structure with an option to elect a seasonal demand and energy structure for a limited time.  All distributor customers would be on a time-of-use wholesale rate structure by no later than October 2012; however, TVA will continue to have discussions with distributor customers on alternative seasonal demand and energy structures.

For directly served customers and distributor-served customers with contract demands in excess of 5 MW, the default rate structure is a time-of-use rate structure.  In addition, TVA is offering an optional seasonal demand and energy structure for these customers.

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For directly served customers and distributor-served customers with contract demands of 5 MW or less, the default rate structure contains seasonal price differentials.  In addition, TVA is offering an optional time-of-use rate structure for these customers.

Current Power Supply

General

Power generating facilities operated by TVA at September 30, 2010, included 29 conventional hydroelectric sites, one pumped storage hydroelectric site, 11 coal-fired sites, three nuclear sites, 11 natural gas and/or oil-fired sites, two diesel generator sites, one wind energy site, one digester gas cofiring site, and 14 solar energy sites.  In addition, TVA acquires power under power purchase agreements of varying duration as well as short-term contracts of less than 24-hours in duration.

On average, TVA’s generation fleet is among the oldest of any utility in the southeastern United States.  During recent years, TVA has invested substantially less in maintaining its coal-fired generation assets than surrounding utilities.  Although TVA is planning to increase its maintenance expenditures on its generating assets in 2011, some assets may not operate as planned in the future due to their age and condition.

The following table summarizes TVA’s net generation in millions of kilowatt-hours (“kWh”) by generating source and the percentage of all electric power generated by TVA for the years indicated:

Power Supply from TVA-Operated Generation Facilities For the years ended September 30 (millions of kWh)
	2010					2009					2008					2007					2006
Coal-fired		74,590		51	%		76,794		53	%		98,752		62	%		100,169		64	%		99,598		64	%
Nuclear		53,339		36	%		53,047		37	%		51,371		33	%		46,441		30	%		45,313		29	%
Hydroelectric		14,013		9	%		11,421		8	%		6,685		4	%		9,047		6	%		9,961		6	%
Natural gas and/or oil-fired		5,475		4	%		3,481		2	%		1,386		1	%		705	<1		%		613	<1		%
Renewable resources (non-hydro)		4	<1		%		29	<1		%		39	<1		%		27	<1		%		36	<1		%
Total		147,421		100	%		144,772		100	%		158,233		100	%		156,389		100	%		155,521		100	%

Note

Operation and maintenance issues reduced the available renewable generation during 2010 from several facilities, including those utilizing methane, solar, and wind.

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Net Capability

The following table summarizes the summer net capability in MW TVA had available as of September 30, 2010:

SUMMER NET CAPABILITY(1) As of September 30, 2010
Source of Capability	Location	Number  of Units		Summer Net Capability (MW)		Date First Unit Placed in Service		Date Last Unit Placed in Service
TVA-OPERATED GENERATING FACILITIES
Coal-Fired
Allen	Tennessee		3		741		1959		1959
Bull Run	Tennessee		1		870		1967		1967
Colbert	Alabama		5		1,184		1955		1965
Cumberland	Tennessee		2		2,470		1973		1973
Gallatin	Tennessee		4		976		1956		1959
John Sevier	Tennessee		4		704		1955		1957
Johnsonville	Tennessee		10		1,206		1951		1959
Kingston	Tennessee		9		1,398		1954		1955
Paradise	Kentucky		3		2,201		1963		1970
Shawnee	Kentucky		10		1,330		1953		1956
Widows Creek(2)	Alabama		7		1,493		1952		1965
Total Coal-Fired			58		14,573
Nuclear
Browns Ferry	Alabama		3		3,242		1974		1977
Sequoyah	Tennessee		2		2,282		1981		1982
Watts Bar	Tennessee		1		1,108		1996		1996
Total Nuclear			6		6,632
Hydroelectric
Conventional Plants	Alabama		36		1,188		1925		1962
	Georgia		2		35		1931		1956
	Kentucky		5		225		1944		1948
	North Carolina		6		491		1940		1956
	Tennessee		60		1,898		1912		1972
Pumped Storage	Tennessee		4		1,653		1978		1979
Total Hydroelectric			113		5,490
Natural Gas and/or Oil-Fired(3)
Allen	Tennessee		20		456		1971		1972
Brownsville	Tennessee		4		474		2008		2008
Caledonia	Mississippi		3		766		2007		2007
Colbert	Alabama		8		392		1972		1972
Gallatin	Tennessee		8		600		1975		2000
Gleason	Tennessee		3		360		2007		2007
Johnsonville	Tennessee		20		1,128		1975		2000
Kemper	Mississippi		4		312		2001		2001
Lagoon Creek	Tennessee		13		1,480		2002		2010
Marshall County	Kentucky		8		616		2007		2007
Southaven	Mississippi		3		774		2008		2008
Total Natural Gas and/or Oil-Fired			94		7,358
Diesel Generator
Meridian	Mississippi		5		9		1998		1998
Albertville	Alabama		4		4		2000		2000
Total Diesel Generators			9		13
TVA Renewable Resources (non-hydro)					2
Total TVA-Operated Generating Facilities					34,068
Contract Renewable Resources (non-hydro)(4)					19
Power Purchase and Other Agreements					3,101
Total Summer Net Capability					37,188
Notes (1)  Net capability is defined as the ability of an electric system, generating unit, or other system component to carry or generate power for a specified time period. (2)  Widows Creek Unit 5 was idled on September 12, 2010. See Item 1, Business – Integrated Resource Plan and Future Power Supply – for other units idled subsequent to September 30, 2010. (3)  See Item 1, Business — Current Power Supply – Natural Gas and/or Oil-Fired Facilities— for a discussion of TVA-operated natural gas and/or oil- fired facilities. (4)  Contract Renewable Resources (non-hydro) include wind and landfill gas contracts.

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Coal-Fired

At September 30, 2010, TVA had 11 coal-fired power sites consisting of 58 active units and one idled unit.  These facilities accounted for 14,573 MW of summer net capability.  TVA began its fossil-plant construction program in the 1940s and its coal-fired units were placed in service between 1951 and 1973.

TVA anticipates that clean air regulations will eventually require all coal-fired plants to install clean air controls, including scrubbers and selective catalytic reduction systems (“SCRs”) for sulfur dioxide (“SO2”), nitrogen oxides (“NOx”), and mercury control.  TVA also expects that legislation or regulations will eventually require it to reduce carbon dioxide (“CO2”) emissions or purchase CO2 allowances.Due to the age, lower capacity, and lower efficiency of some of TVA’s older coal-fired units, it may not be economical to install new clean air controls or purchase CO2 allowances for these units.  Accordingly, TVA has already idled nearly 350 MW of coal-fired generation and expects to idle more coal-fired units in the future.  See Item 1, Business – Integrated Resource Plan and Future Power Supply.

See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations — 2010 Challenges for a discussion of the challenges of dealing with coal combustion byproducts, and Note 8 for a discussion of the Kingston ash spill.

Nuclear

TVA has three nuclear sites consisting of six units in operation.  The units at Browns Ferry Nuclear Plant (“Browns Ferry”) are boiling water reactor units, and the units at the Sequoyah Nuclear Plant (“Sequoyah”) and Watts Bar Nuclear Plant (“Watts Bar”) are pressurized water reactor units.  At September 30, 2010, these facilities accounted for 6,632 MW of summer net capability.  In addition, construction has resumed on Watts Bar Unit 2, and that unit is scheduled to be placed in service in CY 2012.Statistics for each of these units are included in the table below.

TVA Nuclear Power As of September 30, 2010
Nuclear Unit	Status	Installed Capacity (MW)		Net Capacity Factor for 2010		Date of Expiration of Operating License		Date of Expiration of Construction Permit
Sequoyah Unit 1	Operating		1,221		97.9		2020		—
Sequoyah Unit 2	Operating		1,221		85.5		2021		—
Browns Ferry Unit 1	Operating		1,150		92.6		2033		—
Browns Ferry Unit 2	Operating		1,190		87.9		2034		—
Browns Ferry Unit 3	Operating		1,190		79.1		2036		—
Watts Bar Unit 1	Operating		1,230		91.1		2035		—
Watts Bar Unit 2	Construction resumed in December 2007		—		—		—		2013

Sequoyah License Renewal.  On August 5, 2009, TVA notified the Nuclear Regulatory Commission (“NRC”) of its intent to submit license renewal applications for both Sequoyah units in the third quarter of 2013.  If approved, the licenses for both units would be extended by an additional 20 years to 2040 for Unit 1 and 2041 for Unit 2.  Prior to the 2013 submittal date, TVA will prepare a detailed application and perform the necessary environmental reviews.  The NRC reviews are expected to take up to three years after submittal.

Tritium-Related Services.  TVA and DOE are engaged in a long-term interagency agreement under which TVA will, at DOE’s request, irradiate tritium producing burnable absorber rods to assist DOE in producing tritium for the Department of Defense (“DOD”).  This agreement, which ends in 2035, requires DOE to reimburse TVA for the costs that TVA incurs in connection with providing irradiation services and to pay TVA an irradiation services fee at a specified rate per tritium-producing rod over the period when irradiation has occurred.

                In general, tritium-producing rods are irradiated for a full fuel cycle, which lasts about 18 months.  At the end of the cycle, TVA removes the irradiated rods and loads them into a shipping cask.  DOE then ships them to its tritium-extraction facility.  TVA loads a fresh set of tritium-producing rods into the reactor during each refueling outage.  Irradiating the tritium-producing rods does not affect TVA’s ability to operate the reactors to produce electricity.

               The interagency agreement provides for irradiation services to be performed in Watts Bar Unit 1 and Sequoyah Units 1 and 2.  TVA has provided irradiation services using only Watts Bar Unit 1 since 2003.  TVA believes it can meet DOE and DOD tritium requirements using Watts Bar Unit 1 while maintaining Sequoyah reactors as backups.

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Other Nuclear Matters.  See Item 1, Business — Fuel Supply — Nuclear Fuel — Spent Nuclear Fuel for a discussion of spent nuclear fuel, Item 1, Business — Fuel Supply — Nuclear Fuel — Low-Level Radioactive Waste for a discussion of low-level radioactive waste, Note 20 — Contingencies — Decommissioning Costs for a discussion of TVA’s nuclear decommissioning liabilities and related trust, and Note 20 — Contingencies — Nuclear Insurance for a discussion of nuclear insurance, which discussions are incorporated herein by reference.

Hydroelectric

TVA maintains 29 conventional hydroelectric dams throughout the Tennessee River system and one pumped-storage facility for the production of electricity.  At September 30, 2010, these facilities accounted for 5,490 MW of summer net capability.  The amount of electricity that TVA is able to generate from its hydroelectric plants depends on a number of factors outside TVA’s control, including the amount of precipitation, runoff, initial water levels, and the need for water for competing water management objectives.  The amount of electricity generation also depends on the availability of the hydroelectric generation plants, over which TVA does have some control.  When these factors are unfavorable, TVA must increase its reliance on more expensive generation plants and purchased power.  In addition, four hydroelectric dams owned by a third party on the Little Tennessee River and eight U.S. Army Corps of Engineers dams on the Cumberland River contribute to the TVA power system.  With dry conditions significantly easing in TVA’s service area in 2010, TVA realized increased conventional hydroelectric generation.  See Item 1, Business — Weather and Seasonality.

TVA’s Hydro Modernization Program (“HMOD”) began in 1992 to address reliability issues on a majority of its conventional hydroelectric units and on its Raccoon Mountain pumped storage facility.  As of September 30, 2010, updates to 57 hydroelectric units had been completed.  The capacity gain has been 565 MW, and the average efficiency gain has been approximately five percent.  There are 38 units remaining to be updated for reliability and/or capacity increases.

A preliminary analysis performed as part of an update to TVA’s hydrology model indicated that under “probable maximum flood” assumptions, four of TVA’s dams would not be high enough to contain the flood waters.  While the “probable maximum flood” is an extremely unlikely event, TVA is taking actions with the aim of ensuring that flood waters would not spill over the top of these dams even under these conditions.   TVA implemented interim dam modifications in the second quarter of 2010.  Permanent dam modifications are being assessed to determine appropriate changes needed at TVA dams to prevent a “probable maximum flood” from spilling over the top of these dams, and cost estimates are being prepared.

As a result of the update, TVA is also performing additional hydrologic assessments at most of its other dams to determine whether water might spill over the top of these dams during a “probable maximum flood.”  The total financial impact of permanent modifications to any additional dams which may be identified as a result of the ongoing assessment will be determined as these assessments are completed in 2011.

Natural Gas and/or Oil-Fired

As of September 30, 2010, TVA operated 94 combustion turbine units, 87 of which are simple-cycle and seven of which are combined cycle.  The simple-cycle units provide a maximum of 5,278 MW of summer net capability.  The seven combined cycle units provide a maximum of 2,080 MW of summer net capability.  Eighty of the simple-cycle units are fueled by either natural gas or diesel fuel.  The remaining seven simple-cycle units as well as the seven combined cycle units are fueled by natural gas only.  Seventy-six of the simple-cycle units are capable of quick-start response allowing full generation capability in approximately 10 minutes.  TVA uses combustion turbines as peaking or backup units.  Their relatively low capital requirements and quick start-up capabilities make them favorable for intermittent operation to generate power at periods of high demand or to provide ancillary services.  Additionally, low natural gas prices during 2010 have made these units more economical to operate.  As of September 30, 2010, 24 of the simple-cycle combustion turbine units were leased by private entities and leased back to TVA under long-term leases. Also, TVA leases the three Caledonia combined cycle units under a long-term lease.  In addition, as of September 30, 2010, Seven States Southaven, LLC (“SSSL”) owned an undivided 90 percent interest in the three Southaven combined cycle units, and TVA has entered into an agreement under which TVA leases SSSL’s undivided 90 percent interest in Southaven and operates the entire facility through April 23, 2013.  For additional details, see Note 12.

Diesel Generators

TVA has two diesel generator plants consisting of nine units.  At September 30, 2010, these facilities provided 13 MW of summer net capability.

Renewable Resources

TVA owns and operates three wind turbines, one digester gas cofiring site, and 14 solar energy sites.  As of  September 30, 2010, the wind sites provided two MW of summer net capability and the digester gas cofiring site and solar sites provided less than one MW of summer net capability.

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Purchased Power and Other Agreements

TVA acquires power from a variety of power producers through long-term and short-term power purchase agreements as well as through power spot market purchases.  During 2010, TVA acquired 26 percent of the power that it purchased on the power spot market, nine percent through short-term power purchase agreements (agreements with a duration of less than one year but longer than the term of spot market purchase), and 65 percent through long-term power purchase agreements (agreements with a duration of more than one year).

A portion of TVA’s capability provided by power purchase agreements is provided under contracts that expire between 2011 and 2032, and the most significant of these contracts are discussed below.

• TVA has contracted for 720 MW of summer net capability from a natural gas-fired generating plant located at Decatur, Alabama.  This contract expires on August 31, 2012.

• TVA has contracted for 500 MW of summer net capability from a natural gas-fired generating plant located in Morgan County, Alabama.  This contract expires on December 31, 2011.

• TVA has contracted for 690 MW of summer net capability from a natural gas-fired generating plant located near Ackerman, Mississippi.  The contract expires on December 31, 2012.

• TVA has contracted for 440 MW of summer net capability from a lignite-fired generating plant in Chester, Mississippi.  The contract expires on March 31, 2032.  See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations — Risk Management Activities — Credit Risk.

• Four hydroelectric plants owned by a third party are operated in coordination with the TVA system.  Under contractual arrangements which terminate on June 30, 2011, TVA currently purchases and dispatches all electricity generated at these facilities and uses the power to supply the owner’s energy needs.  TVA may be the net purchaser or net supplier under these arrangements.

• TVA has contracted for 27 MW of wind energy generation from 15 wind turbine generators located on Buffalo Mountain near Oak Ridge, Tennessee.  Because of the nature of intermittent wind conditions in the TVA service area, these generators provide energy benefits but are not included in TVA’s summer net capability total.  The contract expires on December 31, 2024.

• TVA has contracted for 300 MW of wind energy generation from 150 wind turbine generators located in Livingston County, Illinois.  Deliveries under this contract began May 11, 2010.  Because of the nature of intermittent wind conditions in that area, these generators provide energy benefits but contribute only 35 MW of summer net capability.  The contract expires on May 10, 2030.

• TVA has contracted for 115 MW of wind energy generation from 70 wind turbine generators located in Howard and Mitchell Counties, Iowa.  Deliveries under this contract began September 10, 2010.  Because of the nature of intermittent wind conditions in that area, these generators provide energy benefits but contribute only 13 MW of summer net capability.  The contract expires on September 9, 2030.

• Like TVA, the Southeastern Power Administration (“SEPA”) is a federal agency and is therefore a related party.  SEPA contracts with other utilities to provide transmission services for federal power.  Preference in the sale of power is given to public bodies and cooperatives.  TVA, along with others, has contracted with SEPA to obtain power from eight U.S. Army Corps of Engineers hydroelectric facilities on the Cumberland River system.  The agreement with SEPA can be terminated upon three years’ notice, but this notice of termination may not become effective prior to June 30, 2017.  The contract requires SEPA to provide TVA an annual minimum of 1,500 hours of power for each megawatt of TVA’s 405 MW allocation, and all surplus power from the Cumberland River system.  Because hydroelectric production has been reduced at two of the hydroelectric facilities on the Cumberland River system due to repair work being performed by U.S. Army Corps of Engineers at those facilities and because of reductions in the summer stream flow on the Cumberland River, SEPA declared “force majeure” on February 25, 2007.  SEPA then instituted an emergency operating plan that, among other things, eliminates SEPA’s obligation to provide TVA and other affected customers with a minimum amount of power.  It is unclear how long the emergency operating plan will remain in effect.

In addition, under federal law, TVA is required to purchase energy from qualifying facilities, cogenerators, and small power producers at TVA's avoided cost of self-generating or purchasing this energy from another source.  At September 30, 2010, there were seven suppliers, with a combined capacity of 919 MW, whose power is purchased by TVA under this law.

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During the past five years, TVA supplemented its power generation through power purchases as follows:

 

Purchased Power* For the years ended September 30
	2010			2009			2008			2007			2006
Millions of kWh		28,782			22,088			20,887			22,141			19,019
Percent of TVA’s Total Power Supply		16.3	%		13.1	%		11.6	%		12.4	%		10.9	%
Note * Purchased power amounts for 2006 have been adjusted to remove third-party purchases and include them as a credit to power sales. Purchased power amounts include generation from Caledonia, which is currently a leased facility operated by TVA.

Renewables, Energy Efficiency, and Demand Response Initiative

In May 2009, TVA began offering new incentives for homes and businesses to encourage the installation of renewable, distributed generation sources such as solar, wind, biomass, and low-impact hydropower below one MW of capacity.  In August 2010, the eligible program size was reduced to 200 kW.  Under this program, TVA purchases all of the energy output at a premium price, and the distributor credits the customers for the generation received through a credit on their monthly electric bills.  All new participants receive a one-time incentive of $1,000 to help offset the startup costs for installing qualifying renewable resources.  The price that TVA pays for solar generation is now 12 cents per kWh above the rates charged by TVA’s distributor customers, and the price that TVA pays for wind, low-impact hydro, and biomass generation is currently three cents per kWh above the rates charged by TVA’s distributor customers.  TVA anticipates that these projects will qualify for renewable energy credits under any future legislation establishing requirements for renewable electricity.

On September 16, 2009, DOE confirmed funding to support the State of Tennessee’s Volunteer State Solar Initiative.  Upon completion of applicable environmental reviews, the proposed initiative will include a five MW solar power generation facility to be located in west Tennessee.  Under the proposed initiative, TVA plans to purchase the power generated from the facility.

On May 27, 2009, TVA announced additional energy efficiency programs designed to promote energy efficiency to residential and commercial customers.  These initiatives, which support the TVA Board’s directive to reduce energy use during times when demand and cost for power is highest, are briefly described below:

Tests for the new residential program, called the In-Home Energy Evaluation Program, have begun in 22 markets including Nashville, Chattanooga, and the Tri-Cities area (Bristol, Johnson City, and Kingsport) in Tennessee as well as Hopkinsville, Kentucky, and Decatur, Alabama.  The program offers comprehensive in-home energy audits as well as financing options and incentives to help homeowners who choose to make investments in significant energy efficiency improvements.  In 2010, the program was expanded across the TVA system and is now offered by 137 distributor customers.  In addition to the In-Home Energy Evaluation Program in 2010, TVA continued to offer a suite of existing residential energy efficiency programs that included offerings for new homes, manufactured homes, and heat pump replacement, as well as an on-line, do-it-yourself home energy audit.

In April 2009, the Commercial Efficiency Advice and Incentives Program, an initiative targeting efficient lighting and HVAC systems for existing commercial facilities and institutions, began testing in Mississippi and Nashville.  This program offered businesses in these areas an opportunity to receive an energy assessment of their facilities to help them identify energy-saving opportunities.  Financial incentives were also available for projects that help reduce electric power consumption.  Later in 2009, incentives for efficient lighting and HVAC in existing industrial facilities with up to five MW of contract demand were added to the program.  In 2010, the program scope expanded to include prescriptive lighting and HVAC rebates for small businesses.  At the end of 2010, 100 distributor customers were offering the program to their customers under the revised name, the Commercial and Industrial Efficiency Advice and Incentives Program.

The Major Industrial Program targets very large industrial customers with contract demand greater than five MW and offers technical assistance and incentives for energy efficiency projects that lower the customer’s demand for power during peak usage periods on the TVA system.

These three programs are part of an effort which involved input from TVA power distributor customers and the public regarding the best options for encouraging electricity users in TVA’s service area to save energy.

In June 2009, TVA began testing residential building techniques, energy efficiency technologies, and household appliances at three experimental houses near Knoxville, Tennessee.  Testing will be conducted over a three-year period to learn more about how cutting-edge residential construction affects energy efficiency in homes in TVA’s service area. The three houses include (1) a newly built home that meets ENERGY STAR performance standards, (2) a home modified with improvements that could easily be made to existing homes for increased efficiency, and (3) a home built from the ground up to be a “near-Zero Energy Home.”  TVA will use the data collected to evaluate new efficiency applications.   This

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project is expected to help enable builders, developers, and consumers to learn about how to apply these new technologies, as well as their costs and benefits.  Ultimately, this information should help consumers better manage the energy they use and save money on their electric bills.  Results after one year of testing show the average consumer can realize significant energy savings through good weatherization and insulating techniques, sealing air gaps, routing HVAC duct in conditioned space, and using fluorescent lighting.

During the summer of 2010, TVA utilized a third-party aggregator of demand response load as a virtual peaking power plant for approximately 170 MW of demand response for nine events totaling 40 hours.  The third party delivered the load requested by TVA in connection with the nine events.

Fuel Supply

General

TVA’s consumption of various types of fuel depends largely on the demand for electricity by TVA’s customers, the availability of various generating units, and the availability and cost of fuel.  The following table summarizes TVA’s expenses for various fuels for the years indicated:

Fuel for TVA-Operated Facilities* For the years ended September 30 (in millions)
	2010		2009		2008		2007		2006
Coal	$	2,126	$	2,127	$	2,242	$	2,074	$	1,996
Natural gas		236		129		131		63		60
Fuel oil		38		38		45		26		27
Nuclear fuel		277		267		256		180		173
Total fuel	$	2,677	$	2,561	$	2,674	$	2,343	$	2,256
Note * Excludes affects of the FCA deferrals and amortization on fuel expense.

  The following table indicates TVA’s average fuel expense by generation-type for the years indicated:

Fuel Expense Per kWh* For the years ended September 30 (cents/kWh)
	2010		2009		2008		2007		2006
Coal		2.90		2.81		2.31		2.09		2.02
Natural gas and fuel oil		4.37		3.77		9.73		9.62		10.65
Nuclear		0.52		0.50		0.50		0.39		0.38
Average fuel cost per kWh net thermal      generation from all sources		2.01		1.92		1.76		1.59		1.54
Note * Excludes affects of the FCA deferrals and amortization.

TVA also has tolling agreements under which it buys power production from outside suppliers.  Under these tolling agreements, TVA supplies the fuel to the outside supplier, and the outside supplier converts the fuel into electricity.  The following table indicates the cost of fuel supplied by TVA under these agreements and also the average fuel expense per kWh for the years indicated:

Natural Gas Purchases for Tolling Plants For the years ended September 30
	2010		2009		2008		2007		2006
Cost of fuel (in millions)	$	381	$	255	$	457	$	430	$	288
Average fuel expense (cents/kWh)		5.93		6.54		12.26		5.51		6.07

Coal

Coal consumption at TVA’s coal-fired generating facilities during 2010 was approximately 36 million tons.  As of September 30, 2010, and 2009, TVA had 36 days of system-wide coal supply at full burn rate, respectively, with a net book value of $465 million and $460 million, respectively.

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TVA utilizes both short-term and long-term coal contracts.  Long-term coal contracts last longer than one year, while short-term contracts are for one year or less.  During 2010, long-term contracts made up 98 percent of coal purchases and short-term contracts accounted for the remaining two percent.  TVA plans to continue using contracts of various lengths, terms, and coal quality to meet its expected consumption and inventory requirements.  During 2010, TVA purchased coal by basin as follows:

• 43 percent from the Illinois Basin;

• 28 percent from the Powder River Basin in Wyoming;

• 20 percent from the Uinta Basin of Utah and Colorado; and

• 9 percent from the Appalachian Basin of Kentucky, Pennsylvania, Tennessee, Virginia, and West Virginia.

Total system coal inventories were at or above target levels for most of 2010.  During 2010, 34 percent of TVA’s coal supply was delivered by rail, 26 percent was delivered by barge, and 33 percent was delivered by a combination of barge and rail.  The remainder was delivered by truck.

Natural Gas and Fuel Oil

During 2010, TVA purchased substantially all of its natural gas requirements from a variety of suppliers under contracts with terms of one year or less but managed its exposure to spot market volatility through its Financial Trading Program (“FTP”).  TVA purchases substantially all of its natural gas to operate combustion turbine units and to supply fuel under tolling agreements in which TVA is the fuel supplier.  At September 30, 2010, all but 14 of TVA’s combustion turbine units were dual fuel capable, and TVA has fuel oil stored on each site for its dual fuel combustion turbines as a backup to natural gas.

During 2010, TVA purchased substantially all of its fuel oil on the spot market, but managed its exposure to spot market volatility through its FTP.  At September 30, 2010, and 2009, the net book value of TVA’s natural gas in inventory was $8 million and $3 million, respectively, and the net book value of TVA’s fuel oil in inventory was $66 million and $71 million, respectively.

Nuclear Fuel

Converting uranium to nuclear fuel generally involves four stages: the mining and milling of uranium ore to produce uranium concentrates; the conversion of uranium concentrates to uranium hexafluoride gas; enrichment of uranium hexafluoride; and the fabrication of the enriched uranium hexafluoride into usable fuel assemblies.  For its forward five-year (2011-2015) requirements, TVA currently has 100 percent of its uranium mining and milling, conversion services, enrichment services, and fabrication services requirements either in inventory or under contract.  TVA anticipates being able to fill its needs beyond this period by normal contracting processes as market forecasts indicate that the fuel cycle components will be readily available.

TVA, DOE, and certain nuclear fuel contractors have entered into agreements that provide for the blending down of surplus DOE highly enriched uranium (uranium that is too highly enriched for use in a nuclear power plant) with other uranium.  Under these agreements, the enriched uranium that results from this blending process, which is called blended low enriched uranium (“BLEU”), is fabricated into fuel that can be used in a nuclear power plant.  This blended nuclear fuel  was first loaded in a Browns Ferry reactor in 2005 and is expected to continue to be used to reload the Browns Ferry reactors through at least 2016.  BLEU fuel was loaded into Sequoyah Unit 2 in CY 2008 and CY 2009 and is expected to be loaded again in CY 2011.

Under the terms of an interagency agreement between DOE and TVA, in exchange for supplying highly enriched uranium materials for processing into usable BLEU fuel for TVA, DOE participates to a degree in the savings generated by TVA’s use of this blended nuclear fuel.  See Note 1 — Blended Low Enriched Uranium Program for a more detailed discussion of the BLEU project.

TVA owns all nuclear fuel held for its nuclear plants.  As of September 30, 2010, and 2009, the net book value of this nuclear fuel was $1.1 billion and $898 million, respectively.

Mixed Oxide Nuclear Fuel.  TVA signed an agreement with DOE in February 2010 under which DOE would reimburse TVA for its costs in investigating the potential use of mixed oxide (“MOX”) fuel in TVA’s Browns Ferry and Sequoyah nuclear reactors.  The MOX fuel is a mixture of plutonium and depleted uranium oxide with the plutonium originating from surplus nuclear weapon material.  DOE is building a plant near Aiken, South Carolina to produce MOX fuel.

DOE is completing a Supplemental Environmental Impact Statement (“SEIS”) to include TVA as a potential user of MOX fuel.  TVA has not committed to using MOX fuel and will only go forward with the program if TVA believes it is safe to do so and will result in a benefit to TVA customers.  A decision on whether to go forward is expected in 2012 with the first potential delivery of MOX fuel in 2018.

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Low-Level Radioactive Waste.  Low-level radioactive waste (“radwaste”) results from the normal operation of nuclear units and includes such materials as disposable protective clothing, mops, and filters.  TVA has certain types of radwaste processed and shipped to a disposal facility in Clive, Utah, and TVA also stores some radwaste at its own facilities.  TVA is capable of storing radwaste at its facilities for an extended period of time.

Spent Nuclear Fuel.  Under the Nuclear Waste Policy Act of 1982, TVA (and other domestic nuclear utility licensees) entered into a contract with DOE for the disposal of spent nuclear fuel.  Payments to DOE are based upon TVA’s nuclear generation and charged to nuclear fuel expense.  Although the contracts called for DOE to begin accepting spent nuclear fuel from the utilities by January 31, 1998, DOE has yet to establish a permanent disposal site for spent nuclear fuel.  TVA, like other nuclear utilities, stores spent nuclear fuel at its nuclear sites.  TVA would have had sufficient space to continue to store spent nuclear fuel in storage pools indefinitely had DOE begun accepting spent nuclear fuel.  DOE’s failure to do so in a timely manner required TVA to construct dry cask storage facilities at Sequoyah and Browns Ferry and to purchase special storage containers for the spent nuclear fuel.  The Sequoyah and Browns Ferry dry cask storage facilities have been in use since 2004 and 2005, respectively, and currently provide storage capacity through 2026 at Sequoyah and 2018 at Browns Ferry.  Watts Bar has sufficient storage capacity in its spent fuel pool to last until approximately 2015.  In September 2010, the NRC announced its approval of final revisions to its Waste Confidence findings and regulations expressing the NRC’s confidence that spent nuclear fuel can be safely stored for at least 60 years beyond the licensed life of any reactor and that sufficient repository capacity will be available when necessary.

To recover the cost of providing long-term, on-site storage for spent nuclear fuel, TVA filed a breach of contract suit against the United States in the Court of Federal Claims in 2001.  In August 2006, the United States paid TVA almost $35 million in damages awarded by the Court of Federal Claims, which offset partially the construction costs of the dry cask storage facilities that TVA incurred through 2004.  The United States has also paid TVA approximately $24 million in damages to offset partially operational costs for on-site storage from 2005 to 2007.  TVA anticipates submitting additional claims to DOE periodically.

Transmission

The TVA transmission system is one of the largest in North America.  TVA’s transmission system has 66 interconnections with 14 neighboring electric systems, and delivered nearly 174 billion kilowatt-hours of electricity to TVA customers in 2010.  In carrying out its responsibility for grid reliability in the TVA service area, TVA has operated with 99.999 percent reliability over the last eleven years in delivering electricity to customers.

TVA’s transmission system consists primarily of the following assets:

• Approximately 15,940 circuit miles of transmission lines (primarily 500 kilovolt and 161 kilovolt lines);

• 498 transmission substations, power switchyards, and switching stations; and

• 1,240 connection points (customer, generation, and interconnection).

To the extent that federal law requires access to the TVA transmission system, the TVA transmission organization offers transmission services to others to transmit power at wholesale in a manner that is comparable to TVA's own use of the transmission system.  TVA has also adopted and operates in accordance with a published Standards of Conduct for Transmission Providers and appropriately separates its transmission functions from its marketing functions.

Weather and Seasonality

Weather affects both the demand for and the market prices of electricity.  TVA uses degree days to measure the impact of weather on TVA’s power operations.  Degree days measure the extent to which average temperatures in the five largest cities in TVA's service area vary from 65 degrees Fahrenheit.  During 2010, TVA had 269, or nearly eight percent, more heating degree days and 556, or over 30 percent, more cooling degree days than in 2009.

	2010	Percent Change	2009	Percent Change	2008
Combined degree days (normal 5,267)	6,057	15.8%	5,232	2.6%	5,099

TVA’s power system is generally a dual-peaking system where the demand for electricity peaks during the summer and winter months to meet cooling and heating needs.  TVA met an all-time summer peak demand of 33,482 MW on August 16, 2007 at 102 degrees Fahrenheit and an all-time winter peak demand of 32,572 MW on January 16, 2009 at nine degrees Fahrenheit.  As a result of a cold wave during the first week of January 2010, TVA set a number of energy demand records.  A new total daily energy demand record of 701 GWh was set on January 8, 2010, and a total weekly energy demand record of 4,633 GWh was set for the seven-day period ended January 10, 2010, when TVA experienced an average demand of 27,582 MW per hour for the entire week.

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After several years of dry weather and drought conditions in the TVA service area, rainfall and runoff totals improved in the Tennessee Valley during 2009 and 2010.  Rainfall in the Tennessee Valley was 93 percent of normal in 2010 and 103 percent of normal in 2009.  Runoff was 111 percent of normal in 2010 and 85 percent of normal in 2009.  Runoff is the amount of rainfall that is not absorbed by vegetation or the ground which actually reaches the rivers and reservoirs that TVA manages.  As a result, TVA’s conventional hydroelectric generation increased 21 percent in 2010 over 2009, and 64 percent in 2009 over 2008.  Conventional hydroelectric generation was 103 percent of normal in 2010 and 85 percent of normal in 2009.  See Item 1A, Risk Factors, for a discussion of the potential impact of weather on TVA.

Competition

TVA provides electricity in a service area that is largely free of competition from other electric power providers.  This service area is defined primarily by two provisions of law: the “fence” and the “anti-cherrypicking” provision.  The fence limits the region in which TVA or distributors of TVA power may provide power.  The “anti-cherrypicking” provision limits the ability of others to use the TVA transmission system for the purpose of serving customers within TVA’s service area.

From time-to-time there have been efforts to erode the protection of the anti-cherrypicking provision, and the protection of the anti-cherrypicking provision could be called into question and perhaps eliminated at some time in the future.

Integrated Resource Plan and Future Power Supply

On June 15, 2009, TVA initiated an Integrated Resource Plan (“IRP”) entitled TVA's Environmental and Energy Future.  The purpose of the IRP is to create a framework for the analysis of alternatives to address the electricity needs in TVA’s service area for the next 20 years.  The alternative portfolios developed for this effort will be evaluated using several criteria including capital and fuel costs, reliability, possible environmental impacts, compliance with existing and anticipated future laws and regulations, and other factors.  TVA expects to issue a final IRP in early CY 2011.  While economic conditions have reduced power demand in recent years, TVA believes power demand will grow under most likely scenarios, and TVA intends to make capital investments in the current year as well as future years.

Aligned with TVA’s IRP efforts, the TVA Board asked management in 2010 to review TVA’s mission of providing low-cost power, economic development, environmental stewardship, river management, and technological innovation and to develop a vision for TVA’s future based on that mission.  In assessing TVA’s current operating environment, which is affected by economic uncertainty, the need for infrastructure investment, and uncertain national energy policy, management adopted a vision for TVA to be one of the nation’s leading providers of low-cost and cleaner energy by 2020 by becoming:

•The nation’s leader in improving air quality,

•The nation’s leader in increased nuclear production, and

•The southeastern United States’s leader in increased energy efficiency.

Improving Air Quality

TVA anticipates that clean air regulations will eventually require all coal-fired plants to install clean air controls, including scrubbers and SCRs for SO2, NOx, and mercury control.  TVA also expects that legislation or regulation will eventually require it to reduce CO2 emissions or purchase CO2 allowances.   Due to the age, lower capacity, and lower efficiency of some of TVA’s older coal-fired units, it may not be economical to install new clean air controls or purchase CO2 allowances, particularly for the 6,800 MW of TVA’s coal-fired units that do not have scrubbers.  TVA is studying one of the options in the IRP that calls for 3,000 MW of coal-fired units to be idled by 2017.  In September 2010, TVA idled Unit 5 at Widows Creek Fossil Plant (“Widows Creek”), and in October 2010 idled Widows Creek Unit 2 as well as Shawnee Fossil Plant Unit 10.  The three units account for nearly 350 MW of summer net capability.  TVA may decide to idle other coal-fired units in the future.

TVA is working toward obtaining greater amounts of its power supply from clean (low or zero carbon-emitting) or renewable sources.  TVA defines its clean energy portfolio as (1) energy that has a zero or near-zero CO2 emission rate, such as nuclear and renewables (energy production that is sustainable and often naturally replenished), (2) energy efficiency improvements, including demand reduction, and (3) waste heat recovery.  In 2010, about 40 percent of TVA’s total power came from non-CO2-emitting sources (nuclear, hydroelectric, and renewable energy) as defined by TVA.  TVA’s plans to add clean and renewable power are consistent with increasing expectations that the Environmental Protection Agency (“EPA”) will adopt regulations, in the near-term that require utilities to supply a certain percentage of energy from renewable sources and, possibly, to participate in an economy-wide program to cap and reduce emissions of greenhouse gases (“GHGs”), including CO2.  If such regulations are adopted, TVA may be required to reduce or offset emissions, or to purchase emission allowances under a cap-and-trade program, and may be required to contract for or generate an increasing percentage of energy from renewable sources.  Since the final outcome of any such legislation or regulations is not known, TVA is presently unable to accurately estimate the cost of future renewable and GHG requirements.  The current

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process for the development of TVA’s IRP will help to inform future decisions on investment in new renewable and clean generation.

An emerging factor related to air quality is the greater use of electric vehicles.  One of the important benefits expected from the switch to electric vehicles is a reduction in the burning of fossil fuels, which could reduce localized air pollution from transportation as well as the threat of climate change. Other potential impacts include faster growth in energy demand, increased peak hour demand due to daytime use of charging stations, and increased congestion on the transmission and distribution infrastructure.   Technology adoption rates for electric transportation are difficult to predict, however, and introduce a new source of forecast uncertainty.

Combustion Turbines

It is TVA’s intention to significantly increase production from low-emission generation facilities with the addition of natural gas plants to its generation fleet in the near future.

In September 2010, the Lagoon Creek Combined Cycle Facility began commercial operation with a summer net capability of approximately 550 MW.  In addition, TVA is in the process of constructing the John Sevier Combined Cycle Facility in northeast Tennessee.  TVA expects to complete the combined cycle facility by mid-CY 2012.  The completed facility is expected to add approximately 880 MW of summer net capability to the TVA system at a cost of approximately $820 million. TVA may also decide to make further strategic investments in natural gas-fired facilities in the future.

Certain upgrades planned for TVA’s Gleason Combustion Turbine Plant and a newly planned New Caledonia Combustion Turbine Plant were cancelled by the TVA Board during 2010 based on its decision to construct the John Sevier Combined Cycle Facility.  See Note 19.

Increased Nuclear Production

Central to TVA’s vision of becoming one of the nation's leading providers of low-cost cleaner energy by 2020 is an increased focus on nuclear energy.  While TVA is planning to idle some of its older coal-fired generation capacity, it looks to both replace the idled capability and expand overall capability with additions to its nuclear generating fleet.

Watts Bar Unit 2.  On August 1, 2007, the TVA Board approved the completion of Watts Bar Unit 2.  The project is scheduled to be completed in CY 2012.  TVA has applied for an NRC operating license, and this process includes opportunity for a public hearing.  Contentions against the licensing request have been filed.  See Note 20 — Legal Proceedings — Administrative Proceeding Regarding Watts Bar Nuclear Plant Unit 2.  Completing Watts Bar Unit 2 is expected to cost approximately $2.5 billion, excluding allowance for funds used during construction (“AFUDC”) and the cost of the initial fuel load.  Watts Bar Unit 2 is expected to provide 1,150 MW of summer net capability.

Extended Power Uprate.  TVA is undertaking an Extended Power Uprate (“EPU”) project at Browns Ferry which is expected to increase the amount of electrical generation by increasing the amount of steam produced by the reactors.  Additional fuel would be added to the reactors during each refueling outage to support the increased steam production.  The NRC licenses for each reactor must be modified to allow reactor operation at the higher power level.  TVA has submitted license amendment requests and is currently in discussions with the NRC on selected technical issues affecting EPU licensing.  The result of these discussions may impact the amount of power level increase realized by the EPU.  Completion of the licensing process will determine the final implementation schedule.

Bellefonte Units 1 and 2.  Construction of Bellefonte Nuclear Plant (“Bellefonte”) Units 1 and 2 located in Hollywood, Alabama, began in 1974 but was deferred in 1988 and 1985, respectively.  TVA’s construction of Bellefonte Units 1 and 2 had been undertaken pursuant to construction permits issued by the NRC, but in November 2005 TVA cancelled the construction of these units and asked the NRC to withdraw the permits.  Subsequently, changes in new generation capacity economics prompted TVA to re-evaluate the feasibility of completing these units, and in August 2008, TVA asked the NRC to reinstate the construction permits for both units in order to preserve the completion option.  On March 9, 2009, the NRC issued an order reinstating the construction permits for Bellefonte Units 1 and 2. Following completion of more detailed feasibility studies, on August 20, 2010, the TVA Board approved spending $248 million for additional engineering, design, and licensing activities, as well as the procurement of long lead-time components for the partially completed Bellefonte Unit 1.  TVA requested in October 2010 to extend the expiration date of the Bellefonte construction permit from October 2011 to October 2020.  While the TVA Board’s action will help maintain Unit 1 as a viable alternative to meet the projected need for generation on the TVA system in the 2018 to 2020 timeframe, this action does not mean TVA can re-commence construction of Unit 1.  Further action by the NRC, reviews by TVA, and final approval by the TVA Board after the IRP has been completed are required before construction activities can resume. See Note 20 —Legal Proceedings — Proceedings Regarding Bellefonte Nuclear Plant Units 1 and 2.

Bellefonte Units 3 and 4.  TVA is developing options for future nuclear generation at its Bellefonte site.  In October 2007, TVA submitted a Combined Construction and Operating License Application to the NRC for two new designed Advanced Passive 1000 reactors to be located at the Bellefonte site and designated as Bellefonte Units 3 and 4.  TVA’s application was being supported, in part, by NuStart, an industry consortium comprised of 10 utilities and two reactor vendors the purpose of which is to satisfactorily demonstrate the new NRC licensing process for nuclear plants.  The Bellefonte Combined Construction and Operating License Application is one of several Advanced Passive 1000 Westinghouse

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standardized plant applications, and other applicants have announced construction schedules that call for their license reviews to be completed prior to Bellefonte’s.  As a result, NuStart, with TVA’s agreement, has transitioned its reference plant to the Combined Construction and Operating License Application of another utility.  On September 29, 2010, TVA notified the NRC that the recently completed Final Supplemental Environmental Impact Statement had determined that completion of the partially constructed Bellefonte Unit 1 is the preferred alternative for near-term additional generating capacity at the Bellefonte site.  Consequently, with the exception of the ongoing review of hydrology-related portions of the application, TVA requested that the NRC defer review of the Bellefonte Units 3 and 4 Combined Construction and Operating License Application pending a final decision of the TVA Board regarding new generation capacity at the Bellefonte site.  Contentions have been filed with respect to the Bellefonte Combined Construction and Operating License Application.  See Note 20 — Contingencies Legal Proceedings — Administrative Proceeding Regarding Bellefonte Nuclear Plant Units 3 and 4.

Other Nuclear Initiatives.  TVA has signed a letter of intent to begin evaluating a site for the first B&W mPower reactor at its Clinch River site in Oak Ridge, Tennessee.  The B&W mPower reactor would have a scalable, modular design, allowing utilities to add electrical generation capacity in increments of 125 megawatts.  The B&W mPower reactor is expected to be competitive with and more quickly built than larger reactors on the market.

Hydroelectric

Annual hydroelectric generation is highly dependent on weather conditions and can vary significantly from year to year. TVA is assessing its conventional hydroelectric units for reliability and/or capacity increases through 2030.

Renewable Energy

In December 2008, TVA issued requests for proposals (“RFPs”) for both dispatchable capacity and as-available energy from renewable energy sources for up to a total of 2,000 MW of generation.  In May 2010, TVA began receiving up to 300 MW of energy under a 20-year contract from a wind farm in Illinois.  TVA currently does not purchase the renewable attributes for this energy, but has the opportunity to obtain them in the future.  In September 2010, TVA began receiving up to 115 MW of renewable wind energy under a 20-year contract from a wind farm in Iowa. TVA has entered into six additional 20-year contracts for the purchase of up to 1,166 MW of renewable wind energy from wind farms located in various Midwest states.  Power under these six additional wind energy contracts is scheduled to be delivered beginning in CY 2012.  Bringing power from distant locations raises transmission issues and costs, and the intermittent nature of wind, solar, and other renewable sources can result in TVA needing backups for those sources or mechanisms.

TVA has also entered into one contract for up to five MW of renewable landfill gas energy from a location inside TVA’s service area.  TVA is scheduled to begin receiving over three MW under this contract in January 2011, and this amount is expected to increase up to five MW by January 2013.

There are currently several bills pending before Congress that contain provisions proposing various forms of renewable energy and energy efficiency requirements.  Under most legislation proposing a federal renewable energy standard, TVA would be required to ensure that a certain percentage (currently ranging from three percent to 20 percent) of the electricity it sells is produced by renewable energy sources as defined in the legislation.  Although TVA considers hydroelectric generation a renewable source, it is unlikely it will contribute to a future renewable portfolio standard requirement.  Some proposals would allow utilities to pay alternative compliance payments if that percentage could not be met because of certain restrictions.  See Item 1, Business – Environmental Matters.

Technology advancements will be needed to address some of the operational issues associated with renewable energy, such as energy storage to address intermittency.   In addition, most renewable energy resources are geographically specific.  Some regions of the United States have an abundance of wind and solar resources, whereas other regions have hydroelectric resources.  Regional differences and limitations play a primary role in the types and amount of renewable and clean energy developed across the country.  Within the area served by TVA, two of the most abundant renewable resources are hydroelectric and biomass.  Feasible wind energy in this region is primarily associated with mountain top and ridgeline installations, and the total potential capacity is limited when compared to other parts of the nation where wind energy is more abundant.  If TVA is required to increase its use of renewable resources and the cost of doing so is greater than the costs of other sources of generation, TVA’s costs may increase.

Power Purchases

Purchasing power from others will likely remain a component of how TVA addresses the power needs of its service area.  TVA intends to balance production capabilities with power supply requirements by promoting the conservation and efficient use of electricity and, when necessary, buying, building, and/or leasing assets or entering into purchased power agreements.

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Energy Efficiency and Demand Response Programs

Nationally, much attention is being focused on the smart grid, an electric power system that provides increased information and load control for customers, distributors, and grid operators.  The smart grid supports behavioral change in a way that reduces system demands and costs and increases energy efficiency. The smart grid is also designed to promote societal benefits such as reduced emissions, lower energy costs, and greater flexibility to accommodate new renewable distributed energy sources.  TVA, in partnership with its distributors, is developing a smart grid deployment plan for the TVA service area.  This deployment plan is expected to lead to new technology improvements that enhance the performance of the existing transmission and distribution systems.  Additionally, the plan is expected to utilize emerging smart grid technology to empower residential, commercial, and industrial customers to more efficiently use electric power and lower their power costs.  The TVA service area faces a unique challenge since TVA serves 155 distributor customers at the wholesale level and these distributor customers serve the end-use customers; accordingly, the deployment plan must address the differences of the 155 distributor customers and evaluate the costs and benefits of different technology solutions to determine the best business case for each distributor customer.  Also, the cyber security of each system should be addressed.

TVA is implementing a pilot program with some distributor customers to enhance smart grid infrastructure through investment in communication technologies and end-use customer devices.   By providing start-up capital, TVA aims to gather information useful for guiding distributor customers through a successful roll-out plan.  Products being tested in the pilot program include (1) systems that enable two-way direct load control of water heaters and air conditioners, (2) smart thermostats, (3) smart displays, (4) systems that empower participation in voluntary critical-peak pricing products, and (5) distribution systems that regulate voltage.   Terms of this pilot program are currently being negotiated with 19 distributor customers.

TVA has an existing portfolio of programs focusing on energy efficiency and demand response which are designed to promote the wise use of energy.  See Item 1, Business – Current Power Supply.  In July 2010, TVA furthered its demand response portfolio with a new power supply agreement with a third-party aggregator of demand response load.  Under this arrangement, the third-party is expected to provide by the end of 2012 up to 560 MW of peak load reduction when requested by TVA.  This arrangement is expected to allow TVA to reduce its purchase of more expensive generation as well as to reduce power grid stress.

Research and Development

TVA makes investments in science and technological innovation to help enable TVA to meet future challenges in a variety of areas.  TVA is currently focused on the following initiatives:

•   Evaluation of technologies and development of a utility plan for the integration of electric vehicles onto the distribution and transmission system, including:  developing technologies to make electric vehicles and the charging stations that fuel them work together efficiently, dealing with demands on the power grid caused by charging stations, finding ways to minimize demands on the power grid, including solar-assisted charging stations and distributed energy storage, and refining existing processes for power system control to maximize energy efficiency and take full advantage of the environmental benefits of electric transportation;

•   Development of smart grid infrastructure for both transmission and distribution systems;

•   Development and testing of infrastructure and technologies to enable consumer awareness and access to demand response and energy efficiency tools;

          •Development and demonstration of coal ash utilization technologies;

•   Evaluation, demonstration, and implementation of clean and renewable energy technologies that reduce TVA’s environmental footprint, including participation in technology evaluations for carbon capture and sequestration;

•   Evaluation, demonstration, and implementation of technologies that improve the operational efficiency and extend asset life of our generation fleet (fossil, nuclear, and hydro).

TVA seeks to leverage research and development activities through partnerships with distributors of TVA power, the Electric Power Research Institute (“EPRI”), DOE, Oak Ridge National Laboratory, other utilities, and universities.

Environmental Stewardship Activities

TVA’s mission includes managing the Tennessee River, its tributaries, and public lands along the shoreline to provide, among other things, year-round navigation, flood damage reduction, affordable and reliable electricity, and, consistent with these primary purposes, recreational opportunities, adequate water supply, improved water quality, and natural resource protection.  There are 49 dams that comprise TVA’s integrated reservoir system.  The reservoir system provides 800 miles of commercially navigable waterway and also provides significant flood reduction benefits both within the Tennessee River system and downstream on the lower Ohio and Mississippi Rivers.  The reservoir system also provides a water supply for residential and industrial customers, as well as cooling water for some of TVA’s coal-fired and nuclear power plants.  TVA’s Environmental Policy provides objectives

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for an integrated approach related to providing cleaner, reliable, and affordable energy, supporting sustainable economic growth, and engaging in proactive environmental stewardship.  The Environmental Policy provides additional direction in several environmental stewardship areas, including water resource protection and improvements, sustainable land use, and natural resource management.  TVA also manages approximately 293,000 acres of reservoir lands for natural resource protection, recreation, and other purposes.  On June 15, 2009, TVA initiated a Natural Resource Plan (“NRP”).  The purpose of the NRP is to establish a framework for the management of TVA’s lands and shorelines to meet its environmental stewardship mission for the next 20 years.  TVA expects to issue a final NRP in 2011.

Economic Development Activities

Since its creation in 1933, TVA has promoted the development of the Tennessee Valley.  TVA works with its distributor customers, regional, state, and local agencies, and communities to showcase the advantages available to businesses locating or expanding in TVA’s service area.  At its October 30, 2008 meeting, the TVA Board approved a new economic development initiative, the Valley Investment Initiative.  Under the Valley Investment Initiative, TVA and its distributor customers provide an incentive award to new and existing companies in TVA’s  service area that demonstrate a multi-year commitment to sustained capital investment, the creation of quality jobs, compatible and efficient power use, and a commitment to remain in the TVA service area. Continued recruitment of desirable companies and retention of the current industrial and manufacturing base also continue to be critical to TVA’s economic development mission.

Governance

TVA is governed by the TVA Board.  The TVA Board consists of up to nine part-time members, no more than two of whom may be legal residents outside of TVA’s service area.  TVA Board members are appointed by the President of the United States with the advice and consent of the U.S. Senate.  TVA Board members serve five-year terms, and at least one member’s term ends each year.  The TVA Board, among other things, establishes broad goals, objectives, and policies for TVA; establishes long-range plans to carry out these goals, objectives, and policies; approves annual budgets; and establishes a compensation plan for employees.  Information about members of the TVA Board and TVA’s executive officers is discussed in Item 10, Directors, Executive Officers and Corporate Governance.

Regulation

Congress

TVA exists pursuant to legislation enacted by Congress and carries on its operations in accordance with this legislation.  Congress can enact legislation expanding or reducing TVA’s activities, change TVA’s structure, and even eliminate TVA.  Congress can also enact legislation requiring the sale of some or all of the assets TVA operates or reduce the United States’s ownership in TVA.  To allow TVA to operate more flexibly than a traditional government agency, Congress exempted TVA from certain general federal laws that govern other agencies, such as federal labor relations laws and the civil service laws related to the hiring of federal employees, the procurement of supplies and services, and the acquisition of land.  Other federal laws enacted since the creation of TVA have been made applicable to TVA, including those related to paying employees overtime and protecting the environment, cultural resources, and civil rights.

Securities and Exchange Commission

Section 37 of the Securities Exchange Act of 1934 (the “Exchange Act”) requires TVA to file with the SEC such periodic, current, and supplementary information, documents, and reports as would be required pursuant to section 13 of the Exchange Act if TVA were an issuer of a security registered pursuant to section 12 of the Exchange Act.  Section 37 of the Exchange Act exempts TVA from complying with section 10A(m)(3) of the Exchange Act, which requires each member of a listed issuer’s audit committee to be an independent member of the board of directors of the issuer.  Since TVA is an agency and instrumentality of the United States, securities issued or guaranteed by TVA are “exempted securities” under the Securities Act of 1933, as amended (the “Securities Act”), and may be offered and sold without registration under the Securities Act.  In addition, securities issued or guaranteed by TVA are “exempted securities” and “government securities” under the Exchange Act.  TVA is also exempt from sections 14(a)-(d) and 14(f)-(h) of the Exchange Act (which address proxy solicitations) insofar as those sections relate to securities issued by TVA, and transactions in TVA securities are exempt from rules governing tender offers under Regulation 14E of the Exchange Act.  Also, since TVA securities are exempted securities under the Securities Act, TVA is exempt from the Trust Indenture Act of 1939 insofar as it relates to securities issued by TVA, and no independent trustee is required for these securities.

Federal Energy Regulatory Commission

Under the FPA, TVA is not a “public utility,” a term which generally includes investor-owned utilities.  Therefore, TVA is not subject to the full jurisdiction that FERC exercises over public utilities under the FPA.  TVA is, however, an “electric utility” and a “transmitting utility” as defined in the FPA and, thus, is directly subject to certain aspects of FERC’s jurisdiction.

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• Under section 210 of the FPA, TVA can be ordered to interconnect its transmission facilities with the electrical facilities of qualified generators and other electric utilities that meet certain requirements.  It must be found that the requested interconnection is in the public interest and would encourage conservation of energy or capital, optimize efficiency of facilities or resources, or improve reliability.  The requirements of section 212 concerning the terms and conditions of interconnection, including reimbursement of costs, must also be met.

• Under section 211 of the FPA, TVA can be ordered to transmit power at wholesale provided that the order does not impair the reliability of the TVA or surrounding systems and likewise meets the applicable requirements of section 212 concerning terms, conditions, and rates for service.  Under section 211A of the FPA, TVA is subject to FERC review of the transmission rates and the terms and conditions of service that TVA provides others to ensure comparability of treatment of such service with TVA’s own use of its transmission system and that the terms and conditions of service are not unduly discriminatory or preferential.  The anti-cherrypicking provision of the FPA precludes TVA from being ordered to wheel another supplier’s power to a customer if the power would be consumed within TVA’s defined service territory.

• Sections 221 and 222 of the FPA, applicable to all market participants, including TVA, prohibit (i) using manipulative or deceptive devices or contrivances in connection with the purchase or sale of power or transmission services subject to FERC’s jurisdiction and (ii) reporting false information on the price of electricity sold at wholesale or the availability of transmission capacity to a federal agency with intent to fraudulently affect the data being compiled by the agency.

• Under section 215 of the FPA, TVA must comply with certain standards designed to maintain transmission system reliability.  These standards are approved by FERC and enforced by the Electric Reliability Organization.

• Section 206(e) of the FPA provides FERC with authority to order refunds of excessive prices on short-term sales (transactions lasting 31 days or less) by all market participants, including TVA, in market manipulation and price gouging situations if such sales are under a FERC-approved tariff.

• Section 220 of the FPA provides FERC with authority to issue regulations requiring the reporting, on a timely basis, of information about the availability and prices of wholesale power and transmission service by all market participants, including TVA.

• Under sections 306 and 307 of the FPA, FERC may investigate electric industry practices, including TVA’s operations previously mentioned that are subject to FERC’s jurisdiction.

• Under sections 316 and 316A of the FPA, FERC has authority to impose civil penalties of up to $1 million a day for each violation on entities subject to the provisions of Part II of the FPA, which includes the above provisions applicable to TVA.  Criminal penalties may also result from such violations.

Finally, while not required to do so, TVA has elected to implement various FERC orders and regulations pertaining to public utilities on a voluntary basis to the extent that these are consistent with TVA’s obligations under the TVA Act.

Nuclear Regulatory Commission

TVA operates its nuclear facilities in a highly regulated environment and is subject to the oversight of the NRC, an independent agency which sets the rules that users of radioactive materials must follow.  The NRC has broad authority to impose requirements relating to the licensing, operation, and decommissioning of nuclear generating facilities.  In addition, if TVA fails to comply with requirements promulgated by the NRC, the NRC has the authority to impose fines, shut down units, or modify, suspend, or revoke TVA’s operating licenses.

Environmental Protection Agency

TVA is subject to regulation by the EPA in a variety of areas, including air quality control, water quality control, and management and disposal of hazardous wastes.  See Item 1, Business — Environmental Matters.

States

The Supremacy Clause of the U.S. Constitution prohibits states, without congressional consent, from regulating the manner in which the federal government conducts its activities.  As a federal agency, TVA is exempt from regulation, control, and taxation by states except in certain areas such as air and water quality where Congress has given the states limited powers to regulate federal activities.

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Other Federal Entities

TVA’s activities and records are also subject to review to varying degrees by other federal entities, including the Government Accountability Office and the Office of Management and Budget (“OMB”).  There is also an Office of Inspector General which reviews TVA’s activities and records.

Taxation and Tax Equivalents

TVA is not subject to federal income taxes.  In addition, neither TVA nor its property, franchises, or income is subject to taxation by states or their subdivisions.  Section 13 of the TVA Act does, however, require TVA to make tax equivalent payments to states and counties in which TVA conducts power operations or in which TVA has acquired power-producing properties previously subject to state and local taxation.  The total amount of these payments is five percent of gross revenues from the sale of power during the preceding year excluding sales or deliveries to other federal agencies and off-system sales with other utilities, with a provision for minimum payments under certain circumstances.  Except for certain direct payments TVA is required to make to counties, distribution of tax equivalent payments within a state is determined by individual state legislation.

Environmental Matters

TVA’s power generation activities, like those across the utility industry and in other industrial sectors, are subject to most federal, state, and local environmental laws and regulations.  Major areas of regulation affecting TVA’s activities include clean air control, water quality control, and management and disposal of solid and hazardous wastes.  In the future, regulations in all of these areas are expected to become more stringent and to apply to additional emissions and sources, with a particular emphasis on climate change, renewable generation, and energy efficiency.

Clean Air Regulations

The Clean Air Act (“CAA”) establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions.  The major CAA programs that affect TVA’s power generation activities are described below.

National Ambient Air Quality Standards.  The CAA requires EPA to set minimum national ambient air quality standards (“NAAQS”) for certain air emissions including ozone, particulate matter, SO2, and nitrogen dioxide (“NO2”).  The CAA established two types of NAAQS: (1) primary standards, which set limits to protect public health, and (2) secondary standards, which set limits to protect public welfare.  Most NAAQS require measurement over a defined period of time (typically one hour, eight hours, twenty-four hours, or one year) to determine the average concentration of the pollutant present in a defined geographic area.

When a NAAQS has been established, each state must recommend, and EPA must designate, the areas within its boundaries that meet NAAQS (“attainment areas”) and those that do not (“non-attainment areas”).  Each state must develop a state implementation plan (“SIP)” to bring non-attainment areas into compliance with NAAQS and maintain good air quality in attainment areas.  Non-attainment designations can have serious repercussions by, among other things, causing states to impose stricter controls on industrial facilities, including TVA’s power plants, and complicating the air permitting process for the construction, expansion, or modification of industrial facilities.  If counties in which TVA facilities are located are designated as non-attainment for one or more types of emissions, TVA’s expansion or modification plans could be affected, possibly resulting in increased costs or schedule delays.  The NAAQS that affect or potentially affect TVA operations are summarized below.

NAAQS for Ozone.  In March 2008, EPA issued final rules adopting new, more stringent eight-hour NAAQS for ozone.  EPA lowered the primary standard from 84 parts per billion to 75 parts per billion and promulgated a new secondary standard that is the same as the primary standard.  Virtually all of the larger cities in the TVA service area, as well as those rural counties where ozone monitors are present, will likely be designated as non-attainment areas under the new standard.  States must submit to EPA no later than CY 2014 plans that demonstrate attainment with the standard.  Areas must reach attainment by deadlines that vary (CY 2016 to CY 2030) depending on the severity of the ozone problem.

On January 19, 2010, EPA published a proposed rule that would establish more stringent primary and secondary ozone NAAQS standards.  EPA announced that it expects to publish the final rule with the new ozone standards before the end of CY 2010.  As the ozone standards become more stringent, utilities are expected to come under increasing pressure to further reduce NOx emissions from their existing fossil plants.

NAAQS for Particulate Matter.  EPA has developed annual NAAQS for coarse particulate matter (defined as particles of 10 micrometers or larger) and both annual and 24-hour NAAQS for fine particulate matter (particles with a size of up to 2.5 micrometers).  On October 8, 2009, EPA issued non-attainment designations for areas not meeting the 24-hour NAAQS for fine particulate matter.   In the TVA service area, Anderson, Blount, Knox, and Loudon Counties in Tennessee, and a portion of Roane County, also in

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Tennessee, were designated as non-attainment.  TVA operates coal-fired power plants in Anderson and Roane Counties.  TVA also operates a coal-fired plant in Jackson County, Alabama, and part of that county is designated non-attainment for the annual fine particulate standard.  State and some local governments will be required to take steps to control fine particulate pollution affecting these non-attainment areas.  Those steps may include stricter controls on industrial facilities, possibly including TVA’s power plants, and additional planning requirements for transportation-related sources.  States must submit their SIPs to EPA within three years after EPA makes final nonattainment area designations.  Areas are required to attain the standard no later than five years after the effective date of the designations.  EPA may grant attainment date extensions for up to five additional years in areas with more severe fine particulate matter problems as well as in areas where emissions control measures are not available or feasible.

EPA is currently reconsidering the annual fine particulate standard, and if lowered as expected, additional non-attainment designations are likely.  EPA expects its reconsideration of the adequacy of the annual fine particulate standard to be completed in October 2011.

NAAQS for SO2.  On June 2, 2010, EPA established a new one-hour SO2 NAAQS at 75 parts per billion and revoked the 24 hour and annual SO2 NAAQS.  EPA expects to designate areas as attainment, non-attainment, or unclassifiable by January 2012 based on the existing monitoring network and modeling.  Non-attainment designations are expected to result in lower SO2 emission limits for sources of SO2 in or near those areas.  Several areas in the TVA service area are expected to be designated non-attainment, and the new standard is expected to make permitting for some new and modified sources, including TVA sources, more difficult.

NAAQS for NO2.  On January 22, 2010, EPA established a new one-hour NAAQS for NO2 at the level of 100 parts per billion.  To determine compliance with the new standard, EPA is establishing new ambient air monitoring requirements near major roads as well as in other locations where maximum concentrations are expected.  Although existing air quality monitors do not currently show exceedances of this new standard in the TVA service area, additional community and roadside monitoring is expected to result in the designation of new non-attainment areas.  EPA intends to re-designate areas in CY 2016 or CY 2017, as appropriate, based on the air quality data from the new monitoring network.  This new short-term standard could make permitting new and modified sources, including TVA sources, more difficult.  Several areas in the TVA service area are expected to be designated non-attainment.

New Source Review.  The New Source Review (“NSR”) provisions of the CAA require persons constructing new major air emission sources or making major modifications to existing air pollution sources to obtain a permit prior to such construction or modifications.   Major modifications are non-routine physical or operational changes that increase the emissions from an air emission source above specified thresholds.  In order to proceed with a project, the facility must first obtain a permit which requires the identification and implementation of Best Available Control Technology (“BACT”) for all regulated air pollutants emitted above the prescribed thresholds and an analysis of the ambient air quality impacts of the new construction or major modification.  In 1999, EPA announced plans to actively pursue NSR enforcement actions against electric utilities for making changes to their coal-fired power plants without obtaining an NSR permit.  Under section 114 of the CAA, EPA has the authority to request from any person who owns or operates an emission source information and records about operation, maintenance, and emissions as well as other data relating to such source for the purpose of developing regulatory programs, determining if a violation occurred (such as the failure to comply with NSR), or carrying out other statutory responsibilities.  If violations are found to have occurred, EPA or, possibly, other enforcement authorities could require the installation of new pollution control equipment and could impose fines and penalties.  See Note 20 – Legal Proceedings – Case Involving Alleged Violations of the New Source Review Regulations at Bull Run for a discussion of litigation under the NSR provisions affecting TVA.

Clean Air Interstate Rule.  EPA promulgated the Clean Air Interstate Rule (“CAIR”) in 2005.  CAIR proposed to reduce utility SO2 and NOx emissions to address ozone and fine particulate matter attainment issues in 28 eastern states, including all of TVA’s service area, and the District of Columbia through an emissions cap-and-trade program.

On July 11, 2008, the U.S. Court of Appeals for the D.C. Circuit (“D.C. Circuit”) issued a decision in State of North Carolina vs. EPA that vacated CAIR in its entirety and directed EPA to promulgate a new rule that is consistent with the D.C. Circuit’s opinion.  On December 23, 2008, the D.C. Circuit, in response to EPA’s petition for a rehearing, ordered EPA to develop a new rule but allowed CAIR to remain in effect during this process.  This decision reinstated CAIR, including the cap-and-trade program, until EPA issues a final new rule consistent with the D.C. Circuit’s decision.

On August 2, 2010, EPA published a proposed replacement rule for CAIR referred to as the Transport Rule.  The Transport Rule is more stringent than CAIR and would require reduction of SO2 and NOx emissions from electric generating units (“EGUs”) in 32 states in the eastern United States, including all of TVA’s service area. Under this proposed rule, SO2 and NOx emission reductions from the EGUs in all 32 states would take effect in CY 2012, and further SO2 emission reductions would be required in CY 2014 for EGUs in certain states, including Tennessee and Kentucky.

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TVA expects that the final CAIR replacement rule – either the Transport Rule, as currently proposed, or another replacement rule - will require additional SO2 and NOx emission reductions from many of TVA’s power plants and/or require TVA to purchase emission credits or allowances.  These requirements may result in increased capital expenditures, increased operating expenses, and schedule delays as compared to TVA’s plans to comply with the original CAIR program.  TVA will adjust its emission reduction plans as required to comply with the Transport Rule, or other replacement rule, when it becomes final and effective.  EPA expects to finalize the Transport Rule by June 2011.

Hazardous Air Pollutants.  In 2005, EPA issued the Clean Air Mercury Rule (“CAMR”), which set mercury limits via a cap-and-trade program.  The D.C. Circuit vacated CAMR.  EPA now plans to regulate hazardous air pollutants from utilities under section 112(d) of the CAA, which requires emission standards to be based on the maximum achievable control technology (“MACT”) and the use of command-and-control permit programs instead of a cap-and-trade program such as the one proposed by CAMR and rejected by the D.C. Circuit.  Further, EPA is expected to regulate not just mercury but also other hazardous pollutants such as non-mercury metals, acid gases, and organics in a future section 112(d) rule establishing MACT standards for these pollutants.  The cost to comply with the future MACT standards for mercury emissions is not known at this time, but is expected to be higher than what the cost would have been to comply with CAMR.

On June 4, 2010, EPA published a proposed rule to establish standards for hazardous air pollutants emitted from industrial, commercial, and institutional boilers and process heaters.  Some of TVA’s startup and auxiliary boilers may be required to install monitors and/or controls to meet these standards by CY 2014.  Until the final rule is published, specific requirements are too uncertain to predict.

On August 20, 2010, EPA published a final rule regulating the emissions of hazardous air pollutants from reciprocating internal combustion engines, including existing stationary spark ignition reciprocating internal combustion engines located at power plant sites.  This final rule, which became effective October 19, 2010, will require the reduction of emissions of hazardous air pollutants from covered engines.  TVA's reciprocating engines will be covered by this new rule, and TVA is currently evaluating compliance options, including the installation of emissions control technology.  TVA does not expect that the costs to comply with this new rule will be material.

Multi-Pollutant Legislation.  The U.S. Congress has expressed interest recently in adopting multi-pollutant control legislation focused on the electric power sector.  Among other things, such an approach could seek to establish coordinated caps for power plant emissions of mercury, SO2, NOx, and, in some cases, CO2.  TVA cannot predict whether multi-pollutant legislation will ultimately become law.  The legislative and regulatory landscape is continuing to change for these and other issues, and the outcome cannot be predicted accurately at this time.

North Carolina’s Petition to EPA. In 2005, North Carolina petitioned EPA under section 126 of the CAA to impose additional emission reduction requirements for SO2 and NOx on coal-fired power plants in 13 states, including the states where TVA’s coal-fired power plants are located.  In March 2006, EPA denied the North Carolina petition primarily on the basis that CAIR remedied the problem.  In June 2006, North Carolina filed a petition for review of EPA’s decision with the D.C. Circuit.   In Sierra Club v. EPA, the D.C. Circuit remanded the petition back to EPA in March 2009 for reconsideration in light of the court’s decision to remand CAIR.

Acid Rain Program.  Congress established the Acid Rain Program to achieve reductions in emissions of SO2 and NOx, the primary causes of acid rain.  The program includes a cap-and-trade emission reduction program for SO2 emissions from power plants.  By CY 2000, the program established a nationwide cap on power plant SO2 emissions of 8.9 million tons per year.  The program also contains requirements for power plants to reduce NOx emissions through the use of available combustion controls.

Regional Haze Program.On June 15, 2005, EPA issued the Clean Air Visibility Rule, amending its CY 1999 regional haze rule, which had established timelines for states to improve visibility in national parks and wilderness areas throughout the United States.  Under the amended rule, certain types of older sources may be required to install best available retrofit technology ("BART").  To comply with this requirement, certain utilities, including TVA, may have to install additional controls for particulate matter, SO2, and NOx emissions.

Opacity.  Opacity, or visible emissions, measures the denseness (or color) of power plant plumes and has traditionally been used by states as a means of monitoring good maintenance and operation of particulate control equipment.  Under some conditions, retrofitting a unit with additional equipment to better control SO2 and NOx emissions can adversely affect opacity performance, and TVA and other utilities are addressing this issue.  The evaluation of a utility’s compliance with state opacity requirements is coming under increased scrutiny, especially compliance during periods of startup, shutdown, and malfunction.  SIPs developed under the CAA typically provide for allowances during periods of startup, shutdowns, and malfunctions.  EPA is currently reconsidering its previous approval of the state of Alabama’s SIP for opacity.

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Climate Change

Legislation.   In 2009, both the U.S. House of Representatives and the U.S. Senate considered separate climate bills requiring reductions of GHGs across the economy through a cap-and-trade program.

•   On June 26, 2009, the U.S. House of Representatives passed H.R. 2454, the American Clean Energy and Security Act of 2009.  This bill, if enacted, would impose a cap on emissions of GHGs from covered sources, including TVA, of three percent, 17 percent, 40 percent, and 83 percent below CY 2005 emission levels by CY 2012, CY 2020, CY 2030, and CY 2050, respectively.

•   On November 5, 2009, the U.S. Senate’s Environmental & Public Works Committee passed S.1733, the Clean Energy Jobs and American Power Act.  The GHG cap-and-trade provisions in this bill are slightly more stringent than those in H.R. 2454.

Although it is unlikely that climate change legislation will pass during the 111th Congress, the 112th Congress may consider climate change and energy-related proposals.  It is not unreasonable to anticipate that new EPA regulations or laws may set limits on GHG emissions for the electric utility sector.  Prospects for future proposals becoming law, and the resulting potential impact on electric rates, are not clear at this time.  However, if GHG emission reductions from electricity generating facilities become mandatory, the costs and impacts are expected to be significant, especially for coal-fired plants.

Regulation.  On April 2, 2007, the U.S. Supreme Court issued a decision in Massachusetts v. EPA holding that GHG emissions, including CO2, are “air pollutants” under the CAA and requiring EPA to determine whether GHGs from new motor vehicles pose a threat to health and welfare.  On December 15, 2009, EPA published its finding under the CAA that GHGs contribute to air pollution that may endanger public health or welfare.  In the endangerment finding, EPA declared that the six identified GHGs – CO2, methane, nitrous oxide, hydro-fluorocarbons, perfluorocarbons, and sulfur hexafluoride – cause or contribute to global warming, and that the effects of climate change endanger public health and welfare by increasing the likelihood of severe weather events and other related consequences of climate change.  The issuance of the endangerment finding triggered the statutory requirement that EPA regulate emissions of GHGs from motor vehicles.  These regulations were finalized on April 1, 2010, when EPA and the U.S. Department of Transportation issued a joint final rule imposing GHG emission standards on light-duty vehicles (cars and light trucks).  These regulations take effect on January 2, 2011.

On March 29, 2010, EPA affirmed its position that the CAA permitting requirements under the Prevention of Significant Deterioration (“PSD”) and Title V permit programs are not triggered for a pollutant until a regulatory requirement to control emissions of that pollutant becomes effective.  (The PSD program requires permits before commencement of construction of new major stationary sources or major modifications of such sources, and the Title V program requires operating permits for all major stationary sources.)  As a result of this EPA determination, new or modified plants that are subject to PSD or Title V programs will have to address GHG emissions in new permit applications as of January 2, 2011, which is the date the new motor vehicle rule takes effect.  Similarly, GHGs emitted above certain thresholds from existing plants would be covered under the Title V program beginning on January 2, 2011.

On May 13, 2010, EPA issued a final rule to establish applicability thresholds that trigger reviews under the PSD and Title V permitting programs for GHG emissions from major sources.  The threshold levels established by this rule, known as the Tailoring Rule, include both a mass-based calculation and a metric known as the carbon dioxide equivalent (“CO2e”), which incorporates the global warming potential for each of the six individual gases identified in the endangerment finding.

Under the Tailoring Rule, EPA will phase in the CAA permitting requirements for emissions of GHG from stationary sources in at least three phases.

The first phase becomes effective January 2, 2011, and applies only to sources that are already subject to PSD and/or Title V programs because of their emission levels of other regulated pollutants.  Under the first phase, a source will be subject to PSD requirements for GHGs if (1) the source is already subject to PSD requirements for another pollutant and (2) the source increases its GHG emissions by at least 75,000 tons per year on a CO2e basis.  Sources that are subject to PSD requirements for GHGs will be required to conduct a BACT review for their GHG emissions.  EPA has issued guidance, which is out for comment, on the technologies or operations that would constitute BACT for GHGs.  Pending the commercial demonstration of technologies such as carbon capture and sequestration, it is expected that the use of energy efficiency measures will constitute BACT.   Additionally, under the first phase, any source that is required to have a Title V permit for a non-GHG pollutant will be required to address GHG requirements, including monitoring, record keeping, and reporting requirements, when it applies for, renews, or revises its Title V permit.

The second phase of the Tailoring Rule becomes effective July 1, 2011, and, unlike the first phase, is not limited to sources that are already subject to PSD and/or Title V programs.  Under the second phase, EPA has established different thresholds for construction and modification activities. Construction of a major source will become subject to PSD requirements for GHGs if the construction results in an increase in GHG emissions of at least 100,000 tons per year on a CO2e basis.  The modification of an existing major source will

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become subject to PSD requirements for GHGs if the modification results in an increase in GHG emissions of at least 75,000 tons per year on a CO2e basis.  Additionally, under the second phase, sources that emit GHGs in an amount equal to at least 100,000 ton per year on a CO2e basis will be required to obtain a Title V permit if they do not have one already.

The EPA has not yet established thresholds or an effective date for the third phase of the Tailoring Rule.

On October 30, 2009, EPA published the final rule for mandatory monitoring and annual reporting of GHG emissions from various categories of facilities, including fossil fuel suppliers, industrial gas suppliers, direct GHG emitters (such as electric generating facilities), and manufacturers of heavy-duty and off-road vehicles and engines.  This rule does not require controls or limits on emissions, but requires data collection beginning January 1, 2010, with the first annual reports due on March 31, 2011.  The requirements for monitoring, reporting, and record keeping with respect to GHG emissions from existing units should not have a material impact on TVA.

Executive Orders.  On October 5, 2009, President Obama signed Executive Order 13514, which requires federal agencies to establish GHG emission reduction targets and prepare inventories for three main categories of GHG emissions.  The emission reduction targets do not apply to direct emissions of GHGs associated with electricity generation.  As required by the executive order, TVA submitted its Sustainability Plan on June 2, 2010, and OMB approved that plan in August 2010.  Consistent with this executive order, TVA has established GHG reduction targets of between 17 percent and 21 percent by 2020 compared to a 2008 baseline, depending on the category of emissions.  TVA intends to achieve these reductions primarily by (1) improving the energy efficiency of its buildings, (2) improving the reliability and efficiency of its hydro-generation portfolio, (3) reducing solid waste disposal, (4) utilizing higher fuel efficiency standards for new cars and light trucks, and (5) increasing the use of employee telecommuting and employee car-pooling.  The executive order also requires developing and reporting inventories of GHG emissions by January 31, 2011.  The inventory must include emissions of CO2, methane, nitrous oxide, hydroflourocarbons, perfluorocarbon gases, and sulfur hexafluoride.  The White House Council on Environmental Quality released final Federal Greenhouse Gas Accounting and Reporting Guidance on October 6, 2010, which is the basis for these inventories.

 International Accords.  The Kyoto Protocol was adopted in 1997 by the United Nations to address global climate change by reducing emissions of CO2 and other GHGs.  Although the United States has not adopted the Kyoto Protocol, the United States pledged to reduce its GHG emissions in the range of 17 percent below CY 2005 levels by CY 2020 in connection with the 15th Conference of the Parties to the United Nations Framework Convention on Climate Change.  An act of the U.S. Congress is required to make such a reduction in GHG emissions enforceable.  The pledged reduction is in line with a climate bill that passed the U.S. House of Representatives in June 2009.  TVA is unable to predict whether this climate bill or other climate-related legislation requiring such reductions in GHG emissions ultimately will become law.

Litigation.  In addition to legislative activity, climate change issues are the subject of a number of lawsuits, including lawsuits against TVA.  See Note 20 —Legal Proceedings.

Indirect Consequences of Regulation or Business Trends.  Legal, technological, political, and scientific developments regarding climate change may create new opportunities and risks.   The potential indirect consequences could include an increase or decrease in electricity demand, increased demand for generation from alternative energy sources, and subsequent impacts to business reputation and public opinion.  See Item 1, Business – Integrated Resource Plan and Future Power Supply.

Physical Impacts of Climate Change.  In November 2009, EPRI published a report entitled Potential Impacts of Climate Change on Natural Resources in the Tennessee Valley Authority Region (the “EPRI Report”).  TVA co-sponsored this report, with the objective of providing preliminary information on climate change impacts across the TVA service area.  The EPRI Report was based on data from the Fourth Assessment Report of the Interagency Panel on Climate Change published in CY 2007.  Subject to substantial uncertainties, the EPRI Report predicted that future (2020-2100) precipitation in the TVA service area will increase approximately three percent during the winter and will be unchanged over the summer in the eastern portion of the TVA service area, but will decline six to seven percent over the western portion of TVA’s service area.  In addition, extreme weather events such as droughts and floods are also expected to become more frequent, although their frequency is difficult to quantify.  The EPRI Report also predicted that temperatures could increase across the TVA service area by approximately one degree Celsius by 2020, two degrees Celsius by 2050, and three to four degrees Celsius by 2100.

If realized, projected changes in precipitation and increasing temperatures could impact future TVA management of water resources in the Tennessee Valley in the following ways:

Power generation.Power generation depends on having sufficient water flow available for hydroelectric generation.  Hydroelectric generation will depend on the precipitation runoff within each reservoir drainage basin and the upstream flow into each reservoir.  Power generation also depends on having water available for cooling fossil and nuclear power plants.  Cooling water is withdrawn and then returned to the source.  Increasing water temperatures would require withdrawing more water to achieve the same amount

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of cooling at fossil and nuclear power plants, increasing the cooling capacities of plants, or reducing power generation to match the available water supply.  See Water Quality Control Developments.

Agricultural, municipal, and industrial uses.Agricultural, municipal, and industrial water uses are driven by temperature and extreme weather.  Warmer temperatures and drought will increase water demand for these purposes.

Navigation.Commercial navigation relies on maintaining the minimum channel depth as well as reasonable flow rates. Increasingly frequent extreme weather events (drought episodes and flooding) may create more challenges to maintaining the entire length of a commercial navigation channel.

Aquatic life.Water quality impacts the aquatic life dependent on the river system. Changes in water flow due to the increasing frequency of extreme weather events may impact the habitats and biodiversity of the Tennessee River system.

As changes in future precipitation and temperature develop, the current river management system employed by TVA may require periodic re-evaluations to balance the competing water use interests across the Tennessee Valley.

Actions Taken by TVA to Reduce GHG Emissions.  TVA has taken significant voluntary steps to reduce GHG emissions, including the following:

As discussed earlier in Item 1, Business, TVA has increased its nuclear capacity, modernized its hydroelectric program, increased its purchases of renewable resources, and helped reduce demand for electricity through its energy efficiency initiatives.

In CY 1995, TVA was the first utility in the nation to participate in Climate Challenge, a DOE-sponsored voluntary GHG reduction program.  Over the past decade, TVA has reduced, avoided, or sequestered over 300 million tons of CO2 under this program.

TVA participates in DOE’s Climate VISION program, a public-private partnership that calls on the electric utility sector, along with other industry sectors, to help meet a national goal of reducing the GHG intensity of the U.S. economy by 18 percent from CY 2002 to CY 2012.

TVA is a member of the Southeast Regional Carbon Sequestration Partnership and is working with EPRI and other electric utilities on projects investigating technologies for CO2 capture and geologic storage, as well as carbon sequestration via reforestation.

TVA’s CO2 Emissions.  In FY 2010, TVA produced about 84 million tons of CO2.  Historically, TVA has produced about 100 million tons of CO2 per year.  TVA produced less CO2 in 2010 because of a decrease in coal-fired generation.

Renewable Energy Standards

In CY 2009, both the U.S. House of Representatives and the U.S. Senate considered separate energy bills that would require compliance with renewable energy standards.

In July 2009, the U.S. Senate Committee on Energy and Natural Resources reported S. 1462, the American Clean Energy Leadership Act of 2009, which would require electricity suppliers to meet 15 percent of their electricity sales through renewable sources of energy or energy efficiency by CY 2021.  The legislation would also set interim minimum annual percentage requirements for renewable generation of three percent by CY 2011, six percent by CY 2014, nine percent by CY 2016, and 12 percent by CY 2019.  The legislation would allow demonstrated electricity savings from energy efficiency measures to meet up to 26.67 percent of the annual renewable generation requirements.  Full U.S. Senate consideration of this bill is not expected in the 111th Congress.

In June 2009, the U.S. House of Representatives passed H.R. 2454, the American Clean Energy and Security Act of 2009, which, in addition to mandated GHG reductions, would require electricity suppliers to meet 20 percent of their electricity sales through renewable sources of energy or energy efficiency by CY 2020.  The bill would set interim minimum annual percentage requirements for renewable generation of six percent by CY 2012, 9.5 percent by CY 2014, 13 percent by CY 2016, and 16.5 percent by CY 2018.  The bill would allow demonstrated electricity savings from energy efficiency measures to meet up to 25 percent of the annual renewable generation requirements, or up to 40 percent upon FERC’s approval of a governor’s petition to allow a higher percentage through energy efficiency.

It is unclear whether the U.S. Congress will adopt a law that mandates a certain percentage of electric generation from a specified list of eligible renewable energy technologies.  To date, 29 states have established requirements for electric utilities to generate a certain amount of electricity from renewable sources, including one state in the TVA

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service area (North Carolina). The North Carolina program does not apply to TVA but does apply to TVA distributor customers located in that state.  Each state has adopted unique definitions of qualifying renewable resources.

Water Quality Control Developments

EPA is expected to propose a new rule by the end of CY 2010 designed to minimize the adverse impacts to fish and shellfish from the design and operation of cooling water intake structures at existing power plants.  The new rule is expected to require changes in the operation of cooling water intakes and modifications to their design.  These changes could potentially result in significant increases in capital costs and operating and maintenance costs.  All of the intakes at TVA’s existing coal and nuclear generating facilities are likely to be subject to the new rule.  Because of the uncertainty of the changes to be made by EPA, the impacts of the rulemaking are uncertain at this time.

EPA and many states are taking increased interest in potential effects of hydrothermal discharges.  TVA is working with states and EPA to demonstrate that the data collected in the vicinity of TVA plants is sufficient to assess the impacts of thermal discharges on the aquatic environment and validate existing thermal limits.  TVA expects to collect substantially more in-stream biological and temperature data than in the past to justify current thermal limits.  Specific data requirements in the future will be determined based on negotiations between TVA and regulators.

Water temperature issues at TVA’s Cumberland Fossil Plant continue to be complicated by reduced flows in the Cumberland River due to ongoing repairs at Wolf Creek and Center Hill dams initiated by the U.S. Army Corps of Engineers in CY 2007.  The greatly reduced flows combined with thermal discharges at the Cumberland Fossil Plant have resulted in increased stress to aquatic organisms and have contributed to a portion of Barkley Reservoir being included on the State of Tennessee’s CY 2008 list of impaired waters.  The lower river flows are expected to continue to impact TVA’s ability to operate the Cumberland Fossil Plant at normal rates, which may result in increased spending for power purchases. TVA continues to work with the U.S. Army Corps of Engineers and the Tennessee Department of Environment and Conservation (“TDEC”) to alleviate aquatic impacts in the Barkley Reservoir and to improve the conditions in the reservoir.

The effluent guidelines required by the Clean Water Act for the Steam Electric Power Generating Category were last revised by EPA in CY 1982.  EPA is currently conducting studies and surveys of wastewater discharges from the industry, and is expected to issue a proposed rule to revise the existing guidelines in CY 2012.  A future rule is expected to focus on wastewaters from ash handling and clean air control systems. The revised effluent guidelines are likely to require more restrictive discharge limitations through more advanced wastewater treatment, resulting in significant additional expenditures to meet the new requirements.

As is the case in other industrial sectors, TVA and other utilities are also facing more stringent requirements related to the protection of wetlands, reductions in storm water impacts from construction activities, new water quality criteria for nutrients and other pollutants, wastewater analytical methods, and regulation of herbicide discharges.  In addition, other new environmental requirements under the Clean Water Act related to mountain top mining of coal in the Appalachian region may result in additional increases in the costs of fuel for TVA’s coal-fired power plants.

Cleanup of Solid and Hazardous Wastes

Liability for releases and cleanup of hazardous substances is primarily regulated under the federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), and other federal and parallel state statutes.  In a manner similar to many other industries and power systems, TVA has generated or used hazardous substances over the years.

Non-TVA Sites.  TVA is aware of alleged hazardous-substance releases at 11 non-TVA areas for which it may have some liability.  TVA has reached agreements with EPA to settle its liability at two of these non-TVA areas for a total of less than $23,000.  There is little or no known evidence that TVA contributed any significant quantity of hazardous substances to six of the non-TVA areas, and there has been no recent assertion of potential TVA liability for five of these six areas.  There is evidence that TVA sent some materials to the remaining three non-TVA sites: the David Witherspoon site in Knoxville, Tennessee, the Ward Transformer site in Raleigh, North Carolina, and the General Waste Products site in Evansville, Indiana.

David Witherspoon Site.  The David Witherspoon site was contaminated with radionuclides, polychlorinated biphenyls (“PCBs”), and metals.  DOE admitted to being the main contributor of materials to the site and cleaned the site up at a reported cost of about $35 million.  Although DOE asked TVA to “cooperate” in completing the cleanup, TVA believes it sent only a relatively small amount of equipment to the site and that none of it was radioactive; accordingly, TVA believes that its liability for these cleanup costs is limited.

Ward Transformer Site.The Ward Transformer site in Raleigh, North Carolina, is contaminated by PCBs from electrical equipment.  There is documentation showing that TVA sent a limited amount of electrical equipment containing PCBs to the site in CY 1974.  A working group of potentially responsible parties (the “PRP Work Group”) is cleaning up

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on-site contamination in accordance with an agreement with EPA.  The cleanup effort has been divided into four areas: two phases of soil cleanup; cleanup of off-site contamination in the downstream drainage basin; and supplemental groundwater remediation.  The cost estimate for the first phase of soil cleanup is approximately $55 million.  The cost estimate for the second phase of soil cleanup is $10 million.  Estimates for cleanup of off-site contamination in the downstream drainage basin range from $6 million to $25 million.  There are no reliable estimates for the supplemental groundwater remediation phase.  On April 30, 2009, the PRP Work Group filed an amended complaint in federal court against potentially responsible parties who had not yet settled, including TVA, regarding the two phases of soil cleanup.  TVA settled this lawsuit and its potential liability for the two phases of soil cleanup for $300,000 and has been dismissed as a party.  Although the settlement with respect to the first two phases does not prohibit TVA from having liability in connection with the other two phases or any natural resource damages, the U.S. Department of Justice is attempting to negotiate a government-wide settlement of the liability of all federal agencies (including TVA) for cleanup of offsite contamination in the downstream drainage basin and the investigative portion of the supplemental groundwater remediation.

General Waste Products Site. General Waste Products, located in Evansville, Indiana, operated from the 1930s until CY 1998 scrap metal salvage yards that contain contamination from lead batteries and PCB transformers.  The original defendants in a CERCLA action for the sites have filed a third-party complaint in the U.S. District Court for the Southern District of Indiana against TVA and others seeking cost contribution for cleanup of the yards.  There is evidence that TVA sent scrap metal to General Waste Products, but TVA has not found any records indicating that it sent batteries or PCB equipment.  Counsel for the original plaintiffs has informed TVA that the first yard has been cleaned up at a cost of $3.2 million, and cleanup estimates for the second yard range from $2 million to $7 million.  TVA settled the claims against it for a minimal amount and was dismissed from the case on September 8, 2010.  TVA did not admit to any liability for the site contamination as part of the settlement.

TVA Sites.  TVA operations at some TVA facilities have resulted in oil spills and other contamination that TVA is addressing.

Estimated Liability.  As of September 30, 2010, TVA’s estimated liability for cleanup and similar environmental work for those sites for which sufficient information is available to develop a cost estimate is approximately $23 million and is included in Other liabilities on the Balance Sheet.

Coal-Combustion Wastes

On May 4, 2010, EPA released the text of a proposed rule describing two possible regulatory options it is considering under the Resource Conservation and Recovery Act (“RCRA”) for the disposal of coal ash generated from the combustion of coal by electric utilities and independent power producers.  Under either option, EPA would regulate the construction of impoundments and landfills, and seek to ensure both the physical and environmental integrity of disposal facilities.

Under the first proposed regulatory option, EPA would list coal ash destined for disposal in landfills or surface impoundments as “special wastes” subject to regulation under Subtitle C of RCRA.  Subtitle C regulations set forth EPA’s hazardous waste regulatory program, which regulates management and disposal of wastes.  The proposed rule would create a new category of waste so that coal ash would be subject to many of the Subtitle C regulatory requirements.  Under this option, coal ash would be subject to technical requirements from the point of generation to final disposal.  Transporters and treatment, storage, and disposal facilities would be subject to federal requirements and permits.  EPA is considering imposing disposal facility requirements such as liners, groundwater monitoring, fugitive dust controls, financial assurance, corrective action, closure of units, and post-closure care.  This first option also proposes requirements for dam safety and stability for surface impoundments, land disposal restrictions, treatment standards for coal ash, and a prohibition on the disposal of treated coal ash below the natural water table.  This first option would not apply to certain beneficial reuses of coal ash.

Under the second proposed regulatory option, EPA would regulate the disposal of coal ash under Subtitle D of RCRA, the regulatory program for non-hazardous solid wastes.  Under this option, EPA is considering issuing national minimum criteria to ensure the safe disposal of coal ash, which would subject disposal units to location standards, composite liner requirements, groundwater monitoring, corrective action standards for releases, closure and post-closure care requirements, and requirements to address the stability of surface impoundments.  Existing surface impoundments would not have to close or install composite liners and could continue to operate for their useful life.  This second option would not regulate the storage or treatment of coal ash prior to disposal, and no federal permits would be required.

The proposed rule also states that EPA is considering listing coal ash as a hazardous substance under CERCLA, and includes proposals for alternative methods to adjust the statutory reportable quantity for coal ash.  The extension of CERCLA to coal ash could significantly increase TVA’s liability for cleanup of past and future coal ash disposal.

EPA has not decided which regulatory approach it will take with respect to the management and disposal of coal ash.  TVA is therefore unable to determine the effects of this proposed rule at this time.

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Kingston Ash Spill

See Note 8 for a discussion of the environmental issues associated with the Kingston ash spill.

 Environmental Investments

From 1977 to 2010, TVA spent approximately $5.3 billion to reduce emissions from its power plants, including $58 million, $172 million, and $274 million in 2010, 2009, and 2008, respectively.  Among other things, TVA has taken the following steps to reduce emissions:

SO2 Emissions.  To reduce SO2 emissions, TVAinstalled scrubbers on 17 of its coal-fired units, and switched to lower-sulfur coals at 41 coal-fired units.

NOx Emissions.  To reduce NOxemissions, TVA installed SCRson 21 of its largest coal-fired units, installed selective non-catalytic reduction systems on two coal-fired units (although TVA is no longer operating one of these systems because of technical challenges), installed High Energy Reagent Technology (“HERT”) systems on seven coal-fired units, installed low-NOx burners (“LNB”) or low-NOx combustion systems on 47 of its 59 coal-fired units, optimized combustion on 10 coal-fired units, and began operating NOx control equipment year round when units are operating (except during maintenance periods) starting in October 2008.

Particulate Emissions.  To reduce particulate emissions, TVA has equipped all of its coal-fired units with scrubbers, mechanical collectors, electrostatic precipitators, or baghouses.

Primarily on account of the actions described above, emissions of NOx on the TVA system have been reduced by 89 percent below peak 1995 levels, and emissions of SO2 on the TVA system have been reduced by 90 percent below 1977 levels.  In addition, the actions described above have also provided a co-benefit of reducing hazardous air pollutants, including mercury, at some units.

TVA estimates that compliance with future CAA requirements (excluding GHG requirements) could lead to additional costs of $3.8 billion in the decade beginning in CY 2011.   There could be additional material costs if reductions of GHGs, including CO2, are mandated under the CAA or by legislation, or if future legislative, regulatory, or judicial actions lead to more stringent emission reduction requirements for conventional pollutants.  These costs cannot reasonably be predicted at this time because of the uncertainty of such potential actions.

In addition to the costs described above, TVA is planning to invest between $1.5 billion and $2.0 billion over an eight to ten year period to convert wet ash and gypsum facilities to dry storage facilities.  See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations – 2010 Challenges – Coal Combustion Product Facilities.

To meet strategic clean air objectives, TVA is also planning to idle certain of its coal-fired units.  In September 2010, TVA idled Unit 5 at Widows Creek and in October 2010, TVA idled Widows Creek Unit 2 and Shawnee Fossil Plant Unit 10.  TVA is evaluating its remaining coal-fired portfolio and may make decisions to idle more coal-fired capacity in the future.    See Item 1, Business – Integrated Resource Plan and Future Power Supply – Improving Air Quality.

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Estimated Required Environmental Expenditures

The following table contains information about TVA’s current estimates on projects related to environmental

laws and regulations.

 

TVA Air, Water, and Waste Quality Estimated Potential Environmental Expenditures As of September 30, 2010 (in millions)
	Estimated Timetable	Total Estimated Expenditures
Site environmental remediation costs(1)	2011+	$        23
CCP conversion and remediation(2)	2011-2020	$   1,553
Proposed clean air projects(3)	2011-2018	$   3,779
Clean Water Act requirements(4)	2015-2020	TBD*
Notes (1)  Estimated liability for cleanup and similar environmental work for those sites for which sufficient information is available to develop a cost estimate. (2)  Includes closure of impoundments, construction of lined landfills, and construction of dewatering systems. (3)  Includes air quality projects that TVA is currently planning to undertake to comply with existing and proposed air quality regulations, but does not include any projects that may be required to comply with potential GHG regulations. (4)  Compliance plans to meet the requirements of a revised or new implementing rule under Section 316(b) of the Clean Water Act and the EPA’s decision to revise the steam electric effluent guidelines will be determined upon finalization of the rules. *  TBD – to be determined as regulations become final

Employee Relations

On September 30, 2010, TVA had 12,457 employees, of whom 4,776 were trades and labor employees.  Under the TVA Act, TVA is required to pay trades and labor workers hired by TVA or certain of its contractors the rate of wages for work of a similar nature prevailing in the vicinity where the work is being performed.  Neither the federal labor relations laws covering most private sector employers nor those covering most federal agencies apply to TVA.  However, the TVA Board has a long-standing policy of acknowledging and dealing with recognized representatives of its employees, and that policy is reflected in long-term agreements to recognize the unions (or their successors) that represent TVA employees.  Federal law prohibits TVA employees from engaging in strikes against TVA.

ITEM 1A.  RISK FACTORS

The risk factors described below, as well as the other information included in this Annual Report, should be carefully considered.  Risks and uncertainties described in these risk factors could cause future results to differ materially from historical results as well as from the results anticipated in forward-looking statements.  Although the risk factors described below are the ones that TVA considers significant, additional risk factors that are not presently known to TVA or that TVA presently does not consider significant may also impact TVA’s business operations.  Although the TVA Board has the authority to set TVA’s own rates and may thus mitigate some risks by increasing rates, there may be instances in which TVA would be unable to partially or completely eliminate one or more of these risks through rate increases over a reasonable period of time or at all.   Accordingly, the occurrence of any of the following could have a material adverse effect on TVA’s cash flows, results of operations, and financial condition.

New laws, regulations, and administrative orders may negatively affect TVA’s cash flows, results of operations, and financial condition, as well as the way TVA conducts its business.

Because TVA is a corporate agency and instrumentality established by federal law, it may be affected by a variety of laws, regulations, and administrative orders that do not affect other electric utilities.  For example, Congress may enact legislation that expands or reduces TVA’s activities, changes its governance structure, requires TVA to sell some or all of the assets that it operates, reduces or eliminates the United States’s ownership of TVA, or even liquidates TVA.  Although it is difficult to predict exactly how new laws, regulations, and administrative orders may impact TVA, some of the possible effects are described below.

TVA may lose its protected service territory.

TVA’s service area is defined by the fence and protected by the anti-cherrypicking provision.  If Congress were to eliminate or reduce the coverage of the anti-cherrypicking provision but retain the fence, TVA could more easily lose customers that it could not replace within its specified service area.  The loss of these customers could adversely affect TVA’s cash flows, results of operations, and financial condition.

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The TVA Board may lose its sole authority to set rates for electricity.

Under the TVA Act, the TVA Board has the sole authority to set the rates that TVA charges for electricity and these rates are not subject to further review.  If the TVA Board loses this authority or if the rates become subject to outside review, there could be material adverse effects on TVA including, but not limited to, the following:

The TVA Board might be unable to set rates at a level sufficient to generate adequate revenues to service TVA’s financial obligations, properly operate and maintain its power assets, and provide for reinvestment in its power program; and

TVA might become subject to additional regulatory oversight that could impede its ability to manage its business.

TVA may lose responsibility for managing the Tennessee River system.

TVA’s management of the Tennessee River system is important to effective operation of the power system.  TVA’s ability to integrate management of the Tennessee River system with power system operations increases power system reliability and reduces costs.  Restrictions on how TVA manages the Tennessee River system could negatively affect its operations.

Congress may take actions that lead to a downgrade of TVA’s credit ratings.

TVA’s current credit ratings are not based solely on its underlying business or financial condition but are based to a large extent on the legislation that defines TVA’s business structure.  Key characteristics of TVA’s business defined by legislation include (1) the TVA Board’s ratemaking authority, (2) the current competitive environment, which is defined by the fence and the anti-cherrypicking provision, and (3) TVA’s status as a corporate agency and instrumentality of the United States.  Accordingly, if Congress takes any action that effectively alters any of these characteristics, TVA’s credit ratings could be downgraded.  Although TVA Bonds are not obligations of the United States, and the United States does not guarantee the payments of principal or interest on Bonds, TVA’s credit ratings could be downgraded if the sovereign credit ratings of the United States are downgraded.

TVA may become subject to additional environmental regulation.

New environmental laws, regulations, and orders may become applicable to TVA or the facilities it operates, and existing environmental regulations may be revised or reinterpreted in a way that adversely affects TVA.  Possible areas of future regulation include, but are not limited to, the following:

Greenhouse gases.  Costs to comply with future regulation of CO2 and other GHGs may reduce TVA’s cash flows and negatively impact TVA’s financial position and results of operations.  The cost impact of legislation or regulation cannot be determined at this time.

Coal combustion products.  The federal government has proposed stronger regulations concerning coal-combustion products, and state governments may impose additional regulations.  These regulations may require TVA to make additional capital expenditures, increase operating and maintenance costs, or even lead it to shut down certain facilities.

Renewable energy portfolio standards.  TVA is not currently obligated to provide a percentage of the power it sells from renewable sources but may be required to do so in the future.  In such a case, depending on the amount required, TVA may have to build or purchase additional facilities that use renewable resources to produce the power itself, purchase renewable power from other companies, or offset some of its renewable requirements through energy efficiency.  Such developments could require TVA to make significant capital expenditures, increase its purchased power costs, or make changes in how it operates its facilities.

Existing laws, regulations, and orders may negatively affect TVA’s cash flows, results of operations, and financial condition, as well as the way TVA conducts its business.

TVA is required to comply with comprehensive and complex laws, regulations, and orders.  The costs of complying with these laws, regulations, and orders are expected to be substantial, and costs could be significantly more than TVA anticipates, especially in the environmental area.  In fact, the cost to install the necessary equipment to comply with existing environmental laws, regulations, and orders at some facilities may render some facilities uneconomical, which may cause TVA to shut down or idle certain facilities.  In addition, TVA is required to obtain numerous permits and approvals from governmental agencies that regulate its business, and TVA may be unable to obtain or maintain all required regulatory approvals.  If there is a delay in obtaining required regulatory approvals or if TVA fails to obtain or maintain any approvals or to comply with any law, regulation, or order, TVA may have to change how it operates certain facilities, may be unable to operate certain facilities, or may have to pay fines or penalties.

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TVA may be responsible for environmental clean-up activities.

TVA may be responsible for on-site liabilities associated with the environmental condition of facilities or property that TVA has acquired or that TVA operates regardless of when the liabilities arose, whether they are known or unknown, and whether they were caused by TVA, prior owners or operators, or a third party.

The costs associated with remediating the Kingston ash spill as well as other coal combustion product facilities may be significantly higher than TVA anticipates.

TVA estimates that the cost of remediating the Kingston ash spill will be between $1.1 billion and $1.2 billion.  Actual costs could substantially exceed expected costs if, among other things, TVA has to remove more ash than currently anticipated, additional environmentally sensitive material is uncovered in the river sediment, there are delays in the ash removal process, or the methods of final remediation change.  Also, certain costs, such as any damages associated with Kingston-related litigation, natural resources damages, and additional penalties, are not included in the current estimate.  In addition, TVA expects to spend between $1.5 billion and $2.0 billion to convert its wet fly ash, bottom ash, and gypsum facilities to dry collection facilities and to remediate or eliminate the coal combustion product facilities that are classified as high risk.  Actual costs may substantially exceed expected costs.

TVA may have to make significant contributions in the future to fund its pension benefit plan.

At September 30, 2010, TVA’s pension plan had assets of $6.8 billion compared to liabilities of $10.4 billion, even after a $1.0 billion contribution by TVA in September 2009.  The ability of the plan’s funded status to improve quickly is limited by the maturity of the plan.  With approximately 23,000 retirees, there are almost twice as many retirees as current employee participants.  As a result, a significant portion of the plan’s assets is required to fund the annual retiree benefits.  The costs of providing pension benefits depend upon a number of factors, including, but not limited to:

•   Provisions of the pension plan;

•   Changing employee demographics;

•   Rates of increase in compensation levels;

•   Rates of return on plan assets;

•   Discount rates used in determining future benefit obligations and required funding levels;

•   Future government regulation; and

•   Level of contributions made to the plan.

Any of these factors or any number of these factors could keep at high levels or even increase the costs of providing pension benefits and require TVA to make significant contributions to the pension plan.  Recent financial market conditions may result in lower expected rates of return on plan assets and lower discount rates used in determining future benefit obligations.  These changes would negatively impact the funded status of the plan.  Additional contributions to the plan and absorption of additional costs would negatively affect TVA’s cash flows, results of operations, and financial condition.

Approaching or reaching TVA’s debt ceiling could limit TVA’s ability to carry out its business.  Additionally, TVA’s debt ceiling could be made more restrictive.

The TVA Act provides that TVA can issue Bonds in an amount not to exceed $30.0 billion outstanding at any time.  At September 30, 2010, TVA had $23.7 billion of Bonds outstanding (not including noncash items of foreign currency exchange loss of $14 million and net discount on sale of Bonds of $216 million).

Approaching or reaching the debt ceiling may adversely affect TVA’s business by limiting TVA’s ability to access capital markets and increasing the amount of debt TVA must service.  Also, Congress may lower TVA’s debt ceiling or broaden the types of financial instruments that are covered by the ceiling.  Either of these scenarios may also restrict TVA’s ability to raise capital to maintain power program assets, to construct additional generation facilities, to purchase power under long-term purchase power agreements, or to meet regulatory requirements.  In addition, approaching or reaching the debt ceiling may lead to increased legislative or regulatory oversight of TVA’s activities and could lead to negative credit rating actions.

Demand for electricity may be significantly reduced, negatively affecting TVA’s cash flows, results of operations, and financial condition.

Some of the factors that could reduce the demand for electricity include the following:

Economic downturns.  Sustained economic downturns in TVA’s service area or other parts of the United States could reduce overall demand for power and thus reduce TVA’s power sales and cash flows, especially as TVA’s industrial customers reduce their operations and thus their consumption of power.

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Loss of customers.  During 2010, two distributor customers terminated their power contracts with TVA.  The loss of additional customers could have a material adverse effect on TVA’s cash flows, results of operations, or financial condition, and could result in higher rates.

Change in technology.  Research and development activities are ongoing to improve existing and alternative technologies to produce electricity, including gas turbines, wind turbines, fuel cells, microturbines, solar cells, and distributed generation devices.  It is possible that advances in these or other alternative technologies could reduce the costs of electricity production from alternative technologies to a level that will enable these technologies to compete effectively with traditional power plants like TVA’s.  To the extent these technologies become a more cost-effective option for certain customers, TVA’s sales to these customers could be reduced, negatively affecting TVA’s cash flows, results of operations, and financial condition.

Catastrophic events may affect TVA’s ability to supply electricity or reduce demand for electricity.

TVA may be adversely affected, directly or indirectly, by catastrophic events such as fires, earthquakes, solar events, droughts, floods, tornadoes, wars, national emergencies, terrorist activities, pandemics, and other similar events.  These events, the frequency and severity of which are unpredictable, may negatively affect TVA’s cash flows, results of operations, and financial condition by, among other things, limiting TVA’s ability to generate and transmit power, reducing the demand for power, disrupting fuel or other supplies, requiring TVA to produce additional tritium, leading to an economic downturn, or creating instability in the financial markets.  Some recent studies have predicted that climate change may cause certain catastrophic events, such as droughts and floods, to occur more frequently in the Tennessee Valley region.

Weather conditions may influence TVA’s ability to supply power and its customers’ demands for power.

Extreme temperatures may increase the demand for power and require TVA to purchase power at high prices to meet the demand from customers, while unusually mild weather may result in decreased demand for power and lead to reduced electricity sales.  In addition, in periods of below normal rainfall or drought, TVA’s low-cost hydroelectric generation may be reduced, requiring TVA to purchase power or use more costly means of producing power.  Furthermore, high river water temperatures in the summer may limit TVA’s ability to use water from the Tennessee or Cumberland River systems for cooling at certain of TVA’s generating facilities, thereby limiting its ability to operate these generating facilities.

TVA may incur delays and additional costs in power plant construction and may be unable to obtain necessary regulatory approval.

TVA is completing the construction of Watts Bar Nuclear Unit 2, planning major upgrades to and modernization of current generating plants, and evaluating construction of more generating facilities in the future.  These activities involve risks of schedule delays and overruns in the cost of labor and materials.  In addition, if TVA does not obtain the necessary regulatory approvals, is otherwise unable to complete the development or construction of a facility, decides to cancel construction of a facility, or incurs delays or cost overruns in connection with constructing a facility, TVA’s cash flows, financial condition, and results of operations could be negatively affected.  In addition, if construction projects are not completed according to specifications, TVA may suffer, among other things, reduced plant efficiency and higher operating costs.

TVA is the sole power provider for its customers within its service area, and if demand for power in TVA’s service area increases, TVA is contractually obligated to take steps to meet this increased demand.

If demand for power in TVA’s service area increases, TVA may need to meet this increased demand by purchasing additional power from other sources, building new generation and transmission facilities, or purchasing existing generation and transmission facilities.  Purchasing power from external sources, as well as acquiring or building new generation and transmission facilities, may negatively affect TVA’s cash flows, results of operations, and financial condition.

Failure to meet TVA’s energy efficiency and demand reduction goals may negatively impact TVA’s cash flows, results of operations, and financial condition.

TVA’s energy efficiency and demand reduction initiatives are important components of TVA’s plan to meet future power needs in its service territory.  It is possible, however, that results from these programs may be less favorable than TVA anticipates.  If TVA fails to meet its energy efficiency and demand reduction goals, TVA may, among other things, need to purchase additional power from third parties or build or purchase additional generation facilities.

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Owning and operating nuclear units may subject TVA to nuclear risks and significant costs that adversely affect its cash flows, results of operations, and financial condition.

TVA has six operating nuclear units and has resumed construction of one nuclear unit that is scheduled to be placed in service in CY 2012.  Risks associated with these units include the following:

Nuclear Risks.  A nuclear incident at a TVA facility could have significant consequences including loss of life, damage to the environment, damage to or loss of the facility, and damage to non-TVA property.  Although TVA carries certain types of nuclear insurance, the amount that TVA is required to pay in connection with a nuclear incident could significantly exceed the amount of coverage provided by insurance.  Also, any nuclear incident, even at a facility that is not operated by or licensed to TVA, has the potential to impact TVA adversely by obligating TVA to pay up to $105 million per year and a total of $671 million per nuclear incident under the Price-Anderson Act.  In addition, a nuclear incident could negatively affect TVA by, among other things, obligating TVA to pay retrospective insurance premiums, reducing the availability and affordability of insurance, increasing the costs of operating nuclear units, or leading to increased regulation or restriction on the construction, operation, and decommissioning of nuclear facilities.  Moreover, Congress could impose revenue-raising measures on the nuclear industry to pay claims exceeding the limit for a single incident under the Price-Anderson Act.

Decommissioning Costs.  TVA maintains a Nuclear Decommissioning Trust (“NDT”) for the purpose of providing funds to decommission its nuclear facilities.  The NDT is invested in securities generally designed to achieve a return in line with overall equity market performance.  The NDT was 94 percent funded as of September 30, 2010.  TVA might have to make unplanned contributions to the trust if, among other things:

•   The value of the investments in the trust declines significantly, as it did during the recent financial crisis, or the investments fail to achieve the assumed real rate of return;

•   The decommissioning funding requirements are changed by law or regulation;

•   The assumed real rate of return on plan assets, which is currently 5 percent, is lowered by the TVA Board or is optimistic;

•   The actual costs of decommissioning are more than planned;

•   Changes in technology and experience related to decommissioning cause decommissioning cost estimates to increase significantly; or

•   TVA is required to decommission a nuclear plant sooner than it anticipates.

If TVA makes additional contributions to the NDT, the contributions may negatively affect TVA’s cash flows, results of operations, and financial condition.

Increased Regulation.  The NRC has broad authority to adopt requirements related to the licensing, operation, and decommissioning of nuclear generation facilities that can result in significant restrictions or requirements on TVA.  If the NRC modifies existing requirements or adopts new requirements, TVA may be required to make substantial capital expenditures at its nuclear plants or make substantial contributions to its NDT.  In addition, if TVA fails to comply with requirements promulgated by the NRC, the NRC has the authority to impose fines, shut down units, or modify, suspend, or revoke TVA’s operating licenses.

TVA’s generation and transmission assets or their supporting infrastructure may not operate as planned.

Many of TVA’s generation and transmission assets have been operating since the 1950s or earlier and have been in nearly constant service since they were completed.  If these assets or their supporting infrastructure fail to operate as planned, TVA, among other things:

•   May have to invest a significant amount of resources to repair or replace the assets or the supporting infrastructure;

•   May be unable to operate the assets for a significant period of time;

•   May have to purchase replacement power on the open market;

•   May not be able to meet its contractual obligations to deliver power;

•   May have to remediate collateral damage caused by a failure of the assets or the supporting infrastructure; and

•   May have to increase its efforts to reduce vegetation intrusions onto transmission lines to comply with applicable regulations.

In addition, the failure of TVA’s generation and transmission assets or their supporting infrastructure to perform as planned may cause health, safety, and environmental problems and may evenresult in events such as the failure of a dam, the failure of a containment pond, or a nuclear incident.  Any of these potential outcomes may negatively affect TVA’s cash flows, results of operations, and financial condition.

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TVA’s information technology assets may not operate as planned.

TVA’s operations are extensively computerized, and a failure of TVA’s information technology assets may significantly disrupt operations.  Among other things, such a failure may negatively impact TVA’s accounting and administrative systems as well as TVA’s ability to generate and transmit power, and may also lead to the loss or inappropriate release of critical data.  Such a failure may be caused by, among other things, a cyber attack, a natural disaster, a solar event, an electromagnetic event, the age and condition of TVA’s information technology assets, and human error.  Any of these occurrences could negatively affect TVA’s cash flows, results of operations, and financial condition.

TVA’s organizational transformation efforts may fail.

Following the Kingston ash spill, the TVA Board directed TVA to develop a plan to improve its control systems, operating standards, and corporate culture.  The failure to make improvements in these areas may contribute to other incidents or challenges that could adversely affect TVA’s cash flow, results of operations, and financial condition as well as TVA’s reputation.  Any deterioration in TVA’s reputation may harm TVA’s relationships with its customers and stakeholders and may potentially lead to the imposition of additional laws and regulations that negatively affect the way TVA conducts its business.

TVA’s service reliability could be affected by problems at other utilities or at TVA facilities or by the increase in intermittent sources of power.

TVA’s transmission facilities are directly interconnected with the transmission facilities of neighboring utilities and are thus part of the larger interstate power transmission grid.  Accordingly, problems at other utilities or at TVA’s facilities may cause interruptions in TVA’s service to its customers.  In addition, the increasing contribution of intermittent sources of power such as wind and solar may place additional strain on TVA’s system as well as on surrounding systems.  If TVA suffers a service interruption, TVA’s cash flows, results of operations, financial condition, and reputation may be negatively affected.

Events which affect the supply of water in the Tennessee River system and Cumberland River system may interfere with TVA’s ability to generate power.

An inadequate supply of water in the Tennessee River system and Cumberland River system could negatively impact TVA’s cash flows, results of operations, and financial condition by reducing generation not only at TVA hydroelectric plants but also at its coal-fired and nuclear plants, which depend on water from the river systems near which they are located for cooling and for use in boilers where water is converted into steam to drive turbines.  An inadequate supply of water could result, among other things, from periods of low rainfall or drought, the withdrawal of water from the river systems by governmental entities, and incidents affecting bodies of water not managed by TVA.  While TVA manages the Tennessee River and large portions of its tributary system in order to provide much of the water necessary for the operation of its power plants, the U.S. Army Corps of Engineers operates and manages other bodies of water upon which some TVA facilities rely.  Events at these non-TVA managed bodies of water or their associated hydroelectric facilities may interfere with the flow of water and may result in TVA’s having insufficient water to meet the needs of its plants.  If TVA has insufficient water to meet the needs of its plants, TVA may be required to reduce generation at its affected facilities to levels compatible with the available supply of water.

TVA’s fuel and purchased power supplies may be disrupted.

TVA purchases coal, uranium, natural gas, fuel oil, and electricity from a number of suppliers.  Disruption in the acquisition or delivery of fuel or purchased power may result from a variety of physical and commercial events, political developments, or environmental regulations affecting TVA’s fuel and purchased power suppliers as well as from transportation or transmission constraints.  If one of TVA’s fuel or purchased power suppliers fails to perform under the terms of its contract with TVA, TVA might have to purchase replacement fuel or power, perhaps at a significantly higher price than TVA was entitled to pay under the contract.  In some circumstances, TVA may not be able to recover this difference from the supplier.  In addition, any disruption of TVA’s fuel and purchased power supplies could require TVA to operate higher cost plants, thereby adversely affecting TVA’s cash flows, results of operations, and financial condition.  Moreover, if TVA is unable to acquire enough replacement power or fuel and does not have enough reserve generation capacity available to offset the loss of power or fuel, TVA may not be able to supply enough power to meet demand, resulting in power curtailments, brownouts, or even blackouts.

Failure to attract and retain an appropriately qualified workforce may negatively affect TVA’s results of operations.

TVA’s business depends on its ability to recruit and retain key executive officers as well as skilled professional and technical employees.  The inability to attract and retain an appropriately qualified workforce could adversely affect TVA’s ability to, among other things, operate and maintain generation and transmission facilities, complete large

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construction projects such as Watts Bar Nuclear Unit 2, and successfully implement its organizational transformation efforts.

TVA is involved in various legal and administrative proceedings whose outcomes may affect TVA’s finances and operations.

TVA is involved in various legal and administrative proceedings and is likely to become involved in other legal proceedings in the future in the ordinary course of business, as a result of catastrophic events or otherwise.  Although TVA cannot predict the outcome of the individual matters in which TVA is involved or will become involved, the resolution of these matters could require TVA to make expenditures in excess of established reserves and in amounts that could have a material adverse effect on TVA’s cash flows, results of operations, and financial condition.  Similarly, resolution of any such proceedings may require TVA to change its business practices or procedures and may require TVA to reduce emissions from its coal-fired units, including emissions of GHGs, to a greater extent than TVA had planned.

TVA is subject to a variety of market risks that may negatively affect TVA’s cash flows, results of operations, and financial condition.

TVA is subject to a variety of market risks, including, but not limited to, commodity price risk, investment price risk, interest rate risk, counterparty credit and performance risk, and currency exchange rate risk.

Commodity Price Risk.  Prices of commodities critical to TVA’s operations, including coal, uranium, natural gas, fuel oil, crude oil, construction materials, emission allowances, and electricity, have been extremely volatile in recent years.  If prices of these commodities increase, TVA’s rates may increase.

Investment Price Risk.  TVA is exposed to investment price risk in its NDT, its Asset Retirement Trust (“ART”), and its pension fund.  If the value of the investments held in the NDT or the pension fund either decrease or fail to increase in accordance with assumed rates of return, TVA may be required to make substantial contributions to these funds.

Interest Rate Risk.  Changes in interest rates may increase the amount of interest that TVA pays on new Bonds that it issues, decrease the return that TVA receives on its short-term investments, decrease the value of the investments in TVA’s pension fund and trusts, and increase the losses on the mark-to-market valuation of certain derivative transactions into which TVA has entered.

Counterparty Credit and Performance Risk.  TVA is exposed to the risk that its counterparties will not be able to perform their contractual obligations.  If TVA’s counterparties fail to perform their obligations, TVA’s cash flows, results of operations, and financial condition may be adversely affected.  In addition, the failure of a counterparty to perform may make it difficult for TVA to perform its obligations, particularly if the counterparty is a supplier of electricity or fuel.

Currency Exchange Rate Risk.  Over the next several years, TVA plans to spend a significant amount of capital on clean air projects, capacity expansion, and other projects.  A portion of this amount may be spent on contracts that are denominated in one or more foreign currencies.  The value of the U.S. dollar compared with other currencies has fluctuated widely in recent years, and, if not effectively managed, foreign currency exposure could negatively impact TVA’s cash flows, results of operations, and financial condition.

TVA’s ability to use derivatives to hedge certain risks may be limited.

TVA currently uses derivatives to hedge a variety of risks.  Depending on how regulatory agencies interpret and implement the provisions of the Dodd-Frank Wall Street Reform 

           and Consumer Protection Act, TVA’s hedging costs may increase and its ability to use derivatives to hedge certain risks may be limited.  These occurrences may, among other

           things, cause TVA to change its operations, increase the risks to which TVA is exposed, and negatively affect TVA’s cash flows.

TVA may be unable to meet its current cash requirements if TVA’s access to the debt markets is limited.

TVA uses cash provided by operations together with proceeds from power program financings to fund its current cash requirements.  It is critical that TVA continues to have access to the debt markets in order to meet its cash requirements.  The importance of having access to the debt markets is underscored by the fact that TVA, unlike many utilities, relies almost entirely on debt capital since TVA is not authorized to issue equity securities.

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TVA, together with owners of TVA securities, may be impacted by a downgrade of TVA’s credit ratings.

A downgrade of TVA’s credit ratings may have material adverse effects on TVA’s cash flows, results of operations, and financial condition as well as on investors in TVA securities.  Among other things, a downgrade may have the following effects:

•   A downgrade would increase TVA’s interest expense by increasing the interest rates that TVA pays on new Bonds that it issues.  An increase in TVA’s interest expense may reduce the amount of cash available for other purposes, which may result in the need to increase borrowings, to reduce other expenses or capital investments, or to increase power rates.

•   A downgrade may result in TVA’s having to post collateral under certain physical and financial contracts that contain rating triggers.

•   A downgrade below a contractual threshold may prevent TVA from borrowing under two credit facilities totaling $2.0 billion.

•   A downgrade may lower the price of TVA’s securities in the secondary market.

TVA’s financial control system cannot guarantee that all control issues and instances of fraud or errors will be detected.

No financial control system, no matter how well designed and operated, can provide absolute assurance that the objectives of the control system are met, and no evaluation of financial controls can provide absolute assurance that all control issues and instances of fraud or errors can be detected.  The design of any system of financial controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions, regardless of how remote.

Payment of principal and interest on TVA securities is not guaranteed by the United States.

Although TVA is a corporate agency and instrumentality of the United States government, TVA securities are not backed by the full faith and credit of the United States.  If TVA were to experience extreme financial difficulty and were unable to make payments of principal or interest on its Bonds, the federal government would not be legally obligated to prevent TVA from defaulting on its obligations.  Principal and interest on TVA securities are payable solely from TVA’s net power proceeds.  Net power proceeds are the remainder of TVA’s gross power revenues after deducting the costs of operating, maintaining, and administering its power properties and payments to states and counties in lieu of taxes, but before deducting depreciation accruals or other charges representing the amortization of capital expenditures, plus the net proceeds from the sale or other disposition of any power facility or interest therein.

The market for TVA’s securities might be limited.

All of TVA’s Bonds are listed on the New York Stock Exchange except for TVA’s discount notes, which have maturities of less than one year, the 2009 Series A and B power bonds, and the power bonds issued under TVA’s electronotes® program, which is TVA’s medium-term retail notes program.  In addition, some of TVA’s Bonds are listed on foreign stock exchanges.

Although many of TVA’s Bonds are listed on stock exchanges, there can be no assurances that any market will develop or continue to exist for any Bonds.  Additionally, no assurances can be made as to the ability of the holders to sell their Bonds or as to the price at which holders will be able to sell their Bonds.  Future trading prices of Bonds will depend on many factors, including prevailing interest rates, the then-current ratings assigned to the Bonds, the amount of Bonds outstanding, the time remaining until the maturity of the Bonds, the redemption features of the Bonds, the market for similar securities, and the level, direction, and volatility of interest rates generally, as well as the liquidity of the market for those securities.

If a particular series of Bonds is offered through underwriters, those underwriters may attempt to make a market in the Bonds.  Dealers other than underwriters may also make a market in TVA securities.  However, the underwriters and dealers are not obligated to make a market in any TVA securities and may terminate any market-making activities at any time without notice.

In addition, legal limitations may affect the ability of banks and others to invest in Bonds.  For example, national banks may purchase TVA Bonds for their own accounts in an amount not to exceed 10 percent of unimpaired capital and surplus.  Also, TVA Bonds are “obligations of a corporation which is an instrumentality of the United States” within the meaning of section 7701(a)(19)(C)(ii) of the Internal Revenue Code for purposes of the 60 percent of assets limitation applicable to U.S. building and loan associations.

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ITEM 1B.  UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2.  PROPERTIES

TVA holds personal property in its own name but holds real property as agent for the United States of America.  TVA may acquire real property as an agent of the United States by negotiated purchase or by eminent domain.

Generating Properties

At September 30, 2010, generating assets operated by TVA consisted of 58 active coal-fired units and one idled coal-fired unit, six nuclear units, 109 conventional hydroelectric units, four pumped storage units, 87 simple-cycle combustion turbine units, seven combined cycle units, nine diesel generator units, one digester gas site, one wind energy site, and 14 solar energy sites.  Two additional coal-fired units were idled during October 2010.  See Item 1, Business — Current Power Supply – Net Capability for a chart that indicates the location, capability, and in-service dates for each of these properties, which chart is incorporated into this Item 2, Properties.  As of September 30, 2010, 24 of the simple-cycle combustion turbine units were leased by private entities and leased back to TVA under long-term leases, and TVA is leasing the three Caledonia combined cycle units under a long-term lease.  In addition, as of September 30, 2010, SSSL owned an undivided 90 percent interest in the three Southaven combined cycle units, and TVA has entered into a lease with SSSL under which TVA leases SSSL’s undivided 90 percent interest in the facility and operates the entire facility through April 23, 2013.  For additional details, see Note 12.  TVA is also in the process of constructing additional generating assets.  For a discussion of these assets, see Item 1, Business — Integrated Resource Plan and Future Power Supply.

Transmission Properties

TVA’s transmission system interconnects with systems of surrounding utilities and consists primarily of the following assets:

• Approximately 15,940 circuit miles of transmission lines (primarily 500 kilovolt and 161 kilovolt lines);

• 498 transmission substations, power switchyards, and switching stations; and

• 1,240 customer connection points (customer, generation, and interconnection).

As of September 30, 2010, certain qualified technological equipment and other software related to TVA’s transmission system was leased by private entities and leased back to TVA under long-term leases.

Natural Resource Stewardship Properties

TVA operates and maintains 49 dams and manages the following natural resource stewardship properties:

• Approximately 11,000 miles of reservoir shoreline;

• Approximately 293,000 acres of reservoir land;

• Approximately 650,000 surface acres of water; and

• Over 100 public recreation facilities.

As part of its stewardship responsibilities, TVA approval is required to be obtained before any obstruction affecting navigation, flood control, or public lands can be constructed in or along the Tennessee River and its tributaries.

Buildings

TVA has a variety of buildings throughout its service area in addition to the buildings located at its generation and transmission facilities, including office buildings, customer service centers, power service centers, warehouses, visitor centers, and crew quarters.  The most significant of these buildings is the Knoxville Office Complex.  TVA also leases buildings, including its Chattanooga Office Complex, which consists of approximately 1.2 million square feet of office space.  The initial term of TVA's lease of approximately 1.05 million square feet of the Chattanooga Office Complex expires on January 1, 2011.  On February 8, 2008, TVA finalized an agreement to purchase this portion of the Chattanooga Office Complex upon the expiration of the existing lease term on January 1, 2011.  The lease on the Monteagle Place, the remaining portion of the Chattanooga Office Complex (approximately 131,979 square feet), expires on September 30, 2012.  On May 18, 2009, TVA finalized a purchase agreement for the Monteagle Place portion of the Chattanooga Office Complex with closing to occur October 1, 2012, upon the expiration of the existing lease term.  TVA also has a significant number of buildings in Muscle Shoals, Alabama, and is currently evaluating strategies for long-term solutions to further reduce its Muscle Shoals portfolio.

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Disposal of Property

Under the TVA Act, TVA has broad authority to dispose of personal property but only limited authority to dispose of real property.  TVA’s primary sources of authority to dispose of real property are briefly described below:

• Under section 31 of the TVA Act, TVA has authority to dispose of surplus real property at a public auction.

• Under section 4(k) of the TVA Act, TVA can dispose of real property for certain specified purposes, including providing replacement lands for certain entities whose lands were flooded or destroyed by dam or reservoir construction and to grant easements and rights-of-way upon which are located transmission or distribution lines.

• Under section 15d(g) of the TVA Act, TVA can dispose of real property in connection with the construction of generating plants or other facilities under certain circumstances.

• Under 40 U.S.C. § 1314, TVA has authority to grant easements for rights-of-way and other purposes.

In addition, the Basic Tennessee Valley Authority Power Bond Resolution adopted by the TVA Board on October 6, 1960, as amended on September 28, 1976, October 17, 1989, and March 25, 1992, prohibits TVA from mortgaging any part of its power properties and from disposing of all or any substantial portion of these properties unless TVA provides for a continuance of the interest, principal, and sinking fund payments due and to become due on all outstanding Bonds, or for the retirement of such Bonds.

ITEM 3.  LEGAL PROCEEDINGS

From time to time, TVA is party to or otherwise involved in lawsuits, claims, proceedings, investigations, and other legal matters (“Legal Proceedings”) that have arisen in the ordinary course of conducting TVA’s activities, as a result of catastrophic events or otherwise.  While the outcome of the Legal Proceedings to which TVA is a party cannot be predicted with certainty, any adverse outcome to a Legal Proceeding involving TVA may have a material adverse effect on TVA’s cash flows, results of operations, and financial condition.

For a discussion of Legal Proceedings involving TVA, see Note 20 — Legal Proceedings, which discussion is incorporated into this Item 3 by reference.

ITEM 4.  RESERVED

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PART II

ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Not applicable.

ITEM 6.  SELECTED FINANCIAL DATA

The following selected financial data for the years 2006 through 2010 should be read in conjunction with the audited financial statements and notes thereto (collectively, the “Financial Statements”) presented in Item 8, Financial Statements and Supplementary Data.  Certain reclassifications have been made to the 2006, 2007, 2008, and 2009 financial statement presentation to conform to the 2010 presentation.

Selected Financial Data(1), (2) For the years ended, or as of, September 30 (dollars in millions)
	2010		2009		2008		2007		2006
Sales (millions of kWh)		173,662		163,804		176,304		175,529		171,651
Peak Load (MW)		31,778		32,572		32,027		30,320		27,718
Operating revenues(3)	$	10,874	$	11,255	$	10,382	$	9,326	$	8,983
Fuel and purchased power	$	3,219	$	4,745	$	4,176	$	3,449	$	3,342
Operating and maintenance	$	3,232	$	2,395	$	2,307	$	2,353	$	2,328
Net interest expense	$	1,294	$	1,272	$	1,376	$	1,232	$	1,264
Net income	$	972	$	726	$	817	$	423	$	113
Construction expenditures	$	2,015	$	1,793	$	1,984	$	1,379	$	1,370
Total assets	$	42,753	$	40,017	$	37,137	$	33,732	$	34,308
Financial Obligations
Net long-term statutory debt, excluding  current maturities	$	22,389	$	21,788	$	20,404	$	21,099	$	19,544
Discount notes		27		844		185		1,422		2,376
Current maturities of long-term debt, net		1,008		8		2,030		90		985
Total short-term statutory debt		1,035		852		2,215		1,512		3,361
Total statutory debit(4)	$	23,424	$	22,640	$	22,619	$	22,611	$	22,905
Capital leases(5)	$	47	$	77	$	95	$	104	$	128
Leaseback obligations	$	1,353	$	1,403	$	1,353	$	1,072	$	1,108
Energy prepayment obligations	$	822	$	927	$	1,033	$	1,138	$	1,244
Notes (1) See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations for a description of special items in 2010, 2009, and 2008 affecting results in those years. In addition, during 2006, TVA adopted a new accounting methodology for conditional asset retirement obligations that resulted in a cumulative effect charge to income of $109 million and an increase in accumulated depreciation of $20 million. (2) See Item 1A, Risk Factors and Note 20 for a discussion of risks and contingencies that could affect TVA’s future financial results. (3) Prior to 2007, TVA reported certain revenue not directly associated with revenue derived from electric operations as Operating revenues. This income of $10 million for 2006 has been reclassified from Operating revenues to Other income. (4)  Statutory debt is debt subject to the $30.0 billion limit on bonds, notes, and other evidences of indebtedness as defined in the TVA Act of 1933, as amended. (5) Included in Accrued liabilities and Other liabilities on the balance sheets.

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ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Dollars in millions except where noted)

Business Overview

TVA operates the nation’s largest public power system. At September 30, 2010, TVA provided electricity to 50 large industrial customers, six federal customers, and 155 distributor customers that serve over nine million people in parts of seven southeastern states.  TVA generates almost all of its revenues from the sale of electricity, and in 2010 revenues from the sale of electricity totaled $10.7 billion.  As a wholly-owned agency and instrumentality of the United States, however, TVA differs from other electric utilities in a number of ways:

(1)   TVA is a government corporation.

(2)   The area in which TVA sells power is limited by the TVA Act under a provision known as the “fence”; however, another provision of federal law known as the “anti-cherrypicking” provision generally protects TVA from being forced to provide access to its transmission lines to others for the purpose of delivering power to customers within substantially all of TVA’s defined service area.

(3)   Unlike other utilities, the rates TVA charges for power are not set or reviewed by another entity, such as a public utility commission.  TVA's rates are set solely by the TVA Board.  In setting rates, however, the TVA Board is charged by the TVA Act to have due regard for the primary objectives of the TVA Act, including the objective that power be sold at rates as low as feasible.

(4)   TVA, unlike investor-owned power companies, is not authorized to raise capital by issuing equity securities.  TVA relies primarily on cash from operations and proceeds from power program borrowings to fund its operations and is authorized by the TVA Act to issue bonds, notes, and other evidences of indebtedness (“Bonds”) in an amount not to exceed $30.0 billion outstanding at any given time.  Although TVA’s operations were originally funded primarily with appropriations from Congress, TVA has not received any appropriations from Congress for any activities since 1999 and, as directed by Congress, has funded essential stewardship activities primarily with power revenues.

Executive Summary

The economic weakness in the TVA service area showed some signs of easing during 2010 with improving regional economic conditions.  Power sales increased six percent in 2010 from 2009.  Colder than normal winter weather and hotter than normal summer weather were responsible for most of the increase.

2010 revenues from the sale of electricity totaled $10.7 billion.  Despite the increase in sales, revenues decreased over three percent in 2010 compared to 2009, primarily due to a $1.7 billion reduction in FCA revenue.  This lower FCA revenue resulted from an overall decrease in the FCA rate in 2010 and the liquidation of $822 million in FCA overcollections in prior periods as a result of market prices for fuel-related commodities being lower than forecasted.  This decrease in FCA revenue was partially offset by a base rate increase of nine percent that became effective on October 1, 2009, and resulted in additional revenue of $707 million.

Beginning with the October 1, 2009 billing period, the FCA formula changed from a quarterly to a monthly basis.  This change to a monthly FCA formula has resulted in smaller reconciliations and faster liquidation of any balances. 

Operating expenses decreased over seven percent in 2010 compared to 2009 due primarily to a 32 percent reduction in fuel and purchased power costs, partially offset by a nearly 35 percent increase in operating and maintenance costs.

2010 Highlights

 2010 was marked by a favorable ruling in the lawsuit brought by the State of North Carolina that alleged emissions from the operations of certain of TVA’s coal-fired power plants constituted a public nuisance.  The initial court decision ordering the installation of certain emission controls on four coal-fired plants presented significant financial challenges for TVA.  With the decision overturned on appeal and the case dismissed, TVA believes it will be better positioned to assess the options it has with respect to coal-fired plant emissions as well as the amounts and timing of related capital expenditures.

Other positive business developments in 2010 included:

•   TVA received a favorable court ruling related to its alleged violation of the New Source Review regulations at its Bull Run Fossil Plant (“Bull Run”).

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•   TVA completed the installation of scrubbers at the Kingston Fossil Plant ("Kingston").

•   TVA executed an agreement with a leading provider of clean and intelligent energy management applications and services for a demand response program that is expected to provide up to 560 MW of peak load reduction.

•   TVA entered into seven contracts for the purchase of up to 1,380 MW of wind energy.  An agreement to purchase an additional 200 MW of wind energy was executed on October 7, 2010.

•   For the eleventh straight year, TVA’s transmission system operated with 99.999 percent reliability in delivering electricity to customers.

•   The Lagoon Creek Combined Cycle Facility, which has a summer net capability of approximately 550 MW, began commercial operation on September 28, 2010.

•   TVA completed a major 500-kilovolt transmission project in May 2010 as well as upgrades to a 500-kV substation undertaken as a result of growth in demand in middle Tennessee.

•   TVA experienced improvements in safety and performed in the top decile in the utility industry.

•   Browns Ferry Nuclear Plant (“Browns Ferry”) Unit 1 completed a 586 day run from March 15, 2009 to October 23, 2010, during which it produced over 14,583 GWh of electricity.

•   TVA’s economic development efforts helped recruitment and/or expansion of over 150 companies into the TVA service area.  These companies announced capital investments of over $4.3 billion and the expected creation and/or retention of over 40,500 jobs.  In addition, Toyota resumed construction of its new plant in Mississippi during 2010.

2010 Challenges

TVA faced several challenges during 2010 that impacted its operations and financial conditions, including those discussed below.

Weather Extremes

The TVA service area experienced a colder than normal winter and a hotter than normal summer in 2010.  This weather was a primary reason for TVA selling six percent more electricity in 2010 than in 2009.  TVA met the increased demand by using some of its higher-cost facilities and by buying more power in the market.

The hot summer, however, also resulted in TVA having to curtail the use of some of its generating facilities.  The summer heat increased the temperatures of the water in the Cumberland and Tennessee Rivers.  There were 68 days during the summer when TVA had to curtail generation at some of its coal-fired units because of water temperature.  TVA estimates the amount of generation lost was about 540 GWh.  Similarly, there were 56 days during the summer when TVA had to curtail generation at some of its nuclear units, primarily Browns Ferry, because of water temperature.  TVA estimates the amount of lost nuclear generation at nearly 1,000 GWh.

The increased purchased power and fuel-related costs associated with the cold winter, the hot summer, and the curtailment of generation because of water temperature issues were reflected in TVA’s rates through the FCA.  The 6.4 percent FCA increase effective for October 2010 was due in large part to the excessively high temperatures in August that limited TVA's power generation capabilities and increased power demand by eight percent, compared to forecasts, resulting in actual fuel costs exceeding the forecast fuel costs that were used to develop the August FCA rate.  The resulting under-recovered fuel cost will be collected through subsequent FCA calculations.

To better address the water temperature issues at Browns Ferry, TVA has initiated a capital project to construct a new cooling tower, to upgrade four of the existing cooling towers, and to improve the support systems for the plant’s cooling towers.  The project is expected to be completed in three phases.  TVA anticipates having a new cooling tower constructed before the summer of 2011 and having the improved support systems and upgrades in place by the summer of 2013.

Kingston Ash Spill

TVA continues cleanup and recovery efforts related to the Kingston ash spill in conjunction with federal and state agencies.  TVA completed the removal of time-critical ash from the Emory River during the third quarter of 2010.  Removal of the remaining ash is considered to be non-time-critical.  Once the removal actions are completed, TVA will be required

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to assess the site and determine whether any additional actions may be needed at Kingston or the surrounding impacted area.  This assessment and any additional activities found to be necessary are considered remedial actions.

TVA has recorded an estimate in the amount of $1.1 billion for the cost of cleanup related to this event.  TVA originally charged $933 million of this amount in 2009 to expense.  However, the TVA Board reclassified the $933 million as a regulatory asset during the fourth quarter of 2009, and the amount is being charged to expense as it is collected in rates over 15 years, which began on October 1, 2009.  Any changes to this estimate are also being deferred and charged to expense prospectively as costs are collected in future rates.

During 2010, TVA increased the estimate for the cost of cleanup related to this event by $192 million.  The change in estimate was due to increased scope of work to be performed at the site as defined in the Engineering Evaluation Cost Analysis (“EE/CA”) work order plan which was prepared in accordance with the EPA’s Guidance on Conducting Non-Time-Critical Removal Actions under CERCLA.  In May 2010, the EPA approved TVA’s ash disposal plan, which clarified the amount of ash to be removed from the site and the final design and closure of the dredge cell and ash ponds on site.  The plan involves moving less ash offsite than was originally assumed, which resulted in potential cost savings from the original estimate.  These potential savings were more than offset, however, by the estimated costs of other elements of the plan, including the required expansion of the failed cell and the closure and capping of all cells on the plant site that hold wet ash.  The potential savings are also offset by costs of handling the ash under CERCLA requirements, penalties assessed by TDEC as described below, and regulatory oversight costs.  TVA has also found that certain previously estimated costs, such as dredging, were more expensive than originally estimated due to more equipment and staffing being needed to ensure timely completion of removal of time critical ash from the river.  Final designs of holding cells and dikes are more robust than originally estimated as well.

As work continues to progress and more information is available, TVA will review its estimates and revise them as appropriate.  TVA currently estimates the recovery process will be substantially completed in 2014 although monitoring may continue beyond that date.  As such, TVA has accrued a portion of the estimated cost in current liabilities, with the remaining portion accrued as a long-term liability on TVA’s balance sheets.  Costs incurred since the event through September 30, 2010, totaled $600 million with a remaining estimated liability of $525 million.

Because of the uncertainty at this time of the final costs to complete the work prescribed by the ash disposal plan, a range of reasonable estimates has been developed by cost category and either the known amounts, most likely scenarios, or low end of the range for each category has been accumulated and evaluated to determine the total estimate.  The range of estimated costs varies from approximately $1.1 billion to approximately $1.2 billion.  See Note 8.

TVA has not included the following categories of costs in the above estimate since it has determined that these costs are currently either not probable or not reasonably estimable:  penalties (other than the penalties set out in the TDEC order), regulatory directives, natural resources damages, outcomes of lawsuits, future claims, long-term environmental impact costs, final long-term disposition of ash processing area, costs associated with new laws and regulations, or costs of remediating any mixed waste discovered during ash removal process.  There are certain other costs that will be incurred that have not been included in the estimate as they are appropriately accounted for in other areas of the financial statements.  Associated capital asset purchases are recorded in property, plant, and equipment.  Ash handling and disposition from current plant operations are recorded in operating expenses.  A portion of the pond and dredge cell closure costs are also not included in the estimate as those costs are included in the non-nuclear asset retirement obligation liability.

On June 14, 2010, TDEC issued a civil penalty order of approximately $12 million to TVA for the Kingston ash spill, citing violations of the Tennessee Solid Waste Disposal Act and the Tennessee Water Quality Control Act.  Of the $12 million, TVA has already satisfied $6 million of the obligation and may also be credited up to $2 million for performing environmental projects approved by TDEC.  The remaining obligation will be paid in installments through July 2012.

Coal Combustion Product Facilities

TVA retained an independent third-party engineering firm to perform a multi-phased evaluation of the overall stability and safety of all existing embankments associated with TVA’s wet coal combustion product (“CCP”) facilities.  The first phase of the evaluation, which is finished, involved a detailed inspection of all wet CCP facilities, detailed documentation reviews, and a determination of any immediate actions necessary to reduce risks.  The second phase of the program, which is also complete, included geotechnical explorations, material testing, stability analyses, and studies.  The study showed that none of TVA’s other coal-fired plants showed the same set of conditions that existed at Kingston at the time of the spill and that the ongoing remediation work being done at the plants should bring all of them within industry standards in terms of stability.  The third phase of the program, which is implementation of recommended actions, is ongoing.  This phase includes risk mitigation steps such as performance monitoring, designing and completing repairs, developing planning documents, obtaining permits, and generally implementing the lessons learned from the Kingston ash spill at TVA’s other CCP facilities.  As a part of this effort, an ongoing dam oversight program has been undertaken, and TVA employees have received additional training in dam safety and monitoring.

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TVA is converting its wet fly ash, bottom ash, and gypsum facilities to dry collection facilities and remediating or eliminating the CCP facilities that were classified as “high” risk during the preliminary reassessment.  The classifications, such as “high,” do not measure the structural integrity of the facility or the possibility of whether a failure could occur.  Rather, they are designed to identify where loss of life or significant economic or environmental damage could occur in the event of a failure.  The expected cost of the CCP work is between $1.5 billion and $2.0 billion, and the work is expected to take between eight and 10 years to complete.

Investment Funds

Nuclear Decommissioning Trust Fund.  The nuclear decommissioning trust (“NDT”) portfolio increased in value by $104 million in 2010 and as of September 30, 2010, the NDT was 94 percent funded.  TVA submitted an NDT funding assurance plan to the Nuclear Regulatory Commission (“NRC”) during 2009 utilizing the external sinking fund method as described in the NRC’s regulations.  The plan is based on estimated positive long-term investment performance above an anticipated increase in the decommissioning liability over the remaining lives of TVA’s nuclear units.  The funding assurance plan provides mechanisms to address this shortfall under a schedule with the goal of ensuring sufficient funds are available when the nuclear plants are eventually decommissioned.

Pension Fund.  While financial markets improved in 2010, the pension plan remains underfunded.  Net assets in the plan at September 30, 2010 were approximately $6.8 billion and obligations were approximately $10.4 billion for a net underfunded status of $3.6 billion at September 30, 2010.  The ability of the plan’s funded status to quickly improve is limited because the pension plan pays a significant amount of benefits each year to plan beneficiaries.  The plan currently has nearly 23,000 retirees receiving benefits of approximately $600 million per year.

TVARS’s investment policies are based on the objective of meeting long-term obligations, and the allocation of investments is based on the assumption of encountering distressed market conditions from time to time.  TVARS does not anticipate making significant changes in its basic investment policies as a result of recent market conditions.  See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations — Risk Management Activities — Investment Price Risk and Note 18 — Plan Investments.

Future Challenges

Many of the challenges that TVA faced in 2010 will continue to be challenges in the future, including those related to the Kingston ash spill, TVA’s coal-combustion facilities, and TVA’s NDT and pension plan.  In addition, TVA will face the challenges discussed below in the future.

Wholesale Rate Changes and Rate Adjustments

TVA has been discussing with its distributor customers and directly served customers a move from TVA’s current rate structure to a new wholesale rate structure, which includes seasonal and time-of-use rates.  The objectives of the rate change are four-fold:  to provide the proper price signals; to encourage demand response, energy efficiency, and smart grid technology; to provide customers with opportunities to save on energy costs; and to keep bills as low as feasible.  The new wholesale rate structure was approved by the TVA Board in August 2010 to be effective in April 2011.  During the discussions, however, several customers indicated they would like the rates to be effective before that time, so TVA is offering optional rates for large directly served and distributor-served customers from October 2010 to March 2011.  See Item 1, Business — Rates.

The new wholesale base rates are designed to be revenue neutral to TVA, so this change in structure will not materially impact TVA’s annual revenue recovery but will more closely align TVA’s revenue with its costs.  There will, however, be some seasonal structural changes that may impact the timing of the revenue between seasons.  The TVA Board did not approve a base rate increase for 2011.  Because 2011 will not be impacted by the $822 million FCA liquidation that occurred in the first nine months of 2010, TVA anticipates a ten percent increase in revenues in 2011 over 2010, or an estimated $1.0 billion, if weather conditions are normal.

In addition to the wholesale rate structure change, TVA revised its FCA formula in October 2010 to more accurately adjust for seasonal fuel costs within the FCA formula.

Capital Investments

TVA also faces large capital requirements to maintain its power system infrastructure and invest in new power assets, including cleaner energy sources.  TVA believes it is likely that laws or regulations will come into effect in the near future that will require electric utilities to reduce greenhouse gas (“GHG”) emissions or obtain emission allowance permits under a cap and trade program, and obtain a specified portion of their power supply from renewable resources.  Due to the age, lower capacity, and lower efficiency of TVA’s older coal-fired units, it may not be economical to continue to operate some plants in the future, particularly if new environmental laws or regulations are passed.  TVA is also planning to end the

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wet storage of fly ash and gypsum at its coal-fired plants, an effort that will involve significant investment.   See Item 1, Business — Integrated Resource Plan and Future Power Supply.

Environmental Regulation

TVA anticipates that clean air regulations will eventually require all coal-fired units to install air quality controls, including scrubbers and selective catalytic reduction systems (“SCRs”) for sulfur dioxide (“SO2”), nitrogen oxides (“NOx”), and mercury control.  TVA also expects that legislation or regulations will eventually require it to reduce carbon dioxide (“CO2”) emissions or purchase CO2 allowances. Furthermore, TVA believes it is likely that new laws or regulations will come into effect in the future that will require electric utilities to obtain a specified portion of their power supply from renewable resources. The cost of compliance with any such laws and regulations is currently unknown but compliance could require significant expenditures by TVA. TVA would have to recover such costs in rates or pursue some other action which, among other options, might include idling additional coal-fired units.  See Item 1, Business — Integrated Resource Plan and Future Power Supply.

Coal-Fired Generation

       Future environmental regulations could result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and financing requirements.  TVA currently has approximately 14,000 MW of coal-fired generation.  Approximately 6,800 MW of this capacity are from units that do not have scrubbers or, in some cases, other emission controls.  Although TVA uses scrubbers on its largest generating units and low sulfur coal on other units to remove SO2, and SCRs and other controls to reduce NOx emissions, several of TVA’s older coal-fired plants do not have clean air controls, and their lower efficiency leads to higher CO2 emission rates.  Some of these less efficient units have been less economical to use in recent periods.  Due to the age, lower capacity, and lower efficiency of some units, it may not be economical to install new clean air controls; accordingly, TVA may choose to retire some coal-fired units.  In response to these anticipated emissions-reduction requirements, TVA plans to place certain fossil assets in long-term idle status and/or expedite existing plans for placing fossil assets in long-term idle status. These changes have been incorporated into the IRP used as the base case for the need for power analysis.  In September 2010, TVA idled Unit 5 at Widows Creek Fossil Plant (“Widows Creek”) and idled Widows Creek Unit 2 and Unit 10 at Shawnee Fossil Plant in October 2010.  These units account for approximately 350 MW of capacity.  TVA may make decisions about other units in the near future.

 Integrated Resource Plan

Despite the current economic conditions which are leading towards lower energy demand in the short-term, TVA believes that new generation sources will be needed to meet load growth under most likely scenarios.  Additionally, TVA intends to move toward more generation with low or no emissions.  TVA has considered, and intends to continue considering, fuel mix in making decisions about additional generation.  The restart of Browns Ferry Unit 1, the decision to complete Unit 2 of Watts Bar Nuclear Plant (“Watts Bar”), the filing of a Combined Construction and Operating License Application for two new units at the Bellefonte Nuclear Plant (“Bellefonte”), and the reactivation of the construction permits for existing Bellefonte units are examples of TVA’s activities to pursue or consider generation sources that do not emit GHGs and mercury.  This requires capital investment in the current year and over the next few years.  Another challenge in this area is that TVA must have sufficient generation capacity to meet peak demands.  TVA is exploring alternatives to reduce or shift the peak demands of energy.

On June 15, 2009, TVA began the preparation of a new Integrated Resource Plan (“IRP”) the purpose of which is to analyze alternative ways of addressing the Tennessee Valley's electricity needs for the next 20 years.  The alternative portfolios developed for this effort will be evaluated using several criteria including capital and fuel costs, reliability, possible environmental impacts including climate change, compliance with existing and anticipated future regulations, and other factors.  Of the five alternative portfolios developed, TVA’s more favored option includes annual EEDR reductions of 3,600 MW and 11,400 GWh by 2020, renewables additions of 2,500 MW and 9,600 GWh by 2020, 3,000 MW of coal plant idling by 2017, and a pumped storage unit. Nuclear, coal, and gas-fired plants are options to meet demand. The primary source of new generation to meet future electricity needs is nuclear and gas-fired capacity. Transmission upgrades would be necessary to support new renewable, gas, nuclear and coal-fired capacity, and TVA could also participate in interregional projects to transmit renewable energy. TVA expects to issue a final IRP in early CY 2011.

Debt Ceiling

The TVA Act specifies that TVA’s Bonds may not exceed $30.0 billion outstanding at one time.  As of September 30, 2010, TVA had $23.7 billion of Bonds outstanding.  Increased future capital expenditures along with a restrictive debt ceiling may pose a challenge to TVA’s ability to maintain low and competitive power rates.

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Organizational Transformation

TVA’s agency-wide Organization Effectiveness Initiative (“OEI”) to transform TVA into a more effective and accountable operation began in 2009 as a response to the TVA Board’s directive to develop an extensive remediation plan to address deficiencies in TVA’s control systems, operating standards, and corporate culture.  The diagnostic phase of the OEI was completed during early 2010.  The design and implementation planning phases of the initiative were completed in the second quarter of 2010.  The specific improvement programs began in the second quarter of 2010 and are expected to be completed in the first quarter of 2011.

Cyber Security

Cyber security and the protection of TVA operations and activities are a priority.  TVA uses a defense-in-depth security model in an effort to prevent, detect, respond to, and recover from threats against its systems.  TVA plans to modify and upgrade its protections as technology advances and threat environments and business requirements change.  TVA currently plans to spend approximately $20 million to $40 million in cyber security updates between 2011 and 2013.

Inflation

The economy recently experienced a very deep recession which has led to increased unemployment and low industrial capacity utilization.  Given the current low levels of capacity utilization and high unemployment, inflationary pressures should remain low.  However, a strong, sustained recovery with increasing labor, construction, and commodity costs, as well as high interest rates, could result in higher costs for TVA and pressure to increase power rates.

Liquidity and Capital Resources

Sources of Liquidity

To meet cash needs and contingencies, TVA depends on various sources of liquidity.  TVA’s primary sources of liquidity are cash from operations and proceeds from the issuance of short-term and long-term debt.  Networking capital may be negative from time to time due in part to the fact that current liabilities may exceed current assets.  TVA uses short-term debt to fund short-term cash needs and scheduled maturities of long-term debt.  The daily balance of cash and cash equivalents maintained is based on near-term expectations for cash expenditures and funding needs.

Financial markets experienced extreme volatility from 2008 to 2010 amid negative developments in housing and mortgage-related activities, weakness of major financial institutions, government actions, and negative economic developments.  These conditions have resulted in disruptions in credit and lending activities, particularly in the short-term credit markets through which corporate institutions borrow and lend to each other.  Disruptions in the short-term credit markets have the potential to impact TVA because TVA uses short-term debt to meet working capital needs, and because it typically invests its cash holdings in the short-term debt securities of other institutions.

Despite the disruptions in the credit markets, TVA has not experienced difficulty in issuing short-term debt, or in refunding maturing debt.  Throughout the period of market volatility, TVA has experienced strong demand for its short-term discount notes and long-term bonds, and has been able to issue debt at competitive rates.  TVA issued $179 million of electronotes® and $1.5 billion of other power bonds in 2010.  TVA expects continued demand for its debt securities.

In addition to cash from operations and proceeds from the issuance of short-term and long-term debt, TVA’s sources of liquidity include a $150 million credit facility with the U.S. Treasury, two revolving credit facilities totaling $2.0 billion, and occasional proceeds from other financing arrangements including call monetization transactions, sales of assets, and sales of receivables and loans.  Management expects these sources to provide more than adequate liquidity to TVA for the foreseeable future.

Issuance of Debt.  The TVA Act authorizes TVA to issue Bonds in an amount not to exceed $30.0 billion outstanding at any time.  TVA Bonds are not obligations of the United States, and the United States does not guarantee the payments of principal or interest on Bonds.  At September 30, 2010, TVA had only two types of Bonds outstanding: power bonds and discount notes.  Power bonds have maturities of between one and 50 years, and discount notes have maturities of less than one year.  Power bonds and discount notes have a first priority and equal claim of payment out of net power proceeds.  Net power proceeds are defined as the remainder of TVA’s gross power revenues after deducting the costs of operating, maintaining, and administering its power properties and payments to states and counties in lieu of taxes, but before deducting depreciation accruals or other charges representing the amortization of capital expenditures, plus the net proceeds from the sale or other disposition of any power facility or interest therein.  See Note 1 — General.

Power bonds and discount notes are both issued pursuant to section 15d of the TVA Act and pursuant to the Basic Tennessee Valley Authority Power Bond Resolution adopted by the TVA Board on October 6, 1960, as amended on September 28, 1976, October 17, 1989, and March 25, 1992 (the “Basic Resolution”).  The TVA Act and the Basic Resolution each contain two bond tests: the rate testand the bondholder protection test.

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Under the rate test, TVA must charge rates for power which will produce gross revenues sufficient to provide funds for:

•   Operation, maintenance, and administration of its power system;

•   Payments to states and counties in lieu of taxes;

•   Debt service on outstanding Bonds;

•   Payments to the U.S. Treasury as a repayment of and a return on the Power Program Appropriation Investment; and

•   Such additional margin as the TVA Board may consider desirable for investment in power system assets, retirement of outstanding Bonds in advance of maturity, additional reduction of the government’s appropriation investment in TVA’s power facilities (the “Power Program Appropriation Investment”), and other purposes connected with TVA’s power business, having due regard for the primary objectives of the TVA Act, including the objective that power shall be sold at rates as low as are feasible.  See Note 15 — Appropriation Investment.

The rate test for the one-year period ending September 30, 2010, was calculated after the end of 2010, and TVA met the test’s requirements.

Under the bondholder protection test, TVA must, in successive five-year periods, use an amount of net power proceeds at least equal to the sum of:

•   The depreciation accruals and other charges representing the amortization of capital expenditures, and

•   The net proceeds from any disposition of power facilities,

for either

•   The reduction of its capital obligations (including Bonds and the Power Program Appropriation Investment), or

•   Investment in power assets.

The bondholder protection test for the five-year period ended September 30, 2010, was calculated after the end of 2010, and TVA met the test’s requirements.  TVA must next meet the bondholder protection test for the five-year period ending September 30, 2015.

As discussed above, TVA uses proceeds from the issuance of discount notes, in addition to other sources of liquidity, to fund short-term cash needs and scheduled maturities of long-term debt.  The following table provides additional information regarding TVA’s short-term borrowings.

Short-Term Borrowing Table
	At September 30, 2010			For Quarter Ended September 30, 2010			For Year Ended September 30, 2010			At September 30, 2009			For Year Ended September 30, 2009			At September 30, 2008			For Year Ended September 30, 2008
Amount Outstanding (at End of Period) or Average Amount Outstanding (During Period)
Discount Notes	$	27		$	745		$	905		$	844		$	1,650		$	185		$	767
Borrowings from U.S. Treasury*		—			—			—			—			—			—			74
Weighted Average Interest Rate
Discount Notes		0.040	%		0.146	%		0.089	%		0.063	%		0.323	%		1.258	%		3.709	%
Borrowings from U.S. Treasury*		—			—			—			—			—			—			3.020	%
Maximum Month-End Amount Outstanding During Period
Discount Notes	$	—		$	996		$	1,176		$	—		$	2,637		$	—		$	1,570
Borrowings from U.S. Treasury*		—			—			—			—			—			—			148
Notes *  In 2009, TVA and the U.S. Treasury replaced previous financing arrangements with a memorandum of understanding, under which TVA now has a $150 million credit facility with the U.S.Treasury.

    TVA held a lower balance of short-term debt at September 30, 2010, than the end of the previous year primarily because it issued more long-term debt than it redeemed in 2010 and applied some of those proceeds to the redemption of short-term debt.  The redemption of short-term debt also accounted for the average balance of short-term debt being lower in

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2010 than 2009.  The average balance of short-term debt was higher in 2009 than 2008 primarily due to the timing of issuance of long-term debt.  The variance in the average interest rate on discount notes is primarily due to changes in market conditions.

TVA issues power bonds primarily to refinance previously-issued power bonds as they mature.  During 2010 and 2009, TVA issued $1.7 billion and $2.4 billion of power bonds, respectively, and redeemed $69 million and $2.9 billion of power bonds, respectively.  At September 30, 2010, outstanding power bonds (including current maturities of long-term debt) consisted of the following:

Outstanding Power Bonds As of September 30, 2010
CUSIP or Other Identifier	Maturity	Coupon Rate			Principal Amount (1)			Stock Exchange Listings
electronotes®	02/15/2020 - 10/15/2029		2.650% -  5.500	%(2)	$	594		None
880591DN9	01/18/2011		5.625	%		1,000		New York, Luxembourg
880591DL3	05/23/2012		7.140	%		29		New York
880591DT6	05/23/2012		6.790	%		1,486		New York
880591CW0	03/15/2013		6.000	%		1,359		New York, Hong Kong, Luxembourg, Singapore
880591DW9	08/01/2013		4.750	%		940		New York, Luxembourg
880591DY5	06/15/2015		4.375	%		1,000		New York, Luxembourg
880591EE8	11/15/2015		2.250	%		18		None
880591DS8	12/15/2016		4.875	%		524		New York
880591EA6	07/18/2017		5.500	%		1,000		New York, Luxembourg
880591CU4	12/15/2017		6.250	%		650		New York
880591EC2	04/01/2018		4.500	%		1,000		New York, Luxembourg
880591DC3	06/07/2021		5.805	%(3)		314		New York, Luxembourg
880591CJ9	11/01/2025		6.750	%		1,350		New York, Hong Kong, Luxembourg, Singapore
880591300	06/01/2028		4.728	%		330		New York
880591409	05/01/2029		4.500	%		274		New York
880591DM1	05/01/2030		7.125	%		1,000		New York, Luxembourg
880591DP4	06/07/2032		6.587	%(3)		393		New York, Luxembourg
880591DV1	07/15/2033		4.700	%		472		New York, Luxembourg
880591EF5	06/15/2034		3.770	%		448		None
880591DX7	06/15/2035		4.650	%		436		New York
880591CK6	04/01/2036		5.980	%		121		New York
880591CS9	04/01/2036		5.880	%		1,500		New York
880591CP5	01/15/2038		6.150	%		1,000		New York
880591ED0	06/15/2038		5.500	%		500		New York
880591EH1	09/15/2039		5.250	%		2,000		New York
880591BL5	04/15/2042		8.250	%		1,000		New York
880591DU3	06/07/2043		4.962	%(3)		236		New York, Luxembourg
880591CF7	07/15/2045		6.235	%		140		New York
880591EB4	01/15/2048		4.875	%		500		New York, Luxembourg
880591DZ2	04/01/2056		5.375	%		1,000		New York
880591EJ7	09/15/2060		4.625	%		1,000		New York
Subtotal						23,614
Unamortized discounts, premiums, and other						(216	)
Total outstanding power bonds, net					$	23,398
Notes (1) The above table includes net exchange losses from currency transactions of $14 million at September 30, 2010. (2) The weighted average interest rate of TVA’s outstanding electronotes® was 4.47 percent at September 30, 2010. (3) The interest rate represents TVA’s effective interest rate.

TVA manages its aggregate debt levels based on a desire to maintain a relatively stable balance of cash and cash equivalents on hand.  TVA uses short-term debt to meet working capital requirements and finance the maturities of long-term debt.  As a result, the balance of short-term debt can change significantly from day to day.  The amount of short-term debt as a percent of total debt also depends on market conditions and management decisions to issue long-term debt and to use long-term debt proceeds to redeem short-term debt.

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For additional information about TVA debt issuance activity and debt instruments issued and outstanding as of September 30, 2010, and 2009, including identifiers, rates, maturities, outstanding principal amounts, and redemption features, see Note 11 – Debt Securities Activity.

Credit Facility Agreements.  TVA and the U.S. Treasury have entered into a memorandum of understanding under which the U.S. Treasury provides TVA with a $150 million credit facility.  This credit facility matures on September 30, 2011, and is expected to be renewed.  This arrangement is pursuant to the TVA Act.  Access to this credit facility or other similar financing arrangements has been available to TVA since the 1960s.  TVA plans to use the U.S. Treasury credit facility as a secondary source of liquidity.  The interest rate on any borrowing under this facility is based on the average rate on outstanding marketable obligations of the United States with maturities from date of issue of one year or less.  There were no outstanding borrowings under the facility at September 30, 2010.

TVA also has short-term funding available in the form of two short-term revolving credit facilities of $1.0 billion each.  These credit facilities will mature on February 7, 2011, and May 11, 2011.  The credit facilities also accommodate the issuance of letters of credit.  The interest rate on any borrowing under these facilities is variable based on market factors and the rating of TVA’s senior unsecured long-term non-credit enhanced debt.  TVA is required to pay an unused facility fee on the portion of the total $2.0 billion which TVA has not borrowed or committed under letters of credit.  This fee, along with letter of credit fees, may fluctuate depending on the rating of TVA’s senior unsecured long-term non-credit enhanced debt.  At September 30, 2010, there were $411 million of letters of credit outstanding under the facilities, and there were no outstanding borrowings.  TVA anticipates renewing each credit facility or replacing it with a different credit facility as it matures.  See Note 11 — Short-Term Debt.

Call Monetization Transactions.  TVA has entered into swaption transactions to monetize the value of call provisions on certain of its Bond issues.  A swaption essentially grants a third party the right to enter into a swap agreement with TVA under which TVA receives a floating rate of interest and pays the third party a fixed rate of interest equal to the interest rate on the Bond issue whose call provision TVA monetized.  Through September 30, 2010, TVA had entered into four swaption transactions that generated proceeds of $261 million.

•   In 2003, TVA monetized the call provisions on a $1.0 billion Bond issue and a $476 million Bond issue by entering into swaption agreements with a third party in exchange for $175 million and $81 million, respectively.

•   In 2005, TVA monetized the call provisions on two Bond issues ($42 million total par value) by entering into swaption agreements with a third party in exchange for $5 million.

For more information regarding TVA’s call monetization transactions, see Note 13 — Derivatives Not Receiving Hedge Accounting Treatment — Swaption and Interest Rate Swaps.

Sale of Interest in TVA Generating Facility. Seven States Power Corporation (“Seven States”), through its subsidiary, Seven States Southaven, LLC (“SSSL”), exercised Seven States’s option to purchase an undivided 90 percent interest in a combined cycle combustion turbine facility in Southaven, Mississippi.  As part of interim joint-ownership arrangements, Seven States has the right at any time during the interim period, and for any reason, to require TVA to buy back the Seven States interest in the facility.

The interim period under the original agreements was to expire on April 30, 2010. On April 22, 2010, TVA and Seven States, through SSSL, amended the joint ownership agreement, lease agreement, and buy-back arrangements to extend the term of the interim arrangements by approximately three years, until April 23, 2013. The other material terms and conditions of the agreements were not changed and remain in full force and effect.  Under the amended agreements, TVA will buy back the Seven States interest if long-term operational and power sales arrangements for the facility among TVA, Seven States, and SSSL, or alternative arrangements, are not in place by April 23, 2013. TVA’s buy-back obligation will terminate if such long-term arrangements are in place by that date. In the event of a buy-back, TVA will re-acquire the Seven States interest in the facility and the related assets. As of September 30, 2010, the carrying amount of the obligation was approximately $413 million.

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        Summary Cash Flows

A major source of TVA’s liquidity is operating cash flows resulting from the generationand sales of electricity.  A summary of cash flow components for the years ended September 30 follows:

Summary Cash Flows For the years ended September 30
	2010			2009			2008
Cash provided by (used in):
Operating activities	$	1,901		$	2,163		$	1,967
Investing activities		(2,458	)		(2,287	)		(2,309	)
Financing activities		684			112			390
Net increase (decrease) in cash and cash equivalents	$	127		$	(12	)	$	48

Operating Activities

2010 Compared to 2009

Net cash flows from operating activities decreased $262 million in 2010 compared to 2009. This decrease resulted from lower operating revenues from FCA rate decreases, which reduced operating revenues by $1.7 billion.  The decrease was nearly fully offset by a $1.0 billion advance contribution to TVA’s pension fund in 2009 which was not made in 2010 and a $707 million base rate increase.  See Results of Operations.

2009 Compared to 2008

Net cash flows from operating activities increased $196 million in 2009 compared to 2008.  This increase resulted primarily from an increase in operating revenues as a result of higher base and FCA rates, as well as from lower cash fuel costs.See Results of Operations.  This increase was offset partially by a $1.0 billion contribution in 2009 to TVA’s pension fund as an advance on contributions for 2010 through 2013.

Investing Activities

The majority of TVA’s investing cash flows are related to investments in property, plant, and equipment for new generating assets as well as additions and upgrades to existing facilities.  A summary of changes in investing cash flows is provided below.

2010 Compared to 2009

Net cash flows used in investing activities increased $171 million in 2010 compared to 2009.  The increase resulted primarily from an additional $222 million spent on major capital projects including new combined cycle and combustion turbine units, as well as ongoing construction on Watts Bar Unit 2, in 2010.

2009 Compared to 2008

Net cash flows used in investing activities decreased $22 million in 2009 compared to 2008.  The decrease primarily reflects the absence of the acquisition of new generating assets in 2009 compared to the $466 million purchase in 2008 of the Southaven combined-cycle facility.  This absence was offset partially by a $191 million increase in investments to existing facilities, a $110 million increase in expenditures for the enrichment and fabrication of nuclear fuel related to higher prices paid for enriched uranium and the normal year to year variability resulting from the timing of refueling outages at the nuclear plants, and a $17 million decrease during 2009 in collateral held by TVA in connection with a swap agreement as compared to a $25 million increase in collateral held in 2008.

Financing Activities

2010 Compared to 2009

Net cash flows provided by financing activities increased $572 million in 2010 compared to 2009.    The change was primarily due to a decrease of $2.8 billion in redemptions and repurchases of long-term debt offset partially by a decrease of $1.5 billion in net issuances of short-term debt and a decrease of $690 million in long-term debt issuances.  The increase in debt reflects the need for cash primarily to fund capital investments.

2009 Compared to 2008

Net cash flows provided by financing activities decreased $278 million in 2009 compared to 2008.  The decrease resulted primarily from a $2.2 billion increase in redemptions and repurchases of long-term debt, with long-term debt of $2.9 billion retired in 2009, and a $221 million reduction in proceeds from the sale/leaseback of the Southaven combined-cycle

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facility in 2008.  These items were offset partially by a $264 million increase in long-term debt issues, reflecting the issuance of $2.4 billion of long-term debt in 2009, and net issuance of $659 million of short-term debt in 2009 as compared to the net redemption of $1.2 billion of short-term debt in 2008.

Cash Requirements and Contractual Obligations

The future planned construction expenditures for property, plant, and equipment additions, including clean air projects and new generation, are estimated to be as follows:

Future Planned Construction Expenditures(1) As of September 30
	Actual			Estimated Construction Expenditures
	2010			2011		2012		2013
Watts Bar Unit 2	$	690		$	635	$	441	$	—
Other capacity expansion expenditures		374			600		819		943
Environmental expenditures		58			100		219		513
Ash pond remediation		103			141		107		120
Transmission expenditures		202			249		271		280
Other capital expenditures (2)		596			779		784		840
Total capital projects requirements	$	2,023	(3)	$	2,504	$	2,641	$	2,696
Notes (1) TVA plans to fund these expenditures with cash from operations and proceeds from power program financings. This table shows only expenditures that are currently planned. Additional expenditures may be required among other things for TVA to meet growth in demand for power in its service area or to comply with new environmental laws, regulations, or orders. (2) Other capital expenditures are primarily associated with short lead time construction projects aimed at the continued safe and reliable operation of generating assets. (3) The numbers above exclude Allowance for Funds Used During Construction ("AFUDC") of $57 million and include items accrued of $65 million.

TVA conducts a continuing review of its construction expenditures and financing programs.  The amounts shown in the table above are forward-looking amounts based on a number of assumptions and are subject to various uncertainties.  Amounts may differ materially based upon a number of factors, including, but not limited to, changes in assumptions about system load growth, environmental regulation, rates of inflation, total cost of major projects, and availability and cost of external sources of capital.  See Forward-Looking Information.

In the near term, TVA may be negatively impacted by investments in new generation, such as Watts Bar Unit 2 and the John Sevier Combined Cycle Facility, that are not expected to provide a cash return until put into service.

TVA has certain obligations and commitments to make future payments under contracts,  including contracts executed in connection with certain of the planned construction expenses.  The following table sets forth TVA’s estimates of future payments as of September 30, 2010.  See Note 11, Note 12, Note 15, and Note 20 for a further description of these obligations and commitments.

Commitments and Contingencies Payments due in the year ending September 30
	2011		2012		2013		2014		2015		Thereafter		Total
Debt*	$	1,035	$	1,523	$	2,308	$	32	$	1,032	$	17,696	$	23,626
Interest payments relating to debt		1,339		1,310		1,166		1,081		1,080		19,916		25,892
Lease obligations
Capital		53		5		—		—		—		2		60
Non-cancelable operating		49		41		39		28		25		171		353
Purchase obligations
Power		275		256		197		189		238		4,304		5,459
Fuel		1,956		1,360		1,174		865		825		1,712		7,892
Other		85		118		113		122		55		313		806
Litigation settlement		3		3		3		3		—		—		12
Environmental cleanup costs-Kingston ash spill		220		124		97		84		—		—		525
Payments on other financings		135		136		488		100		104		713		1,676
Payments to U.S. Treasury
Return of Power Program     Appropriation Investment		20		20		20		10		—		—		70
Return on Power Program     Appropriation Investment		8		22		20		19		18		235		322
Total	$	5,178	$	4,918	$	5,625	$	2,533	$	3,377	$	45,062	$	66,693
Notes * Does not include noncash items of foreign currency valuation loss of $14 million and net discount on sale of Bonds of $216 million.

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In addition to the cash requirements above, TVA has contractual obligations in the form of revenue discounts related to energy prepayments.

Energy Prepayment Obligations
	2011		2012		2013		2014		2015		Thereafter		Total
Energy Prepayment Obligations	$	105	$	105	$	102	$	100	$	100	$	310	$	822

Results of Operations

Sales of Electricity

Sales of electricity accounted for substantially all of TVA’s operating revenues in 2010, 2009, and 2008.  TVA sells power at wholesale to distributor customers, consisting of municipalities and cooperatives that resell the power to their customers at retail rates.  TVA also sells power to directly served customers, consisting primarily of federal agencies and customers with large or unusual loads.  In addition, power that exceeds the needs of the TVA system is sold under exchange power arrangements with other electric systems.  The following table compares TVA’s energy sales statistics for 2010, 2009, and 2008.

Sales of Electricity For the years ended September 30
(millions of kWh)
	2010		Percent Change			2009		Percent Change			2008
Municipalities and cooperatives		141,448		6.3	%		133,078		(4.7	%)		139,596
Industries directly served		30,099		4.8	%		28,718		(17.2	%)		34,695
Federal agencies and other		2,115		5.3	%		2,008		(0.2	%)		2,013
Total sales of electricity		173,662		6.0	%		163,804		(7.1	%)		176,304
Weather Normalized Sales		168,852		0.6	%		167,807		(7.0	%)		180,477
Heating degree days (normal 3,408)		3,672		7.9	%		3,403		9.5	%		3,109
Cooling degree days (normal 1,859)		2,385		30.4	%		1,829		(8.1	%)		1,990
Combined degree days (normal 5,267)		6,057		15.8	%		5,232		2.6	%		5,099

2010 Compared to 2009

The 8.4 billion kilowatt-hour (“kWh”) increase in sales to Municipalities and cooperatives was primarily due to an increase in residential sales as a result of a record number of degree days due to both a colder than normal winter and a hotter than normal summer during 2010, as well as an increase in sales to the commercial and industrial customers of TVA’s distributor customers due to improving economic conditions.

The 1.4 billion kWh increase in sales to Industries directly served was primarily due to improving economic conditions.

The 107 million kWh increase in sales to Federal agencies and other was due to a 57 million kWh increase in sales to federal agencies directly served and an increase of 50 million kWh sold off-system due to an increase in excess generation available for resale.

2009 Compared to 2008

The 6.5 billion kWh decrease in sales to Municipalities and cooperativeswas primarily due to a decrease in demand from the commercial and industrial customers of TVA’s distributor customers as a result of the economic downturn.  Several of these commercial and industrial customers experienced less demand as a result of layoffs and decreased production in 2009 versus 2008.  Additionally, several more shut down plants.  Sales to residential customers of TVA’s distributor customers also experienced a slight decline in 2009.  The decrease in sales to residential customers was primarily due to a milder summer in 2009 compared to 2008.

The 6.0 billion kWh decrease in sales to Industries directly servedwas primarily due to the downturn in the economy.

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The decrease in sales to Federal agencies and other was primarily attributable to a decrease in off-system sales and was offset partially by an increase in sales to federal agencies directly served due to increased demand by two federal agencies.

Financial Results

The following table compares operating results for 2010, 2009, and 2008:

Summary Statements of Operations For the years ended September 30
	2010			2009			2008
Operating revenues	$	10,874		$	11,255		$	10,382
Operating expenses		(8,632	)		(9,282	)		(8,198	)
Operating income		2,242			1,973			2,184
Other income, net		24			25			9
Interest expense, net		(1,294	)		(1,272	)		(1,376	)
Net income	$	972		$	726		$	817

Operating Revenues.  Operating revenues during 2010, 2009, and 2008 consisted of the following:

Operating Revenue For the years ended September 30
	2010		Percent Change			2009		Percent Change			2008
Operating Revenues
Municipalities and cooperatives	$	9,275		(3.8	%)	$	9,644		11.4	%	$	8,659
Industries directly served		1,321		(3.4	%)		1,367		(7.1	%)		1,472
Federal agencies and other		117		(10.7	%)		131		8.3	%		121
Other revenue		161		42.5	%		113		(13.1	%)		130
Total operating revenues	$	10,874		(3.4	%)	$	11,255		8.4	%	$	10,382

Operating revenues decreased $381 million or 3.4 percent in 2010 compared to 2009, and increased $873 million or 8.4 percent in 2009 compared to 2008 due to the following:

	Variance 2010 vs. 2009			Variance 2009 vs. 2008
Base rate changes	$	707		$	754
FCA rate changes		(1,714	)		742
Volume		580			(598	)
Off system sales and other		(2	)		(8	)
Other revenue		48			(17	)
Total	$	(381	)	$	873

2010 Compared to 2009

Significant items contributing to the $381 million decrease in operating revenues included:

• A $369 million decrease in revenue from Municipalities and cooperatives primarily due to FCA rate decreases which reduced revenues by $1.5 billion.  This decrease was offset partially by a nine percent increase in base rates effective in October 2009, which provided $629 million in revenues and an increase in sales volume of 6.3 percent, which increased revenues an additional $521 million.

• A $46 million decrease in revenues from Industries directly served primarily due to FCA rate decreases, which reduced revenues by $174 million.  This decrease was offset partially by a nine percent increase in base rates mentioned above, which provided $72 million in revenues, and an increase in sales volume of 4.8 percent, which increased revenues an additional $56 million.

• A $14 million decrease in revenues from Federal Agencies and other as a result of a $12 million decrease in revenues from federal agencies directly served primarily due to the FCA rate decreases and $7 million in capitalized revenue related to pre-commercial operations of the Lagoon Creek Combined Cycle Facility.  These items were offset partially by an increase in off-system sales of $5 million.

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2009 Compared to 2008

Significant items contributing to the $873 million increase in operating revenues included:

• A $985 million increase in revenue from Municipalities and cooperatives primarily due to an increase in average base rates of 9.1 percent due to base rate increases effective April 1, 2008 and October 1, 2008, which together provided $689 million in additional revenue.  FCA rate increases provided an additional $669 million in revenue.  These increases were offset partially by a decline in sales volume of 4.7 percent, which reduced revenues by $373 million.

• A $105 million decrease in revenue from Industries directly served primarily due to decreased sales volume of 17.2 percent, which reduced revenues by $230 million.  This decrease was offset partially by FCA rate increases which provided $63 million in additional revenue, and an increase in average base rates of 5.6 percent which provided $62 million in additional revenues.

• A $10 million increase in revenue from Federal agencies and other as a result of an $18 million increase in revenues from federal agencies directly served primarily due to the FCA rate increases and increased volume.  This increase was offset partially by a decrease in off-system sales of $8 million due to decreased volume.

Operating Expenses. Operating expenses during 2010, 2009, and 2008 consisted of the following:

TVA Operating Expenses For the years ended September 30
	2010		Percent Change			2009		Percent Change			2008
Fuel and purchased power	$	3,219		(32.2	%)	$	4,745		13.6	%	$	4,176
Operating and maintenance		3,232		34.9	%		2,395		3.8	%		2,307
Depreciation, amortization, and accretion		1,724		7.9	%		1,598		30.6	%		1,224
Tax equivalents		457		(16.0	%)		544		10.8	%		491
Total operating expenses	$	8,632		(7.0	%)	$	9,282		13.2	%	$	8,198

2010 Compared to 2009

Significant drivers contributing to the $650 million decrease in total operating expenses are described below:

Fuel and purchased power expense decreased $1.5 billion due to:

• A $1.7 billion decrease in fuel and purchased power expense related to the FCA mechanism which matches the recognition of fuel and purchased power expense with the period it is collected in the FCA.  This decrease primarily resulted from a decrease in the FCA rate, which included the liquidation in 2010 of FCA amounts that were overcollected during 2009.

• A $118 million increase in fuel expense resulting from a five percent increase in the aggregate fuel cost per kWh of net thermal generation, which caused a $104 million increase in fuel expense.  Additionally, net thermal generation increased slightly, which increased fuel expense by $14 million.  The additional generation required to meet the six percent increase in electricity sales in 2010 compared to 2009 was primarily met through increased hydroelectric generation of 2.6 billion kWh, or 21 percent, and an increase in purchased power during 2010 due to economically favorable prices for purchased power.

• An $80 million increase in purchased power expense primarily because of an increase in purchased power volume of 6.7 billion kWh or 30 percent, which increased purchased power expense by $408 million.  This increase was offset partially by a decrease in the average price of purchased power of 19 percent in 2010, compared to 2009, which decreased purchased power expense by $328 million.  Included in the favorable rate variance was a decrease in net realized losses related to natural gas derivatives of $253 million compared to 2009.  Lower priced purchased power allowed TVA to displace some of the generation from its less economical generating units with purchased power.

Operating and maintenance expense increased $837 million.  The primary drivers for the increase were a $217 million increase in pension and postretirement benefit expense due to market declines in prior years and a reduction in the assumed discount rate in the prior year and a $172 million increase in operating and maintenance expense at nuclear plants due in part to a change in TVA’s accounting for nuclear refueling outages.  Historically, nuclear refueling outage costs were deferred and amortized on a straight-line basis over the estimated period until the next routine outage.  Beginning in 2010, however, outage costs have been expensed as incurred, although previously-deferred outage costs continue to be

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amortized as the remaining amounts are collected in rates.  Additional items contributing to the increase in Operating and maintenance expense included a $97 million increase in post-employment benefit costs primarily due to the results of the actuarial study relating to workers’ compensation claims, recognition in 2010 of $62 million in expense due to amortization of the Environmental cleanup costs – kingston  ash spill regulatory asset, a $51 million increase in costs to support energy efficiency and demand response initiatives, a $37 million increase related to ash handling due to increased handling activities as TVA is in process of converting from wet storage to dry storage facilities, a $30 million increase to support economic development initiatives, a $30 million increase in other benefit costs, a $23 million increase at coal-fired and combustion turbine plants largely due to forced maintenance outages at Paradise and Shawnee Fossil Plants and other maintenance projects, and a $21 million increase in expense associated with on-going studies related to future uses of the Bellefonte Nuclear Plant site.  TVA also wrote off $20 million of costs during 2010 related to upgrades for the Gleason Combustion Turbine Plant (“Gleason”).  In 2009, TVA deferred the Gleason project and transferred certain equipment to the new John Sevier Combined Cycle Facility.  At its August 2010 meeting, the TVA Board cancelled the upgrades to Gleason, and the Gleason-specific costs were subsequently charged to operating and maintenance expense.

Depreciation, amortization, and accretion expense increased $126 million primarily because of an increase in net plant additions and the implementation of accelerated depreciation rates on certain coal-fired units due to the long-term idling of those units.

Tax equivalents expense decreased $87 million.  This change primarily reflects a decrease in the accrued tax equivalent expense related to the FCA.  The accrued tax equivalent expense is equal to five percent of the FCA revenues and decreased in 2010, since the FCA revenues were lower in 2010 than 2009.

2009 Compared to 2008

Significant drivers contributing to the $1.1 billion increase in total operating expenses are described below:

Fuel and purchased power expense increased $569 million due to:

• A $717 million increase due to deferred fuel expense to be returned to customers in 2010 as part of the FCA mechanism.

• A $113 million decrease in fuel expense from a decrease in net thermal generation of 12 percent, which reduced fuel expense by $295 million.  The decrease in net thermal generation was due to lower demand, an increase in conventional hydroelectric generation of 4.7 billion kWh or 64 percent, and the decision to purchase more power in 2009 due to favorable market prices.  The aggregate fuel cost per kWh net thermal generation increased nine percent and resulted in an increase of $182 million in fuel expense.  The higher fuel cost was primarily due to higher prices for coal and was offset partially by lower prices for natural gas.

• A $35 million decrease in purchased power expense primarily due to a decrease in the average price of purchased power of 36 percent in 2009 compared to 2008, which resulted in a $529 million reduction in expense.  This decrease was offset partially by an increase in purchased power volume of six  percent, which increased purchased power expense by $80 million.  Purchased power expense also increased $414 million due to net realized losses related to natural gas derivatives compared to net realized gains on such derivative contracts in 2008.

Operating and maintenance expense increased $88 million primarily due to a $44 million increase in Operating and maintenance expense at nuclear plants due to increased number of personnel, an increase in forced maintenance outages at Browns Ferry and Sequoyah Nuclear Plants, and an increase in amortization of deferred nuclear outage costs.  TVA also experienced increased costs of $25 million primarily due to studies related to future uses of the Bellefonte Nuclear Plant, increased costs for reagents of $15 million largely due to increased volume as a result of additional SCR capacity online in 2009 compared to 2008, increased administrative costs of $13 million due to increased insurance costs and increased expenses related to new information technology implementation in the third quarter of 2008, and increased costs of $14 million to support energy efficiency and demand response initiatives.

These increases were offset partially by a $29 million decrease in operating and maintenance expenses at coal-fired and combustion turbine plants largely due to repair and recovery work at Paradise Fossil Plant in 2008 that did not recur in 2009, partial write-downs of scrubber projects at Bull Run and John Sevier Fossil Plants in 2008 that did not recur in 2009, and a decrease in outage costs due to 573 outage days in 2009 compared to the 889 outage days in 2008.  These decreases were offset partially by the cost of studies primarily related to ash remediation and expenditures related to the discharge event at Widows Creek.

Depreciation, amortization, and accretion expense increased $374 million primarily due to inclusion in 2008 of a one-time adjustment to Depreciation, amortization, and accretion expense of $350 million related to a change in regulatory accounting for non-nuclear asset recovery obligations (“AROs”).  See Note 7 — Non-Nuclear Decommissioning

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Costs.In addition, depreciation expense increased $24 million primarily due to an increase in depreciation rates on transmission and substation equipment as a result of an external depreciation cost study implemented in the fourth quarter of 2008.

Tax equivalents expense increased $53 million reflecting increased gross revenues from the sale of power (excluding sales or deliveries to other federal agencies and off-system sales with other utilities) during 2008 compared to 2007, and increased FCA revenues in 2009 compared to 2008.

Interest Expense. Interest expense and interest rates during 2010, 2009, and 2008 were as follows:

Interest Expense For the years ended September 30
	2010			Percent Change			2009			Percent Change			2008
Interest on debt and leaseback obligations	$	1,353			4.7	%	$	1,292			(5.9	%)	$	1,373
Amortization of debt discount, issue, and reacquisition costs, net		20			0.0	%		20			0.0	%		20
Allowance for funds used during construction and nuclear fuel expenditures		(79	)		97.5	%		(40	)		135.3	%		(17	)
Net interest expense	$	1,294			1.7	%	$	1,272			(7.6	%)	$	1,376
		2010		Percent Change				2009		Percent Change				2008
Interest rates (average)
Long-term*		5.91			(1.2	%)		5.98			1.2	%		5.91
Discount notes		0.09			(71.9	%)		0.32			(91.4	%)		3.71
Blended*		5.68			2.0	%		5.57			(4.6	%)		5.84
Note * The average interest rates on long-term debt reflected in the table above are calculated using an average of long-term debt balances at the end of each month in the fiscal years depicted, and interest expense for those periods. Interest expense is interest on long-term debt, including amortization of debt discounts, issue, and reaquisition costs, net. Average long-term interest rates reported in previous TVA reports were calculated using the average balance of debt based at the beginning and ending of the fiscal year.  The calculation was changed so that the average rate reflects fluctuations in the balance of long-term debt throughout the year and the impact on interest expense.

2010 Compared to 2009

The $22 million increase in net interest expense was primarily due to an increase in interest on debt as a result of an increase in the average balance of long-term debt in 2010 compared to 2009.  This increase was offset partially by the greater amounts of capitalized interest in 2010 compared to 2009 due to an increase in the construction work in progress base used to calculate AFUDC as a result of ongoing construction activities at Watts Bar Unit 2.

2009 Compared to 2008

The $104 million decrease in net interest expense included a decrease in interest on debt of $90 million primarily due to a decrease in the average balance of long-term debt during 2009 compared to 2008.  Interest expense also decreased $23 million due to an increase in the construction work in progress base used to calculate AFUDC as a result of ongoing construction activities at Watts Bar Unit 2.  These decreases in interest expense were offset partially by an increase in interest on leaseback obligations of $9 million primarily due to the addition of the Southaven leaseback obligation.

Off-Balance Sheet Arrangements

As of September 30, 2010, TVA had no off-balance sheet arrangements.

Critical Accounting Policies and Estimates

The preparation of financial statements requires TVA to estimate the effects of various matters that are inherently uncertain as of the date of the financial statements.  Although the financial statements are prepared in conformity with GAAP, TVA is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the amounts of revenues and expenses reported during the reporting period.  Each of these estimates varies in regard to the level of judgment involved and its potential impact on TVA’s financial results.  Estimates are deemed critical either when a different estimate could have reasonably been used, or where changes in the estimate are reasonably likely to occur from period to period, and such use or change would materially impact TVA’s financial condition, changes in

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financial position, or results of operations.  TVA’s accounting policies are also discussed in Note 1.

Regulatory Accounting

TVA’s Board is authorized by the TVA Act to set rates for power sold to its customers; thus, TVA is “self regulated.”  Additionally, TVA’s regulated rates are designed to recover its costs of providing electricity.  In view of demand for electricity and the level of competition, it is reasonable to assume that the rates, set at levels that will recover TVA’s costs, can be charged and collected.  As a result of these factors, TVA records certain assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities.  Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates.  Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that are not likely to be incurred or deferral of gains that will be credited to customers in future periods.  TVA assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes, potential legislation, and changes in technology.  Based on these assessments, TVA believes the existing regulatory assets are probable of recovery.  This determination reflects the current regulatory and political environment and is subject to change in the future.  The timeframe over which the regulatory assets and liabilities are recovered is subject to annual TVA Board approval.  If future recovery of regulatory assets ceases to be probable, TVA would be required to write off these costs and recognize them in earnings.  See Note 7.

Environmental Cleanup Costs - Kingston Ash Spill

Environmental clean-up costs related to the Kingston ash spill are based upon estimates of the incremental direct costs of the remediation effort, including costs of compensation and benefits for those employees who are expected to devote a significant amount of time directly to the remediation effort, to the extent of the time expected to be spent directly on the remediation effort.  Such amounts are included in the estimate when it is probable that a liability has been incurred as of the financial statement date and the amount of loss can be reasonably estimated. When both of those recognition criteria are met and the estimated loss is a range, TVA accrues the amount that appears to be a better estimate than any other estimate within the range, or accrues the minimum amount in the range if no amount within the range is a better estimate than any other amount.  If the actual costs materially differ from the estimate, TVA’s results of operations, financial condition, and cash flows could be affected materially.

As of September 30, 2010, the costs included in the environmental cleanup estimate for Kingston included ash dredging and processing, ash disposition, infrastructure repair, dredge cell repair, root cause analysis, certain legal and settlement costs, environmental impact studies and remediation, human health assessments, community outreach and support, regulatory oversight, cenosphere recovery, skimmer wall installation, construction of temporary ash storage areas, dike reinforcement, project management, and certain other remediation costs associated with the clean up.  As of September 30, 2010, TVA estimates that these costs will range from $1.1 billion to $1.2 billion based on the likelihood of multiple scenarios.  TVA has incurred $600 million of remediation costs through September 30, 2010.  TVA has deferred the $1.1 billion cost estimate as a regulatory asset and is amortizing such costs into operating expenses over a 15-year period beginning in 2010 as such amounts are collected in rates.

The following categories could have a significant effect on estimates related to the Kingston ash spill remediation costs:

•   Final Closure Design – TVA is still in the process of designing the final closure of the failed dredge cell, other cells on-site, and the lateral expansion of the failed cell.  Until the final design is completed and contracts for the work are awarded, costs estimates are subject to change.

•   Excluded Costs – TVA has not included the following categories of costs because it has determined that these costs are currently either not probable or not reasonably estimable: penalties (other than the penalties set out in the TDEC order) or regulatory directives, natural resource damages, outcome of lawsuits, future claims, long-term environmental impact costs, final long-term disposition of ash processing area, costs associated with new laws and regulations, or costs of remediating any mixed waste discovered during the ash removal process.  See Note 8.

Revenue Recognition

Revenues from power sales are recorded as power is delivered to customers.  TVA is primarily a wholesale provider of power to distributor customers that resell the power to end users at retail rates.  Under TVA’s end-use billing arrangements with distributor customers, TVA relies on the distributor customers to report their end-use sales.  Because of the delay between the wholesale delivery of power to the end-use customer and the report of end-use sales to TVA, TVA must estimate the unbilled revenue at the end of each financial reporting period.  TVA accrues estimated unbilled revenues for power sales provided to end-use customers for the period of time from the meter-read date to the end of the month.  The methodology for estimating unbilled revenue from electricity sales uses the distributor customers’ meter readings for the current billing period and an estimated rate based on the end-use customers’ historical usage and product mix.  These rates can vary from historical trends.  See Note 1 — Revenues.

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Asset Retirement Obligations

TVA recognizes legal obligations associated with the future retirement of certain tangible long-lived assets.  These obligations relate to fossil-fired generating plants, nuclear generating plants, hydroelectric generating plants/dams, transmission structures, and other property-related assets.  These other property-related assets include, but are not limited to leases.  Activities involved with retiring these assets could include decontamination and demolition of structures, removal and disposal of wastes, and site reclamation.  Revisions to the amount and timing of certain cash flow estimates of AROs may be made based on engineering studies.  For nuclear assets, the studies are performed annually in accordance with NRC requirements.  For non-nuclear obligations, revisions are made whenever factors indicate that the timing or amounts of estimated cash flows have changed.  Any accretion or depreciation expense related to these liabilities and assets are charged to a regulatory asset.  See Note 10.

Nuclear Decommissioning.  Utilities that own and operate nuclear plants are required to use different procedures in estimating nuclear decommissioning costs under GAAP than those that are used in estimating nuclear decommissioning costs that are reported to the NRC.  The two sets of procedures produce different estimates for the costs of decommissioning primarily because of the difference in the discount rates used to calculate the present value of decommissioning costs.  At September 30, 2010, the present value of the estimated future nuclear decommissioning cost under GAAP was $1.9 billion and was included in AROs, and the unamortized regulatory asset of $898 million was included in Regulatory assets.  Under the NRC’s regulations, the present value of the estimated future nuclear decommissioning cost was $1.0 billion at September 30, 2010.  This decommissioning cost estimate is based on NRC’s requirements for removing a plant from service, releasing the property for unrestricted use, and terminating the operating license.  The actual decommissioning costs may vary from the derived estimates because of changes in current assumptions, such as the assumed dates of decommissioning, changes in regulatory requirements, changes in technology, and changes in the cost of labor, materials, and equipment.

TVA maintains an NDT to provide funding for the ultimate decommissioning of its nuclear power plants.  The trust’s funds are invested in securities generally designed to achieve a return in line with overall equity market performance.  The assets of the trust are invested in debt and equity securities and certain derivative instruments.  The derivative instruments are used across various asset classes to achieve a desired investment structure.  The balance in the trust as of September 30, 2010, is less than the present value of the estimated future nuclear decommissioning costs under both the NRC methodology and under GAAP.

The following key assumptions can have a significant effect on estimates related to the nuclear decommissioning costs:

•   Timing – In projecting decommissioning costs, two assumptions must be made to estimate the timing of plant decommissioning.  First, the date of the plant’s retirement must be estimated.  (At a multiple unit site, the estimated retirement date is based on the unit with the longest licensed period remaining, or an assumption could be made that the plant will be relicensed and operate for some time beyond the original license term.)  Second, an assumption must be made whether decommissioning will begin immediately upon plant retirement, or whether the plant will be held in SAFSTOR status – a status authorized by applicable regulations which allows a nuclear facility to be maintained and monitored in a condition that allows the radioactivity to decay, after which the facility is decommissioned and dismantled.  While the impact of these assumptions cannot be determined with precision, assuming either license extension or use of SAFSTOR status can significantly decrease the present value of these obligations.

•   Technology and Regulation – There is limited experience with actual decommissioning of large nuclear facilities.  Changes in technology and experience as well as changes in regulations regarding nuclear decommissioning could cause cost estimates to change significantly.  TVA’s cost studies assume current technology and regulations.

•   Discount Rate – TVA uses a blended rate of 5.3 percent to calculate the present value of the weighted estimated cash flows required to satisfy TVA’s decommissioning obligation.

•   Investment Rate of Return – TVA assumes that its decommissioning investments will achieve a rate of return that is five percent greater than the rate of inflation.  This results in a 9.2 percent estimated investment rate of return for all periods presented.

•   Cost Escalation Factors – TVA’s decommissioning estimates include an assumption that decommissioning costs will escalate over present cost levels by four percent annually.

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Non-Nuclear Decommissioning.  The present value of the estimated future non-nuclear decommissioning cost was $1.0 billion at September 30, 2010.  This decommissioning cost estimate involves estimating the amount and timing of future expenditures and making judgments concerning whether or not such costs are considered a legal obligation.  Estimating the amount and timing of future expenditures includes, among other things, making projections of the timing and duration of the asset retirement process and how costs will escalate with inflation.  The actual decommissioning costs may vary from the derived estimates because of changes in current assumptions, such as the assumed dates of decommissioning, changes in regulatory requirements, changes in technology, and changes in the cost of labor, materials, and equipment.

TVA maintains an Asset Retirement Trust (“ART”) to provide funding for the ultimate decommissioning of its power assets.  The trust’s funds are invested in securities generally designed to achieve a return in line with fixed-income market performance.  The assets of the fund are invested in fixed income securities directly and indirectly through commingled funds.  Estimates involved in determining if additional funding will be made to the ART include inflation rate and rate of return projections on the fund investments.

The following key assumptions can have a significant effect on estimates related to the non-nuclear decommissioning costs:

•   Timing – In projecting non-nuclear decommissioning costs, the date of the asset’s retirement must be estimated.  TVA uses a probability-weighted scenario approach based on management assumptions, type of asset, and other factors to estimate the expected retirement time period.  In instances where the retirement of a specific asset differs from the anticipated retirement date, the anticipated retirement date of that specific asset is used.  Additionally, TVA expects to incur certain ongoing costs subsequent to the initial asset retirement.

•   Technology and Regulation – Changes in technology and experience as well as changes in regulations regarding non-nuclear decommissioning could cause cost estimates to change significantly.  TVA’s cost studies generally assume current technology and regulations.  With respect to the CCP facilities, TVA assumes that any future closures will require more costly materials and processes than what is legally required as of September 30, 2010.

•   Discount Rate – TVA uses its incremental lending rate over a period consistent with the remaining timeframe until the costs are expected to be incurred to calculate the present value of the weighted estimated cash flows required to satisfy TVA’s non-nuclear decommissioning obligation.  As of September 30, 2010, the discount rates used in the calculations range from 0.37 percent to 5.66 percent.

•   Cost Escalation Factors – TVA’s non-nuclear decommissioning estimates include an assumption that decommissioning costs will escalate over present cost levels at rates between 2.5 percent and four percent annually.

Pension and Other Post-Retirement Benefits

TVA sponsors a defined benefit pension plan that is qualified under IRS rules and covers substantially all of its full-time annual employees.  The TVA Retirement System (“TVARS”), a separate legal entity governed by its own board of directors, administers the qualified defined benefit pension plan.  TVA also provides a Supplemental Executive Retirement Plan (“SERP”) to certain executives in critical positions, which provides supplemental pension benefits tied to compensation levels that exceed limits imposed by IRS rules applicable to the qualified defined benefit pension plan.  Additionally, TVA provides post-retirement health care benefits for most of its full-time employees who reach retirement age while still working for TVA.  TVA’s costs of providing these benefits are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms.  The most significant of these factors are discussed below.

Expected Return on Plan Assets.The qualified defined benefit pension plan is the only plan that is funded with qualified plan assets.  The expected returns on pension plan assets used to develop net pension expense were 7.75 percent, 8.00 percent, and 8.75 percent during 2010, 2009, and 2008, respectively, and are determined at the beginning of the period.  Changes in the expected return rates are generally based on studies performed by third party professional investment consultants.  A higher expected rate of return decreases net periodic pension expense.  A lower expected rate of return increases net periodic pension expense.  TVA adjusted the expected rate of return on pension plan assets to 7.5 percent for 2011 based on a recent asset/liability study performed by third party professional investment consultants.  The expected rate of return had been reduced for 2010 based on a similar study and upon a June 2009 change in the TVARS policy allocating the investment mix of plan assets.  The change in 2010 shifted a portion of target asset investment allocations from equities to fixed income.  The change in the TVARS investment allocation policy was based on a recommendation by the TVARS investment consultant.  The recent changes in the expected rate of return on pension plan assets discussed do not affect TVA’s post-retirement benefits plan because TVA does not separately set aside assets to fund such benefits.  TVA funds its post-retirement plan benefits on an as-paid basis.  These changes in the expected rate of return on pension plan assets also do not impact the SERP as any

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assets set aside for that plan are not considered plan assets under GAAP.  The actuarial gain related to the difference between expected and actual return on pension plan assets for 2010 was $159 million.  This amount has been recognized as a reduction to the related regulatory asset.

Discount Rate. In the case of selecting an assumed discount rate, TVA reviews market yields on high-quality corporate debt and long-term obligations of the U.S. Treasury and endeavors to match, through the use of a hypothetical bond portfolio, instrument maturities with the maturities of its pension obligations in accordance with the prevailing accounting standards.  In addition, TVA looks at published pension spot yield curves and applies expected cash flows to the curve to approximate the rate expected to settle the projected benefit payments.  The discount rates used to determine net pension cost were 5.75 percent, 7.5 percent, and 6.25 percent during 2010, 2009, and 2008, respectively.  The discount rate is determined at the beginning of the period.  TVA plans to use a discount rate of five percent in the determination of 2011 net periodic pension expense and also used this rate to value plan obligations at the end of 2010.  Changes in the discount rate for 2010 were due to decreased long-term interest rates.  The discount rate is somewhat volatile because it is determined based upon the prevailing rate as of the measurement date.  The discount rate used to determine the post-retirement benefits costs is the same rate used to determine pension benefits costs due to a similar expected duration of the post-retirement and pension benefit obligations.  A higher discount rate decreases the plan obligations and correspondingly decreases the net periodic pension and post-retirement benefits expense for those plans where actuarial losses are being amortized.  On the other hand, a lower discount rate increases net periodic pension and post-retirement benefits costs.

Mortality.  Mortality assumptions are based on the results obtained from a recent actual company experience study performed which included retirees as well as other plan participants.  TVA obtained an updated study in 2008 and, accordingly, adjusted the mortality rates from the 1983 Group Annuity Mortality Tables to the RP-2000 Mortality Tables.  During 2010, company experience was reexamined and it was determined that TVA’s mortality experience has continued to improve.  As a result, TVA adjusted the mortality rates to RP-2000 Combined Healthy Mortality table projected to 2013 using scale AA at September 30, 2010.

Cost of Living Adjustment.  Thequalified defined benefit pension plan includes a cost of living adjustment (“COLA”) that is generally indexed against the Consumer Price Index (“CPI”), subject to a floor and ceiling.  The CPI fell during 2009, and market-based measures of inflation expectations at the end of 2009 projected slow growth in the CPI through 2015.  Additionally, the COLA had been temporarily reduced for current retirees and deferred to age 60 for employees retiring on or after January 1, 2010.  As a result of these COLA benefit reductions and low inflationary expectations, TVA reduced the COLA assumption from 3.0 percent to 2.5 percent at September 30, 2009. The CPI experienced moderate growth during 2010.  Due to stabilizing long-term expectations, TVA determined the COLA assumption should be held at 2.5 percent at September 30, 2010.

Sensitivity of Costs to Changes in Assumptions.  The following chart reflects the sensitivity of pension costs to changes in certain actuarial assumptions:

Sensitivity to Certain Changes in Pension Assumptions
Actuarial Assumption	Change in Assumption			Impact on 2010 Pension Cost		Impact on 2010 Projected Benefit Obligation
Discount rate		(0.25	%)	$	17	$	296
Rate of return on plan assets		(0.25	%)	$	16	NA

Each fluctuation above assumes that the other components of the calculation are held constant and excludes any impact for unamortized actuarial gains or losses.

The following chart reflects the sensitivity of post-retirement benefit costs to changes in the health care cost trend rate:

Sensitivity to Changes in Assumed Health Care Cost Trend Rates
	1% Increase		1% Decrease
Effect on total of service and interest cost components	$	5	$	(6	)
Effect on end-of-year accumulated post-retirement benefit obligation	$	78	$	(87	)

Each fluctuation above assumes that the other components of the calculation are held constant and excludes any impact for unamortized actuarial gains or losses.

Accounting Mechanisms.  In accordance with current accounting methodologies, TVA utilizes a number of accounting mechanisms that reduce the volatility of reported pension expense.  Differences between actuarial assumptions and actual plan results are deferred and are amortized into periodic expense only when the accumulated differences exceed 10 percent of the greater of the projected benefit obligation or the market-related value of plan assets.  If necessary, the excess is amortized over the average remaining service period of active employees.

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Additionally, TVA recognizes the impact of asset performance on pension expense over a three-year phase-in period through a “market-related” value of assets calculation.  Since the market-related value of assets recognizes investment gains and losses over a three-year period, the future value of assets will be impacted as previously deferred gains or losses are recognized.  As a result, the losses that the pension plan assets experienced in the current year may have an adverse impact on pension expense in future years depending on whether the actuarial losses at each measurement date exceed the 10 percent corridor in accordance with current accounting methodologies.  See Note 18 for a discussion of obligations and funded status.

Expected Contributions.  TVA expects to contribute $8 million to its SERP and $36 million to its post-retirement health care benefit plans in 2011.  TVA made a contribution to the qualified defined benefit pension plan on September 24, 2009, of $1.0 billion that constituted an advance of contributions for 2010 through 2013. TVA has not determined at this time whether additional contributions will be directed to the qualified defined benefit pension plan during 2011.

Changes in Ratemaking Impacting Accounting

Fuel Cost Adjustment

In August 2009, the TVA Board approved a revision to the FCA formula.  Starting with the October 1, 2009 billing period, all adjustments to the FCA have been made on a monthly basis instead of a quarterly basis.  In August 2010, the TVA Board approved another revision to the FCA formula.  Starting with the October 1, 2010 billing period, the FCA rate has adjusted for seasonal fuel costs within the FCA formula.  Both of these changes allow for the FCA rate to be more closely aligned with TVA’s costs.  The FCA formula contains a deferred account, which is used to reconcile the difference between actual and forecasted fuel costs in the FCA.  The difference between the amounts is included in the deferred account, and 50 percent of the account is disbursed or collected on a monthly basis.  These changes in the FCA result in smaller reconciliations and faster liquidation of any balances in the account. 

Wholesale Rate Structure

On August 20, 2010, the TVA Board approved the terms and conditions of new rate structures to become effective in April 2011.  The proposed changes are not intended to provide additional revenue for TVA; however, individual distributors and end-use customers may see some effects on their bills.  The proposed rate structures would provide price signals intended to incentivize distributor customers and end-use customers to shift energy usage from high cost periods to less expensive periods.  For distributor customers, the wholesale rates would initially be a time-of-use rate with an option for a demand and energy rate .  TVA is proposing to have all distributor customers on a time-of-use wholesale rate structure by no later than October 2012; however, TVA will continue to have discussions with distributors on other alternative wholesale rate structures.  For directly served customers and distributor-served customers with loads in excess of five MW, TVA is proposing a default time-of-use rate structure with the option of a seasonal demand and energy rate structure.  See Item 1 — Rates — Rate Structure.

TVA faces several challenges in implementing time-of-use rates.  Although metering is in place today to facilitate implementation at the wholesale level, additional metering and infrastructure will be needed to pass through the time-of-use pricing signals at the retail level.  TVA is working with distributors to explore how additional metering and infrastructure resources can best be acquired in a cost-effective manner.  In addition, there will be additional administration costs associated with implementing the time-of-use rates.  Billing, metering, communication, and data management systems will have to be modified (and in some cases acquired) to read, communicate, and ultimately generate customer bills.

Environmental Cleanup Costs - Kingston Ash Spill

In August 2009,the TVA Board approved the use of regulatory accounting treatment for current and future incurred costs and future estimated costs related to the environmental cleanup of the Kingston ash spill.  These costs had previously been expensed as part of operations when such costs were deemed to be probable and estimable.  Cumulative costs incurred or estimated since the spill in December 2008 were recaptured as a regulatory asset as of September 30, 2009.  The offset to this adjustment was a one-time decrease to operating expenses.  The costs are being recovered and amortized into operating expenses over a 15-year period beginning in October 2009 as amounts are collected in rates.  Any changes to the estimated cost will be deferred as estimates are revised and future years’ rates will reflect those adjustments prospectively over the remaining portion of the 15-year period.  TVA believes it is reasonable to conclude that it can collect these expenses in its rates over this period.  SeeNote 8.

Non-Nuclear Decommissioning Costs

In August 2008, the TVA Board approved deferring costs related to the future closure and retirement of TVA's non-nuclear long-lived assets under various legal requirements as allowed under GAAP.  These costs had previously been included in rates as the ARO was accreted and the asset was depreciated.  These costs did not previously meet the asset

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recognition criteria under GAAP guidance in effect at the date the costs were incurred.  Because of the establishment of the ART and the approval of the funding in rates as part of the TVA Board’s budget and ratemaking process, these costs met asset recognition criteria in the fourth quarter of 2008.  Accordingly, all cumulative ARO costs were recaptured as a regulatory asset as of September 30, 2008.  The regulatory asset initially created related to this adjustment totaled $350 million.  The offset to this adjustment was a one-time decrease to depreciation, amortization, and accretion expense. See Note 7 — Non-Nuclear Decommissioning Costs.

Nuclear Outage Costs

TVA’s investment in the fuel used in its nuclear units is being amortized and accounted for as a component of fuel expense.  Nuclear refueling outage and maintenance costs have historically been deferred as a regulatory asset and amortized on a straight-line basis over the estimated period until the next refueling outage.  In August 2009, the TVA Board approved changing this methodology for rate setting purposes, and in 2010, TVA began expensing outage and maintenance costs as incurred rather than deferring and amortizing them.  Previously deferred costs will continue to be amortized.

Fair Value Measurements

Investments

Investments classified as trading consist of amounts held in the NDT, the ART, and the SERP.  These assets are generally measured at fair value based on quoted market prices or other observable market data such as interest rate indices.  These investments are primarily U.S. equities, international equities, real estate investment trusts, fixed income investments, high-yield fixed income investments, U.S. Treasury inflation-protected securities, commodities, currencies, derivative instruments, and other investments.  TVA has classified all of these trading securities as either Level 1, Level 2, or Level 3 valuations.  See Note 14 — Valuation Techniques for a discussion of valuation levels of the investments.  See Note 18 — Fair Value Measurements for disclosure of fair value measurements for investments held by the TVARS that support TVA’s qualified defined benefit pension plan.

Prices provided by third-parties for the investments are subjected to automated tolerance checks by the investment portfolio trustee to identify and avoid, where possible, the use of inaccurate prices.  Any questionable prices identified are reported to the vendor which provided the price.  If the prices are validated, the primary pricing source is used.  If not, a secondary source price which has passed the applicable tolerance check is used (or queried with the vendor if it is out of tolerance), resulting in either the use of a secondary price, where validated, or the last reported default price, as in the case of a missing price.  For monthly valued accounts, where secondary price sources are available, an automated inter-source tolerance report identifies prices with an inter-vendor pricing variance of over two percent at an asset class level.  For daily valued accounts, each security is assigned, where possible, an indicative major market index, against which daily price movements are automatically compared.  Tolerance thresholds are established by asset class.  Prices found to be outside of the applicable tolerance threshold are reported and queried with vendors as described above.

Derivatives

Commodity derivatives under the Financial Trading Program (“FTP”) are classified as Level 1 and Level 2 valuations.  Currency swaps and interest rate swaps are classified as Level 2 valuations.  The swaption and certain coal contract derivatives are classified as Level 3 valuations.

Currency Swaps, Swaption, and Interest Rate Swaps.  TVA has three currency swaps, one swaption, and three “fixed for floating” interest rate swaps.  The currency swaps and interest rate swaps are classified as Level 2 valuations as the rate curves and interest rates affecting the fair value of the contracts are based on observable data.  While most of the fair value measurement is based on observable inputs, volatility for TVA’s swaption is generally unobservable and it is classified as a Level 3 valuation.  Therefore, the valuation is derived from an observable volatility measure with adjustments.  The application of credit valuation adjustments (“CVAs”) resulted in a decrease of $1 million in the fair value of the swaption and interest rate swaps, and did not materially affect the fair values of the currency swaps at September 30, 2010.

Coal Contracts.  The fair value of this derivative portfolio is valued using internal models.  The significant inputs to these models are price indications such as quoted spot prices and implied forward prices.  The pricing model is based on significant unobservable inputs, similar products, or products priced in different time periods.  TVA designs price curves and valuation models based on the best available information and industry accepted practices.  As a result, these valuations are classified as Level 3 valuations.  Additionally, any settlement fees related to early termination of coal supply contracts are included at the contractual amount.  The application of CVAs resulted in a decrease of $25 million in the fair values of coal contracts in an asset position at September 30, 2010.

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Commodity Derivatives under the Financial Trading Program.  TVA uses quoted Chicago Mercantile Exchange (“CME”) prices in its determination of the fair value of these contracts.  Contracts settled on the CME are classified as Level 1 valuations.  These are primarily natural gas futures, fuel oil futures, crude oil futures, and natural gas option contracts.  Contracts where nonperformance risk exists outside of the exit price are measured with the incorporation of CVAs and are classified as Level 2 valuations.  These are primarily natural gas, fuel oil, and crude oil swap contracts.  The application of CVAs did not materially affect the fair value of these assets and liabilities at September 30, 2010.

TVA maintains policies and procedures to value commodity contracts using what is believed to be the best and most relevant data available.  In addition, TVA’s risk management group reviews valuations and pricing data.  TVA retains independent pricing vendors to assist in valuing certain instruments without market liquidity.

Fair Value Considerations

In determining the fair value of its financial instruments, TVA considers the source of observable market data inputs, liquidity of the instrument, credit risk, and risk of nonperformance of itself or the counterparty to the contract.  The conditions and criteria used to assess these factors are described below.

Sources of Market Assumptions.  TVA derives its financial instrument market assumptions from market data sources (e.g., CME, Moody’s Investors Service (“Moody’s”)).  In some cases, where market data is not readily available, TVA uses comparable market sources and empirical evidence to derive market assumptions and determine a financial instrument's fair value.

Market Liquidity.  Market liquidity is assessed by TVA based on criteria as to whether the financial instrument trades in an active or inactive market.  A financial instrument is considered to be in an active market if the prices are fully transparent to the market participants, the prices can be measured by market bid and ask quotes, the market has a relatively high trading volume as compared to TVA's current trading volume, and the market has a significant number of market participants that will allow the market to rapidly absorb the quantity of the assets traded without significantly affecting the market price.  Other factors TVA considers when determining whether a market is active or inactive include the presence of government or regulatory control over pricing that could make it difficult to establish a market based price upon entering into a transaction.

Nonperformance Risk.  In determining the potential impact of nonperformance risk, which includes credit risk, TVA considers changes in current market conditions, readily available information on nonperformance risk, letters of credit, collateral, other arrangements available, and the nature of master netting arrangements.  TVA is a counterparty to derivatives which subject TVA to nonperformance risk.  Nonperformance risk on the majority of investments and certain exchange-traded instruments held by TVA is incorporated into the exit price that is derived from quoted market data that is used to mark the investment to market.

Nonperformance risk for most of TVA’s derivative instruments is an adjustment to the initial asset/liability fair value.  TVA adjusts for nonperformance risk, both of TVA (for liabilities) and the counterparty (for assets) by applying a CVA.  TVA determines an appropriate CVA for each applicable financial instrument based on the term of the instrument and TVA’s or the counterparty’s credit rating as obtained from Moody’s.  For companies that do not have an observable credit rating, TVA uses internal analysis to assign a comparable rating to the company.  TVA discounts each financial instrument using the historical default rate (as reported by Moody’s for CY 1983 to CY 2009) for companies with a similar credit rating over a time period consistent with the remaining term of the contract.

All derivative instruments are analyzed individually and are subject to unique risk exposures.  At September 30, 2010, the aggregate counterparty credit risk adjustments applied to TVA's derivative asset and liability positions were decreases of $25 million and $2 million, respectively.

Collateral. TVA’s interest rate swaps, its currency swaps, and its swaption contain contract provisions that require a party to post collateral (in a form such as cash or a letter of credit) when the party’s liability balance under the agreement exceeds a certain threshold. See Note 13 — Collateral for a discussion of collateral related to TVA’s derivative liabilities.

Level 3 Information.  Unrealized gains and/or losses on contracts classified as Level 3 valuations are included in regulatory assets and/or liabilities until the contracts are settled. TVA experienced unrealized gains on coal contracts with volume options due to changes in coal market prices during the year ended September 30, 2010.  TVA also experienced unrealized losses on the swaption liability due to decreases in interest rates during the year ended September 30, 2010.  Unrealized losses on these instruments did not have a material effect on liquidity or capital resources. There were no realized gains (losses) during the year ended September 30, 2010.  At September 30, 2010, Level 3 valuations represented 13 percent of total assets measured at fair value and 54 percent of total liabilities measured at fair value.

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New Accounting Standards and Interpretations

The following accounting standards and interpretations became effective for TVA during 2010.

Fair Value Measurements.  In September 2006, the Financial Accounting Standards Board (“FASB”) issued guidance for measuring assets and liabilities that currently require fair value measurement.  The guidance also responds to investors’ requests for expanded information about the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurements on earnings.  The guidance applies whenever other standards require (or permit) assets or liabilities to be measured at fair value but does not expand the use of fair value in any new circumstances.  The guidance establishes a fair value hierarchy that prioritizes the information used to develop measurement assumptions.  In February 2008, FASB issued guidance that delayed the effective date of the fair value accounting changes for nonfinancial assets and nonfinancial liabilities except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis.  Effective October 1, 2008, TVA adopted these fair value accounting changes for its nonfinancial assets and nonfinancial liabilities.  The adoption of this guidance did not materially impact TVA’s financial condition, results of operations, or cash flows.

 

           In August 2009, FASB issued guidance regarding fair value measurements of liabilities.  The guidance clarifies how the fair value of a liability should be measured when a quoted price in an active market for the identical liability either is or is not available.  Additionally, the guidance clarifies how to consider a restriction when estimating the fair value of a liability and the appropriate level within the fair value disclosure hierarchy in which the various measurement techniques result.  These changes became effective for TVA on October 1, 2009.  The adoption of this guidance changed certain financial statement disclosures but did not materially impact TVA’s financial condition, results of operations, or cash flows.

In September 2009, FASB issued guidance regarding fair value measurements for certain alternative investments, such as interests in hedge funds, private equity funds, real estate funds, venture capital funds, offshore fund vehicles, and funds of funds.  The guidance allows reporting entities to use net asset value per share to estimate the fair value of these investments as a practical expedient.  The guidance also requires disclosures by major category of investment about the attributes of the investments, such as the nature of any restrictions on the investor's ability to redeem its investments at the measurement date, any unfunded commitments, and the investment strategies of the investees.  These changes became effective for TVA on October 1, 2009.  The adoption of this guidance changed certain financial statement disclosures but did not materially impact TVA’s financial condition, results of operations, or cash flows.

See Note 14 — Investments for related fair value disclosures for TVA’s investments and Note 18 — Fair Value Measurements for disclosure of fair value measurements for investments held by TVARS that support TVA’s qualified defined benefit pension plan.

Employers’ Disclosures about Post-Retirement Benefit Plan Assets. In December 2008, FASB issued guidance that changes employers’ disclosures about post-retirement benefit plan assets.  The guidance requires that an employer disclose the following information about the plan assets: (1) information regarding how investment allocation decisions are made; (2) the major categories of plan assets; (3) information about the inputs and valuation techniques used to measure fair value of the plan assets; (4) the effect of fair value measurements using significant unobservable inputs on changes in plan assets for the period; and (5) significant concentrations of risk within plan assets.  At initial adoption, these changes became effective for TVA on October 1, 2009.  Upon initial application, these changes were not required for earlier periods that are presented for comparative purposes.  See Note 18 — Fair Value Measurements for disclosure of fair value measurements for investments held by TVARS that support TVA’s qualified defined benefit pension plan.

Business Combinations.  In December 2007, FASB issued guidance that changes the accounting for business combinations.  The guidance establishes principles and requirements for determining how an enterprise recognizes and measures the fair value of certain assets and liabilities acquired in a business combination, including non-controlling interests, contingent consideration, and certain acquired contingencies.  The guidance also requires acquisition-related transaction expenses and restructuring costs to be expensed as incurred rather than capitalized as a component of the business combination.  In April 2009, FASB issued additional guidanceto amend and clarify the initial recognition and measurement, subsequent measurement and accounting, and related disclosures arising from contingencies in a business combination.  This guidance became effective for TVA as of October 1, 2009.  The adoption of this guidance did not materially impact TVA’s financial condition, results of operations, or cash flows but will impact the accounting for any future business acquisitions.

Noncontrolling Interests.  In December 2007, FASB issued guidance that introduces significant changes in the accounting for noncontrolling interests (formerly minority interests) in a partially-owned consolidated subsidiary.  The guidance also changes the accounting for and reporting for the deconsolidation of a subsidiary.  The guidance requires that noncontrolling interests in a consolidated subsidiary be displayed in the consolidated statement of financial position as a separate component of equity.  The guidance also requires that earnings attributed to noncontrolling interests be reported as part of consolidated earnings, and requires disclosure of the attribution of consolidated earnings to the controlling and noncontrolling interests on the face of the consolidated income statement.  These changes became effective for TVA as of October 1, 2009.  The adoption of this guidance did not materially impact TVA’s financial condition, results of operations, or cash flows but will impact the accounting for any future noncontrolling interests.

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The following accounting standards have been issued, but as of September 30, 2010, were not effective and had not been adopted by TVA.

Transfers of Financial Assets.  In June 2009, FASB issued guidance regarding accounting for transfers of financial assets.  This guidance eliminates the concept of a qualifying special-purpose entity (“QSPE”) and subjects those entities to the same consolidation guidance as other variable interest entities (“VIEs”).  The guidance changes the eligibility criteria for certain transactions to qualify for sale accounting and the accounting for certain transfers.  The guidance also establishes broad disclosure objectives and requires extensive specific disclosure requirements related to the transfers.  These changes became effective for TVA for any transfers of financial assets occurring on or after October 1, 2010.  TVA does not believe adoption of this guidance will materially affect its financial condition, results of operations, or cash flows.

Variable Interest Entities.  In June 2009, FASB issued guidance that changes the consolidation guidance for VIEs.  The guidance eliminates the consolidation scope exception for QSPEs.  The statement amends the triggering events to determine if an entity is a VIE, establishes a primarily qualitative model for determining the primary beneficiary of the VIE, and requires on-going assessment of whether the reporting entity is the primary beneficiary.  These changes became effective for TVA on October 1, 2010, and apply to all entities determined to be VIEs as of and subsequent to the date of adoption.  TVA does not believe adoption of this guidance will materially affect its financial condition, results of operations, or cash flows.

Legislative and Regulatory Matters

Two inter-related major health care reform bills were enacted into law in 2010.  The first, the Patient Protection and Affordable Care Act (H.R. 3590 -- Public Law No. 111-148), was enacted on March 23, 2010, and was followed by the enactment on March 30, 2010, of the Health Care and Education Reconciliation Act of 2010 (H.R. 4872 – Public Law No. 111-152), which amended the earlier act.  The new laws are complex, and TVA is in the process of analyzing them in terms of potential effects.  TVA’s final analysis as to potential impacts will not be completed until future rulemakings are undertaken and finalized by the various federal agencies which have been given regulatory responsibilities under the new laws.

The President signed the Dodd-Frank Wall Street Reform and Consumer Protection Act on July 21, 2010.  The act instructs regulatory agencies to determine many of the specific requirements related to the broad areas of reform.  The legislation will make changes in many financial sectors, including how certain types of derivatives are structured, traded, and used.  Depending upon how the so-called “end user exemption” and other provisions are ultimately interpreted and implemented by regulators, this legislation could impact the ability of TVA (as well as other electric suppliers and other “end users”) to use certain derivatives to hedge various risks and might increase the costs of doing so.  See Note 13 — Overview of Accounting Treatment for a discussion of TVA’s use of derivatives to hedge various risks.  This could increase the cost of hedging transactions, and/or require a significant increase in collateral to be posted.

For a discussion of environmental legislation and regulation, see Item 1, Business - Environmental Matters.

Given the nature of the legislative process, it is possible that new legislation or a change to existing legislation that has a significant impact on TVA’s activities could become law with little or no advance notice.  As a federal entity, the very nature of TVA can be changed by legislation.  For a discussion of the potential impact of legislation and regulation on TVA, see Item 1A, Risk Factors in this Annual Report.

Environmental Matters

See Item 1, Business — Environmental Matters, which discussion is incorporated into this Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Legal Proceedings

From time to time, TVA is party to or otherwise involved in lawsuits, claims, proceedings, investigations, and other legal matters (“Legal Proceedings”) that have risen in the ordinary course of conducting its activities, as a result of catastrophic events or otherwise.  These Legal Proceedings include the matters discussed in Note 20 — Legal Proceedings.  TVA had accrued approximately $14 million and $16 million with respect to Legal Proceedings as of September 30, 2010, and 2009, respectively.  No assurance can be given that TVA will not be subject to significant additional claims and liabilities.  If actual liabilities significantly exceed the estimates made, TVA’s results of operations, liquidity, and financial condition could be materially adversely affected.

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For a discussion of TVA’s current material Legal Proceedings, see Note 20 — Legal Proceedings, which discussion is incorporated into this Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Risk Management Activities

TVA is exposed to various market risks.  These market risks include risks related to commodity prices, investment prices, interest rates, currency exchange rates, inflation, and counterparty credit and performance risk.  To help manage certain of these risks, TVA has entered into various derivative transactions, principally commodity option contracts, forward contracts, swaps, swaptions, futures, and options on futures.  Other than certain derivative instruments in its trust investment funds, it is TVA’s policy to enter into these derivative transactions solely for hedging purposes and not for speculative purposes.  See Note 13.

Risk Governance

The Enterprise Risk Council (“ERC”) was created in 2005 to strengthen and formalize TVA’s enterprise-wide risk management efforts.  The ERC is responsible for the highest level of risk oversight at TVA and is also responsible for communicating enterprise-wide risks with policy implications to the TVA Board or a designated TVA Board committee.  The ERC’s current members are the President and Chief Executive Officer (chair), Chief Information Officer, Group President, Strategy and External Relations, the Chief Financial Officer, the Controller and Chief Risk Officer, the Chief Operating Officer, the Executive Vice President for People and Performance, the General Counsel, and a designated representative from the Office of the Inspector General (“OIG”) as an advisory member.

The ERC has established a subordinate Risk Management Steering Committee (“RMSC”).  The RMSC is responsible for (1) reviewing risk management policies to ensure their consistency with TVA’s Enterprise Risk Management (“ERM”) policies and guidelines, (2) reviewing Strategic Business Unit risks and emerging issues, (3) providing executive guidance and support in enterprise risk assessments and risk management plans, (4) presenting enterprise risks for consideration by the ERC, (5) recommending general risk management processes and methodologies for the enterprise, and (6) sponsoring special projects related to cross-functional risk management activities.

TVA has a designated ERM organization within its Financial Services organization, responsible for (1) coordinating risk assessment efforts at TVA organizations, (2) facilitating enterprise risk discussions with the risk subject matter experts at the RMSC, ERC, and TVA Board levels, and (3) developing and improving risk governance structure and risk assessment processes and methodologies.

TVA has cataloged major short-term and long-term enterprise level risks across the organization. A discussion of significant risks is presented in Item 1A, Risk Factors.

Commodity Price Risk

TVA is exposed to effects of market fluctuations in the price of commodities that are critical to its operations, including coal, uranium, natural gas, fuel oil, crude oil, construction materials, emission allowances, and electricity.  TVA’s commodity price risk is substantially mitigated by its cost-based rates, including its automatic FCA mechanism.  To manage cost volatility for its wholesale and direct-served customers, TVA has established a FTP.  Under the FTP, TVA currently hedges the risks associated with the price of natural gas, fuel oil, crude oil, and coal.  TVA is prohibited from taking speculative positions in its FTP.

Following is a discussion of the impact on the value of TVA’s natural gas, coal, fuel oil, and crude oil derivative positions in its FTP that would result from hypothetical changes in commodity prices:

Natural Gas.  A hypothetical 10 percent decline in market price of natural gas on September 30, 2010, and 2009, would have resulted in a decrease of approximately $32 million, and $94 million, respectively, in the fair value of TVA’s natural gas trading derivative instruments as of these dates.

Coal.  A hypothetical 10 percent decline in the market price of coal on September 30, 2010 would have resulted in a decrease of approximately $3 million in the fair value of TVA’s financial coal derivative instruments as of this date.   As of September 30, 2009, TVA had no financial coal trading derivative instruments outstanding.

Fuel Oil.  A hypothetical 10 percent decline in market price of fuel oil on September 30, 2010, and 2009, would have resulted in a decrease of approximately $6 million, and $13 million, respectively, in the fair value of TVA’s fuel oil derivative instruments as of these dates.

Crude Oil.  A hypothetical 10 percent decline in market price of crude oil on September 30, 2010, and 2009, would have resulted in a decrease of approximately $8 million, and $5 million, respectively, in the fair value of TVA’s crude oil derivative instruments as of these dates.

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      Investment Price Risk

TVA’s investment price risk relates primarily to investments in TVA’s NDT, ART, pension fund, and SERP.

Nuclear Decommissioning Trust.  The NDT is generally designed to achieve a return in line with overall equity market performance.  The assets of the trust are invested in debt and equity securities and certain derivative instruments including forwards, futures, options, and swaps, and through these investments the trust has exposure to U.S. equities, international equities, real estate investment trusts, high-yield debt, U.S. Treasury inflation-protected securities, commodities, currencies, and private partnerships.  As of September 30, 2010, and 2009, an immediate 10 percent decrease in the price of the investments in the trust would have reduced the value of the trust by $94 million, and $84 million, respectively.  See Item 7,Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates — Nuclear Decommissioning for more information regarding TVA’s NDT.

Asset Retirement Trust.  The ART is presently invested to achieve a return in line with fixed income market performance. The assets of the trust are invested in fixed income securities directly and indirectly through commingled funds.  As of September 30, 2010, and 2009, an immediate 10 percent decrease in the price of the investments in the trust would have reduced the value of the trust by $16 million, and $12 million, respectively.

Pension Fund. TVARS targets an asset allocation policy for its pension plan assets of 45 percent equity securities including U.S. and non U.S. equities, 40 percent fixed income securities, and 15 percent alternative investments including private equity, private real estate, distressed debt, and timber.  The pension plan assets are invested in equity securities, debt securities, U.S. equities, international equities, real estate investment trusts, private real estate, timber, investment-grade debt, high-yield debt, U.S. Treasury inflation-protected securities, commodities, currencies, and derivative instruments such as futures, options, swaps, and forwards. Under the derivative policy, investment managers may not use derivative financial instruments to fundamentally change the risk/return profile of their portfolio relative to their benchmarks.  As of September 30, 2010, and 2009, an immediate 10 percent decrease in the value of the net assets in the fund would have reduced the value of the fund by approximately $680 million, and $660 million, respectively.  See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates — Pension and Other Post-retirement Benefits and Note 18 — Fair Value Measurements.

      Interest Rate Risk

TVA’s interest rate risk is related primarily to its short-term investments, short-term debt, long-term debt, swaption transaction, and interest rate swaps related to three of TVA’s swaption transactions.

Short-Term Investments.   At September 30, 2010, TVA had $328 million of cash and cash equivalents, and the average balance of cash and cash equivalents for 2010 was $234 million.  The average interest rate that TVA received on its short-term investments during 2010 was less than one percent.  If the rates of interest that TVA received on its short-term investments during 2010 were zero percent, TVA would have received less than $1 million in interest from its short-term investments during 2010.  At September 30, 2009, TVA had $201 million of cash and cash equivalents, and the average balance of cash and cash equivalents for 2009, was $471 million.  The average interest rate that TVA received on its short-term investments during 2009 was less than one percent.  If the rates that TVA received on its short-term investments during 2009 were zero percent, TVA would have received approximately $3 million less in interest on short-term investments during 2009.  In addition to affecting the amount of interest that TVA receives from its short-term investments, changes in interest rates could affect the value of the investments in its pension fund, ART, and NDT.  See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations — Risk Management Activities — Investment Price Risk.

Short-Term Debt.  At September 30, 2010, TVA’s short-term borrowings were $27 million, and the current maturities of long-term debt were $1.0 billion.  Based on TVA’s interest rate exposure at September 30, 2010, an immediate one percentage point increase in interest rates would result in an increase of $10 million in TVA’s short-term interest expense.  At September 20, 2009, TVA’s short-term borrowings were $844 million, and the current maturities of long-term debt were $8 million.  Based on TVA’s interest rate exposure at September 30, 2009, an immediate one percentage point increase in interest rates would result in an increase of $9 million in TVA’s short-term interest expense.

Long-Term Debt.  At September 30, 2010, and 2009, the interest rates on all of TVA’s outstanding long-term debt were fixed.  Accordingly, an immediate one percentage point increase in interest rates would not have affected TVA’s interest expense associated with its long-term debt.  When TVA’s long-term debt matures or is redeemed, however, TVA typically refinances this debt by issuing additional long-term debt.  Accordingly, if interest rates are high when TVA issues this additional long-term debt, TVA’s cash flows, results of operations, and financial condition may be adversely affected.  This risk is somewhat mitigated by the fact that TVA’s debt portfolio is diversified in terms of maturities and has a long average life.  As of September 30, 2010, and 2009, the average life of TVA’s debt portfolio was 18.2 years, and 17.5 years, respectively.  A schedule of TVA’s debt maturities is contained in Note 11 — Debt Outstanding.

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Swaption and Interest Rate Swap Agreements. Changes in interest rates also affect the mark-to-market valuation of TVA’s swaption agreement and interest rate swaps.  Net unrealized gains and losses on these transactions are reflected on TVA’s balance sheets in a regulatory asset account, and realized gains and losses are reflected in earnings.  Based on TVA’s interest rate exposure at September 30, 2010, an immediate one percentage point decrease in interest rates would have increased the interest rate swap liabilities by $112 million and the swaption liability by $346 million at September 30, 2010.  Based on TVA’s interest rate exposure at September 30, 2009, an immediate one percentage point decrease in interest rates would have increased the swap liabilities by $151 million.  Due to the low interest rate environment and the nature of the swaption, a full percentage point decrease in rates could not be used to determine the change in the swaption liability for 2009.  However, an immediate decrease of almost half a percentage point in interest rates would have increased the swaption liability by $715 million at September 30, 2009.

Currency Exchange Rate Risk

As of September 30, 2010, and 2009, TVA had three issues of Bonds outstanding whose principal and interest payments were denominated in British pounds sterling.  TVA issued these Bonds in amounts of £200 million, £250 million, and £150 million in 1999, 2001, and 2003, respectively.  When TVA issued these Bonds, it hedged its currency exchange rate risk by entering into currency swap agreements.  Accordingly, as of September 30, 2010, and 2009, a 10 percent change in the British pound sterling-U.S. dollar exchange rate would not have had a material impact on TVA’s cash flows, results of operations, or financial position.

Counterparty Credit Risk

Counterparty credit risk is the exposure to economic loss that would occur as a result of a counterparty’s nonperformance of its contractual obligations.  Where exposed to counterparty credit risk, TVA analyzes the counterparty’s financial condition prior to entering into an agreement, establishes credit limits, monitors the appropriateness of those limits, as well as any changes in the creditworthiness of the counterparty on an ongoing basis, and employs credit mitigation measures, such as collateral or prepayment arrangements and master purchase and sale agreements, to mitigate credit risk.

Credit of Customers.  The majority of TVA’s counterparty credit risk is limited to trade accounts receivable from delivered power sales to municipal and cooperative distributor customers, all located in the Tennessee Valley region.  To a lesser extent, TVA is exposed to credit risk from industries and federal agencies directly served and from exchange power arrangements with a small number of investor-owned regional utilities related to either delivered power or the replacement of open positions of longer-term purchased power or fuel agreements.  As previously mentioned in Item 1, Business — Customers — Other Customers, power sales to United States Enrichment Corp (“USEC”) represented five percent of TVA’s total operating revenues in 2010.  USEC’s senior unsecured credit ratings are currently ‘CCC-’ by Standard & Poor’s and ‘Caa2’ by Moody’s.  As a result of USEC’s credit ratings, it has provided credit assurance to TVA under the terms of its power contract.  TVA also buys a significant amount of uranium enrichment services from USEC.

TVA had concentrations of accounts receivable from seven customers that represented 41 percent of total accounts receivable as of September 30, 2010 and 2009.

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The table below summarizes TVA’s customer credit risk from trade accounts receivable as of September 30, 2010 and 2009:

Customer Credit Risk As of September 30
	2010			2009
Trade Accounts Receivable *
Investment Grade
Municipalities and cooperative distributor customers	$	994		$	790
Exchange power arrangements		3			2
Industries and federal agencies directly served		40			26
Internally rated - investment grade
Municipalities and cooperative distributor customers		542			417
Industries and federal agencies directly served		7			—
Non-investment grade
Industries and federal agencies directly served		11			5
Internally rated - non-investment grade
Exchange power arrangements		—			—
Industries and federal agencies directly served		4			9
Subtotal		1,601			1,249
Other Accounts Receivable
Miscellaneous accounts		40			52
Provision for uncollectible accounts		(2	)		(2	)
Subtotal		38			50
Total	$	1,639		$	1,299
Note * Includes unbilled power receivables of $1,004 million and $940 million as of September 30, 2010 and September 30, 2009, respectively.

Counterparty Performance Risk. In addition to being exposed to economic loss due to the nonperformance of TVA’s customers, TVA is exposed to economic loss because of the nonperformance of its other counterparties, including suppliers and counterparties to its derivative contracts.  Where exposed to performance risk, TVA analyzes the counterparty’s financial condition prior to entering into an agreement and employs performance assurance measures, such as parent guarantees, letters of credit, cash deposits, or performance bonds, to mitigate the risk.

TVA has various agreements under which it has exposure to various institutions with which it does business.  Most of these are not material on a net exposure basis.  TVA believes its policies and procedures for counterparty performance risk reviews have generally protected TVA against significant exposure to institutions in poor financial condition due to recent market and economic conditions.

Credit of Suppliers.  If one of TVA’s fuel or purchased power suppliers fails to perform under the terms of its contract with TVA, TVA might lose the money that it paid to the supplier under the contract and have to purchase replacement fuel or power on the spot market, perhaps at a significantly higher price than TVA was entitled to pay under the contract.  In addition, TVA might not be able to acquire replacement fuel or power in a timely manner and thus might be unable to satisfy its own obligations to deliver power.  As mentioned in Item 1, Business — Power Supply — Purchased Power and Other Agreements, TVA has a power purchase agreement with a supplier that expires on March 31, 2032.  The supplier’s senior secured credit ratings are currently ‘BB-’ by Standard & Poor’s and ‘B2’ with Moody’s.  As a result of the supplier’s credit ratings, the company has provided credit assurance to TVA under the terms of its agreement.

Credit of Derivative Counterparties.  TVA has entered into derivative contracts for hedging purposes, and TVA’s NDT and pension fund have entered into derivative contracts for investment purposes.  If a counterparty to one of TVA’s hedging transactions defaults, TVA might incur substantial costs in connection with entering into a replacement hedging transaction.  If a counterparty to the derivative contracts into which the NDT and the pension fund have entered for investment purposes defaults, the value of the investment could decline significantly, or perhaps become worthless.

Credit of TVA

A downgrade in TVA’s credit rating could have material adverse effects on TVA’s cash flows, results of operations, and financial condition and would harm investors in TVA securities.  Among other things, a downgrade could have the following effects:

•   A downgrade would increase TVA’s interest expense by increasing the interest rates that TVA pays on debt securities that it issues.  An increase in TVA’s interest expense would reduce the amount of cash available for other purposes, which could result in the need to increase borrowings, to reduce other expenses or capital investments, or to increase electricity rates.

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•   A downgrade could result in TVA having to post additional collateral under certain physical and financial contracts that contain rating triggers.

•   A downgrade below a contractual threshold could prevent TVA from borrowing under two credit facilities totaling $2.0 billion.

•   A downgrade could lower the price of TVA securities in the secondary market, thereby hurting investors who sell TVA securities after the downgrade and diminishing the attractiveness and marketability of TVA Bonds.

For a discussion of factors that could lead to a downgrade in TVA’s credit rating, see Item 1A, Risk Factors.

Subsequent Event

See Note 23, which discussion is incorporated by reference into this Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Quantitative and qualitative disclosures about market risk are reported in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations — Risk Management Activities, which discussion is incorporated into this Item 7A, Quantitative and Qualitative Disclosures About Market Risk.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

TENNESSEE VALLEY AUTHORITY STATEMENTS OF OPERATIONS For the years ended September 30 (in millions)
	2010			2009			2008
Operating revenues
Sales of electricity
Municipalities and cooperatives	$	9,275		$	9,644		$	8,659
Industries directly served		1,321			1,367			1,472
Federal agencies and other		117			131			121
Other revenue		161			113			130
Total operating revenues		10,874			11,255			10,382
Operating expenses
Fuel and purchased power		3,219			4,745			4,176
Operating and maintenance		3,232			2,395			2,307
Depreciation, amortization, and accretion		1,724			1,598			1,224
Tax equivalents		457			544			491
Total operating expenses		8,632			9,282			8,198
Operating income		2,242			1,973			2,184
Other income (expense), net		24			25			9
Interest expense
Interest on debt and leaseback obligations		1,353			1,292			1,373
Amortization of debt discount, issue, and reacquisition costs, net		20			20			20
Allowance for funds used during construction and nuclear fuel expenditures		(79	)		(40	)		(17	)
Net interest expense		1,294			1,272			1,376
Net income	$	972		$	726		$	817
The accompanying notes are an integral part of these financial statements.

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TENNESSEE VALLEY AUTHORITY BALANCE SHEETS At September 30 (in millions)
ASSETS
	2010			2009
Current assets
Cash and cash equivalents	$	328		$	201
Accounts receivable, net		1,639			1,299
Inventories		1,012			918
Regulatory assets		791			684
Other current assets		78			111
Total current assets		3,848			3,213
Property, plant, and equipment
Completed plant		42,997			41,273
Less accumulated depreciation		(19,326	)		(18,086	)
Net completed plant		23,671			23,187
Construction in progress		3,008			2,569
Nuclear fuel and capital leases		1,151			961
Total property, plant, and equipment, net		27,830			26,717
Investment funds		1,128			983
Regulatory and other long-term assets
Regulatory assets		9,756			8,994
Other long-term assets		191			110
Total regulatory and other long-term assets		9,947			9,104
Total assets	$	42,753		$	40,017
LIABILITIES AND PROPRIETARY CAPITAL
Current liabilities
Accounts payable and accrued liabilities	$	1,698		$	1,253
Environmental cleanup costs - Kingston ash spill		220			348
Accrued interest		407			401
Current portion of leaseback obligations		74			463
Current portion of energy prepayment obligations		105			105
Regulatory liabilities		63			1,003
Short-term debt, net		27			844
Current maturities of long-term debt		1,008			8
Total current liabilities		3,602			4,425
Other liabilities
Other liabilities		6,255			4,757
Regulatory liabilities		106			30
Asset retirement obligations		2,963			2,683
Leaseback obligations		1,279			940
Energy prepayment obligations		717			822
Environmental cleanup costs - Kingston ash spill		305			354
Total other liabilities		11,625			9,586
Long-term debt, net		22,389			21,788
Total liabilities		37,616			35,799
Commitments and contingencies (Note 20)
Proprietary capital
Appropriation-investment power program		328			348
Retained earnings power program		4,264			3,291
Total power program proprietary capital		4,592			3,639
Appropriation investment nonpower programs, net		640			654
Accumulated other comprehensive loss		(95	)		(75	)
Total proprietary capital		5,137			4,218
Total liabilities and proprietary capital	$	42,753		$	40,017
The accompanying notes are an integral part of these financial statements.

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TENNESSEE VALLEY AUTHORITY STATEMENTS OF CASH FLOWS For the years ended September 30 (in millions)
	2010			2009			2008
Cash flows from operating activities
Net income	$	972		$	726		$	817
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization, and accretion		1,743			1,618			1,244
Nuclear refueling outage amortization		102			122			107
Amortization of nuclear fuel		238			216			189
Non-cash retirement benefit expense		364			146			145
Prepayment credits applied to revenue		(105	)		(105	)		(105	)
Fuel cost adjustment deferral		(898	)		850			123
Environmental cleanup costs – Kingston ash spill – non cash		62			—			—
Changes in current assets and liabilities
Accounts receivable, net		(342	)		90			(59	)
Inventories and other, net		(119	)		(182	)		(138	)
Accounts payable and accrued liabilities		237			94			(78	)
Accrued interest		6			(40	)		35
Pension contributions		(6	)		(1,005	)		(165	)
Refueling outage costs		—			(128	)		(150	)
Environmental cleanup costs – Kingston ash spill		(369	)		(231	)		—
Other, net		16			(8	)		2
Net cash provided by operating activities		1,901			2,163			1,967
Cash flows from investing activities
Construction expenditures		(2,015	)		(1,793	)		(1,984	)
Nuclear fuel expenditures		(401	)		(432	)		(322	)
Change in restricted cash and investments		—			(17	)		25
Purchases of investments		(42	)		(42	)		(39	)
Loans and other receivables
Advances		(25	)		(13	)		(6	)
Repayments		21			11			13
Other, net		4			(1	)		4
Net cash used in investing activities		(2,458	)		(2,287	)		(2,309	)
Cash flows from financing activities
Long-term debt
Issues		1,679			2,369			2,105
Redemptions and repurchases		(69	)		(2,874	)		(689	)
Short-term debt issues (redemptions), net		(817	)		659			(1,237	)
Proceeds from sale/leaseback financing		11			104			325
Payments on leases and leaseback financing		(94	)		(79	)		(43	)
Bond premium received		28			—			—
Financing costs, net		(23	)		(33	)		(32	)
Payments to U.S. Treasury		(29	)		(33	)		(40	)
Other		(2	)		(1	)		1
Net cash provided by financing activities		684			112			390
Net change in cash and cash equivalents		127			(12	)		48
Cash and cash equivalents at beginning of year		201			213			165
Cash and cash equivalents at end of year	$	328		$	201		$	213
See Note 17 for supplemental cash flow information. The accompanying notes are an integral part of these financial statements.

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TENNESSEE VALLEY AUTHORITY STATEMENTS OF CHANGES IN PROPRIETARY CAPITAL For the years ended September 30 (in millions)
	Power Program Appropriation Investment			Power Program Retained Earnings			Nonpower  Appropriation Investment,Net			Accumulated Other Comprehensive Income (Loss)			Total			Comprehensive Income (Loss)
Balance at September 30, 2007	$	388		$	1,763		$	672		$	(19	)	$	2,804
Net income (loss)		–			828			(11	)		–			817		$	817
Other comprehensive income (loss)
Net unrealized gain on future cash flow hedges		–			–			–			(179	)		(179	)		(179	)
Reclassification to earnings from cash flow hedges		–			–			–			161			161			161
Total other comprehensive income (loss)		–			–			–			(18	)		(18	)		(18	)
Total comprehensive income (loss)																$	799
Return on Appropriation Investment		–			(20	)		–			–			(20	)
Return of Appropriation Investment		(20	)		–			–			–			(20	)
Balance at September 30, 2008	$	368		$	2,571		$	661		$	(37	)	$	3,563
Net income (loss)		–			733			(7	)		–			726		$	726
Other comprehensive income (loss)
Net unrealized gain on future cash flow hedges		–			–			–			(146	)		(146	)		(146	)
Reclassification to earnings from cash flow hedges		–			–			–			108			108			108
Total other comprehensive income (loss)		–			–			–			(38	)		(38	)		(38	)
Total comprehensive income (loss)																$	688
Return on Appropriation Investment		–			(13	)		–			–			(13	)
Return of Appropriation Investment		(20	)		–			–			–			(20	)
Balance at September 30, 2009	$	348		$	3,291		$	654		$	(75	)	$	4,218
Net income (loss)		–			982			(10	)		–			972		$	972
Other comprehensive income (loss)
Net unrealized gain on future cash flow hedges		–			–			–			(37	)		(37	)		(37	)
Reclassification to earnings from cash flow hedges		–			–			–			17			17			17
Total other comprehensive income (loss)		–			–			–			(20	)		(20	)		(20	)
Total comprehensive income (loss)																$	952
Return on Appropriation Investment		–			(9	)		–			–			(9	)
Return of Appropriation Investment		(20	)		–			(4	)		–			(24	)
Balance at September 30, 2010	$	328		$	4,264		$	640		$	(95	)	$	5,137
The accompanying notes are an integral part of these financial statements.

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NOTES TO FINANCIAL STATEMENTS

(Dollars in millions except where noted)

Note No.		Page No.
1	Summary of Significant Accounting Policies	81
2	Impact of New Accounting Standards and Interpretations	87
3	Accounts Receivable	88
4	Inventories	88
5	Completed Plant	89
6	Other Long-Term Assets	89
7	Regulatory Assets and Liabilities	90
8	Kingston Fossil Plant Ash Spill	92
9	Other Long-Term Liabilities	94
10	Asset Retirement Obligations	94
11	Debt	95
12	Seven States Power Corporation Obligation	100
13	Risk Management Activities and Derivative Transactions	100
14	Fair Value Measurements	107
15	Proprietary Capital	112
16	Other Income (Expense), Net	114
17	Supplemental Cash Flow Information	114
18	Benefit Plans	114
19	Asset Acquisitions and Dispositions	124
20	Commitments and Contingencies	125
21	Related Parties	132
22	Unaudited Quarterly Financial Information	133
23	Subsequent Event	133

1.  Summary of Significant Accounting Policies

General

In response to a request by President Franklin D. Roosevelt, the U.S. Congress in 1933 enacted legislation creating the Tennessee Valley Authority (“TVA”), a government corporation.  TVA was created to, among other things, improve navigation on the Tennessee River, reduce the damage from destructive flood waters within the Tennessee River system and downstream on the lower Ohio and Mississippi Rivers, further the economic development of TVA’s service area in the southeastern United States, and sell the electricity generated at the facilities TVA operates.

Today, TVA operates the nation’s largest public power system and supplies power in most of Tennessee, northern Alabama, northeastern Mississippi, and southwestern Kentucky and in portions of northern Georgia, western North Carolina, and southwestern Virginia to a population of over nine million people.

TVA also manages the Tennessee River and its tributaries to provide, among other things, year-round navigation, flood damage reduction, and affordable and reliable electricity.  Consistent with these primary purposes, TVA also manages the river system to provide recreational opportunities, adequate water supply, improved water quality, natural resource protection, and economic development.

The power program has historically been separate and distinct from the stewardship programs.  It is required to be self-supporting from power revenues and proceeds from power financings, such as proceeds from the issuance of bonds, notes, and other evidences of indebtedness (“Bonds”).  Although TVA does not currently receive congressional appropriations, it is required to make annual payments to the U.S. Treasury in repayment of, and as a return on, the government’s appropriation investment in TVA power facilities (the “Power Program Appropriation Investment”).  In the 1998 Energy and Water Development Appropriations Act, Congress directed TVA to fund essential stewardship activities related to its management of the Tennessee River system and TVA properties with power funds in the event that there were insufficient appropriations or other available funds to pay for such activities in any fiscal year.  Congress has not provided any appropriations to TVA to fund such activities since 1999.  Consequently, during 2000, TVA began paying for essential stewardship activities primarily with power revenues, with the remainder funded with user fees and other forms of revenues derived in connection with those activities.  These activities related to stewardship properties do not meet the criteria of an operating segment under accounting principles generally accepted in the United States (“GAAP”).  Accordingly, these assets and properties are included as part of the power program, TVA’s only operating segment.

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Power rates are established by the TVA board of directors (“TVA Board”) as authorized by the Tennessee Valley Authority Act of 1933, as amended, 16 U.S.C. §§ 831-831ee (as amended, the “TVA Act”).  The TVA Act requires TVA to charge rates for power that will produce gross revenues sufficient to provide funds for operation, maintenance, and administration of its power system; payments to states and counties in lieu of taxes; debt service on outstanding indebtedness; payments to the U.S. Treasury in repayment of and as a return on the Power Program Appropriation Investment; and such additional margin as the TVA Board may consider desirable for investment in power system assets, retirement of outstanding Bonds in advance of maturity, additional reduction of the Power Program Appropriation Investment, and other purposes connected with TVA’s power business.  In setting TVA’s rates, the TVA Board is charged by the TVA Act to have due regard for the primary objectives of the TVA Act, including the objective that power shall be sold at rates as low as are feasible.  Rates set by the TVA Board are not subject to review or approval by any state or federal regulatory body.

Fiscal Year

TVA’s fiscal year ends September 30.  Years (2010, 2009, etc.) refer to TVA’s fiscal years unless they are proceeded by “CY,” in which case the references are to calendar years.

Cost-Based Regulation

Since TVA’s Board is authorized by the TVA Act to set rates for power sold to its customers; TVA is “self regulated.”  Additionally, TVA’s regulated rates are designed to recover its costs of providing electricity.  In view of demand for electricity and the level of competition, it is reasonable to assume that the rates, set at levels that will recover TVA’s costs, can be charged and collected.  As a result of these factors, TVA records certain assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities.  Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates.  Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that are not likely to be incurred or deferral of gains that will be credited to customers in future periods.  TVA assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes, potential legislation, and changes in technology.  Based on these assessments, TVA believes the existing regulatory assets are probable of recovery.  This determination reflects the current regulatory and political environment and is subject to change in the future.  If future recovery of regulatory assets ceases to be probable, or any of the other factors described above cease to be applicable, TVA would no longer be considered to be a regulated entity and would be required to write off these costs.  Most regulatory asset write-offs would be required to be recognized in earnings in the period in which future recovery ceases to be probable.

Use of Estimates

The preparation of financial statements requires TVA to estimate the effects of various matters that are inherently uncertain as of the date of the financial statements.  Although the financial statements are prepared in conformity with GAAP, TVA is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the amounts of revenues and expenses reported during the reporting period.  Each of these estimates varies in regard to the level of judgment involved and its potential impact on TVA’s financial results.  Estimates are deemed critical either when a different estimate could have reasonably been used, or where changes in the estimate are reasonably likely to occur from period to period, and such use or change would materially impact TVA’s financial conditions, results of operations, or cash flows.

Reclassifications  

Certain prior period amounts have been reclassified to conform to the current presentation.  Such reclassifications were limited to balance sheets and statements of cash flow presentation and did not impact the statements of operations.  The reclassifications are due primarily to the addition of new line items to the balance sheets to separate the current portions of regulatory assets and regulatory liabilities, separate other current assets from inventories, and display appropriation investments in power and nonpower programs, as well as to recognize the current and long-term assets and liabilities of derivative instruments.  In addition, in the 2009 and 2008 Statements of Cash Flows, TVA reclassified $22 million and $10 million, respectively, from Construction expenditures to Accounts payable and accrued liabilities that related to additions to regulatory assets that had been reclassified in the 2009 Balance Sheet from Property, plant and equipment.

Cash and Cash Equivalents

Cash and cash equivalents include the cash available in TVA’s commercial bank accounts and U.S. Treasury accounts, as well as short-term securities held for the primary purpose of general liquidity.  Such securities mature within three months from the original date of issuance.

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Allowance for Uncollectible Accounts

The allowance for uncollectible accounts reflects TVA’s estimate of probable losses inherent in the accounts receivable, unbilled revenue, and loans receivable balances.  TVA determines the allowance based on known accounts, historical experience, and other currently available information including events such as customer bankruptcy and/or a customer failing to fulfill payment arrangements after 90 days.  It also reflects TVA’s corporate credit department assessment of the financial condition of customers and the credit quality of the accounts.  The allowance for uncollectible accounts was $2 million at September 30, 2010, and 2009, for accounts receivable.  Additionally, loans receivable of $83 million and $81 million as of September 30, 2010, and 2009, respectively, are included in Other long-term assets, and reported net of allowances for uncollectible accounts of $13 million as of both September 30, 2010, and 2009.

Revenues

Revenues from power sales are recorded as power is delivered to customers. In addition to power sales invoiced and recorded during the month, TVA accrues estimated unbilled revenues for power sales provided to customers for the period of time from the meter-read date to the end of the month.  Components of the unbilled revenue include wholesale meter readings at estimated rates based on the historical usage and product mix and sales of excess generation at market rates.  These factors can vary from historical trends.  Exchange power sales are presented in the accompanying Statements of Operations as a component of Sales of electricity — federal agencies and other. Exchange power sales are sales of excess power after meeting TVA native load and directly served requirements.  (Native load refers to the customers on whose behalf a company, by statute, franchise, regulatory requirement, or contract, has undertaken an obligation to serve.)

TVA periodically transfers fiber optic capacity on TVA’s network to telecommunications service carriers and TVA distributor customers.  These transactions are structured as indefeasible rights of use (“IRUs”) which are the exclusive right to use a specified amount of fiber optic capacity for a specified term.  TVA accounts for the consideration received on transfers of fiber optic capacity for cash and on all of the other elements deliverable under an IRU as revenue ratably over the term of the agreement.  TVA does not recognize revenue on any contemporaneous exchanges of its optical capacity for an IRU of optical capacity of the counterparty to the exchange.

      Inventories

Certain Fuel, Materials, and Supplies.  Coal, oil, limestone, tire-based fuel inventories, and materials and supplies inventories are valued using an average unit cost method.  A new average cost is computed after each transaction, and inventory issuances are priced at the latest moving weighted average unit cost.

Allowance for Inventory Obsolescence.  TVA reviews supply and material inventories by category and usage on a periodic basis.  Each category is assigned a probability of becoming obsolete based on the type of material and historical usage data.  Based on the estimated value of the inventory, TVA adjusts its allowance for inventory obsolescence.

Emission Allowances.  TVA has emission allowances for sulfur dioxide (“SO2”) and nitrogen oxides (“NOx”) which are accounted for as inventory.  The average cost of allowances used each month is charged to operating expense based on tons of SO2 and NOx emitted during the respective compliance periods.  Allowances granted to TVA by the Environmental Protection Agency (“EPA”) are recorded at zero cost.

Property, Plant, and Equipment, and Depreciation

Property, Plant, and Equipment. Additions to plant are recorded at cost, which includes direct and indirect costs and an allowance for funds used during construction (“AFUDC”).  The cost of current repairs and minor replacements is charged to operating expense.  Nuclear fuel inventories, which are included in Property, plant, and equipment, are valued using the average cost method for raw materials and the specific identification method for nuclear fuel in a reactor.  Amortization of nuclear fuel in a reactor is calculated on a units-of-production basis and is included in fuel expense.

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Depreciation.  TVA accounts for its properties’ depreciation using the composite depreciation convention of accounting.  Accordingly, the original cost of property retired, less salvage value, is charged to accumulated depreciation.  Except as described below, depreciation is generally computed on a straight-line basis over the estimated service lives of the various classes of assets.  Depreciation expense expressed as a percentage of the average annual depreciable completed plant was 2.92 percent for 2010, 2.81 percent for 2009, and 2.97 percent for 2008.  Average depreciation rates by asset class are as follows:

TVA Property, Plant, and Equipment Depreciation Rates As of September 30
	2010	2009	2008
Asset Class:		(percent)
Nuclear	2.59	2.59	2.57
Coal-Fired	3.22	3.22	3.44
Hydroelectric	1.65	1.65	1.72
Combustion turbine/diesel generators	4.09	4.09	4.39
Transmission	3.40	3.40	2.74
Other	6.03	4.91	6.38

Depreciation rates are determined based on an external depreciation study.  TVA obtained and implemented a new study during the fourth quarter of 2008.  Rates were changed prospectively as a change in estimate.  Depreciation expense for the years ended September 30, 2010, 2009, and 2008, was $1.2 billion, $1.2 billion, and $1.1 billion, respectively.  Depreciation rates were adjusted to ensure that those coal-fired units which have been identified to be idled will be fully depreciated by those idled dates.  In September 2010, TVA idled Widows Creek Fossil Plant (“Widows Creek”) Unit 5, and in October 2010 TVA idled Widows Creek Unit 2 as well as Shawnee Fossil Plant Unit 10.  The accelerated depreciation expense of the three units in 2010 was $35 million.  An additional six fossil units are currently expected to be idled by 2015.  The accelerated depreciation expense on those units in 2010 was $2 million.

Capital Lease Agreements.  Property, plant, and equipment also includes assets recorded under capital lease agreements which primarily consist of office facilities of $27 million and $35 million as of September 30, 2010, and 2009, respectively, and fuel fabrication and blending facilities of $22 million and $28 million as of September 30, 2010, and 2009, respectively.

       Allowance for Funds Used During Construction.   AFUDC capitalized during the year ended September 30, 2010, was $79 million as compared with $40 million capitalized during the year ended September 30, 2009.  TVA capitalizes interest as AFUDC, based on the average interest rate of TVA’s outstanding debt.  The allowance is applicable to construction in progress related to certain projects and certain nuclear fuel inventories.  Since October 1, 2007, interest on funds invested in capital projects has been capitalized only for projects with (1) an expected total project cost of $1.0 billion or more, and (2) an estimated construction period of at least three years in duration.  The adoption of this new criteria has greatly reduced the number of qualifying projects, which was approximately 800 at September 30, 2007.

Only the Watts Bar Nuclear Plant Unit 2 (“Watts Bar Unit 2”) construction met the new AFUDC criteria during the year ended September 30, 2010.  The accumulated balance of costs for qualifying projects, which is used to calculate AFUDC, averaged approximately $1.0 billion for the year ended September 30, 2010.

Software Costs.  TVA capitalizes certain costs incurred in connection with developing or obtaining internal-use software.  Capitalized software costs are included in Property, plant, and equipment on the balance sheet and are primarily amortized over five years.  As of September 30, 2010, and 2009, unamortized computer software costs totaled $139 million and $152 million, respectively.  Amortization expense related to capitalized computer software costs was $45 million, $24 million, and $13 million for 2010, 2009, and 2008, respectively.  Software costs that do not meet capitalization criteria are expensed as incurred.

           Impairment of Assets.  TVA evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable.  For long-lived assets, TVA bases its evaluation on impairment indicators such as the nature of the assets, the future economic benefit of the assets, any historical or future profitability measurements, and other external market conditions or factors that may be present.  If such impairment indicators are present or other factors exist that indicate that the carrying amount of an asset may not be recoverable, TVA determines whether an impairment has occurred based on an estimate of undiscounted cash flows attributable to the asset as compared with the carrying value of the asset.  If an impairment has occurred, the amount of the impairment recognized is measured as the excess of the asset’s carrying value over its fair value.  Additionally, TVA regularly evaluates construction projects.  If the project is cancelled or deemed to have no future economic benefit, the project is written off as an asset impairment.

Decommissioning Costs

TVA recognizes legal obligations associated with the future retirement of certain tangible long-lived assets.  These obligations relate to fossil-fired generating plants, nuclear generating plants, hydroelectric generating plants/dams, transmission structures, and other property-related assets.  These other property-related assets include, but are not limited to, easements, leases, and coal rights.  Activities involved with retiring these assets could include decontamination and demolition of structures, removal and disposal of wastes, and site

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reclamation.  Revisions to the estimates of asset retirement obligation (“AROs”) are made whenever factors indicate that the timing or amounts of estimated cash flows have changed.  Any accretion or depreciation expense related to these liabilities and assets are charged to a regulatory asset.  See Note 7 — Nuclear Decommissioning Costs and Non-Nuclear Decommissioning Costs.

Blended Low Enriched Uranium Program

Under the blended low enriched uranium (“BLEU”) program, TVA, the Department of Energy (“DOE”), and some nuclear fuel contractors have entered into agreements providing for surplus highly enriched uranium to be blended with other uranium down to a level that allows the blended uranium to be fabricated into fuel that can be used in nuclear power plants.  This blended nuclear fuel was first loaded in a Browns Ferry reactor in 2005, which initiated the amortization of the costs of the BLEU fuel assemblies to nuclear fuel expense.  TVA expects to continue to use the blended nuclear fuel to reload the Browns Ferry reactors through at least 2016.  BLEU fuel was loaded into Sequoyah Unit 2 in 2008 and 2009 and is expected to be loaded again in CY 2011.

Under the terms of an interagency agreement between TVA and DOE, DOE supplies off-specification, highly enriched uranium materials to the appropriate third party fuel processors for processing into usable fuel for TVA.  In exchange, DOE will participate to a degree in the savings generated by TVA’s use of this blended nuclear fuel.  Over the life of the program, TVA projects that DOE’s share of savings generated by TVA’s use of this blended nuclear fuel could result in future payments to DOE of as much as $359 million.  TVA accrues an obligation with each BLEU reload batch related to the portion of the ultimate future payments estimated to be attributable to the BLEU fuel currently in use.  As of September 30, 2010, this obligation was $52 million.  During 2009, the DOE and TVA agreed that this obligation will be offset by amounts that DOE expects to owe TVA in the future for certain decommissioning costs that TVA will pay on DOE’s behalf.  Accordingly, TVA will remit the BLEU fuel savings amounts to DOE, plus accrued interest, only after those future decommissioning costs have been offset against TVA’s obligation to DOE.

The third party fuel processors own the conversion and processing facilities and will retain title to all land, property, plant, and equipment used in the BLEU fuel program.  However, the fuel fabrication contract qualifies as a capital lease, and TVA recognized a capital lease asset and corresponding lease obligation related to amounts paid or payable to the processor.

Investment Funds

Investment funds consist primarily of trust funds designated to fund nuclear decommissioning requirements (see Note 20 — Contingencies — Decommissioning Costs), AROs (see Note 7 — Non-Nuclear Decommissioning Costs), and the supplemental executive retirement plan (“SERP”) (see Note 18 — Overview of Plans and Benefits — Supplemental Executive Retirement Plan).  Nuclear decommissioning funds and SERP funds, which are classified as trading, are invested in portfolios of securities generally designed to earn returns in line with overall equity market performance.  Asset retirement funds, which are classified as trading, are invested in securities and commingled funds designed to earn returns in line with fixed-income market performance.

Energy Prepayment Obligations and Discounts on Sales

During 2002, TVA introduced an energy prepayment program, the discounted energy units (“DEU”) program.  Under this program, TVA customers could purchase DEUs generally in $1 million increments, and each DEU entitles the purchaser to a $0.025/kilowatt-hour discount on a specified quantity of firm power over a period of years (five, 10, 15, or 20) for each kilowatt-hour in the prepaid block.  The remainder of the price of the kilowatt-hours delivered to the customer is due upon billing.  TVA’s DEU program allowed customers to use cash on hand to prepay TVA for some of their power needs, providing funding to TVA and a savings to customers in the form of a discount on future purchases.  The distributor customer receives a discount on a specified volume of firm energy purchased.  The supplement to the power contract specifies the discount rate (2.5 cents per kilowatt-hour), the monthly block of kilowatt-hours to which the discount applies, the number of years (term), and contingencies upon contract termination.

TVA has not offered the DEU program since the end of 2004.  The last distributor to participate in the program enrolled in January 2004.  Total sales for the program since inception have been approximately $55 million.  TVA is accounting for the prepayment proceeds as unearned revenue and is reporting the obligations to deliver power as Energy prepayment obligations and Current portion of energy prepayment obligations on the September 30, 2010, and 2009, Balance Sheets.

TVA recognizes revenue as electricity is delivered to customers, based on the ratio of units of kilowatt-hours delivered to total units of kilowatt-hours under contract.  As of September 30, 2010, approximately $42 million has been applied against power billings on a cumulative basis during the life of the program, of which approximately $5 million was recognized as noncash revenue during 2010.  Approximately $5 million and $6 million were applied against power billings during each of 2009 and 2008, respectively.

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In 2004, TVA and its largest customer, Memphis Light, Gas and Water Division (“MLGW”), entered into an energy prepayment agreement under which MLGW prepaid TVA $1.5 billion for the future costs of electricity to be delivered by TVA to MLGW over a period of 180 months.  TVA accounted for the prepayment as unearned revenue and is reporting the obligation to deliver power under this arrangement as Energy prepayment obligations and Current portion of energy prepayment obligations on the September 30, 2010 and 2009 Balance Sheets.  TVA expects to recognize approximately $100 million of noncash revenue in each year of the arrangement as electricity is delivered to MLGW based on the ratio of units of kilowatt-hours delivered to total units of kilowatt-hours under contract.  As of September 30, 2010, $690 million had been recognized as noncash revenue on a cumulative basis during the life of the agreement, $100 million of which was recognized as noncash revenue during each of 2010, 2009, and 2008.

Discounts for both programs amounted to $47 million for each of the years ended September 30, 2010, 2009, and 2008.

Insurance

Although TVA uses private companies to administer its health-care plans for eligible active and retired employees not covered by Medicare, TVA does not purchase health insurance.  Third party actuarial specialists assist TVA in determining certain liabilities for self-assumed claims.  TVA recovers the costs of claims through power rates and through adjustments to the participants’ contributions to their benefit plans.  These liabilities are included in Other liabilities on the balance sheets.

TVA purchases nuclear liability insurance, nuclear property, decommissioning, and decontamination insurance, and nuclear accidental outage insurance.  See Note 20 — Contingencies — Nuclear Insurance.

The Federal Employees’ Compensation Act governs liability to employees for service-connected injuries.  TVA purchases excess workers' compensation insurance above a self insured retention.

TVA purchases excess liability insurance for aviation, auto, marine, and general liability exposures.  TVA purchases property insurance for certain conventional (non-nuclear) assets as well as outage insurance (business interruption) for selected conventional generating assets.

TVA also purchases liability insurance which provides coverage for its directors and officers subject to the terms and conditions of the policy.  Each of the insurance policies purchased contains deductibles or self insured retentions.  The limits, terms, conditions, and deductibles are comparable to those carried by other utilities of similar size.  TVA recovers the costs of losses through power rates.

Operation of dams, transmission facilities, and generating facilities involves inherent risks which may present potential exposures in excess of insurance coverage.

Research and Development Costs

Research and development costs are expensed when incurred.  TVA’s research programs include those related to transmission technologies, emerging technologies (clean energy, renewables, distributed resources, and energy efficiency), technologies related to generation (fossil, nuclear, and hydro), and environmental technologies.

Tax Equivalents

The TVA Act requires TVA to make payments to states and counties in which TVA conducts its power operations and in which TVA has acquired power properties previously subject to state and local taxation.  The amount of these payments is five percent of gross revenues from sales of power during the preceding year, excluding sales or deliveries to other federal agencies and off-system sales with other utilities, with a provision for minimum payments under certain circumstances.

Maintenance Costs

TVA records maintenance costs and repairs related to its property, plant, and equipment on TVA’s statements of operations as they are incurred except for the recording of certain regulatory assets.  Historically, TVA deferred nuclear outage costs that were incurred during the operating cycle subsequent to the refueling outage.  These costs are incurred in the process of performing a nuclear fuel reload outage, and the benefits of these costs are realized during the subsequent 18 to 24 months when the nuclear fuel is burned during its operating cycle in producing electricity.  The TVA Board historically included in rates the amortization of these deferred nuclear outage costs during the operating cycle subsequent to the refueling outage.

Beginning in 2010, TVA implemented a new policy to expense any future outage costs as incurred.  However, TVA will continue to amortize the related existing regulatory asset and include such amounts in rates.  See Note 7 – Deferred Outage Costs.

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2.  Impact of New Accounting Standards and Interpretations

       The following accounting standards and interpretations became effective for TVA during 2010.

Fair Value Measurements.  In September 2006, the Financial Accounting Standards Board (“FASB”) issued guidance for measuring assets and liabilities that currently require fair value measurement.  The guidance also responds to investors’ requests for expanded information about the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurements on earnings.  The guidance applies whenever other standards require (or permit) assets or liabilities to be measured at fair value but does not expand the use of fair value in any new circumstances.  The guidance establishes a fair value hierarchy that prioritizes the information used to develop measurement assumptions.  In February 2008, FASB issued guidance that delayed the effective date of the fair value accounting changes for nonfinancial assets and nonfinancial liabilities except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis.  Effective October 1, 2008, TVA adopted these fair value accounting changes for its nonfinancial assets and nonfinancial liabilities.  The adoption of this guidance did not materially impact TVA’s financial condition, results of operations, or cash flows.

 

           In August 2009, FASB issued guidance regarding fair value measurements of liabilities.  The guidance clarifies how the fair value of a liability should be measured when a quoted price in an active market for the identical liability either is or is not available.  Additionally, the guidance clarifies how to consider a restriction when estimating the fair value of a liability and the appropriate level within the fair value disclosure hierarchy in which the various measurement techniques result.  These changes became effective for TVA on October 1, 2009.  The adoption of this guidance changed certain financial statement disclosures but did not materially impact TVA’s financial condition, results of operations, or cash flows.

In September 2009, FASB issued guidance regarding fair value measurements for certain alternative investments, such as interests in hedge funds, private equity funds, real estate funds, venture capital funds, offshore fund vehicles, and funds of funds.  The guidance allows reporting entities to use net asset value per share to estimate the fair value of these investments as a practical expedient.  The guidance also requires disclosures by major category of investment about the attributes of the investments, such as the nature of any restrictions on the investor's ability to redeem its investments at the measurement date, any unfunded commitments, and the investment strategies of the investees.  These changes became effective for TVA on October 1, 2009.  The adoption of this guidance changed certain financial statement disclosures but did not materially impact TVA’s financial condition, results of operations, or cash flows.  See Note 14 — Investments for related fair value disclosures for TVA’s investments.

Employers’ Disclosures about Post-retirement Benefit Plan Assets. In December 2008, FASB issued guidance that changes employers’ disclosures about post-retirement benefit plan assets.  The guidance requires that an employer disclose the following information about the plan assets: (1) information regarding how investment allocation decisions are made; (2) the major categories of plan assets; (3) information about the inputs and valuation techniques used to measure fair value of the plan assets; (4) the effect of fair value measurements using significant unobservable inputs on changes in plan assets for the period; and (5) significant concentrations of risk within plan assets.  At initial adoption, these changes became effective for TVA on October 1, 2009.  Upon initial application, these changes were not required for earlier periods that are presented for comparative purposes.  See Note 18 — Fair Value Measurements for disclosure of fair value measurements for investments held by TVARS that support TVA’s qualified defined benefit pension plan.

Business Combinations.  In December 2007, FASB issued guidance that changes the accounting for business combinations.  The guidance establishes principles and requirements for determining how an enterprise recognizes and measures the fair value of certain assets and liabilities acquired in a business combination, including non-controlling interests, contingent consideration, and certain acquired contingencies.  The guidance also requires acquisition-related transaction expenses and restructuring costs to be expensed as incurred rather than capitalized as a component of the business combination.  In April 2009, FASB issued additional guidanceto amend and clarify the initial recognition and measurement, subsequent measurement and accounting, and related disclosures arising from contingencies in a business combination.  This guidance became effective for TVA as of October 1, 2009.  The adoption of this guidance did not materially impact TVA’s financial condition, results of operations, or cash flows but will impact the accounting for any future business acquisitions.

Noncontrolling Interests.  In December 2007, FASB issued guidance that introduces significant changes in the accounting for noncontrolling interests (formerly minority interests) in a partially-owned consolidated subsidiary.  The guidance also changes the accounting for and reporting for the deconsolidation of a subsidiary.  The guidance requires that noncontrolling interests in a consolidated subsidiary be displayed in the consolidated statement of financial position as a separate component of equity.  The guidance also requires that earnings attributed to noncontrolling interests be reported as part of consolidated earnings, and requires disclosure of the attribution of consolidated earnings to the controlling and noncontrolling interests on the face of the consolidated income statement.  These changes became effective for TVA as of October 1, 2009.  The adoption of this guidance did not materially impact TVA’s financial condition, results of operations, or cash flows but will impact the accounting for any future noncontrolling interests.

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The following accounting standards have been issued, but as of September 30, 2010, were not effective and had not been adopted by TVA.

Transfers of Financial Assets.  In June 2009, FASB issued guidance regarding accounting for transfers of financial assets.  This guidance eliminates the concept of a qualifying special-purpose entity (“QSPE”) and subjects those entities to the same consolidation guidance as other variable interest entities (“VIEs”).  The guidance changes the eligibility criteria for certain transactions to qualify for sale accounting and the accounting for certain transfers.  The guidance also establishes broad disclosure objectives and requires extensive specific disclosure requirements related to the transfers.  These changes became effective for TVA for any transfers of financial assets occurring on or after October 1, 2010.  TVA does not believe adoption of this guidance will materially affect its financial condition, results of operations, or cash flows.

Variable Interest Entities.  In June 2009, FASB issued guidance that changes the consolidation guidance for VIEs.  The guidance eliminates the consolidation scope exception for QSPEs.  The statement amends the triggering events to determine if an entity is a VIE, establishes a primarily qualitative model for determining the primary beneficiary of the VIE, and requires on-going assessment of whether the reporting entity is the primary beneficiary.  These changes became effective for TVA on October 1, 2010, and apply to all entities determined to be VIEs as of and subsequent to the date of adoption.  TVA does not believe adoption of this guidance will materially affect its financial condition, results of operations, or cash flows.

3.  Accounts Receivable

Accounts receivable primarily consist of amounts due from customers for power sales.  The table below summarizes the types and amounts of receivables:

Accounts Receivable As of September 30
	2010			2009
Power receivables
Billed	$	597		$	309
Unbilled		1,004			940
Total power receivables		1,601			1,249
Other receivables		40			52
Allowance for uncollectible accounts	$	(2	)	$	(2	)
Net accounts receivable	$	1,639		$	1,299

4.  Inventories

The table below summarizes the types and amounts of TVA’s inventories:

Inventories As of September 30
	At September 30, 2010			At September 30, 2009
Fuel inventory	$	539		$	534
Materials and supplies inventory		486			422
Emission allowance inventory		11			12
Allowance for inventory obsolescence		(24	)		(50	)
Inventories, net	$	1,012		$	918

The $26 million reduction in the allowance for inventory obsolescence is primarily due to changes in assumptions based on a detailed inventory observation study completed in 2010.

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5.  Completed Plant

Completed plant consisted of the following at September 30:

TVA Completed Plant As of September 30
	2010						2009
	Cost		Accumulated Depreciation		Net		Cost		Accumulated Depreciation		Net
Coal-Fired	$	12,920	$	6,731	$	6,189	$	12,171	$	6,286	$	5,885
Combustion turbine		2,124		737		1,387		1,653		678		975
Nuclear		17,681		7,866		9,815		17,621		7,440		10,181
Transmission		5,532		2,084		3,448		5,201		1,899		3,302
Hydroelectric		2,193		819		1,374		2,154		791		1,363
Other electrical plant		1,575		745		830		1,501		657		844
Subtotal		42,025		18,982		23,043		40,301		17,751		22,550
Multipurpose dams		928		331		597		928		323		605
Other stewardship		44		13		31		44		12		32
Subtotal		972		344		628		972		335		637
Total	$	42,997	$	19,326	$	23,671	$	41,273	$	18,086	$	23,187

6.  Other Long-Term Assets

The table below summarizes the types and amounts of TVA’s Other long-term assets:

Other Long-Term Assets As of September 30
	2010		2009
Loans and long-term receivables, net	$	83	$	81
Currency swap assets		–		7
Coal contract derivative assets		103		18
Other long-term assets		5		4
Total other long-term assets	$	191	$	110

The increase in coal contract derivative assets during 2010 is due to the change in the market value of coal in relation to the value of contracted amounts for future purchases.

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7.  Regulatory Assets and Liabilities

Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates.  Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that are not likely to be incurred or deferral of gains that will be credited to customers in future periods.  Components of regulatory assets and regulatory liabilities are summarized in the table below.

TVA Regulatory Assets and Liabilities As of September 30
	2010		2009
Current regulatory assets
Deferred capital leases	$	14	$	15
Deferred nuclear generating units		391		391
Deferred outage costs		42		103
Environmental cleanup costs – Kingston ash spill		76		62
Fuel cost adjustment receivable		76		—
Fuel cost adjustment tax equivalents		8		—
Unrealized losses on coal contracts		47		44
Unrealized losses related to TVA’s Financial Trading Program		137		69
Total current regulatory assets		791		684
Non-current regulatory assets
Debt reacquisition costs		174		195
Deferred capital leases		10		25
Deferred nuclear generating units		1,565		1,956
Deferred other post-retirement benefit costs		255		298
Deferred outage costs		—		42
Deferred pension		4,456		3,765
Environmental cleanup costs – Kingston ash spill		987		870
Non-nuclear decommissioning		410		351
Nuclear decommissioning		898		909
Nuclear training costs		59		43
Retirement removal costs		1		—
Unrealized losses on coal contracts		2		26
Unrealized losses on swaps and swaptions		797		498
Unrealized losses related to TVA’s Financial Trading Program		142		16
Total non-current regulatory assets		9,756		8,994
Total regulatory assets	$	10,547	$	9,678
Current regulatory liabilities
Capital leases	$	6	$	21
Fuel cost adjustment		—		822
Fuel cost adjustment tax equivalents		—		81
Unrealized gains on coal contract derivatives		50		68
Unrealized gains relating to TVA’s Financial Trading Program		7		11
Total current liabilities		63		1,003
Non-current regulatory liabilities
Capital leases		—		5
Unrealized gains on coal contract derivatives		103		19
Unrealized gains relating to TVA’s Financial Trading Program		3		6
Total non-current regulatory liabilities		106		30
Total regulatory liabilities	$	169	$	1,033

Deferred Pension Costs and Other Post-retirement Benefit Costs.  TVA measures its benefit obligations related to pension and other post-retirement benefit (“OPEB”) costs as of the year-end balance sheet date.  TVA recognizes the funded status of the plans on the balance sheet which in an unregulated environment would result in a corresponding offset to accumulated other comprehensive income (“AOCI”).  “Incurred cost” is a cost arising from cash paid out or obligation to pay for an acquired asset or service, and a loss from any cause that has been sustained and has been or must be paid for.  In the cases of pension and OPEB costs, the unfunded obligation represents a projected liability to the employee for services rendered, and thus it meets the definition of an incurred cost.  Therefore, amounts otherwise charged to AOCI for these costs will be recorded as a regulatory asset since TVA has historically recovered pension and OPEB expense in rates.  Through historical and current year expense included in ratemaking, the TVA Board has demonstrated the ability and intent to include pension and OPEB costs in allowable costs and in rates for ratemaking purposes.  As a result, it is probable that future revenue, if necessary, will result from inclusion of the pension and OPEB regulatory assets in allowable costs for ratemaking purposes.

These regulatory assets are classified as long-term consistent with the pension and post-retirement liabilities and not amortized to the statement of operations over a specified recovery period.  They are adjusted either upward or downward each year in conjunction with the adjustments in the unfunded pension liability as calculated by the actuaries.  Ultimately this regulatory asset will flow through the statement of operations in the form of pension expense as the actuarial liability is eliminated in future periods.

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Nuclear Decommissioning Costs.  Nuclear decommissioning costs include: (1) certain deferred charges related to the future closure and decommissioning of TVA’s nuclear generating units under Nuclear Regulatory Commission (“NRC”) requirements and (2) recognition of changes in the liability, TVA’s Nuclear Decommissioning Trust (“NDT”), and certain other deferred charges under the accounting rules for AROs.  These future costs will be funded through a combination of the NDT, future earnings on the NDT, and if necessary, additional TVA cash contributions to the NDT, and future earnings thereon.  See Note 1 — Investment Funds.  There is not a specified recovery period; therefore, the regulatory asset is classified as long-term consistent with the NDT investments and ARO liability.

Non-Nuclear Decommissioning Costs.  TVA has established an Asset Retirement Trust (“ART”) to more effectively segregate, manage, and invest funds to help meet future AROs.  The funds from the ART may be used, among other things, to pay the cost of retiring non-nuclear long-lived assets.  The costs of retiring non-nuclear long-lived assets represent the net deferred costs related to the future closure and retirement of TVA's non-nuclear long-lived assets under various legal requirements.  These costs did not previously meet the asset recognition criteria under the GAAP guidance in effect at the date the costs were incurred.  Because of the establishment of the ART and the approval of its funding in rates as part of the TVA Board’s budget and ratemaking process, these costs met asset recognition criteria in the fourth quarter of 2008.  Accordingly, all cumulative ARO costs were recaptured as a regulatory asset as of September 30, 2008.  The regulatory asset initially created related to this adjustment totaled $350 million.  The offset to this adjustment was a one-time decrease to depreciation, amortization, and accretion expense.  These future costs can be funded through a combination of investment funds already set aside in the ART, future earnings on those investment funds, and future cash contributions to the ART and future earnings thereon.  There is not a specified recovery period; therefore, the regulatory asset is classified as long-term consistent with the ART investments and ARO liability.

Debt Reacquisition Costs.  Reacquisition expenses, call premiums, and other related costs, such as unamortized debt issue costs associated with redeemed Bond issues, are deferred under provisions of the Federal Energy Regulatory Commission’s (“FERC”) Uniform System of Accounts Prescribed for Public Utilities and Licensees Subject to the Provisions of the Federal Power Act (“Uniform System of Accounts”).  These costs are deferred and amortized (accreted) on a straight-line basis over the weighted average life of TVA’s debt portfolio (even though TVA is not a public utility subject generally to FERC jurisdiction).

Deferred Gains and Losses Relating to TVA’s Financial Trading Program.  Deferred gains and losses relating to TVA’s Financial Trading Program (“FTP”) represent net unrealized gains and losses on swaps, futures, options, and combinations of these instruments.  The program is used to reduce TVA’s economic risk exposure associated with electricity generation, purchases, and sales.  TVA defers all FTP mark-to-market unrealized gains or losses as regulatory liabilities or assets, respectively, and records realized gains or losses in fuel and purchased power expense to match the delivery period of the underlying commodity product.  Net unrealized losses as of September 30, 2010, were approximately $269 million and as of September 30, 2009, were approximately $68 million.  This accounting treatment reflects TVA’s ability and intent to recover the cost of these commodity contracts in future periods through the Fuel Cost Adjustment (“FCA”).  The current regulatory asset/liability for net unrealized gains and losses represents deferred gains and losses from contracts with a maturity of less than one year.

Swap and Swaption Contracts.  TVA uses regulatory accounting treatment to defer the mark-to-market unrealized gains and losses on certain swap and swaption contracts to reflect that the gain or loss is included in the ratemaking formula when these transactions actually settle.  The value of the swap and swaptions is recorded on TVA’s balance sheet with realized gains or losses, if any, recorded in TVA’s statement of operations.

Environmental Cleanup – Kingston Ash Spill.  In August 2009, TVA began using regulatory accounting treatment to defer all actual costs incurred and expected future costs related to the Kingston ash spill.  The TVA Board approved a plan of amortizing these costs over 15 years beginning October 1, 2009.  As of September 30, 2009, TVA’s remediation cost estimate of $933 million was deferred as a regulatory asset.  During 2010, the estimate was revised and increased by $192 million to a total estimate of $1.1 billion.  The additional amount will be amortized over the remaining term of the initial life.  Amounts included as a current regulatory asset on the balance sheet represent the amount to be amortized in the next 12 months.  Any future revisions to the estimate will be amortized as a change in estimate over the remaining term.

Deferred Outage Costs.  TVA’s investment in the fuel used in its nuclear units is being amortized and accounted for as a component of fuel expense.  Nuclear refueling outage and maintenance costs already incurred have historically been deferred and amortized on a straight-line basis over the estimated period until the next refueling outage.  In 2010, TVA began expensing outage and maintenance costs as incurred.  Previously deferred outage costs will continue to be amortized as the remaining amounts are collected in rates and are included as a current regulatory asset on the balance sheet.  The remaining costs will be fully amortized in 2011.

Deferred Capital Lease Asset Costs.  Deferred capital lease asset costs represent the difference between FERC’s Uniform System of Accounts model balances recovered in

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rates and the balances under GAAP guidance.  Under the Uniform System of Accounts, TVA recognizes the initial capital lease asset and liability at inception of the lease; however, the annual expense under the Uniform System of Accounts is equal to the annual lease payments, which differs from GAAP treatment.  This practice results in TVA’s capital lease asset balances being higher than they otherwise would have been under GAAP, with the difference representing a regulatory asset related to each capital lease.  These costs are being amortized over the respective lease terms as lease payments are made.   The amount to be amortized over the next 12 months is included as a current regulatory asset on the balance sheet.

Fuel Cost Adjustment.  The FCA provides a mechanism to regularly alter rates to reflect changing fuel and purchased power costs, including realized gains and losses relating to transactions under TVA’s FTP.  There is typically a lag between the occurrence of a change in fuel and purchased power costs and the reflection of the change in rates.  Balances in the FCA represent overcollected or undercollected revenues to offset fuel and purchased power costs and are recovered or refunded in FCA rate adjustments.

Starting with the October 1, 2009 billing period, all adjustments to the FCA have been made on a monthly basis instead of a quarterly basis.  Therefore, since October 1, 2009, the balance has been a current regulatory asset or liability.  This allows the FCA to be more closely aligned with TVA’s costs.  The FCA formula also contains a deferred account which is used to reconcile the difference between actual and forecasted fuel and purchased power costs.  The difference between the amounts is included in the deferred account, and starting with the October 1, 2009 billing period, 50 percent of the account has been disbursed or collected on a monthly basis.  This change to a monthly FCA formula has resulted in smaller reconciliations and faster liquidation of any balances in the account.  With the change to the monthly FCA formula on October 1, 2009, the remaining balance in the existing deferred liability account balance at that date of approximately $822 million was liquidated over a nine-month period from October 1, 2009, through June 30, 2010.

Deferred Nuclear Generating Units.  In July 2005, the TVA Board approved the amortization, and inclusion into rates, of TVA’s $3.9 billion investment in the deferred nuclear generating units at Bellefonte Nuclear Plant over a 10-year recovery period beginning in 2006.  The amount to be amortized over the next fiscal year is included as a current regulatory asset on the balance sheet.

Unrealized Gains (Losses) on Coal Contracts with Volume Options.  Unrealized gains (losses) on coal purchase contracts relate to the mark-to-market valuation of coal purchase contracts that contain options to purchase additional or fewer quantities.  These contracts qualify as derivative contracts but do not qualify for cash flow hedge accounting treatment.  As a result, TVA recognizes the changes in the market value of these derivative contracts as a regulatory liability or asset.  This treatment reflects TVA’s ability and intent to recover the cost of these commodity contracts on a settlement basis for ratemaking purposes through the FCA.  TVA has historically recognized the actual cost of fuel received under these contracts in fuel expense at the time the fuel is used to generate electricity.  These contracts expire at various times through 2013.  Unrealized gains and losses on contracts with a maturity of less than one year are included as a current regulatory asset or liability on the balance sheet.  See Note 13 - Risk Management Activities & Derivative Transactions.

Capital Lease Liability.  As a result of a capital lease payment stream requiring larger cash payments during the latter years of the lease term than during the early years of the lease term, TVA levelized the annual lease expense recognition related to this lease in order to promote the fair and equitable cost recovery from ratepayers.  These levelized costs are being amortized over the lease term.  The amount to be amortized over the next 12 months is included as a current regulatory liability on the balance sheet.

Accrued Tax Equivalents.  The FCA structure includes a provision related to the current funding of the future expense TVA will incur for tax equivalent payments.  As TVA records the FCA, the percent of the calculation that relates to a future asset or liability for tax equivalent payments is recorded as a current regulatory asset or liability.  This current regulatory asset or liability is not amortized to the statement of operations on a fixed schedule; rather, this asset or liability adjusts the expense to offset the revenue from the FCA in the proper period.

Nuclear Training Costs.  As a result of refurbishing and restarting Browns Ferry Nuclear Unit 1 in 2007 and the construction and startup of Watts Bar Unit 2, nuclear training costs associated with these units have been deferred as a regulatory asset and will be amortized over a cost recovery period equivalent to the expected useful life of the operating nuclear units.

Retirement Removal Costs.  The TVA Board has approved capitalization of removal costs as incurred into fixed assets to be depreciated consistent with the lives in the depreciation study.  As these costs have been incurred, these assets represent regulatory assets.  The TVA Board has consistently provided rates to cover the depreciation of these assets; therefore, these assets are probable of future recovery.

8.  Kingston Fossil Plant Ash Spill

On December 22, 2008, one of the ash cells at Kingston failed.  Approximately five million cubic yards of water and coal fly ash flowed out of the dredge cell at Kingston onto

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approximately 300 acres, primarily into the Emory River channel portion of the Watts Bar Reservoir and onto shoreline property owned by the United States and managed by TVA, and also structurally damaged three homes, interrupted utility service, and blocked a road.  Fly ash is a coal combustion product of a coal-fired plant.  Kingston used wet ash containment impoundments for fly ash.

TVA is conducting cleanup and recovery efforts in conjunction with federal and state agencies.  Under the May 11, 2009 Administrative Order and Agreement on Consent (“Order and Agreement”) entered into by TVA and EPA under the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), TVA retains its status as a lead federal agency, but TVA's work is subject to review and approval by the EPA, in consultation with the Tennessee Department of Environment and Conservation (“TDEC”).  Under the Order and Agreement, response actions are classified into three categories: time-critical removal; non-time-critical removal; and remedial actions.  Generally, removal of the ash from the Emory River was considered time-critical.  However, the EPA concluded that TVA’s dredging operations should be conducted in a manner that seeks to maximize ash removal while minimizing disturbance to native sediments in the river.  Accordingly, some residual ash will remain in the Emory River, and, except for this residual ash, TVA completed the removal of the ash from the river during the third quarter of 2010.  Removal of the remaining ash is considered to be non-time-critical.  TVA estimates that the recovery process will be substantially completed in 2014 although monitoring may continue beyond that date.  Once the removal actions are completed, TVA will be required to assess the site and determine whether any additional actions may be needed at Kingston or the surrounding impacted area.  This assessment and any additional activities found to be necessary constitute the remedial actions.

Insurance.  TVA has property and excess liability insurance programs in place that may cover some of the Kingston ash spill costs.  The insurers for each of these programs have been notified of the event.  Three of the insurers that provide liability insurance have denied coverage, and three other liability insurers issued reservation of rights letters.  All of the property insurers have denied coverage.  TVA and the insurance companies that have denied coverage continue to discuss coverage and estimates of covered costs.  TVA continues to provide information to the liability insurance companies that have issued reservation of rights letters but have not denied coverage.  No estimate for potential insurance recovery has been accrued.

Claims and Litigation.  Sixty lawsuits based on the Kingston ash spill have been filed.  Five of these have been voluntarily dismissed and three of the class actions have been consolidated into one action.  All of the remaining cases are pending in the United States District Court for the Eastern District of Tennessee.  See Note 20 —Legal Proceedings — Legal Proceedings Related to Kingston Ash Spill.

On June 14, 2010, TDEC issued a civil penalty order of approximately $12 million to TVA for the Kingston ash spill, citing violations of the Tennessee Solid Waste Disposal Act and the Tennessee Water Quality Control Act.  Of the $12 million, TVA has already satisfied $6 million of the obligation and may also be credited up to $2 million for performing environmental projects approved by TDEC.  The remaining obligation will be paid in installments through July 2012.

Financial Impact.  TVA recorded an estimate in the amount of $1.1 billion for the cost of cleanup related to this event.  In 2009, TVA originally charged a portion of this amount to expense as follows:  $525 million, $150 million, and $258 million during the three months ended December 31, 2008, March 31, 2009, and June 30, 2009, respectively.  However, in August 2009 the TVA Board reclassified all amounts previously expensed as a regulatory asset and the amount is being charged to expense as it is collected in rates over 15 years, beginning October 1, 2009.  As the estimate changes, additional costs may be deferred and charged to expense prospectively as they are collected in future rates.

During the year ended September 30, 2010, TVA increased the estimate for the cost of cleanup related to this event by $192 million.  The change in estimate is due to increased scope of work to be performed at the site as defined in the Engineering Evaluation Cost Analysis (“EE/CA”) work order plan which was prepared in accordance with EPA’s Guidance on Conducting Non-Time-Critical Removal Actions under CERCLA.  In May 2010, EPA approved TVA’s ash disposal plan, which clarified the amount of ash to be removed from the site and the final design and closure of ash ponds and dredge cells on site.  The plan involves moving less ash offsite than was originally assumed, which results in potential cost savings.  These potential savings are more than offset, however, by the costs of other elements of the plan, including the required expansion of the failed cell and the closure and capping of all cells on the plant site that hold wet ash.  The potential savings are also offset by the costs of handling the ash under CERCLA requirements and recently assessed penalties and regulatory oversight costs.  TVA has also found that certain previously estimated cost categories, such as dredging, were more expensive than originally estimated due to more equipment and staffing being needed to ensure timely completion of removal of time-critical ash from the river.  Final designs of holding cells and dikes are more robust than originally estimated.

As work continues to progress and more information is available, TVA will review its estimates and revise them as appropriate.  Although TVA has developed a detailed work plan and cost estimate based on the ash disposal plan, the estimate could be subject to volatility until design plans are completed and contracts are finalized.  The design of the lateral expansion of the failed cell and the closure and capping of all ash cells is still in process.  TVA currently estimates the recovery process will be substantially completed in 2014 although monitoring may continue beyond that time.  As such, TVA has accrued a portion of the estimated cost in current liabilities, with the remaining portion shown as a long-term liability on

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TVA’s balance sheets.  Costs incurred since the event through September 30, 2010, totaled $600 million.   The remaining estimated liability at September 30, 2010, was $525 million.

The $1.1 billion estimate currently includes, among other things, a reasonable estimate of costs related to ash dredging and processing, ash disposition, infrastructure repair, dredge cell repair, root cause analysis, certain legal and settlement costs, environmental impact studies and remediation, human health assessments, community outreach and support, regulatory oversight, cenosphere recovery, skimmer wall installation, construction of temporary ash storage areas, dike reinforcement, project management, and certain other remediation costs associated with the cleanup.

Because of the uncertainty at this time of the final costs to complete the work prescribed by the ash disposal plan, a range of reasonable estimates has been developed by cost category and either the known amounts, most likely scenarios, or low end of the range for each category has been accumulated and evaluated to determine the total estimate.  The range of estimated costs varies from approximately $1.1 billion to approximately $1.2 billion.

TVA has not included the following categories of costs in the above estimate since it has determined that these costs are currently either not probable or not reasonably estimable: penalties (other than the penalties set out in the TDEC order), regulatory directives, natural resources damages, outcomes of lawsuits, future claims, long-term environmental impact costs, final long-term disposition of ash processing area, costs associated with new laws and regulations, or costs of remediating any mixed waste discovered during ash removal process.  There are certain other costs that will be incurred that have not been included in the estimate as they are appropriately accounted for in other areas of the financial statements.  Associated capital asset purchases are recorded in property, plant, and equipment.  Ash handling and disposition from current plant operations are recorded in operating expenses.  A portion of the pond and dredge cell closure costs are also not included in the estimate as those costs are included in the non-nuclear ARO liability.

On January 26, 2010, the owners of the landfill in Perry County, Alabama, that is receiving the ash dredged from the Emory River filed a voluntary proceeding under Chapter 11 of the U.S. Bankruptcy Code.  At this time TVA has not incurred any additional costs as a result of the filing, and the landfill has continued to receive ash since the filing.

In June 2010, a group of Perry County residents filed two lawsuits challenging the operation of the landfill in Perry County, Alabama.  Both lawsuits have been remanded to federal court.  TVA has not been named in the lawsuits.

9.  Other Long-Term Liabilities

Other long-term liabilities consist primarily of estimated amounts due for post-retirement and post-employment benefits and liabilities related to certain derivative agreements.  The table below summarizes the types and amounts of liabilities:

Other Long-Term Liabilities As of September 30
	2010		2009
Currency swap liabilities	$	81	$	51
Swaption liability		804		592
Interest rate swap liabilities		371		287
Coal contract derivative liabilities		2		26
Post-retirement and postemployment benefit obligations		4,729		3,678
Commodity swap derivatives		118		—
Other long-term liability obligations		150		123
Total other long-term liabilities	$	6,255	$	4,757

The currency swap held as an asset at September 30, 2009, became a liability during 2010, due primarily to changes in exchange rates.  In addition, the swaption and interest rate swap liabilities increased during 2010 due primarily to a decrease in interest rates.  See Note 18 — Plan Assumptions for discussion related to changes affecting benefit plan obligations.

10.  Asset Retirement Obligations

During 2010, TVA’s total ARO liability increased $280 million.  The increase was comprised of $1 million in new AROs, $138 million of new revisions in the estimated lives and cost estimates related to the ash storage areas, and $147 million in ARO accretion.  The liability was decreased by expenditures on projects at ash storage areas that began during the fourth quarter of 2010.  The nuclear and non-nuclear accretion were deferred as regulatory assets.  During the year ended September 30, 2010, $55 million of the related regulatory assets were amortized into expense since these amounts were collected in rates.  The nuclear ARO liability as of September 30, 2010, was $1.9 billion.  The non-nuclear ARO liability as of September 30, 2010, was $1.0 billion.

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Reconciliation of Asset Retirement Obligation Liability As of September 30
	2010			2009
Balance at beginning of period	$	2,683		$	2,318
Changes in nuclear estimates to future cash flows		—			11
Non-nuclear additional obligations		1			1
Non-nuclear additional obligations (ash storage areas)		138			224
Non-nuclear settlements (ash storage areas)		(6	)		—
		133			236
Add:  ARO (accretion) expense
Nuclear accretion (recorded as regulatory asset)		104			98
Non-nuclear accretion (recorded as regulatory asset)		43			31
		147			129
Balance at end of period	$	2,963		$	2,683

11.  Debt

General

The TVA Act authorizes TVA to issue Bonds in an amount not to exceed $30 billion at any time.  At September 30, 2010, TVA had only two types of Bonds outstanding: power bonds and discount notes.  Power bonds have maturities of between one and 50 years, and discount notes have maturities of less than one year.  Power bonds and discount notes are both issued pursuant to section 15d of the TVA Act and pursuant to the Basic Tennessee Valley Authority Power Bond Resolution adopted by the TVA Board on October 6, 1960, as amended on September 28, 1976, October 17, 1989, and March 25, 1992 (the “Basic Resolution”).  TVA Bonds are not obligations of the United States, and the United States does not guarantee the payments of principal or interest on Bonds.

Power bonds and discount notes rank on parity and have first priority of payment out of net power proceeds, which are defined as:

•   the remainder of TVA’s gross power revenues

•   after deducting

–   the costs of operating, maintaining, and administering its power properties, and

–   payments to states and counties in lieu of taxes, but

•   before deducting depreciation accruals or other charges representing the amortization of capital expenditures, plus

•   the net proceeds from the sale or other disposition of any power facility or interest therein.

Because TVA’s lease payments under its leaseback transactions are considered costs of operating, maintaining, and administering its power properties, those payments have priority over TVA’s payments on the Bonds.  Once net power proceeds have been applied to payments on power bonds and discount notes as well as any other Bonds that TVA may issue in the future that rank on parity with or subordinate to power bonds and discount notes, Section 2.3 of the Basic Resolution provides that the remaining net power proceeds shall be used only for minimum payments into the U.S. Treasury required by the TVA Act in repayment of and as a return on the Power Program Appropriation Investment, investment in power assets, additional reductions of TVA’s capital obligations, and other lawful purposes related to TVA’s power program.

The TVA Act and the Basic Resolution each contain two bond tests: the rate testand the bondholder protection test.  Under the rate test, TVA must charge rates for power which will produce gross revenues sufficient to provide funds for, among other things, debt service on outstanding Bonds.  See Note 1 — General.  Under the bondholder protection test, TVA must, in successive five-year periods, use an amount of net power proceeds at least equal to the sum of:

• the depreciation accruals and other charges representing the amortization of capital expenditures and

• the net proceeds from any disposition of power facilities

for either

• the reduction of its capital obligations (including Bonds and the Power Program Appropriation Investment) or

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• investment in power assets.

TVA met the bondholder protection test for the five-year period ended September 30, 2010, and must next meet the bondholder protection test for the five-year period ending September 30, 2015.

Short-Term Debt

The weighted average rates applicable to short-term debt outstanding in the public market as of September 30, 2010, 2009, and 2008, were 0.04 percent, 0.06 percent, and 1.26 percent, respectively.  During 2010, 2009, and 2008, the maximum outstanding balances of TVA short-term borrowings held by the public were $1.3 billion, $2.7 billion, and $1.6 billion, respectively.  For these same years, the average amounts (and weighted average interest rates) of TVA short-term borrowings were approximately $905 million (0.09 percent), $1.7 billion (0.32 percent), and $767 million (3.71 percent), respectively.

TVA also has short-term funding available in the form of a $150 million credit facility with the U.S. Treasury and two short-term revolving credit facilities of $1.0 billion each.  These credit facilities will mature on February 7, 2011, and May 11, 2011.  The credit facilities also accommodate the issuance of letters of credit.  The interest rate on any borrowing under these facilities is variable based on market factors and the rating of TVA’s senior unsecured long-term non-credit enhanced debt.  TVA is required to pay an unused facility fee on the portion of the total $2.0 billion which TVA has not borrowed or committed under letters of credit.  This fee, along with letter of credit fees, may fluctuate depending on the rating of TVA’s senior unsecured long-term non-credit enhanced debt.  At September 30, 2010, there were $411 million of letters of credit outstanding under the facilities, and there were no outstanding borrowings.  TVA anticipates renewing each credit facility or replacing it with a different credit facility as it matures.  See Debt Outstanding.

Put and Call Options

Bond issues of $1.7 billion held by the public are redeemable in whole or in part, at TVA’s option, on call dates ranging from the present to 2020 and at call prices ranging from 100 percent to 106 percent of the principal amount.  Eighteen Bond issues totaling $569 million, with maturity dates ranging from 2020 to 2029, include a “survivor’s option,” which allows for right of redemption upon the death of a beneficial owner in certain specified circumstances.  There is no accounting difference between a “survivor’s option” put and a “regular” put on any TVA put Bond.

Additionally, TVA has two issues of Putable Automatic Rate Reset Securities (“PARRS”) outstanding.  After a fixed-rate period of five years, the coupon rate on the PARRS may automatically be reset downward under certain market conditions on an annual basis.  The coupon rate reset on the PARRS is based on a calculation.  For both series of PARRS, the coupon rate will reset downward on the reset date if the rate calculated is below the then-current coupon rate on the Bond.  The calculation dates, potential reset dates, and terms of the calculation are different for each series.  The coupon rate on the 1998 Series D PARRS may be reset on June 1 (annually) if the sum of the five-day average of the 30-Year Constant Maturity Treasury (“CMT”) rate for the week ending the last Friday in April, plus 94 basis points, is below the then-current coupon rate.  The coupon rate on the 1999 Series A PARRS may be reset on May 1 (annually) if the sum of the five-day average of the 30-Year CMT rate for the week ending the last Friday in March, plus 84 basis points, is below the then-current coupon rate.  The coupon rates may only be reset downward, but investors may request to redeem their Bonds at par value in conjunction with a coupon rate reset for a limited period of time prior to the reset dates and under certain circumstances.

The coupon rate for the 1998 Series D PARRS, which mature in June 2028, has been reset four times, from an initial rate of 6.75 percent to the current rate of 4.728 percent.  In connection with these resets, $238 million of the bonds have been redeemed, so that $330 million of the bonds were outstanding at September 30, 2010.  The coupon rate for the 1999 Series A PARRS, which mature in May 2029, has been reset three times, from an initial rate of 6.50 percent to the current rate of 4.50 percent.  In connection with these resets, $241 million of the bonds have been redeemed, so that $274 million of the bonds were outstanding at September 30, 2010.

Due to the contingent nature of the put option on the PARRS, TVA determines whether the PARRS should be classified as long-term debt or current maturities of long-term debt by calculating the expected reset rate on the bonds.  The expected reset rate is calculated using forward rates and the fixed spread for each PAARS issue as noted above.  If the expected reset rate is less than the then-current coupon rate on the PARRS, the PARRS are included in current maturities.  Otherwise, the PARRS are included in long-term debt.  At September 30, 2010, the expected reset rate was higher than the then-current coupon rate on each issue of PARRS; therefore, the par amount outstanding for each series of PARRS was classified as long-term debt.

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Debt Securities Activity

The table below summarizes TVA’s Bond activity for the period from October 1, 2009 to September 30, 2010.

Debt Securities Activity from October 1, 2009 to September 30, 2010
Redemptions/Maturities:	2010		2009
electronotes®
First quarter	$	1	$	—
Second quarter		25		558
Third quarter		3		3
Fourth quarter		34		248
1998 Series G		—		2,000
1999 Series A		—		25
2009 Series A		3		1
1998 Series D		—		20
2009 Series B		3		19
Total	$	69	$	2,874
Issues:
electronotes®
First quarter	$	82	$	39
Second quarter		34		89
Third quarter		63		115
Fourth quarter		—		135
2009 Series A		—		22
2009 Series B		—		469
2009 Series C		500		1,500
2010 Series A		1,000		—
Total	$	1,679	$	2,369

Debt Outstanding

Debt outstanding at September 30, 2010, consisted of the following:

Short-Term Debt As of September 30
CUSIP or Other Identifier	Maturity	Call/(Put) Date	Coupon Rate	2010 Par Amount	2009 Par Amount
Discount Notes (net of discount)				$                  27	$            844
Current maturities of long-term debt
880591DN9	01/18/2011		5.63%	1,000	—
880591EE8	05/15/2011		2.25%	3	3
88059TEL1	05/15/2011		2.65%	3	3
880591EF5	06/15/2011		3.77%	2	2
				1,008	8
Total debt due within one year, net				$             1,035	$           852

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Long-Term Debt(1) As of September 30
CUSIP or Other Identifier	Maturity	Call/(Put) Date	Coupon Rate			2010 Par Amount		2009 Par Amount
880591EE8	11/15/2010			2.250	%	$	—	$	2
88059TEL1	11/15/2010			2.650	%		—		1
880591EF5	12/15/2010			3.770	%		—		1
880591DN9	01/18/2011			5.625	%		—		1,000
880591EE8	05/15/2011			2.250	%		—		2
88059TEL1	05/15/2011			2.650	%		—		1
880591EF5	06/15/2011			3.770	%		—		1
Maturing in 2011							—		1,008
880591EE8	11/15/2011			2.250	%		2		2
88059TEL1	11/15/2011			2.650	%		1		1
880591EF5	12/15/2011			3.770	%		1		1
880591EE8	05/15/2012			2.250	%		2		2
88059TEL1	05/15/2012			2.650	%		1		1
880591DL3	05/23/2012			7.140	%		29		29
880591DT6	05/23/2012			6.790	%		1,486		1,486
880591EF5	06/15/2012			3.770	%		1		1
Maturing in 2012							1,523		1,523
880591EE8	11/15/2012			2.250	%		2		2
88059TEL1	11/15/2012			2.650	%		1		1
880591EF5	12/15/2012			3.770	%		1		1
880591CW0	03/15/2013			6.000	%		1,359		1,359
880591EE8	05/15/2013			2.250	%		2		2
88059TEL1	05/15/2013			2.650	%		2		2
880591EF5	06/15/2013			3.770	%		1		1
880591DW9	08/01/2013			4.750	%		940		940
Maturing in 2013							2,308		2,308
880591EE8	11/15/2013			2.250	%		2		2
88059TEL1	11/15/2013			2.650	%		1		1
880591EF5	12/15/2013			3.770	%		1		1
880591EE8	05/15/2014			2.250	%		1		1
88059TEL1	05/15/2014			2.650	%		2		2
880591EF5	06/15/2014			3.770	%		25		25
Maturing in 2014							32		32
880591EE8	11/15/2014			2.250	%		2		2
88059TEL1	11/15/2014			2.650	%		1		1
880591EF5	12/15/2014			3.770	%		1		1
880591EE8	05/15/2015			2.250	%		1		1
88059TEL1	05/15/2015			2.650	%		1		1
880591DY5	06/15/2015			4.375	%		1,000		1,000
880591EF5	06/15/2015			3.770	%		26		26
Maturing in 2015							1,032		1,032

98

CUSIP or Other Identifier	Maturity	Call/(Put) Date	Coupon Rate			2010 Par Amount		2009 Par Amount
880591EE8	11/15/2015			2.250	%		2		2
88059TEL1	11/15/2015			2.650	%		1		1
880591EF5	12/15/2015			3.770	%		1		1
88059TEL1	05/15/2016			2.650	%		1		1
880591EF5	06/15/2016			3.770	%		26		26
88059TEL1	11/15/2016			2.650	%		1		1
880591DS8	12/15/2016			4.875	%		524		524
880591EF5	12/15/2016			3.770	%		1		1
88059TEL1	05/15/2017			2.650	%		1		1
880591EF5	06/15/2017			3.770	%		27		27
880591EA6	07/18/2017			5.500	%		1,000		1,000
88059TEL1	11/15/2017			2.650	%		1		1
880591CU4	12/15/2017			6.250	%		650		650
880591EF5	12/15/2017			3.770	%		1		1
88059TEF4	03/15/2018	03/15/2010		4.500	%		—		25
880591EC2	04/01/2018			4.500	%		1,000		1,000
88059TEL1	05/15/2018			2.650	%		2		2
880591EF5	06/15/2018			3.770	%		28		28
88059TEL1	11/15/2018			2.650	%		1		1
880591EF5	12/15/2018			3.770	%		1		1
88059TCX7	03/15/2019	01/15/2005		4.500	%		—		12
88059TEL1	05/15/2019			2.650	%		2		1
880591EF5	06/15/2019			3.770	%		29		29
88059TEL1	11/15/2019			2.650	%		1		1
880591EF5	12/15/2019			3.770	%		1		1
88059TEY3	02/15/2020	02/15/2012		3.750	%		12		—
88059TFA4	04/15/2020	04/15/2012		4.100	%		39		—
88059TEL1	05/15/2020			2.650	%		1		1
880591EF5	06/15/2020			3.770	%		27		27
88059TDG3	09/15/2020	09/15/2008		4.800	%		—		3
880591EF5	12/15/2020			3.770	%		1		1
880591DC3	06/07/2021			5.805	%		314		320
880591EF5	06/15/2021			3.770	%		28		28
880591EF5	12/15/2021			3.770	%		1		1
880591EF5	06/15/2022			3.770	%		28		28
880591EF5	12/15/2022			3.770	%		1		1
880591EF5	06/15/2023			3.770	%		28		28
88059TEH0	10/15/2023	10/15/2011		5.000	%		14		15
880591EF5	12/15/2023			3.770	%		1		1
88059TEM9	03/15/2024	03/15/2012		4.500	%		58		59
880591EF5	06/15/2024			3.770	%		21		21
88059TES6	07/15/2024	07/15/2012		4.875	%		28		28
880591EF5	12/15/2024			3.770	%		1		1
88059TEZ0	03/15/2025	03/15/2013		4.300	%		22		—
88059TFB2	05/15/2025	05/15/2013		4.250	%		23		—
88059TDC2	05/15/2025	05/15/2009		5.125	%		—		13
880591EF5	06/15/2025			3.770	%		22		22
880591CJ9	11/01/2025			6.750	%		1,350		1,350

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CUSIP or Other Identifier		Maturity	Call/(Put) Date	Coupon Rate			2010 Par Amount			2009 Par Amount
88059TDM0		02/15/2026	02/15/2010		5.500	%		—			6
880591EF5		06/15/2026			3.770	%		20			20
88059TDV0		10/15/2026	10/15/2010		5.500	%		9			9
880591EF5		06/15/2027			3.770	%		20			20
88059TEE7		01/15/2028	01/15/2012		4.750	%		36			36
880591300	(3)	06/01/2028			4.728	%		330			330
880591EF5		06/15/2028			3.770	%		16			16
88059TEJ6		11/15/2008	11/15/2012		5.250	%		7			7
88059TEK3		12/15/2028	12/15/2012		5.000	%		17			18
88059TEP2		04/15/2029	04/15/2013		4.350	%		51			51
880591409	(3)	05/01/2029			4.500	%		274			274
88059TEQ0		05/15/2029	05/15/2013		4.500	%		50			50
88059TER8		06/15/2029	06/15/2013		4.750	%		13			13
880591EF5		06/15/2029			3.770	%		12			12
88059TET4		07/15/2029	07/15/2013		4.750	%		37			37
88059TEV9		08/15/2029	08/15/2013		4.875	%		19			19
88059TEW7		09/15/2029	09/15/2013		4.750	%		51			51
88059TEX5		10/15/2029	10/15/2013		4.375	%		82			—
880591DM1		05/01/2030			7.125	%		1,000			1,000
880591EF5		06/15/2030			3.770	%		12			12
880591EF5		06/15/2031			3.770	%		12			12
880591DP4		06/07/2032			6.587	%		393			399
880591EF5		06/15/2032			3.770	%		12			12
880591EF5		06/15/2033			3.770	%		5			5
880591DV1		07/15/2033			4.700	%		472			472
880591EF5		06/15/2034			3.770	%		5			5
880591DX7		06/15/2035			4.650	%		436			436
880591CK6		04/01/2036			5.980	%		121			121
880591CS9		04/01/2036			5.880	%		1,500			1,500
880591CP5		01/15/2038			6.150	%		1,000			1,000
880591ED0		06/15/2038			5.500	%		500			500
880591EH1		09/15/2039			5.250	%		2,000			1,500
880591BL5		04/15/2042	04/15/2012		8.250	%		1,000			1,000
880591DU3		06/07/2043			4.962	%		236			240
880591CF7		07/15/2045	07/15/2020		6.235	%		140			140
880591EB4		01/15/2048			4.875	%		500			500
880591DZ2		04/01/2056			5.375	%		1,000			1,000
880591EJ7		09/15/2060			4.625	%		1,000			—
Maturing 2015-2056								17,710			16,109
Subtotal								22,605			22,012
Unamortized discounts, premiums, and other								(216	)		(224	)
Total long-term debt, net							$	22,389		$	21,788
Notes (1)The above table includes net exchange losses from currency transactions of $14 million at September 30, 2010. (2)The coupon rate represents TVA’s effective interest rate. (3)TVA PARRS, CUSIP numbers 880591300 and 880591409, may be redeemed under certain conditions.  See Put and Call Options.

12.  Seven States Power Corporation Obligation

Seven States Power Corporation (“Seven States”), through its subsidiary, Seven States Southaven, LLC (“SSSL”), exercised Seven States’s option to purchase an undivided 90-percent interest in a combined cycle combustion turbine facility in Southaven, Mississippi.  As part of interim joint-ownership arrangements, Seven States has the right at any time during the interim period, and for any reason, to require TVA to buy back Seven States’ interest in the facility.

The interim period under the original agreements was to expire on April 30, 2010.  On April 22, 2010, TVA and Seven States, through SSSL, amended the joint ownership agreement, lease agreement, and buy-back arrangements to extend the term of the interim arrangements by approximately three years, until April 23, 2013.  The other material terms and conditions of the agreements were not changed and remain in full force and effect.  Under the amended agreements, TVA will buy back the Seven States interest if long-term operational and power sales arrangements for the facility among TVA, Seven States, and SSSL, or alternative arrangements, are not in place by April 23, 2013. TVA’s buy-back obligation will terminate if such long-term arrangements are in place by that date.   In the event of a buy-back, TVA will re-acquire the Seven States interest in the facility and the related assets. As of September 30, 2010, the carrying amount of the obligation was approximately $413 million.

13.  Risk Management Activities and Derivative Transactions

TVA is exposed to various market risks.  These market risks include risks related to commodity prices, investment prices, interest rates, currency exchange rates, inflation, and counterparty credit and counterparty performance risk.  To help manage certain of these risks, TVA has entered into various derivative transactions, principally commodity option contracts, forward contracts, swaps, swaptions, futures, and options on futures.  Other than certain derivative instruments in investment funds, it is TVA’s policy to enter into these derivative transactions solely for hedging purposes and not for speculative purposes.

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Overview of Accounting Treatment

TVA recognizes certain of its derivative instruments as either assets or liabilities on its balance sheets at fair value.  The accounting for changes in the fair value of these instruments depends on (1) whether TVA uses regulatory accounting to defer the derivative gains and losses, (2) whether the derivative instrument has been designated and qualifies for hedge accounting treatment and (3) if so, the type of hedge relationship (e.g., cash flow hedge).

The following tables summarize the accounting treatment that certain of TVA’s financial derivative transactions receive.

Summary of Derivative Instruments That Receive Hedge Accounting Treatment (part 1)
Derivatives in Cash Flow Hedging Relationship	Objective of Hedge Transaction	Accounting for Derivative Hedging Instrument	Amount of Mark-to-Market (Loss) Gain Recognized in Other Comprehensive Income (Loss) (“OCI”) Years Ended September 30
			2010	2009
Currency swaps	To protect against changes in cash flows caused by changes in foreign currency exchange rates (exchange rate risk)	Cumulative unrealized gains and losses are recorded in OCI and reclassified to interest expense to the extent they are offset by cumulative gains and losses on the hedged transaction	$   (37)	$  (146)

Summary of Derivative Instruments That Receive Hedge Accounting Treatment (part 2)
Derivatives in Cash Flow Hedging Relationship	Amount of Cumulative Unrealized Gain (Loss) Reclassified from OCI to Interest Expense Years Ended September 30 (1)
	2010		2009
Currency swaps	$	17	$	108
Note (1) There were no ineffective portions or amounts excluded from effectiveness testing for any of the periods presented. Also see Note 14.

101

Summary of Derivative Instruments That Do Not Receive Hedge Accounting Treatment
Derivative Type	Objective of Derivative	Accounting for Derivative Instrument	Amount of Gain (Loss) Recognized in Income on Derivatives Years Ended September 30 (1)
			2010	2009
Swaption	To protect against decreases in value of the embedded call (interest rate risk)	Gains and losses are recorded as regulatory assets or liabilities until settlement, at which time the gains/losses (if any) are recognized in gain/loss on derivative contracts.	$    —	$     —
Interest rate swaps	To fix short-term debt variable rate to a fixed rate (interest rate risk)	Gains and losses are recorded as regulatory assets or liabilities until settlement, at which time the gains/losses (if any) are recognized in gain/loss on derivative contracts. (2)	—	—
Coal contracts with volume options	To protect against fluctuations in market prices of purchased coal (price risk)	Gains and losses are recorded as regulatory assets or liabilities.  They are recognized in fuel and purchased power expense when the related coal is used in production.  (3)	—	(37)
Commodity derivatives under Financial Trading Program	To protect against fluctuations in market prices of purchased commodities (price risk)	Realized gains and losses are recorded in earnings as fuel and purchased power expense.  Unrealized gains and losses are recorded as a regulatory asset/liability.	(137)	(408)
Note (1) All of TVA’s derivative instruments that do not receive hedge accounting treatment have unrealized gains (losses) that would otherwise be recognized in income but instead are deferred as regulatory assets and liabilities.  As such, there was no related gain (loss) recognized in income for these unrealized gains (losses) for 2009 and 2010.  See Note 7 — Deferred Gains and Losses Relating to TVA’s Financial Trading Program, Swap and Swaption Contract, and Unrealized Gains (Losses) on Coal Contacts with Volume Options. (2)Generally, TVA maintains a level of outstanding discount notes equal to or greater than the notional amount of the interest rate swaps.  However, in September 2010, TVA issued $1 billion of long-term Bonds in anticipation of the January 2011 maturity of the $1 billion 2001 Series A Bonds.  As a result of this Bond issuance, TVA paid down its discount notes which caused the discount note balance outstanding at September 30, 2010 to be below the notional amount of the interest rate swaps.There is no statement of operations impact of this due to the use of regulatory accounting for these items. (3)  Settlement fees associated with early contract termination are recognized in fuel and purchased power expense in the period incurred.  Settlement fees with early contract terminations that qualify for regulatory accounting are recorded as regulatory assets.

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MARK-TO-MARKET VALUES OF TVA DERIVATIVES As of September 30
	2010				2009
Derivatives That Receive Hedge Accounting Treatment:
	Balance			Balance Sheet Presentation	Balance			Balance Sheet Presentation
Currency swaps:
£200 million Sterling	$	(42	)	Other long-term liabilities	$	(33	)	Other long-term liabilities
£250 million Sterling		(5	)	Other long-term liabilities		7		Other long-term assets
£150 million Sterling		(34	)	Other long-term liabilities		(18	)	Other long-term liabilities
Derivatives that Do Not Receive Hedge Accounting Treatment:
	Balance			Balance Sheet Presentation	Balance			Balance Sheet Presentation
Swaption:
$1.0 billion notional	$	(804	)	Other long-term liabilities	$	(592	)	Other long-term liabilities
Interest rate swaps:
$476 million notional		(356	)	Other long-term liabilities		(276	)	Other long-term liabilities
$42 million notional		(15	)	Other long-term liabilities		(11	)	Other long-term liabilities
Coal contracts derivatives		103		Other long-term assets $103, Other current assets $49; Other long-term liabilities ($2); Accounts payable and accrued liabilities ($47)		7		Other long-term assets $18, Other current assets $68; Other long-term liabilities ($25); Accounts payable and accrued liabilities ($54)
Commodity derivatives under Financial Trading Program:
Margin cash account*		12		Other current assets		28		Other current assets
Unrealized losses, net		(269	)	Current regulatory assets ($137); Regulatory assets ($142); Current regulatory liabilities $7; Regulatory liabilities $3		(68	)	Current regulatory assets ($69); Regulatory assets ($16); Current regulaotry liabilities $11; Regulatory liabilities $6
Note * In accordance with certain credit terms, TVA used leveraging to trade financial instruments under the Financial Trading Program. Therefore, the margin cash account balance does not represent 100 percent of the net market value of the derivative positions outstanding as shown in the Commodity Derivatives Under Financial Trading Program table below.

Cash Flow Hedging Strategy for Currency Swaps

To protect against the exchange rate risk related to three British pound sterling denominated Bond transactions, TVA entered into foreign currency hedges at the time the Bond transactions occurred.  TVA had the following currency swaps outstanding as of September 30, 2010:

Currency Swaps Outstanding As of September 30, 2010
Effective Date of Currency Swap Contract	Associated TVA Bond Issues – Currency Exposure	Expiration Date of Swap	Overall Effective Cost to TVA
2003	£150 million	2043	4.96%
2001	£250 million	2032	6.59%
1999	£200 million	2021	5.81%

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When the dollar strengthens against the British pound sterling, the transaction gain on the Bond liability is offset by an exchange loss on the swap contract.  Conversely, when the dollar weakens, the transaction loss on the Bond liability is offset by an exchange gain on the swap contract.  All such exchange gains or losses on the Bond liability are included in Long-Term Debt, Net.  The offsetting exchange losses or gains on the swap contracts are recognized in Accumulated Other Comprehensive Loss.  If any loss or gain were to be incurred as a result of the early termination of the foreign currency swap contract, any resulting charge or income would be amortized over the remaining life of the associated Bond as a component of interest expense.

Derivatives Not Receiving Hedge Accounting Treatment

Swaption and Interest Rate Swaps

TVA has entered into four swaption transactions to monetize the value of call provisions on certain of its Bond issues.  A swaption grants a third party the right to enter into a swap agreement with TVA under which TVA receives a floating rate of interest and pays the third party a fixed rate of interest equal to the interest rate on the Bond issue whose call provision TVA has monetized.

• In 2003, TVA monetized the call provisions on a $1.0 billion Bond issue by entering into a swaption agreement with a third party in exchange for $175 million (the “2003A Swaption”).

• In 2003, TVA also monetized the call provisions on a $476 million Bond issue by entering into a swaption agreement with a third party in exchange for $81 million (the “2003B Swaption”).

• In 2005, TVA monetized the call provisions on two electronotes® issues ($42 million total par value) by entering into swaption agreements with a third party in exchange for $5 million (the “2005 Swaptions”).

In 2004, the counterparty to the 2003B Swaption exercised its option to enter into an interest rate swap with TVA, requiring TVA to make fixed rate payments to the counterparty of 6.875 percent and the counterparty to make floating payments to TVA based on London Interbank Offered Rate (“LIBOR”).  These payments are based on the notional principal amount of $476 million.

In 2008, the counterparty to the 2005 Swaptions exercised its options to enter into interest rate swaps with TVA.  Under the swaps, TVA is required to make fixed rate payments to the counterparty at 6.125 percent, and the counterparty is required to make floating payments to TVA based on LIBOR.  These payments are based on a combined notional amount of $42 million.

TVA uses regulatory accounting treatment to defer the mark-to-market gains and losses on these swap and swaption agreements and includes the gain or loss in the ratemaking formula when these transactions settle.  The values of the swap and swaption agreements and related deferred unrealized gains and losses are recorded on TVA’s balance sheets with realized gains or losses, if any, recorded on TVA’s statements of operations.  There were no realized gains or losses for the years ended September 30, 2010, and 2009.

For the year ended September 30, 2010, the changes in market value resulted in deferred unrealized losses on the value of the interest rate swaps and swaption of $299 million.  For the year ended September 30, 2009, the changes in market value resulted in deferred unrealized losses on the value of the interest rate swaps and swaption of $272 million.  All net deferred unrealized losses are reclassified as regulatory assets on the balance sheets.

Commodity Derivatives

TVA enters into certain supply contracts for coal that require delivery of fixed quantities at fixed prices.  Certain coal contracts are not required to be marked to market because (1) they are probable of physical delivery and (2) early net settlement is not probable.  Coal contracts that do not qualify for this exception are marked to market on a quarterly basis as coal contract derivatives.  Additionally, certain coal contracts contain options that permit TVA to either increase or reduce the amounts of coal delivered within specified guidelines.  Essentially, the option to take more or less coal represents a purchased option that is combined with the forward coal contract in a single supply contract.

At September 30, 2010, and September 30, 2009, TVA’s coal contract derivatives had net market values of $103 million and $7 million, respectively, which TVA deferred as regulatory assets and liabilities on a gross basis.  TVA will defer all unrealized gains or losses related to the exercise of these options and record only realized gains or losses as fuel and purchase power expense at the time the related coal is used in production.  At September 30, 2010, TVA’s coal contract derivatives had terms of up to three years.

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	Coal Contract Derivatives As of September 30
	2010			2009
	Number of Contracts	Notional Amount (in tons)	Fair Value (MtM) (in millions)	Number of Contracts	Notional Amount (in tons)	Fair Value (MtM) (in millions)
Coal Contract Derivatives	11	27 million	$         103	7	29 million	$        7

Commodity Derivatives Under Financial Trading Program

TVA has a FTP under which it can purchase and sell futures, swaps, options, and combinations of these instruments (as long as they are standard in the industry) to hedge TVA’s exposure to (1) the price of natural gas, fuel oil, electricity, coal, emission allowances, nuclear fuel, and other commodities included in TVA’s FCA calculation, (2) the price of construction materials, and (3) contracts for goods priced in or indexed to foreign currencies.  The combined transaction limit for the FCA and construction material transactions is $130 million (based on one-day value at risk).  In addition, the maximum hedge volume for the construction material transactions is 75 percent of the underlying net notional volume of the material that TVA anticipates using in approved TVA projects, and the market value of all outstanding hedging transactions involving construction materials is limited to $100 million at the execution of any new transaction.  The portfolio value at risk limit for the foreign currency transactions is $5 million and is separate and distinct from the $130 million transaction limit discussed above.  TVA is prohibited from trading financial instruments under the FTP for speculative purposes.

At September 30, 2010, the only risks hedged under the FTP were the economic risks associated with the prices of natural gas, fuel oil, crude oil, and coal.  Futures contracts and option contracts under the FTP had remaining terms of less than two years.  Swap contracts under the FTP had remaining terms of four years or less.

Commodity Derivatives Under Financial Trading Program As of September 30
	2010					2009
	Notional Amount		Fair Value (MtM) (in millions)			Notional Amount		Fair Value (MtM) (in millions)
Natural gas (mmBtu)
Futures contracts		7,920,000	$	(21	)		30,020,000	$	(25	)
Swap contracts		137,110,000		(241	)		115,307,500		(36	)
Option contracts		5,250,000		(2	)		7,300,000		1
Natural gas financial positions		150,280,000	$	(264	)		152,627,500	$	(60	)
Fuel oil/crude oil (in barrels)
Futures contracts		125,000	$	2			398,000	$	3
Swap contracts		1,711,000		8			1,660,000		7
Option contracts		495,000		—			1,236,000		3
Fuel oil/crude oil  financial positions		2,331,000	$	10			3,294,000	$	13
Note Due to the right of setoff and method of settlement, TVA elects to record commodity derivatives under the FTP based on its net commodity position with the broker or other counterparty. Notional amounts disclosed represent the net absolute value of contractual amounts.

TVA defers all FTP unrealized gains (losses) as regulatory liabilities (assets) and records only realized gains or losses to match the delivery period of the underlying commodity product.   In addition to the open commodity derivatives disclosed above, TVA had fixed derivative contracts with market values of $(15) million and $(21) million, at September 30, 2010, and at September 30, 2009, respectively, which were recorded as regulatory assets.

Natural Gas

At September 30, 2010, TVA had natural gas hedges with notional volumes equivalent to 150,280,000 (in mmBtu), the market value of which was a net loss of $264 million.  The unrealized loss of $264 million at September 30, 2010, was deferred as a regulatory asset.  For the year ended September 30, 2010, TVA recognized realized losses on natural gas hedges of $152 million which were recorded as an increase to fuel and purchased power expense.

At September 30, 2009, TVA had natural gas hedges with notional volumes equivalent to 152,627,500 (in mmBtu), the market value of which was a net loss of $60 million.  The unrealized loss of $63 million and unrealized gain of $3 million for the year ended September 30, 2009, were deferred as a regulatory asset and a regulatory liability, respectively.  For the year ended September 30, 2009, TVA recognized realized losses of $405 million, which were recorded as an increase to fuel and purchased power expense.

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Fuel Oil/Crude Oil

At September 30, 2010, TVA had notional volumes of fuel oil/crude oil hedges equivalent to 2,331,000 (in barrels), the market value of which was a net gain of $10 million.  The unrealized gain of $10 million at September 30, 2010, was deferred as a regulatory liability.  For the year ended September 30, 2010, TVA recognized realized gains on fuel oil/crude oil hedges of $15 million, which were recorded as a decrease to fuel and purchased power expense.

At September 30, 2009, TVA had notional volumes of fuel oil/crude oil hedges equivalent to 3,294,000 (in barrels), the market value of which was a net gain of $13 million.  The unrealized loss of $1 million and unrealized gain of $14 million for the year ended September 30, 2009, were deferred as a regulatory asset and a regulatory liability, respectively.  For the year ended September 30, 2009, TVA recognized realized losses on fuel oil/crude oil hedges of $4 million, which were recorded as an increase to fuel and purchased power expense.

Other Derivative Instruments

Other Commodity Derivatives

TVA enters into forward contracts that hedge cash flow exposures to market fluctuations in the price and delivery of certain commodities including coal, natural gas, fuel oil, crude oil, electricity, uranium, and construction commodities.  TVA expects to take or make delivery, as appropriate, under certain of these forward contracts.  Accordingly, these contracts qualify for normal purchases and normal sales accounting.  TVA continually evaluates these forward contracts as to the likelihood of physical delivery of the contractual quantities.  If TVA were to conclude in the future that certain quantities under these commodity derivative contracts were no longer probable of physical delivery, TVA may be required to mark those contracts to market.  As of September 30, 2010, and September 30, 2009, TVA did not have derivative contracts related to the purchase of electricity, uranium, or construction commodities.

Investment Fund Derivatives

Investment funds consist primarily of funds held in the NDT, the ART, and the SERP.  All securities in the trusts are classified as trading.  See Note 14 for a discussion of the trusts’ objectives and the types of investments included in the various trusts.  Derivative instruments in these trusts include swaps, futures, options, forwards, and other instruments.  As of September 30, 2010, and September 30, 2009, the fair value of derivative instruments in these trusts was immaterial.

Collateral

TVA’s interest rate swaps, its currency swaps, and its swaption contain contract provisions that require a party to post collateral (in a form such as cash or a letter of credit) when the party’s liability balance under the agreement exceeds a certain threshold.  As of September 30, 2010, the aggregate fair value of all derivative instruments with credit-risk related contingent features that were in a liability position was $1.3 billion.  TVA’s collateral obligation as of September 30, 2010, under these arrangements was $297 million, for which TVA had an existing position of $411 million under a letter of credit.  These letter of credit postings reduce the available balance in TVA’s two $2.0 billion revolving credit facilities.  TVA’s assessment of the risk of its nonperformance includes a reduction in its exposure under the contract as a result of this posted collateral.

For all of its derivative instruments with credit-risk related contingent features:

• If TVA remains a majority-owned U.S. government entity but S&P or Moody’s Investor Service (“Moody’s”) downgrades TVA’s credit rating to AA+/Aa1, TVA would be required to post an additional $120 million of collateral in excess of its September 30, 2010 obligation; and

• If TVA ceases to be majority-owned by the U.S. government, its credit rating would likely change and TVA would be required to post additional collateral.

Counterparty Credit Risk

Counterparty credit risk is the exposure to economic loss that would occur as a result of a counterparty’s nonperformance of its contractual obligations.  Where exposed to counterparty credit risk, TVA analyzes the counterparty’s financial condition prior to entering into an agreement, establishes credit limits, monitors the appropriateness of those limits, as well as any changes in the creditworthiness of the counterparty on an ongoing basis, and employs credit mitigation measures, such as collateral or prepayment arrangements and master purchase and sale agreements, to mitigate credit risk.

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Credit of Customers

The majority of TVA’s counterparty credit risk is limited to trade accounts receivable from delivered power sales to municipal and cooperative distributor customers, all located in the Tennessee Valley region.  To a lesser extent, TVA is exposed to credit risk from industries and federal agencies directly served and from exchange power arrangements with a small number of investor-owned regional utilities related to either delivered power or the replacement of open positions of longer-term purchased power or fuel agreements.  Power sales to TVA’s largest industrial customer directly served, represented five percent of TVA’s total operating revenues for the year ended September 30, 2010.  This customer’s senior unsecured credit ratings are currently ‘CCC’ by S&P and ‘Caa2’ by Moody’s.  As a result of its credit ratings, this customer has provided credit assurance to TVA under the terms of its power contract. TVA had concentrations of accounts receivable from seven customers that represented 41 percent of total outstanding accounts receivable at September 30, 2010 and September 30, 2009.

Credit of Derivative Counterparties

TVA has entered into derivative contracts for hedging purposes, and TVA’s NDT and defined benefit pension plan have entered into derivative contracts for investment purposes.  If a counterparty to one of TVA’s hedging transactions defaults, TVA might incur substantial costs in connection with entering into a replacement hedging transaction.  If a counterparty to the derivative contracts into which the NDT and the pension fund have entered for investment purposes defaults, the value of the investment could decline significantly, or perhaps become worthless.  TVA has concentrations of credit risk from the banking and coal industries because multiple companies in these industries serve as counterparties to TVA in various derivative transactions.  As of September 30, 2010, the swaption and all of TVA’s currency swaps, interest rate swaps, and commodity derivatives under the FTP were with counterparties whose Moody’s credit rating was “A2” or higher.  As of September 30, 2010, all of TVA’s coal contract derivatives were with counterparties whose Moody’s credit rating, or TVA’s internal analysis when such information was unavailable, was “B2” or higher.

Credit of Suppliers

If one of TVA’s fuel or purchased power suppliers fails to perform under the terms of its contract with TVA, TVA might lose the money that it paid to the supplier under the contract and have to purchase replacement fuel or power on the spot market, perhaps at a significantly higher price than TVA was entitled to pay under the contract.  In addition, TVA might not be able to acquire replacement fuel or power in a timely manner and thus might be unable to satisfy its own obligations to deliver power.  To help ensure a reliable supply of coal, TVA had coal contracts with 17 different suppliers at September 30, 2010.  The contracted supply of coal is sourced from multiple geographic regions of the United States and is to be delivered via various transportation methods (e.g., barge, rail, and truck).  TVA purchases all of its natural gas requirements from a variety of suppliers under short-term contracts.

As mentioned in Item 1, Business — Current Power Supply — Purchased Power and Other Agreements, TVA has a power purchase agreement with a supplier of electricity for 440 MW of summer net capability from a lignite-fired generating plant that expires on March 31, 2032.  The supplier’s senior secured credit ratings are currently ‘BB-’ by Standard & Poor’s and ‘B2’ by Moody’s.  As a result of its credit ratings, the supplier has provided credit assurance to TVA under the terms of its agreement.  Additionally, one company is TVA’s largest supplier of uranium enrichment services.  Any nonperformance by this company could result in TVA incurring additional costs.

14.  Fair Value Measurements

Fair value is determined based on the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in TVA’s principal market, or in the absence of a principal market, the most advantageous market for the asset or liability in an orderly transaction between market participants.  TVA uses market or observable inputs as the preferred source of values, followed by assumptions based on hypothetical transactions in the absence of market inputs.

Valuation Techniques

There are three main approaches to measuring the fair value of assets and liabilities: (1) the market approach; (2) the income approach; and (3) the cost approach.  The market approach uses prices and other relevant information generated from market transactions involving identical or comparable assets or liabilities.  The income approach uses valuation techniques to convert future amounts to a single present value amount.  The measurement is based on the value indicated by current market expectations about those future amounts of income.  The cost approach is based on the amount that would currently be required to replace an asset.  TVA uses the market approach and the income approach in its fair value measurements.

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The valuation techniques used to measure fair value are based upon observable and unobservable inputs. Observable inputs reflect market data obtained from independent sources, while unobservable inputs reflect TVA’s market assumptions.  These two types of inputs create the following fair value hierarchy:

Level 1	—	Unadjusted quoted prices in active markets accessible by the reporting entity for identical assets or liabilities.  Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing.
Level 2	—	Pricing inputs other than quoted market prices included in Level 1 that are based on observable market data and that are directly or indirectly observable for substantially the full term of the asset or liability.  These include quoted market prices for similar assets or liabilities, quoted market prices for identical or similar assets in markets that are not active, adjusted quoted market prices, inputs from observable data such as interest rate and yield curves, volatilities and default rates observable at commonly quoted intervals, and inputs derived from observable market data by correlation or other means.
Level 3	—	Pricing inputs that are unobservable, or less observable, from objective sources.  Unobservable inputs are only to be used to the extent observable inputs are not available.  These inputs maintain the concept of an exit price from the perspective of a market participant and should reflect assumptions of other market participants.  An entity should consider all market participant assumptions that are available without unreasonable cost and effort.  These are given the lowest priority and are generally used in internally developed methodologies to generate management's best estimate of the fair value when no observable market data is available.

A financial instrument's level within the fair value hierarchy (where Level 3 is the lowest and Level 1 is the highest) is based on the lowest level of input significant to the fair value measurement.

The following sections describe the valuation methodologies TVA uses to measure different financial instruments at fair value.  Except for gains and losses on SERP assets, all changes in fair value of these assets and liabilities have been reflected as changes in regulatory assets, regulatory liabilities, or accumulated other comprehensive loss on TVA’s Balance Sheet as of September 30, 2010, and Statements of Changes in Proprietary Capital for  the year ended September 30, 2010.  Except for gains and losses on SERP assets, there has been no impact to the Statements of Operations or the Statements of Cash Flows related to these fair value measurements.

Investments

At September 30, 2010, TVA’s investment funds were composed of $1.1 billion of securities classified as trading and measured at fair value and $2 million of equity investments not required to be measured at fair value.  Trading securities are held in the NDT, ART, and SERP.  The NDT holds funds for the ultimate decommissioning of TVA’s nuclear power plants.  The ART holds funds for the costs related to the future closure and retirement of TVA’s long-lived assets.  TVA established a SERP for certain executives in critical positions to provide supplemental pension benefits tied to compensation that exceeds limits imposed by IRS rules applicable to the qualified defined benefit pension plan.  The NDT and SERP are invested in securities generally designed to achieve a return in line with overall equity market performance.  The ART is presently invested to achieve a return in line with fixed-income market performance.

The NDT, ART, and SERP are composed of multiple types of investments and are managed by external institutional managers.  Most U.S. and international equities, Treasury inflation-protected securities, real estate investment trust (“REIT”) securities, and cash securities, and certain derivative instruments are measured based on quoted exchange prices in active markets and are classified as Level 1 valuations.  Fixed-income investments, high-yield fixed-income investments, currencies, and most derivative instruments are non-exchange traded and are classified as Level 2 valuations.  These measurements are based on market and income approaches with observable market inputs.

Private partnership investments may include venture capital, buyout, mezzanine or subordinated debt, restructuring or distressed debt, and special situations.  Investments in private partnerships generally involve a three to four year investment period where the investor contributes capital. This is followed by a period of distribution, typically over several years. The investment period is generally, at minimum, a ten-year or longer investment commitment.  The NDT had unfunded commitments related to private partnerships of $87 million at September 30, 2010.  These investments have no redemption or limited redemption options and may also have imposed restrictions on TVA’s ability to liquidate its investment interest.  The private partnerships and other similar alternative investments are reported at fair value which is derived by independent appraisals or judgment of the general partners of each such investment. The inputs used in estimating the fair value of the limited partnerships include the original transaction prices, recent transactions in the same or similar instruments, completed or pending third-party transactions in the underlying investments of comparable issuers, subsequent rounds of financing, recapitalizations and other transactions across the capital structure, offerings in the equity or debt capital markets, and changes in financial ratios or cash flows of the limited partnerships. The fair value of these

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investments may also be adjusted to reflect illiquidity and/or non-transferability, with the amount of such discounts estimated by the general partners in the absence of market information. Due to the lack of observable inputs, the determination of the fair value by the general partners may differ materially from the value ultimately realized from the private partnership investments. TVA classifies its interest in these types of investment as Level 3 within the fair value hierarchy. 

Commingled funds represent investment funds comprising multiple individual financial instruments.  The commingled funds held by the NDT and SERP consist either of a single class of security, such as equity, debt, or foreign currency securities, or multiple classes of securities.  All underlying positions in these commingled funds are either exchange traded (Level 1) or measured using observable inputs for similar instruments (Level 2).  The fair value of commingled funds is based on net asset values (“NAV”) per fund share (the unit of account), derived from the prices of the underlying securities in the funds.  These commingled funds can be liquidated at the measurement date NAV price and are classified as Level 2 valuations.  Required notification periods range from zero to 30 days.  The funds can be redeemed unless doing so would violate regulations to which the fund is subject, would be unreasonable or impracticable, or would be seriously prejudicial to the fund.

Realized and unrealized gains and losses on trading securities are recognized in current earnings and are based on average cost.  The SERP had unrealized losses of $7 million and $3 million for the years ended September 30, 2010, and September 30, 2009, respectively. The gains and losses of the NDT and ART are subsequently reclassified to a regulatory liability or asset account in accordance with TVA’s regulatory accounting policy.  The NDT had unrealized gains of $93 million for the year ended September 30, 2010, and the ART had unrealized losses of less than $1 million for the year ended September 30, 2010.

Currency Swaps, Swaption, and Interest Rate Swaps

See Note 13 — Cash Flow Hedging Strategy for Currency Swaps and Derivatives Not Receiving Hedge Accounting Treatment for a discussion of the nature, purpose, and contingent features of TVA’s currency swaps, swaption, and interest rate swaps.

The currency swaps and interest rate swaps are classified as Level 2 valuations and are valued based on income approaches using observable market inputs for similar instruments.  The swaption is classified as a Level 3 valuation and is valued based on an income approach.  The valuation is computed using a broker-provided pricing model utilizing interest and volatility rates.  While most of the fair value measurement is based on observable inputs, volatility for TVA’s swaption is generally unobservable.  Therefore, the valuation is derived from an observable volatility measure with adjustments.

Coal Contract Derivatives and Commodity Derivatives Under TVA’s FTP

Coal Contract Derivatives. These contracts are classified as Level 3 valuations and are valued based on income approaches.    TVA develops an overall coal price forecast using widely-used short-term and mid-range market data from an external pricing specialist in addition to long-term internal estimates.  To value the volume option component of applicable coal contracts, TVA uses a Black-Scholes pricing model which includes inputs from the overall coal price forecast, contract-specific terms, and other market inputs.

Commodity Derivatives Under Financial Trading Program.  These contracts are valued based on market approaches which utilize Chicago Mercantile Exchange (“CME”) quoted prices and other observable inputs.  Futures and options contracts settled on the CME are classified as Level 1 valuations.  Swap contracts are valued using a pricing model based on CME inputs and are subject to nonperformance risk outside of the exit price.  These contracts are classified as Level 2 valuations.

See Note 13 — Derivatives Not Receiving Hedge Accounting Treatment — Commodity Derivatives and Commodity Derivatives Under Financial Trading Program for a discussion of the nature and purpose of coal contracts with volume options and commodity derivatives under TVA’s FTP.

Nonperformance Risk

The impact of nonperformance risk, which includes credit risk, considers changes in current market conditions, readily available information on nonperformance risk, letters of credit, collateral, other arrangements available, and the nature of master netting arrangements.  TVA is a counterparty to currency swaps, a swaption, interest rate swaps, commodity contracts, and other derivatives which subject TVA to nonperformance risk.  Nonperformance risk on the majority of investments and certain exchange-traded instruments held by TVA is incorporated into the exit price that is derived from quoted market data that is used to mark the investment to market.

Nonperformance risk for most of TVA’s derivative instruments is an adjustment to the initial asset/liability fair value.  TVA adjusts for nonperformance risk, both of TVA (for liabilities) and the counterparty (for assets), by applying a Credit Valuation Adjustment (“CVA”).  TVA determines an appropriate CVA for each applicable financial instrument based on

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the term of the instrument and TVA’s or counterparty’s credit rating as obtained from Moody’s.  For companies that do not have an observable credit rating, TVA uses internal analysis to assign a comparable rating to the company.  TVA discounts each financial instrument using the historical default rate (as reported by Moody’s for CY 1983 to CY 2009) for companies with a similar credit rating over a time period consistent with the remaining term of the contract.  The application of CVAs resulted in a $25 million decrease in the fair value of assets and a $2 million decrease in the fair value of liabilities as of September 30, 2010.

The following table sets forth by level, within the fair value hierarchy, TVA's financial assets and liabilities that were measured at fair value on a recurring basis as of September 30, 2010.  Financial assets and liabilities have been classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  TVA's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the determination of the fair value of the assets and liabilities and their classification in the fair value hierarchy levels.

Fair Value Measurements As of September 30, 2010
Assets	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting(1)			Total
Description
Investments
Equity securities	$	96	$	—	$	—	$	—		$	96
Debt securities
U.S. government corporations and agencies		136		57		—		—			193
Corporate debt securities		—		193		—		—			193
Residential mortgage-backed securities		—		22		—		—			22
Commercial mortgage-backed securities		—		2		—		—			2
Collateralized debt obligations		—		3		—		—			3
Commingled funds(2)
Equity security commingled funds		—		340		—		—			340
Debt security commingled funds		—		209		—		—			209
Foreign currency commingled funds		—		12		—		—			12
Other commingled funds		—		45		—		—			45
Private partnerships		—		—		13		—			13
Total investments		232		883		13		—			1,128
Coal contract derivatives		—		—		152		—			152
Commodity derivatives under FTP
Futures contracts		2		—		—		—			2
Swap contracts		—		9		—		(1	)		8
Total commodity derivatives under FTP		2		9		—		(1	)		10
Total	$	234	$	892	$	165	$	(1	)	$	1,290
Liabilities	Quoted Prices in Active Markets for Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting(1)			Total
Description
Currency swaps	$	—	$	81	$	—	$	—		$	81
Interest rate swaps		—		371		—		—			371
Swaption		—		—		804		—			804
Coal contract derivatives		—		—		49		—			49
Commodity derivatives under FTP
Futures contracts		21		—		—		—			21
Swap contracts		15		227		—		(1	)		241
Option contracts		2		—		—		—			2
Total commodity derivatives under FTP		38		227		—		(1	)		264
Total	$	38	$	679	$	853	$	(1	)	$	1,569
Notes (1)Due to the right of setoff and method of settlement, TVA elects to record commodity derivatives under the FTP based on its net commodity position with the counterparty or broker. (2)Commingled funds represent investment funds comprising multiple individual financial instruments and are classified in the table based on their existing investment portfolio. Commingled funds exclusively composed of one class of security are classified in that category (e.g., equity, debt, or foreign currency securities).  Commingled funds comprising multiple classes of securities are classified as “other commingled funds.”

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Fair Value Measurements As of September 30, 2009
Assets	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting(1)			Total
Description
Investments
Equity securities	$	82	$	1	$	—	$	—		$	83
Debt securities
U.S. government corporations and agencies		83		28		—		—			111
Corporate debt securities		—		203		—		—			203
Residential mortgage-backed securities		—		18		—		—			18
Commercial mortgage-backed securities		—		2		—		—			2
Collateralized debt obligations		—		6		—		—			6
Commingled funds(2)
Equity security commingled funds		—		328		—		—			328
Debt security commingled funds		—		185		—		—			185
Foreign currency commingled funds		—		11		—		—			11
Other commingled funds		—		34		—		—			34
Total investments		165		816		—		—			981
Currency swaps		—		7		—		—			7
Coal contracts derivatives		—		—		87		—			87
Commodity derivatives under FTP
Future contracts		10		—		—		(7	)		3
Swap contracts		—		26		—		(14	)		12
Option contracts		1		3		—		(2	)		2
Total commodity derivatives under FTP		11		29		—		(23	)		17
Total	$	176	$	852	$	87	$	(23	)	$	1,092
Liabilities	Quoted Prices in Active Markets for Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting(1)			Total
Description
Currency swaps	$	—	$	51	$	—	$	—		$	51
Interest rate swaps		—		287		—		—			287
Swaption		—		—		592		—			592
Coal contracts with volume options		—		—		80		—			80
Commodity derivatives under FTP
Future contracts		31		—		—		(7	)		24
Swap contracts		—		55		—		(14	)		41
Option contracts		—		—		—		(2	)		(2	)
Total commodity derivatives under FTP		31		55		—		(23	)		63
Total	$	31	$	393	$	672	$	(23	)	$	1,073
Notes (1)Due to the right of setoff and method of settlement, TVA elects to record commodity derivatives under the FTP based on its net commodity position with the broker or other counterparty. (2)Commingled funds represent investment funds comprising multiple individual financial instruments and are classified in the table based on their existing investment portfolio. Commingled funds exclusively composed of one class of security are classified in that category (e.g., equity, debt, or foreign currency securities). Commingled funds comprising multiple classes of securities are classified as “other commingled funds.”

The following table presents a reconciliation of all assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for year ended September 30, 2010:

Fair Value Measurements Using Significant Unobservable Inputs

For the Year Ended September 30, 2010

	Private Partnerships		Coal Contracts with Volume Options		Swaption
Balances as of October 1, 2009	$	—	$	7	$	(592	)
Purchases, issuances, and settlements		13		—		—
Total gains or losses (realized or unrealized):
Net Unrealized gains (losses) deferred as regulatory assets and liabilities		—		96		(212	)
Balances at September 30, 2010	$	13	$	103	$	(804	)

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Fair Value Measurements Using Significant Unobservable Inputs

For the Year Ended September 30, 2009

	Coal Contracts with Volume Options			Swaption
Balances as of October 1, 2009	$	813		$	(416	)
Total gains or losses (realized or unrealized):
Net Unrealized gains (losses) deferred as regulatory assets and liabilities		(796	)		(176	)
Unrealized losses related to expected net settlement fees included in fuel and purchased power expense		(10	)		—
Balances at September 30, 2009	$	7		$	(592	)

There were no realized gains or losses related to the instruments measured at fair value using significant unobservable inputs that affected net income during the year ended September 30, 2010.  All unrealized gains and losses related to these instruments have been reflected as increases or decreases in regulatory assets and liabilities.  See Note 7.

Other Financial Instruments Not Recorded at Fair Value

TVA uses the methods and assumptions described below to estimate the fair value of each significant class of financial instrument.  The fair market value of the financial instruments held at September 30, 2010, and September 30, 2009, may not be representative of the actual gains or losses that will be recorded when these instruments mature or are called or presented for early redemption.  The estimated values of TVA’s financial instruments not recorded at fair value at September 30, 2010, and September 30, 2009, were as follows:

Estimated Values of Financial Instruments As of September 30
	2010				2009
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents	$	328	$	328	$	201	$	201
Loans and other long-term receivables		83		75		81		72
Short-term debt, net		27		27		844		844
Long-term debt (including current portion), net		23,397		27,193		21,796		23,757

Because of the short-term maturity of cash and cash equivalents, restricted cash and investments, and short-term debt, net, the carrying amounts of these instruments approximate their fair values.

Fair value of long-term debt traded in the public market is determined by multiplying the par value of the debt by the indicative market price at the balance sheet date.

Fair values for loans and other long-term receivables are estimated by determining the present value of future cash flows using a discount rate equal to lending rates for similar loans made to borrowers with similar credit ratings and for similar remaining maturities, where applicable.

See Note 18 — Fair Value Measurements for disclosure of fair value measurements for investments held by the TVA Retirement System (“TVARS”) that support TVA’s qualified defined benefit pension plan.

15.  Proprietary Capital

Appropriation Investment

TVA’s power program and stewardship (non power) program were originally funded primarily by appropriations from Congress.  In 1959, Congress passed legislation that required TVA’s power program to be self-financing from power revenues and proceeds from power program financings.  While TVA’s power program did not directly receive appropriated funds after it became self-financing, TVA continued to receive appropriations for certain multipurpose and other mission-related activities as well as for its stewardship activities.  TVA has not received any appropriations from Congress for any activities since 1999, and since that time, TVA has funded stewardship program activities primarily with power revenues in accordance with a statutory directive from Congress.

The 1959 legislation also required TVA, beginning in 1961, to make annual payments to the U.S. Treasury from net power proceeds as a repayment of and as a return on the Power Program Appropriation Investment until an additional $1.0 billion of the Power Program Appropriation Investment has been repaid.  Of this $1.0 billion amount, $70 million remained unpaid at September 30, 2010.  Once the $1.0 billion has been repaid, the TVA Act requires TVA to continue making payments to the U.S. Treasury as a return on the remaining Power Program Appropriation Investment.  The remaining Power Program Appropriation Investment will be $258 million if TVA receives no additional appropriations from Congress for its power program.

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The table below summarizes TVA's activities related to appropriated funds.

Summary of Proprietary Capital Activity As of September 30
	2010						2009
Appropriation Investment	Power Program			Nonpower  Program			Power Program			Nonpower  Program
Balance at beginning of year	$	348		$	4,355		$	368		$	4,355
Return of appropriation investment		(20	)		(4	)		(20	)		—
Balance at end of year		328			4,351			348			4,355
Retained Earnings
Balance at beginning of year	$	3,291		$	(3,701	)	$	2,571		$	(3,694	)
Net income (expense) for year		982			(10	)		733			(7	)
Return on appropriated investment		(9	)		—			(13	)		—
Balance at end of year		4,264			(3,711	)		3,291			(3,701	)
Net proprietary capital at September 30, 2010	$	4,592		$	640		$	3,639		$	654

Payments to the U.S. Treasury

TVA paid $20 million each year for 2010, 2009, and 2008 as a repayment of the Power Program Appropriation Investment.  In addition, TVA paid the U.S. Treasury $9 million in 2010, $13 million in 2009, and $20 million in 2008 as a return on the Power Program Appropriation Investment.  The amount of the return on the Power Program Appropriation Investment is based on the Power Program Appropriation Investment balance as of the beginning of that year and the computed average interest rate payable by the U.S. Treasury on its total marketable public obligations as of the same date.  The interest rates payable by TVA on the Power Program Appropriation Investment were 2.58 percent, 3.67 percent, and 4.90 percent for 2010, 2009, and 2008, respectively.

Accumulated Other Comprehensive Income (Loss)

The items included in Accumulated other comprehensive income (loss) consist of market valuation adjustments for certain derivative instruments.  See Note 14.

Total Other Comprehensive Loss Activity For the years ended September 30
Accumulated other comprehensive income, September 30, 2007	$	(19	)
Changes in fair value:
Foreign currency swaps		(18	)
Accumulated other comprehensive loss, September 30, 2008		(37	)
Changes in fair value:
Inflation swap
Foreign currency swaps		(38	)
Accumulated other comprehensive loss, September 30, 2009		(75	)
Changes in fair value:
Foreign currency swaps		(20	)
Accumulated other comprehensive loss, September 30, 2010	$	(95	)
Note Foreign currency swap changes are shown net of reclassifications from Other comprehensive income to earnings.

TVA records exchange rate gains and losses on debt in net income and marks its currency swap assets and liabilities to market through other comprehensive income.  TVA then reclassifies an amount out of other comprehensive income into earnings, offsetting the earnings gain/loss from recording the exchange gain/loss on the debt.  The amounts reclassified from other comprehensive income into earnings were a decrease to earnings of $17 million in 2010, a decrease to earnings of $108 million in 2009, and an decrease to earnings of $161 million in 2008.  These reclassifications, coupled with the recording of the exchange gain/loss on the debt, resulted in a net effect on earnings of zero for 2010, 2009, and 2008.  Due to the number of variables affecting the future gains/losses on these instruments, TVA is unable to reasonably estimate the amount to be reclassified from other comprehensive income to earnings in future years.

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Unrealized Losses on Swap/Swaption Contracts

TVA uses regulatory accounting treatment to defer the unrealized mark-to-market gains and losses on certain swap and swaption contracts to reflect that the gain or loss is included in the ratemaking formula when these transactions actually settle.  The value of the swap and swaptions is still recorded on TVA’s balance sheet with realized gains or losses on these contracts recorded in TVA's statement of operations.  The deferred unrealized losses on the value of the swaps and swaption were $299 million for 2010 and $272 million for 2009, and are included as a Regulatory asset on TVA’s balance sheets.  See Note 7 — Swap and Swaption Transactions.

16.  Other Income (Expense), Net

Other income (Expense), net is comprised of the following:

Other Income (Expense), Net For the years ended September 30
	2010		2009			2008
Interest income	$	6	$	9		$	13
Gains (losses) on investments		3		(9	)		(27	)
External services		7		14			14
Claims settlement		—		4			8
Miscellaneous		8		7			1
Total other income (expense), net	$	24	$	25		$	9

17.  Supplemental Cash Flow Information

Interest paid was $1.4 billion in each of 2010, 2009, and 2008.  These amounts differ from interest expense due to the timing of payments and interest capitalized of $79 million in 2010, $40 million in 2009, and $17 million in 2008 as a part of major capital expenditures.

Cash flows from futures contracts, forward contracts, option contracts, or swap contracts that are accounted for as hedges are classified in the same category as the item being hedged or on a basis consistent with the nature of the instrument.

18.  Benefit Plans

TVA sponsors a qualified defined benefit pension plan that covers most of its full-time employees, a qualified defined contribution plan that covers most of its full-time employees, two unfunded post-retirement health care plans that provide for non-vested contributions toward the cost of certain retirees’ medical coverage, other post-employment benefits such as workers’ compensation, and the SERP.

Overview of Plans and Benefits

Defined Benefit Pension Plan.  TVA sponsors a qualified defined benefit pension plan for most of its full-time annual employees that provides two benefit structures: the Original Benefit Structure and the Cash Balance Benefit Structure.

•   Original Benefit Structure.  The pension benefit for a member participating in the Original Benefit Structure is based on the member’s creditable service, the member’s average monthly salary for the highest three consecutive years of base pay, and a pension factor based on the member’s age and years of service, less a Social Security offset.

•   Cash Balance Benefit Structure.  The pension benefit for a member participating in the Cash Balance Benefit Structure is based on credits accumulated in the member’s account and the member’s age.  A member’s account receives credits each pay period equal to 6.00 percent of his or her straight-time earnings.  The account also receives monthly interest credits at a rate set at the beginning of each year equal to the change in the Consumer Price Index (“CPI”) for the period ending on the previous October 31 plus 3.00 percent, with the provision that the rate may not be less than 6.00 percent or more than 10.00 percent.  The actual changes in the CPI for the years ended October 31, 2009 and 2008 were negative 0.63 percent and 4.45 percent, which resulted in interest rates of 6.00 percent and 7.45 percent for CY 2010 and 2009, respectively.

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Members of both the Original Benefit Structure and the Cash Balance Benefit Structure can also become eligible for a vested supplemental pension benefit based on age and years of service, which is designed to help retirees offset the cost of medical insurance.

The defined benefit pension plan is administered by a separate legal entity, the TVARS, which is governed by its own board of directors (“TVARS Board”).  Upon notification by the TVARS Board of a recommended contribution for the next fiscal year, TVA determines whether to make the recommended contribution or any contribution that may be required by the rules and regulations of TVARS.

Defined Contribution Plan. TVARS also administers a defined contribution 401(k) plan to which TVA makes matching contributions of 25 cents on the dollar (up to 1.5 percent of annual pay) for members participating in the Original Benefit Structure and of 75 cents on the dollar (up to 4.5 percent of annual pay) for members participating in the Cash Balance Benefit Structure. TVA made matching contributions of about $27 million to the plan during 2010, $24 million during 2009, and $21 million during 2008.

Supplemental Executive Retirement Plan. In 1995, TVA established its SERP for certain executives in critical positions to provide supplemental pension benefits tied to compensation that exceeds limits imposed by IRS rules applicable to the qualified defined benefit pension plan.  TVA has historically funded the annual calculated expense.

Other Post-Retirement Benefits.  TVA sponsors two unfunded post-retirement benefit plans that provide for non-vested contributions toward the cost of certain eligible retirees’ medical coverage.  The first plan covers only certain retirees and surviving dependents who do not qualify for TVARS benefits, including the vested supplemental pension benefit.  The second plan is designed to place a limit on the out-of-pocket amount certain eligible retirees pay for medical coverage and provides a credit based on years of TVA service and monthly base pension amount reduced by any TVARS supplemental pension benefits or any TVA contribution from the first plan described above.

Other Post-employment Benefits.  TVA employees injured in work-related incidents are covered by the workers’ compensation program for federal employees administered through the Department of Labor by the Office of Workers’ Compensation Programs in accordance with the provisions of the Federal Employees’ Compensation Act (“FECA”).  FECA provides compensation benefits to federal employees for permanent and temporary disability due to employment-related injury or disease.

Accounting Mechanisms

Regulatory Accounting.  TVA has classified all amounts related to unrecognized prior service costs, net actuarial gains or losses, and subsequent changes in the funded status into a regulatory asset.  The deferral of incurred costs is allowed if the costs are probable of future recovery in customer rates.

Cost Method. TVA uses the projected unit credit cost method to determine the service cost and the projected benefit obligation for retirement, termination, and ancillary benefits.  Under this method, a “projected accrued benefit” is calculated as of the beginning of the year and as of the end of the year for each benefit that may be payable in the future.  The “projected accrued benefit” is based on the plan’s accrual formula and upon service as of the beginning or end of the year, but using final average compensation, social security benefits, and other relevant factors projected to the age at which the employee is assumed to leave active service.  The projected benefit obligation is the actuarial present value of the “projected accrued benefits” as of the beginning of the year for employed participants and is the actuarial present value of all benefits for other participants.  The service cost is the actuarial present value of the difference between the “projected accrued benefits” as of the beginning and end of the year.

Amortization of Net Gain or Loss.  TVA utilizes the corridor approach to gain/loss amortization.  Differences between actuarial assumptions and actual plan results are deferred and amortized into periodic cost only when the accumulated differences exceed 10 percent of the greater of the projected benefit obligation or the market-related value of plan assets.  If necessary, the excess is amortized over the average remaining service period of active employees.

Asset Method.  TVA recognizes the impact of asset performance on pension expense over a three-year phase-in period through a “market-related” value of assets calculation.  Since the “market-related” value of assets recognizes investment gains and losses over a three year period, the future value of assets will be impacted as previously deferred gains or losses are recognized.  The “market-related” value is used in calculating expected return on plan assets and net gain or loss for pension cost determination.

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Obligations and Funded Status

The changes in plan obligations, assets, and funded status for the years ended September 30, 2010 and 2009 were as follows:

 

Obligations and Funded Status As of September 30
	Pension Benefits						Other Post-retirement Benefits
	2010			2009			2010			2009
Change in benefit obligation
Benefit obligation at beginning of year	$	9,266		$	8,080		$	665		$	498
Service cost		99			84			12			7
Interest cost		513			582			37			36
Plan participants’ contributions		29			32			81			81
Amendments		3			(482	)		(90	)		7
Actuarial loss		1,077			1,552			69			146
Net transfers from variable fund/401(k) plan		3			(3	)		—			—
Expenses paid		(5	)		(6	)		—			—
Benefits paid		(591	)		(573	)		(116	)		(110	)
Benefit obligation at end of year		10,394			9,266			658			665
Change in plan assets
Fair value of netplan assets at beginning of year		6,643			6,188			—			—
Actual return on plan assets		707			—			—			—
Plan participants’ contributions		29			32			81			81
Net transfers from variable fund/401(k) plan		3			(3	)		—			—
Employer contributions		6			1,005			35			29
Expenses paid		(5	)		(6	)		—			—
Benefits paid		(591	)		(573	)		(116	)		(110	)
Fair value of net plan assets at end of year		6,792			6,643			—			—
Funded status	$	(3,602	)	$	(2,623	)	$	(658	)	$	(665	)

The actuarial loss above for 2010 primarily reflects the impact of the reduction in the discount rate from 5.75 percent to 5.00 percent, which increased the liability by approximately $807 million.  The actuarial loss for 2009 primarily reflects the impact of the previous reduction in the discount rate from 7.50 percent to 5.75 percent, which increased the liability by approximately $1.6 billion.

The effect of pension plan amendments at September 30, 2009, disclosed in the table above refers primarily to changes to the TVARS benefit plan effected during 2009.  The following changes were made to the cost of living adjustment (“COLA”) provisions for the four years beginning January 1, 2010:

• For CY 2010, the COLA was zero.

• For CY 2011, the COLA will be the change in the CPI, capped at 3 percent.

• For CY 2012, the COLA will be zero.

• For CY 2013, the COLA will be the change in the CPI, capped at 2.5 percent.

At the end of the four-year period, the COLA benefit of CPI, capped at 5 percent, will be restored.  Further, the eligibility for the COLA changed to age 60 for employees who retire on or after January 1, 2010.  Finally, the interest crediting rate for fixed fund balances and future contributions was reduced to 6 percent effective January 1, 2010.

No similarly significant plan amendments were enacted during 2010.

Amounts recognized in the Balance Sheets at September 30 consist of regulatory assets that have not been recognized as components of periodic benefit cost as of September 30, 2010 and 2009, respectively, and the funded status of TVA’s benefit plans included in accrued liabilities and other long-term liabilities:

Amounts Recognized in the Balance Sheet As of September 30
	Pension Benefits						Other Post-retirement Benefits
	2010			2009			2010			2009
Regulatory assets	$	4,456		$	3,764		$	255		$	298
Accrued liabilities		(4	)		(5	)		(35	)		(35	)
Other long-term liabilities		(3,598	)		(2,618	)		(623	)		(630	)

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Unrecognized amounts included in regulatory assets yet to be recognized as components of accrued benefit cost at September 30 consist of:

Postretirement Benefit Costs Deferred as Regulatory Assets As of September 30
	Pension Benefits						Other Post-retirement Benefits
	2010			2009			2010			2009
Unrecognized prior service cost (credit)	$	(279	)	$	(305	)	$	(64	)	$	31
Unrecognized net loss		4,724			3,987			319			267
Amount deferred due to actions of regulator		11			82			—			—
Total regulatory assets	$	4,456		$	3,764		$	255		$	298

The projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets at September 30, 2010, and 2009, were as follows:

Projected Benefit Obligations in Excess of Plan Assets As of September 30
	2010		2009
Projected benefit obligation	$	10,394	$	9,266
Accumulated benefit obligation		10,085		9,032
Fair value of net plan assets		6,792		6,643

The components of net periodic benefit cost and other amounts recognized as changes in regulatory assets for the years ended September 30 were as follows:

Components of Net Periodic Benefit Cost For the years ended September 30
	Pension Benefits									Other Post-retirement Benefits
	2010			2009			2008			2010		2009		2008
Components of net periodic benefit cost
Service cost	$	99		$	84		$	110		$	12	$	7	$	5
Interest cost		513			581			522			37		36		28
Expected return on plan assets		(548	)		(543	)		(608	)		—		—		—
Amortization of prior service cost		(24	)		37			37			6		5		5
Recognized net actuarial loss		181			14			41			17		7		5
Net periodic benefit cost as actuarially determined		221			173			102			72		55		43
Amount charged (capitalized) due to actions of regulator		71			(82	)		—			—		—		—
Total net periodic benefit cost recognized	$	292		$	91		$	102		$	72	$	55	$	43

The amounts in the regulatory asset that are expected to be recognized as components of net periodic benefit cost during the next fiscal year are as follows:

Expected Amortization of Regulatory Assets in 2010 As of September 30, 2010
	Pension Benefits			Other Post-retirement Benefits			Total
Prior service cost (credit)	$	(23	)	$	(6	)	$	(29	)
Net actuarial loss		282			22			304
Deferred amounts		11			—			11

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Plan Assumptions

TVA’s reported costs of providing the plan benefits are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various assumptions, the most significant of which are noted below.

Actuarial Assumptions As of September 30
	Pension Benefits						Other Post-retirement Benefits
	2010			2009			2010			2009
Assumptions utilized to determine benefit obligations at September 30
Discount rate		5.00	%		5.75	%		5.00	%		5.75	%
Expected return on plan assets		7.50	%		7.75	%		N/A			N/A
Rate of compensation increase		4.41	%		4.40	%		N/A			N/A
Initial health care cost trend rate		N/A			N/A			8.00	%		8.00	%
Ultimate health care cost trend rate		N/A			N/A			5.00	%		5.00	%
Ultimate trend rate is reached in year beginning		N/A			N/A			2016			2015
Assumptions utilized to determine expense for the years ended September 30
Discount rate		5.75	%		7.50	%		5.75	%		7.5	%
Expected return on plan assets		7.75	%		8.00	%		N/A			N/A
Rate of compensation increase		4.40	%		4.33	%		N/A			N/A
Initial health care cost trend rate		N/A			N/A			8.00	%		8.00	%
Ultimate health care cost trend rate		N/A			N/A			5.00	%		5.00	%
Ultimate trend rate is reached in year beginning		N/A			N/A			2015			2014

Discount Rate.  In the case of selecting an assumed discount rate, TVA reviews market yields on high-quality corporate debt and long-term obligations of the U.S. Treasury and endeavors to match, through the use of a hypothetical bond portfolio, instrument maturities with the maturities of its pension obligations in accordance with the prevailing accounting standards.  Additionally, TVA looks at published pension spot yield curves and applies expected cash flows to these curves to approximate the rate expected to settle the projected benefit payments.  Based on recent market trends in all these data points, TVA decreased its discount rate used to determine benefit obligations from 5.75 percent at the end of 2009 to 5.00 percent at the end of 2010.  TVA had decreased its discount rate from 7.50 percent at the end of 2008 to 5.75 percent at the end of 2009.

Rate of Return.  In determining its expected long-term rate of return on pension plan assets, TVA reviews past long-term performance, asset allocations, and long-term inflation assumptions.  The expected rates of return used to develop net pension cost were 7.75 percent and 8 percent during 2010 and 2009, respectively, and were determined at the beginning each year.  TVA adjusted the expected rate for 2011 based on revisions to future expected returns as provided by third party professional investment consultants.  As of October 1, 2010, the expected rate of return was 7.50 percent.  The actual rate of return for the year ended September 30, 2010, was a gain of 11.1 percent.

Compensation Increases.  This assumption is based on the results obtained from an actual company experience study performed during the most recent six years for retirees as well as other plan participants.  TVA obtained an updated study in 2008 and determined that no changes in this assumption were required.

Mortality.  Mortality assumptions are based on the results obtained from a recent actual company experience study performed which included retirees as well as other plan participants.  TVA obtained an updated study in 2008 and, accordingly, adjusted the mortality rates from the 1983 Group Annuity Mortality Tables to the RP-2000 Mortality Tables.  During 2010, company experience was reexamined and it was determined that TVA’s mortality experience has continued to improve.  As a result, TVA adjusted the mortality rates to RP-2000 Combined Healthy Mortality table projected to 2013 using scale AA at September 30, 2010.

Health Care Cost Trends. TVA reviews actual recent cost trends and projected future trends in establishing health care cost trend rates.  The assumed health care trend rate used for 2010 and 2009 was 8.0 percent.  The 2010 health care cost trend rate of 8.0 percent used to determine benefit obligations is assumed to gradually decrease each

successive year until it reaches a 5.0 percent annual increase in health care costs in the year beginning October 1, 2016, and beyond.

Cost of Living Adjustment.  Thequalified defined benefit pension plan includes a COLA that is generally indexed against the CPI, subject to a floor and ceiling.  The CPI fell during 2009, and market-based measures of inflation expectations at the end of 2009 projected slow growth in the CPI through 2015.  Additionally, the COLA had been temporarily reduced for current retirees and deferred to age 60 for employees retiring on or after January 1, 2010.  As a result of these COLA benefit reductions and low inflationary expectations, TVA reduced the COLA assumption from 3.0 percent to 2.5 percent at September 30, 2009.  The CPI experienced moderate growth during 2010.  Due to stabilizing long-term expectations, TVA determined the COLA assumption should be held at 2.5 percent at September 30, 2010.

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Sensitivity of Costs to Changes in Assumptions.  The following chart reflects the sensitivity of pension cost to changes in certain actuarial assumptions:

Sensitivity to Certain Changes in Pension Assumptions As of September 30, 2010
Actuarial Assumption	Change in Assumption			Impact on 2011 Pension Cost		Impact on 2010 Projected Benefit Obligation
	(Increase in millions)
Discount rate		(0.25	%)	$	17	$	296
Rate of return on plan assets		(0.25	%)		16		—

Each fluctuation above assumes that the other components of the calculation are held constant and excludes any impact for unamortized actuarial gains or losses.

The following chart reflects the sensitivity of post-retirement benefit cost to changes in the health care trend rate:

Sensitivity to Changes in Assumed Health Care Cost Trend Rates As of September 30, 2010
	1% Increase		1% Decrease
Effect on total of service and interest cost components	$	5	$	(6	)
Effect on end-of-year accumulated post-retirement benefit obligation		78		(87	)

Each fluctuation above assumes that the other components of the calculation are held constant and excludes any impact for unamortized actuarial gains or losses.

Plan Investments

The qualified defined benefit pension plan, which includes the Original Benefit Structure and the Cash Balance Benefit Structure, is the only plan that includes qualified plan assets.  The plan assets are primarily stocks and bonds.  In June 2009, TVARS adopted a new asset allocation policy.  The policy shifted a portion of target allocations from equities to fixed income securities.  As a result, TVARS currently targets an asset allocation of 45 percent equity securities, 40 percent fixed income securities, and 15 percent alternative investments.  Of the 45 percent equity securities, 22.5 percent may be non-U.S. equity holdings.  Of the 40 percent fixed income securities, 15 percent may be investment grade credit, nine percent may be high yield securities, and six percent may be inflation protected bonds.  Of the 15 percent alternative investments, five percent may be private real estate, four percent may be private equity, three percent may be distressed debt, and three percent may be timberland.  The TVARS asset allocation policy includes a permissible three percent deviation from these target allocations.  The TVARS Board can take action, as appropriate, to rebalance the system’s assets consistent with the asset allocation policy.  For 2010 and 2009, the asset holdings of the system included the following:

Asset Holdings of TVARS As of September 30
				Plan Assets at September 30
Asset Category	Target Allocation			2010			2009
U.S. equity securities		22.5	%		22	%		23	%
Non-U.S. equity securities		22.5	%		23	%		20	%
Private equity holdings or similar alternative investments		10.0	%		10	%		6	%
Private real estate holdings		5.0	%		2	%		1	%
Fixed income securities		31.0	%		33	%		27	%
High yield securities		9.0	%		9	%		7	%
Cash and equivalents		0.00	%		1	%		16	%
Total		100.0	%		100	%		100	%

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The following table provides the fair value measurement amounts for assets held by TVARS at September 30, 2010:

TVA Retirement System As of September 30, 2010
	TOTAL (1) (2)		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Unobservable Inputs (Level 2)
							Significant Unobservable Inputs (Level 3)
Equity securities	$	706	$	706	$	—	$	—
Debt securities
Corporate debt securities		1,180		—		1,180		—
Residential mortgage-backed securities		430		—		430		—
Debt securities issued by U.S. Treasury and other U.S. government agencies		430		426		4		—
Debt securities issued by foreign governments		177		—		177		—
Asset-backed securities		100		—		100		—
Debt securities issued by state/local Governments		20		—		20		—
Commercial mortgage-backed securities		4		—		4		—
Commingled Funds
Equity		1,733		—		1,733		—
Debt		766		—		766		—
Blended		318		—		318		—
Cash equivalents		410		3		407		—
Private equity funds		492		—		—		492
Private real estate funds		180		—		22		158
Treasury bills, U.S. Government notes and securities held as futures and other derivative collateral		46		29		17		—
Securities lending commingled funds		7		—		7		—
Derivatives
Foreign currency forward receivable		737		—		737		—
Futures		19		19		—		—
Purchased options		1		—		1		—
Total Assets	$	7,756	$	1,183	$	5,923	$	650
Liabilities
Derivatives
Foreign currency forward payable	$	742	$	—	$	742	$	—
Interest rate swaps		2		—		2		—
Credit default swaps		1		—		1		—
Written option obligations		3		1		2		—
Total Liabilities	$	748	$	1	$	747	$	—
Note (1)Excludes approximately $208 million in net payables and receivables associated with security purchases and sales. (2)Excludes a $7 million payable for collateral on loaned securities in connection with TVARS’s participation in securities lending programs.

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The following table provides a reconciliation of beginning and ending balances of pension plan assets measured at fair value on a recurring basis where the determination of fair value includes significant unobservable inputs (Level 3):

Fair Value Measurements Using Significant Unobservable Inputs As of September 30, 2010
	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Beginning balance, October 1, 2009	$	458
Net realized/unrealized depreciation		75
Purchases, sales, issuances, and settlements (net)		117
Ending balance,  September 30, 2010	$	650

Fair Value Measurements

On October 1, 2009, TVA adopted the new fair value disclosure requirements for pension and other post-retirement benefit plan assets.  That accounting guidance defines fair value, establishes a framework for measuring fair value and expands disclosure requirements about fair value measurements.  Fair value is considered to be the exchange price in an orderly transaction between market participants to sell an asset or transfer a liability at the measurement date.  The fair value definition focuses on an exit price, which is the price that would be received by TVARS to sell an asset versus an entry price, which would be the price paid to acquire an asset.

TVA classifies fair value measurements based on the fair value hierarchy described in Note 14.  The following sections describe the valuation methods and assumptions used by TVA to estimate the fair value of investments held directly by the qualified defined benefit pension plan.  Third-party pricing vendors provide valuations for investments held by TVARS in most instances.

Vendor-provided prices for TVARS’s investments are subjected to automated tolerance checks by the pension plan’s master trustee to identify and avoid, where possible, the use of inaccurate prices.  Any questionable prices identified are reported to the vendor which provided the price.  If the prices are validated, the primary pricing source is used.  If not, a secondary source price which has passed the applicable tolerance check is used (or queried with the vendor if it is out of tolerance), resulting in either the use of a secondary price, where validated, or the last reported default price, as in the case of a missing price.  For monthly valued accounts, where secondary price sources are available, an automated inter-source tolerance report identifies prices with an inter-vendor pricing variance of over two percent at an asset class level.  For daily valued accounts, each security is assigned, where possible, an indicative major market index, against which daily price movements are automatically compared.  Tolerance thresholds are established by asset class.  Prices found to be outside of the applicable tolerance threshold are reported and queried with vendors as described above.

Equities.  Investment securities, including common stock and mutual funds, listed on either a national or foreign securities exchange are generally valued each business day at the official closing price (typically the last reported sale price) on the exchange on which the security is primarily traded. If there are no current day sales, the securities are valued at their last quoted bid price. Since equities are priced by an exchange in an active market, they are classified as Level 1.

Corporate Debt Securities.  Corporate bonds are valued based upon recent bid prices or the average of recent bid and asked prices when available (Level 2 inputs) and, if not available, they are valued through matrix pricing models developed by sources considered by management to be reliable.  Matrix pricing, which is a mathematical technique commonly used to price debt securities that are not actively traded, values debt securities without relying exclusively on quoted prices for the specific securities but rather by relying on the securities’ relationship to other benchmark quoted securities (Level 2 inputs).

Residential Mortgage-Backed Securities.  Residential mortgage-backed securities consist of collateralized mortgage obligations (“CMOs”) and U.S. pass-through security pools related to government-sponsored enterprises (“GSEs”).  CMO pricing is typically based on either a volatility-driven, multi-dimensional single cash flow stream model or an option-adjusted spread model.  These models incorporate available market data such as trade information, dealer quotes, market color, spreads, bids, and offers.  Pricing for GSE securities including the Federal Home Loan Mortgage Corporation, the Federal National Mortgage Association, and the Government National Mortgage Association is typically based on quotes from the To Be Announced (“TBA”) market, which is highly-liquid with multiple electronic platforms that facilitate the execution of trading between investors and broker/dealers.  Prices from the TBA market are then compared against other live data feeds as well as input obtained directly from the dealer community.  A tolerance check, adjusted dynamically in response to market conditions, is applied to check for consistency across the trading platforms and dealer quotes.  If discrepancies are identified, the data is reviewed to resolve the differences and determine an appropriate evaluation.  Residential mortgage-backed securities are considered to be priced using Level 2 inputs because of the nature of their market-data-based pricing models.

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U.S. Treasury and Agency Securities.  For U.S. Treasury securities, fair values reflect the closing price reported in the active market in which the security is traded (Level 1 inputs).  Agency securities are typically priced using evaluated pricing applications and models incorporating U.S. Treasury yield curves.   Agency securities are classified as Level 2 because of the nature of their market-data-based pricing models.

Debt Securities Issued by Foreign Governments.  Debt securities issued by foreign governments include foreign government bonds and foreign government inflation linked securities.  These are typically priced based on proprietary discounted cash flow models, incorporating option-adjusted spread features as appropriate.  Debt securities issued by foreign governments are classified as Level 2 because of the nature of their market-data-based pricing models.

Asset-Backed Securities.  Asset-backed securities are typically priced based on a single cash flow stream model which incorporates available market data such as trade information, dealer quotes, market color, spreads, bids, and offers.  Because of the market-data-based nature of such pricing models, asset-backed securities are classified as Level 2.

Debt Securities Issued by State and Local Governments.  Debt securities issued by state and local governments are typically priced using market-data-based pricing models, and are therefore classified as Level 2.  These pricing models incorporate market data such as quotes, trading levels, spread relationships, and yield curves as applicable.

Commercial Mortgage-Backed Securities.  Commercial mortgage-backed securities are typically priced based on a single cash flow stream model which incorporates available market data such as trade information, dealer quotes, market color, spreads, bids, and offers.  Because of the market-data-based nature of such pricing models, commercial mortgage-backed securities are classified as Level 2.

Private Equity Funds.  The private equity limited partnerships and other similar alternative investments are reported at fair value which is derived by independent appraisals or judgment of the general partners of each such investment.  The inputs used in estimating the fair value of the limited partnerships include the original transaction prices, recent transactions in the same or similar instruments, completed or pending third-party transactions in the underlying investments of comparable issuers, subsequent rounds of financing, recapitalizations and other transactions across the capital structure, offerings in the equity or debt capital markets, and changes in financial ratios or cash flows of the limited partnerships.  The fair value of these investments may also be adjusted to reflect illiquidity and/or non-transferability, with the amount of such discounts estimated by the general partners in the absence of market information.  Due to the lack of observable inputs, the determination of the fair value by the general partners may differ materially from the value ultimately realized from the private equity limited partnership.

The private equity managers recognize realized gains or losses when they receive income or dispose of an investment. The net realized capital gains or losses, which include management fees and fund expenses, are allocated to the partners in proportion to their commitments.  The private equity values are prepared by the fund managers and classified as Level 3.

Private Real Estate Funds.  The pension plan invests in commingled funds that invest in a wide variety of real estate opportunities and timberland investments.  The valuation methodologies for these investments are as follows:

The pension plan is invested in a limited partnership formed for the purpose of providing investors with enhanced risk-adjusted total returns through long-biased opportunistic investments principally in mortgage and/or real estate-related fixed income instruments and related securities.  This fund is invested primarily in mortgage-backed securities and asset-backed securities.  Due to the market-data-based nature of the pricing models used for these types of securities, as described above, it is classified as Level 2.

The pension plan is invested in a private REIT formed to make direct or indirect investments in commercial timberland properties.  Pricing for these types of investments are based on comprehensive appraisals which are conducted shortly after initial purchase of properties and at three-year intervals thereafter.  All appraisals are conducted by third-party timberland appraisal firms.  Appraisals are based on either a sales comparison analysis or a discounted cash flow analysis.  Due to the inherent uncertainty of the valuation methodology, this investment is classified as Level 3.

The pension plan is invested in certain private real estate commingled funds which are comprised primarily of real estate investments owned either directly or through partnership interests and mortgage and other loans on income-producing real estate.  Fair value estimates are based upon property appraisal reports prepared by independent real estate appraisers within a reasonable amount of time following acquisition of the real estate and no less frequently than annually thereafter.  The appraisals are based on one or a combination of three methodologies: cost of reproduction analysis, discounted cash flow analysis, and sales comparison analysis.  In general, the input values used in the appraisal process are unobservable; therefore, these funds are classified as Level 3.

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Derivatives.  The pension plan invests in a variety of derivative instruments.  The valuation methodologies for these instruments are as follows:

Futures.   The pension plan enters into equity futures, foreign currency futures, and interest rate futures.  The futures contracts are listed on either a national or foreign securities exchange and generally valued each business day at the official closing price (typically the last reported sales price) on the exchange on which the security is primarily traded. The pricing is performed by third-party vendors. Since futures are priced by an exchange in an active market, they are classified as Level 1.

The net due to broker on futures, which consists of cash reconciliations of margin balances, is classified as Level 2.

Options. The pension plan enters into interest rate options, foreign currency options, and fixed income options.  Options that are listed on either a national or foreign securities exchange are generally valued each business day at the official closing price (typically the last reported sales price) on the exchange on which the security is primarily traded.  These options are classified as Level 1 and include both written and purchased options on Treasury note futures and Eurodollar futures.

Options traded over the counter and not on exchanges are priced by third party vendors and are classified as Level 2.  These include both written and purchased options on interest rate swaps.

Swaps.  The pension plan enters into various types of swaps.   Credit default swaps are priced at market using models that consider cash flows, credit curves, recovery rates, and other factors. The pricing is performed by third party vendors. Interest rate swap contracts are priced at market using forward rates derived from the swap curve.  The pricing is also performed by third-party vendors. Other swaps such as currency swaps and total return swaps are priced by third party vendors using market inputs such as spot rates and yield curves.  All swaps are classified as Level 2.

Foreign Currency Forwards.  The pension plan enters into foreign currency forwards.  All commitments are marked to market daily at the applicable translation rates and any resulting unrealized gains or losses are recorded. Foreign currency forwards are priced by third party vendors and are classified as Level 2.

Commingled Funds.  The pension plan invests in commingled funds which include collective trusts, unit investment trusts, and similar investment funds which predominantly hold debt and/or equity securities as underlying assets.  The pension plan’s ownership consists of a pro rata share and not a direct ownership of an underlying investment.  These commingled funds are valued at their closing net asset values (or unit value) per share as reported by the managers of the commingled funds as supported by the unit prices of actual purchase and sale transactions occurring as of or close to the financial statement date (Level 2 inputs).

Cash Collateral Held Under Securities Lending Arrangements.  Fair value has been determined to approximate the deposit account balances held in cash collateral pools (Level 2 inputs), as no discounts for credit quality or liquidity were determined to be applicable.

Cash Equivalents.  Cash equivalents are highly liquid securities with an original maturity of less than three months.  These consist primarily of U.S. Treasury securities, residential mortgage-backed securities, commercial paper, corporate bonds, asset-backed securities, and certificates of deposit.   The pension plan also holds a cash fund with a dollar weighted average maturity of three months or less.  U.S. Treasury securities are priced based on Level 1 inputs as described above.  The other types of cash equivalent securities, as described above, are priced using models which incorporate market-based inputs and are therefore classified as Level 2.

Cash Flows

Estimated Future Benefit Payments.  The following table sets forth the estimated future benefit payments under the benefit plans.

Estimated Future Benefits Payments As of September 30, 2010
	Pension Benefits		Other Post-Retirement Benefits
2011	$	699	$	36
2012		686		38
2013		688		39
2014		688		40
2015		691		41
2016 - 2020		3,474		210

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Plan Contributions.  TVA expects to contribute $8 million to its SERP and $36 million to its other post-retirement benefit plans in 2011.  TVA made a contribution to the defined benefit pension plan on September 24, 2009 of $1.0 billion that constituted the amount that was expected to be contributed from 2010 to 2013.  TVA has not determined at this time whether additional contributions will be directed to the defined benefit pension plan during 2011.

Other Post-Employment Benefits

Post-employment benefit cost estimates are revised to properly reflect changes in actuarial assumptions made at the end of the year.  TVA utilizes a discount rate determined by reference to the U.S. Treasury Constant Maturities corresponding to calculated average durations of TVA’s future estimated post-employment claims payments.  The use of a 2.53 percent discount rate resulted in the recognition of 2010 annual expense of approximately $141 million and an unpaid benefit obligation of about $570 million at September 30, 2010.  The current portion of the obligation is $62 million and is recorded in Accounts payable and accrued liabilities.  The long-term portion of $508 million is recorded in Other liabilities.  TVA utilized a discount rate of 3.31 percent and 3.85 percent in 2009 and 2008, respectively.  The use of these discount rates resulted in expense and unpaid benefit obligations of $47 million and $484 million, respectively, for 2009 and expense and unpaid benefit obligations of $65 million and $434 million, respectively, for 2008.

TVA made a few changes in the actuarial methods and assumptions for the September 30, 2010 actuarial valuation for other post-employment benefits.  These changes stem from review of and recognition of developing trends in TVA’s post-employment claims experience.  The result of the changes increased both the expense and unpaid benefit obligation for 2010.  Additionally, the reduction of the discount rate in 2010 also increased the expense for 2010 and unpaid benefit obligation at September 30, 2010.

19.  Asset Acquisitions and Dispositions

New Generation

Nuclear.  On August 1, 2007, the TVA Board approved the completion of Watts Bar Unit 2 construction, which was halted in 1985.  Preliminary completion project activities began at Watts Bar Unit 2 in October 2007.  TVA is now engaged in unrestricted construction activities, and the project is scheduled to be completed in CY 2012.

TVA is developing options for future nuclear generation at its Bellefonte site.  In October 2007, TVA submitted a Combined Construction and Operating License Application to the NRC for two new Advanced Passive 1000 reactors to be located at the Bellefonte site and designated as Bellefonte Units 3 and 4. TVA’s application was being supported, in part, by NuStart, an industry consortium comprised of 10 utilities and two reactor vendors whose purpose is to satisfactorily demonstrate the new NRC licensing process for new nuclear plants.  The Bellefonte Combined Construction and Operating License Application is one of several Advanced Passive 1000 standardized plant applications, and other applicants have announced construction schedules that call for their license reviews to be completed prior to Bellefonte’s. As a result, NuStart, with TVA’s agreement, has transitioned its reference plant to the Combined Construction and Operating License Application of another utility.  On September 29, 2010, TVA notified the NRC that the recently completed Final Supplemental Environmental Impact Statement had determined that completion of the partially constructed Bellefonte Unit 1 is the preferred alternative for near-term additional generating capacity at the Bellefonte site.  Consequently, with the exception of the ongoing review of hydrology-related portions of the application, TVA requested that the NRC defer review of the Bellefonte Units 3 and 4 Combined Construction and Operating License Application pending a final decision by the TVA Board regarding new generation capacity at the Bellefonte site.  Contentions have been filed with respect to the Bellefonte Combined Construction and Operating License Application.  See Note 20 — Legal Proceedings — Administrative Proceedings Regarding Bellefonte Units 3 and 4.

As another option, TVA asked the NRC in August 2008 to reinstate the construction permits for its two unfinished nuclear units at the Bellefonte site.  On March 9, 2009, the NRC issued an order reinstating the construction permits for Bellefonte Units 1 and 2.  Following completion of more detailed feasibility studies, on August 20, 2010, the TVA Board of Directors approved the expenditure of $248 million for additional engineering, design, and licensing activities, as well as the procurement of long lead-time components for the partially complete Bellefonte Unit 1.  This action, however, does not mean TVA can re-commence construction of these units, and provisions for the termination of procurement contracts have been put in place should TVA decide not to re-commence construction.  TVA requested in October 2010 to extend the expiration date of the Bellefonte construction permit from October 2011 to October 2020.  Further action by the NRC, reviews by TVA, and final approval by the TVA Board are required before construction activities can resume. See Note 20 — Legal Proceedings — Administrative Proceedings Regarding Bellefonte Units 1 and 2.

Combined Cycle.  Seven States, through its subsidiary SSSL, purchased an undivided 90 percent interest from TVA in a three-unit, 792-MW summer net capability combined cycle combustion turbine facility in Southaven, Mississippi.  SSSL paid TVA approximately $420 million for its interest in the facility.  SSSL and TVA have entered into a lease under which TVA leases SSSL’s undivided 90 percent interest in the facility and operates the entire facility through April 23, 2013.  For additional details, see Note 12.

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On September 28, 2010, the Lagoon Creek Combined Cycle facility began commercial operations with a summer net capability of approximately 550 MW.  The gas-fired combined cycle plant consists of two combustion turbines that supply steam to a single steam turbine.

On June 4, 2009, the TVA Board approved deferring certain upgrades planned for TVA’s Gleason Combustion Turbine Facility and the newly planned New Caledonia Combustion Turbine Facility in order to construct the John Sevier Combined Cycle Facility in northeast Tennessee, using, in part, funds and certain equipment originally allocated for the deferred projects.  TVA expects to complete the combined cycle portion of the facility by mid-CY 2012.  The completed facility is expected to add approximately 880 MW of summer net capability to the TVA system at a cost of approximately $820 million.  At its August 2010 board meeting, the TVA Board cancelled the upgrades to Gleason, and the Gleason-specific costs were subsequently charged to operating and maintenance expense.

Buildings

On February 8, 2008, TVA finalized an agreement to purchase the portion of TVA’s Chattanooga Office Complex in Chattanooga, Tennessee, leased from Chattanooga Valley Associates (with the exception of Monteagle Place, which includes approximately 131,979 square feet) upon the expiration of the existing lease term on January 1, 2011.  The purchase price is $22 million, payable on January 3, 2011.  On May 18, 2009, TVA finalized an agreement to purchase the Monteagle Place portion of the Chattanooga Office Complex upon the expiration of the existing lease term on October 1, 2012.  The purchase price is $8 million.  TVA paid $2 million on October 1, 2009, and $2 million on October 1, 2010, and will pay an additional $2 million for each of the next two years (2011-2012) to satisfy its purchase price commitment.  As a result of these transactions, the capital lease liability and the property, plant, and equipment account for capital leases were adjusted in accordance with the applicable accounting guidance related to leased assets purchased by a lessee during the term of a lease.

20.  Commitments and Contingencies

Commitments

As of September 30, 2010, the amounts of contractual cash commitments maturing in each of the next five years and beyond are shown below:

Commitments and Contingencies Payments due in the year ending September 30
	2011		2012		2013		2014		2015		Thereafter		Total
Debt	$	1,035	$	1,523	$	2,308	$	32	$	1,032	$	17,696	$	23,626	(1)
Lease obligations
Capital		53		5		—		—		—		2		60
Non-cancelable operating		49		41		39		28		25		171		353
Purchase obligations
Power		275		256		197		189		238		4,304		5,459
Fuel		1,956		1,360		1,174		865		825		1,712		7,892
Other		85		118		113		122		55		313		806
Payments on other financings		135		136		488		100		104		713		1,676
Total	$	3,588	$	3,439	$	4,319	$	1,336	$	2,279	$	24,911	$	39,872
Note (1) Does not include noncash items of foreign currency valuation loss of $14 million and net discount on sale of Bonds of $216 million.

In addition to the cash requirements above, TVA has contractual obligations in the form of revenue discounts related to energy prepayments.  See Note 1 — Energy Prepayment Obligations.

Energy Prepayment Obligations Payments Due in the Year Ending September 30
	2011		2012		2013		2014		2015		Thereafter		Total
Energy prepayment obligations	$	105	$	105	$	102	$	100	$	100	$	310	$	822

Debt.  At September 30, 2010, TVA had outstanding discount notes of $27 million and long-term debt (including current maturities) at varying maturities and interest rates of $23.4 billion for total outstanding indebtedness of $23.4 billion.  See Note 11.

Leases.  TVA leases certain property, plant, and equipment under agreements with terms ranging from one to 30 years.  Of the total obligations for TVA’s capital leases, $4 million represents the cost of financing.  TVA’s rental expense for operating leases was $57 million in 2010, $62 million in 2009, and $63 million in 2008.

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Power Purchase Obligations.  TVA has contracted with various independent power producers and power distributor customers for additional capability to be made available to TVA.  In total, these agreements provide 3,120 MW of summer net capability and 29 MW of capability from renewable resources that are not included in the determination of summer net capability.  The remaining terms of the agreements range from one to 22 years.  These qualify as normal purchases and normal sales contracts under GAAP and are thus not accounted for as derivatives.  The total financial commitment for these non-renewable power supply contracts is approximately $5.4 billion, and the total financial commitment for these renewable power supply contracts is approximately $71 million.  TVA spent $504 million, $370 million, and $491 million under power purchase agreements during 2010, 2009, and 2008, respectively.  Costs under TVA’s power purchase agreements are included in the Statements of Operations for 2010, 2009, and 2008 as Fuel and purchased power expense and are expensed as incurred.

Under federal law, TVA is obligated to purchase power from qualifying facilities, cogenerators, and small power producers.  At September 30, 2010, there was a combined qualifying capacity of 919 MW, from seven different suppliers, from which TVA purchased power under this law.  TVA’s obligations to purchase power from these qualifying facilities are not included in the Commitments and Contingencies table.

TVA, along with others, contracted with the Southeastern Power Administration (“SEPA”) to obtain power from eight U.S. Army Corps of Engineers hydroelectric facilities on the Cumberland River system.  The agreement with SEPA can be terminated upon three years’ notice, but this notice of termination may not become effective prior to June 30, 2017.  The contract requires SEPA to provide TVA an annual minimum of 1,500 hours of power for each megawatt of TVA’s 405 MW allocation, and all surplus power from the Cumberland River system.  Because hydroelectric production has been reduced at two of the hydroelectric facilities on the Cumberland River system and because of reductions in the summer stream flow on the Cumberland River, SEPA declared “force majeure” on February 25, 2007.  SEPA then instituted an emergency operating plan that, among other things, eliminates SEPA’s obligation to provide TVA and other affected customers with a minimum amount of power.  It is unclear how long the emergency operating plan will remain in effect.  TVA’s obligations under its contract with SEPA are not included in the Commitments and Contingencies table.

Fuel Purchase Obligations.  TVA has approximately $4.7 billion in long-term fuel purchase commitments ranging in terms of up to 11 years primarily for the purchase and transportation of coal.  TVA also has approximately $3.2 billion of long-term commitments ranging in terms of up to 10 years for the purchase of enriched uranium and fabrication of nuclear fuel assemblies.

Other Obligations.  Other obligations of $806 million consist of contracts as of September 30, 2010, for goods and services primarily related to capital projects as well as other major recurring operating costs.

Contingencies

Nuclear Insurance.  The Price-Anderson Act provides a layered framework of protection to compensate for losses arising from a nuclear event.  For the first layer, all NRC nuclear plant licensees, including TVA, purchase $375 million of nuclear liability insurance from American Nuclear Insurers for each plant with an operating license.  Funds for the second layer, the Secondary Financial Program, would come from an assessment of up to $112 million from the licensees of each of the 104 NRC licensed reactors in the United States.  The assessment for any nuclear accident would be limited to $18 million per year per unit.  American Nuclear Insurers, under a contract with the NRC, administers the Secondary Financial Program.  With its six licensed units, TVA could be required to pay a maximum of $671 million per nuclear incident, but it would have to pay no more than $105 million per incident in any one year.  When the contributions of the nuclear plant licensees are added to the insurance proceeds of $375 million, over $12 billion, including a five percent surcharge for legal expenses, would be available.  Under the Price-Anderson Act, if the first two layers are exhausted, the U.S. Congress is required to take action to provide additional funds to cover the additional losses.

TVA carries property, decommissioning, and decontamination insurance of $4.6 billion for its licensed nuclear plants, with up to $2.1 billion available for a loss at any one site, to cover the cost of stabilizing or shutting down a reactor after an accident.  Some of this insurance, which is purchased from Nuclear Electric Insurance Limited (“NEIL”), may require the payment of retrospective premiums up to a maximum of approximately $74 million.

TVA purchases accidental outage (business interruption) insurance for TVA’s nuclear sites from NEIL.  In the event that an accident covered by this policy takes a nuclear unit offline or keeps a nuclear unit offline, NEIL will pay TVA, after a waiting period, an indemnity (a set dollar amount per week) up to a maximum indemnity of $490 million per unit.  This insurance policy may require the payment of retrospective premiums up to a maximum of approximately $31 million.

Decommissioning Costs.  TVA recognizes legal obligations associated with the future retirement of certain tangible long-lived assets related primarily to fossil-fired generating plants and nuclear generating plants, hydroelectric generating plants/dams, transmission structures, and other property-related assets.

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Nuclear.  Provision for decommissioning costs of nuclear generating units is based on options prescribed by NRC procedures to dismantle and decontaminate the facilities to meet NRC criteria for license termination.  At September 30, 2010, the present value under GAAP of the estimated future decommissioning cost of $1.9 billion was included in AROs.  The actual decommissioning costs may vary from the derived estimates because of, among other things, changes in current assumptions, such as the assumed dates of decommissioning, changes in regulatory requirements, changes in technology, and changes in the cost of labor, materials, and equipment.  Utilities that own and operate nuclear plants are required to use different procedures in calculating nuclear decommissioning costs under GAAP than those that are used in calculating nuclear decommissioning costs when reporting to the NRC.  The two sets of procedures produce different estimates for the costs of decommissioning primarily because of the difference in the discount rates used to calculate the present value of decommissioning costs.

TVA maintains a NDT to provide funding for the ultimate decommissioning of its nuclear power plants.  The balance as of September 30, 2010, was less than the present value of the estimated future nuclear decommissioning costs under the NRC methodology and under GAAP.  TVA monitors the monetary value of its NDT and believes that, over the long term and before cessation of nuclear plant operations and commencement of decommissioning activities, adequate funds from investments will be available to support decommissioning.  TVA’s nuclear power units are currently authorized to operate until 2020-2036, depending on the unit.  It may be possible to extend the operating life of some of the units with approval from the NRC.  See Note 7 — Nuclear Decommissioning Costs and Note 10.

Non-Nuclear Decommissioning.  The present value of the estimated future non-nuclear decommissioning cost was $1.0 billion at September 30, 2010.  This decommissioning cost estimate involves estimating the amount and timing of future expenditures and making judgments concerning whether or not such costs are considered a legal obligation.  Estimating the amount and timing of future expenditures includes, among other things, making projections of the timing and duration of the asset retirement process and how costs will escalate with inflation.  The actual decommissioning costs may vary from the derived estimates because of changes in current assumptions, such as the assumed dates of decommissioning, changes in regulatory requirements, changes in technology, and changes in the cost of labor, materials, and equipment.

TVA maintains an ART to provide funding for the ultimate decommissioning of its power assets.  Estimates involved in determining if additional funding will be made to the ART include inflation rate and rate of return projections on the fund investments.  See Note 7—Non-Nuclear Decommissioning Costs and Note 10.

Environmental Matters. TVA’s power generation activities, like those across the utility industry and in other industrial sectors, are subject to most federal, state, and local environmental laws and regulations.  Major areas of regulation affecting TVA’s activities include air quality control, water quality control, and management and disposal of solid and hazardous wastes.  In the future, regulations in all of these areas are expected to become more stringent and to apply to new emissions and sources, with a particular emphasis on climate change, renewable generation, and energy efficiency.

TVA has incurred, and expects to continue to incur, substantial capital and operating and maintenance costs to comply with evolving environmental requirements primarily associated with, but not limited to, the operation of TVA’s coal-fired generating units.  It is virtually certain that environmental requirements placed on the operation of TVA’s coal-fired and other generating units will continue to become more restrictive and potentially apply to new emissions and sources.  Litigation over emissions from coal-fired generating units is also occurring, including litigation against TVA.  Failure to comply with environmental and safety laws can result in being subject to enforcement actions which can lead to the imposition of significant civil liability, including fines and penalties, criminal sanctions, and/or the shutting down of non-compliant facilities.

From 1977 to 2010, TVA spent approximately $5.3 billion to reduce emissions from its power plants, including $58 million, $172 million, and $274 million in 2010, 2009, and 2008, respectively.  TVA estimates that compliance with future Clean Air Act (“CAA”) requirements (excluding greenhouse gas (“GHG”) requirements) could lead to additional costs of $3.8 billion in the decade beginning in 2011.   There could be additional material costs if reductions of GHGs, including carbon dioxide (“CO2”), are mandated under the CAA or by legislation, or if future legislative, regulatory, or judicial actions lead to more stringent emission reduction requirements for conventional pollutants.  These costs cannot reasonably be predicted at this time because of the uncertainty of such potential actions.

Liability for releases and cleanup of hazardous substances is primarily regulated by the federal CERCLA, and other federal and parallel state statutes.  In a manner similar to many other industries and power systems, TVA has generated or used hazardous substances over the years.

TVA is aware of alleged hazardous-substance releases at 11 non-TVA areas for which it may have some liability.  TVA has reached agreements with EPA to settle its liability at two of these non-TVA areas for a total of less than $23,000.  There is little or no known evidence that TVA contributed any significant quantity of hazardous substances to six of the non-TVA areas, and there has been no recent assertion of potential TVA liability for five of these six areas.  There is evidence that TVA sent some materials to the remaining three non-TVA sites: the David Witherspoon site in Knoxville, Tennessee, the Ward Transformer site in Raleigh, North Carolina, and the General Waste Products site in Evansville, Indiana.

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David Witherspoon Site.  The David Witherspoon site was contaminated with radionuclides, polychlorinated biphenyls (“PCBs”), and metals.  DOE admitted to being the main contributor of materials to the site and cleaned the site up at a reported cost of about $35 million.  DOE asked TVA to “cooperate” in completing the cleanup, but TVA believes it sent only a relatively small amount of equipment and that none of it was radioactive.  TVA therefore believes its liability for these cleanup costs is limited.

Ward Transformer Site.The Ward Transformer site in Raleigh, North Carolina, is contaminated by PCBs from electrical equipment.  There is documentation showing that TVA sent a limited amount of electrical equipment containing PCBs to the site in 1974.  A working group of potentially responsible parties (the “PRP Work Group”) is cleaning up on-site contamination in accordance with an agreement with EPA.  The cleanup effort has been divided into four areas: two phases of soil cleanup; cleanup of off-site contamination in the downstream drainage basin; and supplemental groundwater remediation.  The cost estimate for the first phase of soil cleanup is approximately $55 million.  The cost estimate for the second phase of soil cleanup is $10 million.  Estimates for cleanup of off-site contamination in the downstream drainage basin range from $6 million to $25 million.  There are no reliable estimates for the supplemental groundwater remediation phase.  On April 30, 2009, the PRP Work Group filed an amended complaint in federal court against potentially responsible parties who had not yet settled, including TVA, regarding the two phases of soil cleanup.  TVA settled this lawsuit and its potential liability for the two phases of soil cleanup for $300,000 and has been dismissed as a party.  Although the settlement with respect to the first two phases does not prohibit TVA from having liability in connection with the other two phases or any natural resource damages, the U.S. Department of Justice is attempting to negotiate a government-wide settlement of the liability of all federal agencies (including TVA) for cleanup of offsite contamination in the downstream drainage basin and the investigative portion of the supplemental groundwater remediation.

General Waste Products Site. General Waste Products, located in Evansville, Indiana, operated scrap metal salvage yards from the 1930s until 1998 that contain contamination from lead batteries and PCB transformers.  The original defendants in a CERCLA action for the sites have filed a third-party complaint in the U.S. District Court for the Southern District of Indiana against TVA and others seeking cost contribution for cleanup of the yards.  There is evidence that TVA sent scrap metal to General Waste Products, but TVA has not found any records indicating that it sent batteries or PCB equipment.  Counsel for the original plaintiffs has informed TVA that the first yard has been cleaned up at a cost of approximately $3.2 million, and cleanup estimates for the second yard range from $2 million to $7 million.  TVA settled the claims against it for a minimal amount and was dismissed from the case on September 8, 2010.  TVA did not admit to any liability for the site contamination as part of the settlement.

TVA Sites. TVA operations at some TVA facilities have resulted in oil spills and other contamination that TVA is addressing.  As of September 30, 2010, TVA’s estimated liability for cleanup and similar environmental work for those sites for which sufficient information is available to develop a cost estimate (primarily the TVA sites) is approximately $23 million on a non-discounted basis and is included in Other liabilities on the Balance Sheet.

Legal Proceedings

From time to time, TVA is a party to or otherwise involved in lawsuits, claims, proceedings, investigations, and other legal matters (“Legal Proceedings”) that have arisen in the ordinary course of conducting TVA’s activities, as a result of a catastrophic event or otherwise.  TVA had accrued approximately $14 million and $16 million with respect to Legal Proceedings as of September 30, 2010, and September 30, 2009, respectively.  TVA recognized $2 million, $1 million, and $20 million of expense in 2010, 2009, and 2008, respectively, by increasing accruals related to Legal Proceedings.  No assurance can be given that TVA will not be subject to significant additional claims and liabilities.  If actual liabilities significantly exceed the estimates made, TVA’s results of operations, liquidity, and financial condition could be materially adversely affected.

Legal Proceedings Related to Kingston Ash Spill.  Sixty lawsuits based on the Kingston ash spill have been filed in the United States District Court for the Eastern District of Tennessee.  Five of those actions have been voluntarily dismissed.  The lawsuits, filed by residents, businesses, and property owners in the Kingston area, allege various causes of action in tort – including nuisance, strict liability, personal injury, and property damage – as well as inverse condemnation, and generally seek unspecified compensatory and punitive damages, court orders to clean up the plaintiffs’ properties and surrounding properties, and other relief.  Five of the lawsuits are proposed class actions, and three of these have been consolidated.  TVA is the sole defendant in all actions except in the unconsolidated class actions, in which Geosyntec Consultants, Inc., and Worley Parsons Corporation are also defendants.  On March 26, 2010, the court issued its decision on TVA’s motions to dismiss the first seven cases that had been filed – the proposed class actions and three other cases filed on behalf of named individuals.  In those cases, the court dismissed (1) the tort claims related to TVA’s decisions to build and operate the ash pond and TVA’s recovery and remediation activities, (2) the plaintiffs’ demands for punitive damages, and (3) the plaintiffs’ demands for a jury trial.  The court denied TVA’s motions with regard to plaintiffs’ tort claims concerning TVA's maintenance and upkeep of the ash pond, along with the inverse condemnation claims raised by certain plaintiffs.  The court has scheduled the first seven filed cases for trial beginning on September 13, 2011.

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TVA has received several notices of intent to sue under various environmental statutes from both individuals and environmental groups.  In addition, TVA has received substantial other claims from individuals and companies allegedly affected by the ash spill, and may receive additional claims.

Civil Penalty for the Kingston Ash Spill.  On June 14, 2010, TDEC issued a civil penalty order of approximately $12 million to TVA for the Kingston ash spill, citing violations of the Tennessee Solid Waste Disposal Act and the Tennessee Water Quality Control Act.  Of the $12 million, TVA has already satisfied $6 million of the obligation and may also be credited up to $2 million for performing environmental projects approved by TDEC.  The remaining obligation will be paid in installments through July 2012.

Case Brought by North Carolina Alleging Public Nuisance.  On January 30, 2006, North Carolina filed suit against TVA in the United States District Court for the Western District of North Carolina, alleging that TVA’s operation of its coal-fired power plants in Tennessee, Alabama, and Kentucky constitutes a public nuisance.  On January 13, 2009, the court held that emissions from Bull Run Fossil Plant (“Bull Run”), Kingston, and John Sevier Fossil Plant (“John Sevier”), located in Tennessee, and Widows Creek, located in Alabama, constitute a public nuisance. 

The court issued an order that required TVA to operate existing flue gas scrubbers and selective catalytic reduction systems (“SCRs”) at the units that have them, add scrubbers and SCRs by certain dates at the units that do not have them, and meet specified emission rates and annual tonnage caps for NOx and SO2 after the applicable operation dates for the scrubbers.

TVA had already made capital expenditure commitments to decrease emissions from some of the facilities, but the court ordered significant additional investments and in some instances compliance within a time frame that was shorter than TVA had planned. 

TVA appealed the decision to the United States Court of Appeals for the Fourth Circuit (“Fourth Circuit”), which on July 26, 2010, reversed the holding of the district court and directed the district court to dismiss the action against TVA.  In its decision, the Fourth Circuit held that (1) state laws, including nuisance laws, could not be used to bypass the regulatory structure established by Congress and EPA for controlling emissions; (2) the district court improperly applied North Carolina law to power plants located in Alabama and Tennessee; and (3) the plant operations in Alabama and Tennessee could not be considered nuisances because both states had specifically approved these operations.  North Carolina requested an en banc rehearing, but the Fourth Circuit denied this request on September 21, 2010.  The district court dismissed the case with prejudice on October 1, 2010.

Case Involving Alleged Violations of the New Source Review Regulations at Bull Run.  The National Parks Conservation Association and the Sierra Club filed suit against TVA on February 13, 2001, in the United States District Court for the Eastern District of Tennessee, alleging that TVA did not comply with the New Source Review (“NSR”) requirements of the CAA when TVA repaired Bull Run.  On March 31, 2010, the court ruled in TVA’s favor, holding that two maintenance projects at Bull Run were “routine” and therefore did not require NSR permits.  The plaintiffs appealed this decision to the United States Court of Appeals for the Sixth Circuit.

Case Involving Tennessee Valley Authority Retirement System.  On March 5, 2010, eight current and former participants in and beneficiaries of the TVARS filed suit in the United States District Court for the Middle District of Tennessee against the six then-current members of the TVARS Board.  The lawsuit challenged the TVARS Board’s decision to suspend the TVA contribution requirements for 2010 through 2013, and to amend the TVARS Rules and Regulations to (1) reduce the calculation for COLA benefits for CY 2010 through CY 2013, (2) reduce the interest crediting rate for the fixed fund accounts, and (3) increase the eligibility age to receive COLAs from age 55 to 60.  The plaintiffs allege that these actions violated the TVARS Board members’ fiduciary duties to the plaintiffs (and the purported class) and the plaintiffs’ contractual rights, among other claims.  The plaintiffs sought, among other things, unspecified damages, an order directing the TVARS Board to rescind the amendments, and the appointment of a seventh TVARS Board member.  Five of the six individual defendants filed motions to dismiss the lawsuit, while the remaining defendant filed an answer to the complaint.  On July 28, 2010, TVA moved to intervene in the suit in the event it was not dismissed.  On September 7, 2010, the district court dismissed the breach of fiduciary duty claim against the directors without prejudice, allowing the plaintiffs to file an amended complaint within 14 days against TVARS and TVA but not the individual directors.  The plaintiffs previously had voluntarily withdrawn their constitutional claims, so the court also dismissed those claims without prejudice.  The court dismissed with prejudice the plaintiffs’ claims for breach of contract, violation of the Internal Revenue Code, and appointment of a seventh TVARS Board member. 

On September 21, 2010, the plaintiffs filed an amended complaint against TVARS and TVA.  The plaintiffs allege, among other things, violations of their due process, equal protection, and property rights under the United States Constitution, violations of the Administrative Procedure Act, and breach of statutory duties owed to the plaintiffs.   They seek a declaratory judgment and appropriate relief for the alleged statutory and constitutional violations and breaches of duty.

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Case Arising out of Hurricane Katrina.  In April 2006, TVA was added as a defendant to a class action lawsuit brought in the United States District Court for the Southern District of Mississippi by 14 Mississippi residents allegedly injured by Hurricane Katrina.  The plaintiffs sued seven large oil companies and an oil company trade association, three large chemical companies and a chemical trade association, and 31 large companies involved in the mining and/or burning of coal, alleging that the defendants’ greenhouse gas emissions contributed to global warming and were a proximate and direct cause of Hurricane Katrina’s increased destructive force.  The plaintiffs seek monetary damages among other relief.  The district court dismissed the case for lack of standing.  The plaintiffs appealed the dismissal to the United States Court of Appeals for the Fifth Circuit (“Fifth Circuit”) which, in October 2009, reversed the dismissal of the public and private nuisance, trespass, and negligence claims, affirmed the dismissal of the unjust enrichment, fraudulent misrepresentation, and civil conspiracy claims, and remanded the case to the district court for further proceedings.  TVA and the other defendants filed a petition seeking a rehearing by the entire Fifth Circuit, which the Fifth Circuit granted.  However, on April 30, 2010, the Fifth Circuit issued an order stating that it lost the necessary quorum to rehear the appeal and, on May 28, 2010, the court determined that it had no viable way to rehear the case and vacated its original decision.  As a result, the district court’s dismissal was reinstated.  On August 26, 2010, the plaintiffs served a petition to the U.S. Supreme Court for an order requiring the Fifth Circuit to rehear the case.

Global Warming Cases, Southern District of New York.  On July 21, 2004, two lawsuits were filed in the United States District Court for the Southern District of New York against TVA and other companies that generate power from fossil-fuel electric generating facilities alleging that global warming is a public nuisance and that CO2 emissions from fossil-fuel electric generating facilities should be ordered abated because they contribute to causing the nuisance.  The first case was filed by various states (California, Connecticut, Iowa, New Jersey, New York, Rhode Island, Vermont, and Wisconsin) and the City of New York against TVA and other power suppliers.  The second case, which also alleges private nuisance, was filed against the same defendants by Open Space Institute, Inc., Open Space Conservancy, Inc., and the Audubon Society of New Hampshire.  The plaintiffs seek a court order requiring each defendant to cap its CO2 emissions and then reduce these emissions by an unspecified percentage each year for at least a decade.  In September 2005, the district court dismissed both lawsuits because they raised political questions that should not be decided by the courts.  The plaintiffs appealed to the United States Court of Appeals for the Second Circuit (“Second Circuit”).  On September 21, 2009, the Second Circuit reversed the district court’s decision and remanded the cases to the district court for further proceedings.  On November 5, 2009, TVA and the other defendants filed a petition seeking a rehearing by the entire Second Circuit, which petition was denied on March 5, 2010.  Thereafter, the Second Circuit granted defendants’ motions to stay the order to remand pending the filing of petitions for review by the U.S. Supreme Court.  The defendants other than TVA have filed a petition for review by the Supreme Court and the Solicitor General, on TVA’s behalf, has filed a brief in support of the petition.

Case Involving the General Waste Products Sites.  In July 2008, a third-party complaint under CERCLA was filed against TVA in the District Court for the Southern District of Indiana, alleging that TVA and several other defendants disposed, or arranged the disposal, of hazardous materials at two General Waste Products sites in Evansville, Indiana.  This action was brought by a group of potentially responsible parties in order to require the third-party defendants to contribute to, or pay for, the remediation of the sites.  As of September 30, 2010, the total remediation cost for both sites was expected to exceed $10 million.  The court has approved a settlement agreement among TVA and the third-party plaintiffs, and all claims against TVA have been dismissed. 

Administrative Proceedings Regarding Bellefonte Nuclear Plant Units 1 and 2.  On March 9, 2009, in response to a request by TVA, the NRC issued an order reinstating the construction permits for Bellefonte Nuclear Plant (“Bellefonte”) Units 1 and 2 and returning Bellefonte to a terminated status.  On May 8, 2009, the Blue Ridge Environmental Defense League (“BREDL”), the Bellefonte Efficiency and Sustainability Team (“BEST”), and the Southern Alliance for Clean Energy (“SACE”) filed a petition to intervene in the NRC construction permit proceeding, raising several contentions regarding reinstatement of the construction permits.  Holding their other contentions in abeyance, the NRC directed BREDL, BEST, SACE, TVA, and NRC staff to submit briefs addressing whether the NRC has the statutory authority to reinstate the construction permits.  On January 7, 2010, the NRC issued a decision holding that the NRC has legal authority to reinstate the construction permits, dismissing the first two contentions submitted by BREDL, BEST, and SACE.  The NRC referred the remainder of the contentions to an Atomic Safety and Licensing Board (“ASLB”) for further proceedings.  On April 2, 2010, the ASLB found that BREDL and SACE failed to proffer an admissible contention, and dismissed their hearing petition.  On April 20, 2010, BREDL and SACE filed a motion for additional time to file an appeal of the ASLB’s April 2, 2010 decision and also filed the appeal itself.  On April 30, 2010, TVA filed its answer opposing the motion for additional time and filed a brief in opposition to the appeal.  On September 29, 2010, the NRC issued an order denying the motion by BREDL and SACE for additional time and denying their appeal of the ASLB dismissal.  This determination ends the proceeding before the NRC with regard to the reinstatement of the construction permits.

On March 30, 2009, BREDL filed a petition in the United States Court of Appeals for the District of Columbia Circuit (“D.C. Circuit”) challenging the NRC’s authority to reinstate the construction permits and alleging that the NRC failed to follow the requirements of the National Environmental Policy Act (“NEPA”).  On May 6, 2009, the D.C. Circuit granted TVA’s motion to intervene in this proceeding.  On June 11, 2009, the D.C. Circuit issued an order holding the case in abeyance pending further order of the court.  On March 8, 2010, BREDL filed a second petition in the D.C. Circuit, again challenging NRC’s compliance with NEPA and the NRC’s authority to reinstate the construction permits.  TVA was granted intervenor status in this case as well, and requested that the court dismiss this second petition.  On July 26, 2010, the D.C. Circuit issued an order consolidating the two BREDL

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petitions and continuing the stay of the case.  A September 29, 2010 decision by the NRC denying BREDL’s appeal terminated the administrative proceedings regarding reinstatement of the of the construction permit.  On November 5, 2010, the D.C. Circuit Court issued an order returning the two cases to the court’s active docket and establishing a briefing schedule beginning in January and ending in April 2011.

Administrative Proceedings Regarding Bellefonte Units 3 and 4.  TVA submitted its Combined Construction and Operating License Application for two Advanced Passive 1000 reactors at Bellefonte Units 3 and 4 to the NRC in October 2007.  On June 6, 2008, BEST, BREDL, and SACE submitted to the NRC a joint petition for intervention and a request for a hearing.  The petition raised 20 potential contentions with respect to TVA’s Combined Construction and Operating License Application.  The ASLB denied standing to BEST and admitted four of the 20 contentions submitted by BREDL and SACE.  The NRC later reversed the ASLB’s decision to admit two of the four contentions, leaving only two contentions (which involve questions about the estimated costs of the new nuclear plant and the impact of the facility’s operations, in particular the plant intake, on aquatic ecology) to be litigated in a future hearing.  No hearing will take place until the NRC issues a final Environmental Impact Statement and final Safety Evaluation Report for the units.  On September 29, 2010, TVA notified the NRC that the recently completed Final Supplemental Environmental Impact Statement had determined that completion of the partially constructed Bellefonte Unit 1 is the preferred alternative for near-term additional generating capacity at the Bellefonte site.  Consequently, with the exception of the ongoing review of hydrology-related portions of the application, TVA requested that the NRC defer review of the Bellefonte Units 3 and 4 Combined Construction and Operating License Application pending a final decision of the TVA Board regarding new generation capacity at the Bellefonte site.  If the NRC grants TVA’s request, completion of the final Environmental Impact Statement and final Safety Evaluation Report for Bellefonte Units 3 and 4 would be delayed, which in turn would delay completion of the Bellefonte Units 3 and 4 administrative proceedings.  Therefore, completion of the Bellefonte Units 3 and 4 administrative proceedings is also delayed.

Administrative Proceedings Regarding Watts Bar Nuclear Plant Unit 2.  On July 13, 2009, SACE, the Tennessee Environmental Council, the Sierra Club, We the People, and BREDL filed a request for a hearing and petition to intervene in the NRC administrative process reviewing TVA’s application for an operating license for Watts Bar Unit 2.  The petitioners raised seven contentions related to TVA’s environmental review of the project and the NRC’s basis for confidence in the availability of safe storage options for spent nuclear fuel.  On November 19, 2009, the ASLB granted SACE’s request for hearing, admitted two of SACE’s seven contentions for hearing, and denied the request for hearing submitted on behalf of the other four petitioners.  On March 26, 2010, the NRC affirmed the ASLB’s decision denying the other petitioners the opportunity to participate.  After providing additional information to the NRC on April 9, 2010, which addressed one of the two admitted contentions, TVA submitted a motion asking the ASLB to dismiss the contention as moot.  The motion was unopposed by SACE and on June 2, 2010, the ASLB granted TVA’s motion to dismiss the contention.  A hearing on the remaining contention is scheduled to take place between July and September 2011.  SACE has also asked the ASLB to waive the NRC’s longstanding regulations establishing that, for the purposes of NEPA, need for power and alternative energy source issues will not be considered in operating license proceedings.  On June 29, 2010, the ASLB denied this request and declined to refer the waiver petition to the NRC for consideration.  Subsequently, on July 15, 2010, SACE filed a petition for interlocutory review of this decision with the NRC.  TVA filed its answer opposing this petition on July 26, 2010.  NRC review of this appeal is pending.

John Sevier Fossil Plant Clean Air Act Permit.  On September 20, 2010, the Environmental Integrity Project and the Tennessee Environmental Council filed a petition with EPA, requesting that the EPA Administrator object to the CAA permit issued to TVA for operation of John Sevier.  Among other things, the petitioners allege that repair, maintenance, or replacement activities undertaken at John Sevier Unit 3 in 1986 triggered the Prevention of Significant Deterioration (“PSD”) requirements for SO2 and NOx. The CAA permit, issued by the TDEC, remains in effect pending the disposition of EPA’s petition.

Paradise Fossil Plant Clean Air Act Permit.  On December 21, 2007, the Sierra Club, the Center for Biological Diversity, Kentucky Heartwood, Preston Forsythe, and Hilary Lambert filed a petition with EPA raising objections to the conditions of TVA’s current CAA permit at Paradise Fossil Plant (“Paradise”).  Among other things, the petitioners allege that activities at Paradise triggered the NSR requirements for NOx and that the monitoring of opacity at Units 1 and 2 of the plant is deficient.  In an order issued in July 2009, EPA agreed that the permit failed to include a proper PSD analysis for NOx emission increases as a result physical changes made to the plant’s three main boilers in 1986, that the permit failed to require adequate monitoring systems for opacity and NOx, and that the monitoring of soot emissions from the coal washing and handling plant was inadequate.  TVA’s permit at Paradise is issued by the Kentucky Division for Air Quality (“KDAQ”), and if it is changed, it must be changed by KDAQ.  In November 2009, KDAQ determined that the actions at Paradise had not triggered NSR requirements and reissued the operating permit without including NSR compliance milestones.  On January 9, 2010, Sierra Club petitioned EPA to object to the operating permit, alleging that KDAQ had failed to properly take into account the PSD requirements for the physical changes made in 1986.  On May 21, 2010, the Sierra Club filed a lawsuit seeking to compel EPA to act on the petition.  The current permit continues to remain in effect.

Notice of Violation at Widows Creek Unit 7.  On July 16, 2007, TVA received a Notice of Violation (“NOV”) from EPA alleging, among other violations, that TVA failed to properly maintain ductwork at Widows Creek Unit 7.  TVA repaired the ductwork in 2005.  EPA is discussing a potential monetary sanction against TVA.  Additionally, EPA may require TVA to give up emission allowances.  On March 5, 2008, TVA and Alabama entered into an agreed order in which TVA agreed to pay the state $100,000.

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Kingston NPDES Permit Appeal.  The Sierra Club has challenged the National Pollutant Discharge Elimination System (“NPDES”) permit issued by Tennessee for the scrubber-gypsum pond discharge at Kingston.  This is the second such challenge nationally.  In addition to its allegation that Tennessee violated the Clean Water Act by failing to set specific limits on certain toxic discharges, the Sierra Club alleges that no discharges from the pond infrastructure should be allowed because zero-discharge scrubbers exist.  TDEC is the defendant in the challenge, and TVA has intervened in support of TDEC’s decision to issue the permit.  The matter is set for a hearing before the Tennessee Water Quality Board in February 2011.  The other similar challenge involves an Allegheny Power NPDES permit for its scrubber discharge at a Pennsylvania plant.

Information Request from EPA.  On April 25, 2008, TVA received a request from EPA under section 114 of the CAA requesting extensive information about projects at and the operations of 14 of TVA’s coal-fired units.  These 14 units are located in Alabama, Kentucky, and Tennessee.  TVA has responded to this request.  This request for information is similar to but broader than section 114 requests that other companies have received during EPA’s NSR enforcement initiative.  TVA cannot predict whether EPA will consider the maintenance, capital improvement, or other activities at these 14 units to have violated NSR requirements because of the uncertain interpretation of this program and recent court decisions.  If violations are confirmed, TVA could be required to install new clean air control equipment in addition to the modifications that have already been completed or planned, and TVA could become liable for other payments or penalties.  EPA’s request could be the first step in an administrative proceeding against TVA that could then result in litigation in the courts.

Employment Proceedings.  TVA is engaged in various administrative and legal proceedings arising from employment disputes.  These matters are governed by federal law and involve issues typical of those encountered in the ordinary course of business of a utility.  They may include allegations of discrimination or retaliation (including retaliation for raising nuclear safety or environmental concerns), wrongful termination, and failure to pay overtime under the Fair Labor Standards Act.  Adverse outcomes in these proceedings would not normally be material to TVA’s financial condition, results of operations, and cash flows, although it is possible that some outcomes could require TVA to change how it handles certain personnel matters or operates its plants.

21.  Related Parties

TVA is a wholly-owned corporate agency of the federal government, and because of this relationship, TVA’s revenues and expenses are included as part of the federal budget.  TVA’s purpose and responsibilities as an agency are described under the “Other Agencies” section of the federal budget.

TVA currently receives no appropriations from Congress and funds its business using power system revenues, power financings, and other revenues.  TVA is a source of cash to the federal government.  TVA must repay $70 million of the Power Program Appropriation Investment, and then pay a return on the outstanding balance of this investment indefinitely.  See Note 15 — Appropriation Investment.

TVA also has access to a financing arrangement with the U.S. Treasury pursuant to the TVA Act.  TVA and the U.S. Treasury entered into a memorandum of understanding under which the U.S. Treasury provides TVA with a $150 million credit facility.  This credit facility matures on September 30, 2011, and is expected to be renewed.  Access to this credit facility or other similar financing arrangements has been available to TVA since the 1960s.  See Note 11 — Short-Term Debt.

In the normal course of business, TVA contracts with other federal agencies for sales of electricity and other services.  Transactions with agencies of the federal government were as follows:

Related Party Transactions For the years ended, or as of, September 30
	2010		2009		2008
Sales of electricity services	$	215	$	260	$	229
Other revenues		—		1		—
Other expenses		263		250		231
Receivables		26		19		19
Investments		225		25		—
Payables		129		133		60
Return on Power Program Appropriation Investment		9		13		20
Repayment of Power Program Appropriation Investment		24		20		20

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22.  Unaudited Quarterly Financial Information

A summary of the unaudited quarterly results of operations for the years 2010 and 2009 follows.  This summary should be read in conjunction with the audited financial statements appearing herein.  Results for interim periods may fluctuate as a result of seasonal weather conditions, changes in rates, and other factors.

	Unaudited Quarterly Financial Information
	2010
	First		Second		Third		Fourth		Total
Operating revenues	$	2,349	$	2,622	$	2,587	$	3,316	$	10,874
Operating expenses		1,878		1,875		2,073		2,806		8,632
Operating income		471		747		514		510		2,242
Net income (loss)		150		430		199		193		972

	2009
	First			Second		Third			Fourth		Total
Operating revenues	$	3,077		$	2,933	$	2,566		$	2,679	$	11,255
Operating expenses		3,042			2,503		2,425			1,312		9,282
Operating income		35			430		141			1,367		1,973
Net income (loss)		(305	)		133		(167	)		1,065		726

The significant change in quarterly net income during 2009 is due to accounting for the Kingston ash spill.  During the first three quarters of 2009, charges for the estimate to cleanup the site were recorded as expense.  During August 2009, the TVA Board approved that the amount previously expensed is recoverable in future rates, and, thus, the expense was reclassified as a regulatory asset.  See Note 8.

23.  Subsequent Event

In October 2010, TVA and a national bank amended the $1.0 billion credit facility that was scheduled to expire on November 8, 2010, to extend its maturity date to February 7, 2011.

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Report of Independent Registered Public Accounting Firm

The Board of Directors of Tennessee Valley Authority

We have audited the accompanying balance sheets of Tennessee Valley Authority as of September 30, 2010 and 2009, and the related statements of income, changes in proprietary capital, and cash flows for each of the three years in the period ended September 30, 2010. Our audit also included the financial statement schedule listed in the Index at Item 15(a) for the years ended September 30, 2010, 2009 and 2008.  These financial statements and schedules are the responsibility of Tennessee Valley Authority's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Tennessee Valley Authority at September 30, 2010 and 2009 and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2010, in conformity with U.S. generally accepted accounting principles.  Also, in our opinion the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein for the years ended September 30, 2010, 2009 and 2008.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Tennessee Valley Authority's internal control over financial reporting as of September 30, 2010, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated November 19, 2010 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Chattanooga, Tennessee

November 19, 2010

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Not Applicable.

ITEM 9A.  CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

TVA’s management, including the President and Chief Executive Officer and members of the Disclosure Control Committee (including the Chief Financial Officer and Vice President, Controller and Chief Risk Officer), evaluated the effectiveness of TVA’s disclosure and controls procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of September 30, 2010.  Based on this evaluation, TVA’s management, including the President and Chief Executive Officer and members of the Disclosure Control Committee (including the Chief Financial Officer and Vice President, Controller and Chief Risk Officer), concluded that TVA’s disclosure controls and procedures were effective as of September 30, 2010, to ensure that information required to be disclosed by TVA in reports that it files or submits under the Exchange Act, is recorded, processed, summarized, and reported, within the time periods specified in the SEC’s rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by TVA in such reports is accumulated and communicated to TVA’s management, including the President and Chief Executive Officer and members of the Disclosure Control Committee (including the Chief Financial Officer and Vice President, Controller and Chief Risk Officer), as appropriate, to allow timely decisions regarding required disclosure.

Internal Control over Financial Reporting

(a) Management’s Annual Report on Internal Control over Financial Reporting

TVA’s management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Exchange Act Rule 13a-15(f) and required by Section 404 of the Sarbanes-Oxley Act.  TVA’s internal control over financial reporting is designed to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles.  Because of the inherent limitations in all control systems, internal controls over financial reporting and systems may not prevent or detect misstatements.

TVA’s management, including the President and Chief Executive Officer and members of the Disclosure Control Committee (including the Chief Financial Officer and the Vice President, Controller and Chief Risk Officer), evaluated the design and effectiveness of TVA’s internal control over financial reporting as of September 30, 2010, based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, referred to as “COSO.”  Based on this evaluation, TVA’s management concluded that TVA’s internal control over financial reporting was effective as of September 30, 2010.

Although management’s report on the effectiveness of internal control over financial reporting was not subject to attestation by TVA’s registered public accounting firm, TVA has chosen to obtain such a report.  Ernst & Young LLP, the registered public accounting firm that audited the financial statements included in this Annual Report, has issued an attestation report on TVA’s internal control over financial reporting.  The attestation report appears below.

(b) Changes in Internal Control over Financial Reporting

During the quarter ended September 30, 2010, there were no changes in TVA’s internal control over financial reporting that materially affected, or are reasonably likely to materially affect, TVA’s internal control over financial reporting.

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Report of Independent Registered Public Accounting Firm

The Board of Directors of Tennessee Valley Authority

We have audited Tennessee Valley Authority’s internal control over financial reporting as of September 30, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Tennessee Valley Authority’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Tennessee Valley Authority maintained, in all material respects, effective internal control over financial reporting as of September 30, 2010, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheets of Tennessee Valley Authority as of September 30, 2010 and 2009, and the related statements of income, changes in proprietary capital, and cash flows for each of the three years in the period ended September 30, 2010 and our report dated November 19, 2010 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Chattanooga, Tennessee

November 19, 2010

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ITEM 9B.  OTHER INFORMATION

Not Applicable.

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PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Directors

TVA is administered by a board of nine part-time members appointed by the President of the United States with the advice and consent of the U.S. Senate.  The Chairman of the TVA Board is selected by the members of the TVA Board.  The TVA Board is currently composed of nine directors; however, the term of one director, Mr. Thrailkill, will expire at the end of the current Congressional session and this position will need to be filled by nomination by the President of the United States and confirmation by the U.S. Senate.  In considering potential nominees to the TVA Board, the President and U.S. Senate evaluate and consider the appropriateness of the qualifications of each potential nominee to serve as a director given the mission and purpose of TVA and as set forth in the TVA Act.  Under the TVA Act, to be eligible to be appointed as a member of the TVA Board, an individual (i) must be United States citizen; (ii) must have management expertise relative to a large for-profit or nonprofit corporate, government or academic structure; (iii) cannot be a TVA employee; (iv) must make a full disclosure to Congress of any investment or other financial interest that the individual holds in the energy industry; and (v) must affirm support for the objectives and missions of TVA, including being a national leader in technological innovation, low-cost power, and environmental stewardship. In addition, the President of the United States, in appointing members of the TVA Board, must (i) consider recommendations from other public officials such as the Governors of the States in TVA’s service area; individual citizens; business, industrial, labor, electric power distribution, environmental, civic, and service organizations; and the Congressional delegations of the States in TVA’s service area; and (ii) seek qualified members from among persons who reflect the diversity, including geographical diversity, and needs of TVA’s service area.  At least seven of the nine TVA Board members shall be legal residents of the TVA service area.

The TVA Board at November 19, 2010, consisted of the following individuals with their ages and terms of office provided:

Directors	Age	Year Current Term Began	Year Term Expires
Dennis C. Bottorff, Chairman	66	2006	2011
Robert M. Duncan	59	2006	2011
Howard A. Thrailkill	71	2006	2010
Thomas C. Gilliland	62	2008	2011
Bishop William Graves	74	2008	2012
Marilyn Brown	61	2010	2012
Barbara Haskew	70	2010	2014
Neil McBride	64	2010	2013
William B. Sansom	69	2010	2014

Mr. Bottorff of Nashville, Tennessee, joined the TVA Board in March 2006 and became Chairman of the TVA Board in May 2010.  Since January 2001, he has served as Partner of Council Ventures, a venture capital firm.  He was Chairman of AmSouth Bancorporation until his retirement in 2001 and from 1991 to 1999 was Chief Executive Officer of First American Bank.  He served as a director of Dollar General, a variety store company, from 1998 until its sale in 2007.  In addition, he is a director of Ingram Industries, a privately held provider of wholesale distribution, inland marine transportation, and insurance services; a member of the Board of Trustees of Vanderbilt University; and a director of New Day Pharmacy, an institutional pharmacy.

Mr. Duncan of Inez, Kentucky, joined the TVA Board in March 2006 and served as Chairman of the TVA Board from May 2009 to May 2010.  He is the Chairman, Chief Executive Officer, and Director of Inez Deposit Bank, FSB, in Louisa, Kentucky (since April 1984, with a one-year leave of absence from 1989 to 1990 to serve as Assistant Director of Public Liaison in the White House); Chairman, Chief Executive Officer, and Director of Inez Deposit Bank in Inez, Kentucky (since September 1974 with a one-year leave of absence); Chairman, Chief Executive Officer, and Director of Community Holding Company, a single bank holding company (since 1984 with a one-year leave of absence); Chairman, Chief Executive Officer, and Director of Community Thrift Holding Company, a unitary thrift holding company (since 1999).  From 1998 to 2007, Mr. Duncan was the Chairman of the Big Sandy Regional Industrial Development Authority, which manages industrial parks in five eastern Kentucky counties, and he is also the Secretary for the Highlands Regional Medical Center in Prestonsburg, Kentucky, which manages a regional hospital. From January 2007 to January 2009, he was the Chairman of the Republican National Committee, and he became Chairman of American Crossroads during 2010.

Mr. Thrailkill of Huntsville, Alabama, joined the TVA Board in March 2006.  He retired in September 2005 as President and Chief Operating Officer of Adtran, Inc., in Huntsville, Alabama, which supplies equipment for telecommunications service providers and corporate end users.  He joined Adtran, Inc., in 1992.  Although Mr. Thrailkill’s term on the TVA Board expired in May 2010, he is entitled to continue to serve on the TVA Board until this session of Congress adjourns.  Mr. Thrailkill continues to serve on the TVA Board.

Mr. Gilliland of Blairsville, Georgia, joined the TVA Board in March 2008.  He retired in January 2008 as Executive Vice President, Secretary, General Counsel, and Director of United Community Banks, Inc., a bank holding company.  He joined United Community Banks, Inc., in January 1992.

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Bishop Graves of Memphis, Tennessee, served on the TVA Board from October 2006 to December 2007 and began a second term on the TVA Board in June 2008.  He presided as Bishop of the Christian Methodist Episcopal Church in Memphis, Tennessee, from 2006 until his retirement in June 2010.  Previously he was pastor of the Phillips Temple CME Church of Los Angeles, California.  From September 1993 to July 2004, he was a member of the Board of Memphis Light, Gas and Water, a TVA distributor customer.

Dr. Brown of Atlanta, Georgia joined the TVA Board in October 2010.  Dr. Brown has been a Professor in the School of Public Policy at Georgia Institute of Technology in Atlanta, Georgia, since August 2006.  From 1984 to August 2006, Dr. Brown worked at the Oak Ridge National Laboratory (“ORNL”) in Oak Ridge, Tennessee.  At ORNL, she was Deputy Director and Acting Director of the Engineering Science and Technology Division (from 2005 to 2006), and Program Director of the Energy Efficiency and Renewable Energy Program (from 2000 to 2005).

Dr. Haskew of Chattanooga, Tennessee, joined the TVA Board in October 2010.  Dr. Haskew has been a Professor Emeritus at Middle Tennessee State University (“MTSU”) since June 2010.  She began working at MTSU in 1988 and served as Vice President and Provost from 1995 until 2002 and as Distinguished Professor of Economics from 2002 until her retirement in June 2010.  From 1980 to1988, Dr. Haskew served on the Rate Design Staff for TVA.  In addition, she served as Director of the Tennessee Center for Labor-Management Relations from 2004 until August 2009, and has a consulting practice as a labor arbitrator.

Mr. McBride of Oak Ridge, Tennessee, joined the TVA Board in October 2010.  Mr. McBride is the General Counsel of Legal Aid Society of Middle Tennessee and the Cumberlands (“Legal Aid”) and Managing Director of the Oak Ridge Office of Legal Aid, positions he has held since 2002.  In 1978, he founded Rural Legal Services of Tennessee and served as its director until it was consolidated with Legal Aid in 2002.  He also works as an independent consultant for various legal services organization.

Mr. Sansom of Knoxville, Tennessee, served on the TVA Board from March 2006 until December 2009, was Chairman of the TVA Board from March 2006 until May 2009, and began a second term on the TVA Board in October 2010.  Mr. Sansom is Chairman and Chief Executive Officer of the H.T. Hackney Co., a diversified company involved in the wholesale grocery and furniture manufacturing businesses, and has held that position since 1983.  Since 1995, Mr. Sansom has also been a director of Astec Industries, Inc., a corporation based in Chattanooga, Tennessee, that manufactures equipment and components used in road construction, and since 1984, he has been a director at First Horizon National Corporation, a Memphis, Tennessee, bank holding company.  In 2006, he was named director of Mid-America Apartment Communities, Inc., a real estate investment trust with ownership interests in apartment homes.  From 1994 to 2006, he was a director of Martin Marietta Materials, Inc., a company based in Raleigh, North Carolina, that is in the construction material business.

Executive Officers

TVA’s executive officers as of November 19, 2010, their titles, their ages, and the date their employment with TVA commenced are as follows:

Executive Officers	Title	Age	Employment Commenced
Tom Kilgore	President and Chief Executive Officer	62	2005
John M. Thomas, III	Chief Financial Officer	47	2005
Kimberly S. Greene	Group President, Strategy and External Relations	44	2007
Janet C. Herrin	Executive Vice President, People and Performance	56	1978
William R. McCollum, Jr.	Chief Operating Officer	59	2007
Ralph E. Rodgers	Acting General Counsel	56	1979
Daniel A. Traynor	Vice President and Chief Information Officer	54	2010
Preston D. Swafford	Executive Vice President and Chief Nuclear Officer, Nuclear Generation	50	2006
Robin E. Manning	Executive Vice President, Power System Operations	54	2008
Kenneth R. Breeden	Executive Vice President, Customer Relations	62	2004
Van M. Wardlaw	Executive Vice President, Enterprise Relations	50	1982
Ashok S. Bhatnager	Senior Vice President, Nuclear Generation, Development and Construction	54	1999
Steve Byone	Vice President, Controller and Chief Risk Officer	51	2009

Mr. Kilgore was named Chief Executive Officer in October 2006 after having served as President and Chief Operating Officer since joining TVA in March 2005.  He previously served as President and Chief Executive Officer of Progress Energy Ventures, a subsidiary of Progress Energy Company created to manage various operations of Progress Energy Company, including fuel extraction and energy marketing, from April 2000 to February 2005.  Prior to taking that position, Mr. Kilgore had been Senior Vice President of Power Operations for Carolina Power & Light Company (which became Progress Energy) since August 1998.  From 1991 to 1998, Mr. Kilgore was President and Chief Executive Officer of Oglethorpe Power Corporation in Atlanta, Georgia.

Mr. Thomas was named Chief Financial Officer in June 2010.  Prior to this appointment, he served as Senior Vice President, Corporate Governance and Compliance from July

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2009 to June 2010, as Controller and Chief Accounting Officer from January 2008 to September 2009, and as the General Manager, Operations Business Services from November 2005 to January 2008, where he was responsible for financial and performance support to TVA’s operating organizations.  Prior to joining TVA, Mr. Thomas was Chief Financial Officer during 2005 for Benson Security Systems, a security system integrator located in Gilbert, Arizona, where he was responsible for strategic planning, accounting operations, treasury, and financial reporting.  He was also the Controller of Progress Fuels Corporation (from 2003 to 2005) and Controller of Progress Ventures, Inc. (from 2001 to 2002), both subsidiaries of Progress Energy, where he was responsible for accounting operations, financial reporting, forecasting, and risk management.

Ms. Greene was named Group President of Strategy and External Relations in January 2010.  She served as Chief Financial Officer and Executive Vice President, Financial Services from September 2007 to January 2010.  Before joining TVA, Ms. Greene served as Senior Vice President, Finance, and Treasurer at Southern Company Services, an energy company, from July 2003 to September 2007, where she was responsible for financial planning and analysis, capital markets and leasing, treasury, and investor relations.  From July 2002 to July 2003, Ms. Greene was director of portfolio management for Southern Company Generation and Energy Marketing.  Ms. Greene also serves on the Board of the Electric Power Research Institute (“EPRI”), an independent, non-profit company performing research, development and demonstration in the electricity sector.

Ms. Herrin was named Executive Vice President, People and Performance in June 2010.  Prior to this appointment, she was the Senior Vice President, River Operations, a position she had held since February 1999.  In that position, Ms. Herrin was responsible for establishing river operations policies, procedures, and standards for TVA and served as TVA’s Dam Safety Officer.  She began her career at TVA in 1978 as a civil engineer.  She has served on the TVA Retirement System Board since 2005.

Mr. McCollum joined TVA in May 2007 as Chief Operating Officer.  Prior to joining TVA, Mr. McCollum was Executive Vice President and Chief Regulated Generation Officer at Duke Energy Corporation, an energy company, from October 2006 to May 2007.  Mr. McCollum had been with Duke Energy Corporation (and its predecessor) since 1974 and held a variety of leadership positions there, including Group Vice President, Regulated Fossil-Hydro Generation (from April 2006 to October 2006), Vice President, Strategic Planning and Business Development (from January 2005 to April 2006), and Vice President, Nuclear Support (from November 2002 to December 2004).

Mr. Rodgers was named Acting General Counsel in April 2010.  Prior to his appointment, he served as Deputy General Counsel from January 2010 to April 2010, as Assistant General Counsel from February 2001 to January 2010, and as an attorney from June 1979 to March 1986 and from June 1987 to February 2001.

Mr. Traynor was named Vice President and Chief Information Officer in April 2010.  He previously served as Director of Infrastructure Services for Southern Company, an energy company, from 2003 to 2010, where he was responsible for managing one of the largest corporate computer networks in the southeast.  He also served as Southern Company’s Director of Application Services from 1999 to 2003 and as Southern Company’s Client Services Director from 1996 to 1999.

Mr. Swafford was named Executive Vice President and Chief Nuclear Officer, Nuclear Generation in February 2009.  From June 2007 to February 2009, he was Executive Vice President, Fossil Power Group, and from May 2006 to May 2007, he was Senior Vice President, Nuclear Support.  From December 1995 to April 2006, Mr. Swafford held various positions at Exelon Corporation, an energy company based in Illinois, and its subsidiaries.  From 2002 to 2006, he served as Senior Vice President, Exelon Energy Delivery, and was responsible for transmission and distribution of electricity.  From 2002 to 2003, he was Vice President, Exelon Power, and was responsible for its fleet of gas, coal-fired, and hydroelectric generating facilities.  From 2000 to 2002, he was Vice President, Dresden Nuclear Station.

Mr. Manning joined TVA in August 2008 as Executive Vice President, Power System Operations.  From April 2006 to August 2008, Mr. Manning served as Vice President of Field Operations for Duke Energy Corporation, an energy company, where he was responsible for the operation of all transmission and distribution system activity in Duke Energy Corporation’s Carolinas Region.  Mr. Manning joined Duke Energy Corporation in 1978 and held a variety of leadership positions there, including Vice President, Central Region for Duke Energy Power Delivery (from January 2004 to April 2006), Vice President of Engineering Standards and Process Management for Duke Energy Electric Transmission (from May 2003 to January 2004), and Vice President of Engineering for Duke Energy Gas Transmission (now Spectra Corporation) (from September 2000 to June 2003).

Mr. Breeden was named Executive Vice President, Customer Relations in January 2010.  Mr. Breeden served as Executive Vice President, Customer Recources from September 2006 to January 2010 and as Executive Vice President, Customer Service and Marketing from August 2004 until September 2006.  From March 2002 to August 2004, he was the Program Executive for Executive Conversation, Inc., where he was responsible for executive training programs.  From September 1997 to March 2002, he was President of TXU Energy Services, Enterprise Division, in Dallas, Texas, where he was responsible for a new venture created to address customers’ changing energy needs.  Mr. Breeden had joined TXU Corporation in May 1995 as Senior Vice President of TXU Electric & Gas, where he was responsible for marketing and sales.

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Mr. Wardlaw was named Executive Vice President, Enterprise Relations in August 2010.  Mr. Wardlaw served as Acting Executive Vice President of Strategy and Planning from January 2010 until September 2010, as Executive Vice President of Power Supply and Fuels from July 2008 to August 2010, as Senior Vice President, Commercial Operations and Fuels from January 2007 to June 2008, as Vice President, Bulk Power Trading from September 2006 to December 2006, and as Vice President of Transmission and Reliability from December 2000 to September 2006.  Mr. Wardlaw began his career with TVA in January 1982 as an electrical engineer, and has also worked in customer service, marketing, and field services.

Mr. Bhatnagar is the Senior Vice President of Nuclear Generation Development and Construction, a position he has held since April 2007.  He joined TVA in August 1999 as Site Support Manager at Browns Ferry and was subsequently appointed Browns Ferry Plant Manager in July 2000, Browns Ferry Site Vice president in July 2001, and Senior Vice President, Nuclear Operations, in June 2004.

Mr. Byone joined TVA in September 2009 as Vice President and Controller and was also named Chief Risk Officer in January 2010.  Before joining TVA, he served as the Vice President and Chief Financial Officer of the Electric Reliability Council of Texas (“ERCOT”), an independent system operator located in Austin, Texas, from September 2005 to September 2009.  Mr. Byone first came to ERCOT in May 2005 in a consulting role to launch ERCOT’s internal control management and enterprise risk management programs.  Previously, Mr. Byone served as the Vice President and Chief Risk Officer for Progress Energy (from May 2002 to May 2005).  In that position, Mr. Byone designed an enterprise-wide risk management framework to support review and alignment of corporate strategy, capital investments, and risk appetite.

Disclosure and Financial Code of Ethics

TVA has a Disclosure and Financial Ethics Code (“Financial Ethics Code”) that applies to all executive officers (including the Chief Executive Officer, Chief Financial Officer, and Controller) and directors of TVA as well as to all employees who certify information contained in quarterly reports or annual reports or who have responsibility for internal control self-assessments.  The Financial Ethics Code includes provisions covering conflicts of interest, ethical conduct, compliance with applicable laws, rules, and regulations, responsibility for full, fair, accurate, timely, and understandable disclosures, and accountability for adherence to the Financial Ethics Code.  TVA will provide a current copy of the Financial Ethics Code to any person, without charge, upon request.  Requests may be made by calling 888-882-4975 or by sending an e-mail to: investor@tva.com.  Any waivers of or changes to provisions of the Financial Ethics Code that require disclosure pursuant to applicable SEC requirements will be promptly disclosed to the public, subject to limitations imposed by law, on TVA’s website at: www.tva.gov.  Information contained on TVA’s website shall not be deemed incorporated into, or to be a part of, this Annual Report.

Committees of the TVA Board

The TVA Board has an Audit, Risk, and Regulation Committee established in accordance with the TVA Act.  This committee has superseded and largely assumed the duties and responsibilities of the TVA Board’s former Audit, Governance, and Ethics Committee.  TVA’s Audit, Risk and Regulation Committee consists of Thomas C. Gilliland (chair), Robert M. Duncan, Dennis C. Bottorff, and Neil G. McBride.  Director Gilliland and Director Bottorff are each an “audit committee financial expert” as defined in Item 407(d)(5) of Regulation S-K under the Exchange Act.

TVA is exempted by section 37 of the Exchange Act from complying with section 10A(m)(3) of the Exchange Act, which requires each member of a listed issuer’s audit committee to be an independent member of the board of directors of the issuer.  The TVA Act contains certain provisions that are similar to the considerations for independence under section 10A(m)(3) of the Exchange Act, including, as described above, that to be eligible for appointment to the TVA Board, an individual shall not be an employee of TVA and shall make full disclosure to Congress of any investment or other financial interest that the individual holds in the energy industry.

Under section 10A(m)(2) of the Exchange Act, which applies to TVA, the audit committee is directly responsible for the appointment, compensation, and oversight of the external auditor; however, the TVA Act assigns the responsibility for engaging the services of the external auditor to the TVA Board.

The TVA Board has also established the following committees in addition to the Audit, Risk and Regulation Committee:

• Finance, Rates, and Portfolio Committee

• Customer and External Relations Committee

• People and Performance Committee

• Nuclear Committee

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ITEM 11.  EXECUTIVE COMPENSATION

COMPENSATION DISCUSSION AND ANALYSIS

This Compensation Discussion and Analysis provides information about TVA’s compensation philosophy and strategy, as well as the policies and decisions that guided TVA in 2010 in establishing the level and nature of the compensation provided to the named executive officers (“Named Executive Officers” or “NEOs”).  The 2010 Named Executive Officers are: Tom Kilgore, the President and Chief Executive Officer (“CEO”), Kimberly S. Greene, who began 2010 as TVA’s Chief Financial Officer (“CFO”) and Executive Vice President, Financial Services, and was named Group President of Strategy and External Relations in January 2010, John M. Hoskins, who served as Interim CFO from January 2010 until June 2010, John M. Thomas, III, who was named CFO in June 2010, William R. McCollum, Jr., Preston D. Swafford, and Ashok S. Bhatnagar.  Detailed information about the compensation of each of the NEOs is listed in the Summary Compensation Table.

Executive Summary

The TVA Act places significant authority and responsibility in the TVA Board for matters associated with the compensation of TVA employees, including the Named Executive Officers.  The TVA Board exercised this authority when it approved the Compensation Plan and when it delegated certain bounded authority to the Chairman of the TVA Board and to the CEO.  Despite these delegations, the TVA Board, the appropriate TVA Board committee, and individual TVA Board members maintain an active involvement in compensation matters.  The TVA Board-level involvement with the compensation of the Named Executive Officers is an annual process.  This involvement includes the consideration of benchmarking and other information provided by the Board’s compensation consultant.  In addition, Board-level involvement occurs with respect to those items that have been reserved to the TVA Board for approval, with respect to the review, oversight, or consultation by the TVA Board committee, as required, and with respect to the consultation with individual TVA Board members, as required.  These matters are discussed in greater detail below.

The TVA Board has established a compensation plan for all TVA employees (the “Compensation Plan”) based on the requirements of the TVA Act.  The Compensation Plan is designed to support TVA’s mission and to fulfill the following purposes:

• Provide a competitive level of compensation that enables TVA to attract, retain, and motivate highly competent employees.  Total target compensation for each position in TVA is determined by market pricing based on a level needed to attract, retain, and motivate employees critical to TVA’s success in achieving its mission.  Accordingly, total compensation levels typically are targeted at the median (50th percentile) of the relevant labor market for most positions.  However, total compensation levels for some positions are targeted at a higher level (typically between the 50th and 75th percentile).  These positions have higher targeted total compensation levels because of market scarcity, recruitment and retention issues, and other business reasons.

• Encourage and reward executives for their performance and contributions to the successful achievement of financial and operational goals.  A key tenet of the Compensation Plan is to pay for performance by rewarding all employees, but the executives at a greater level, for improvement in TVA’s overall performance, as well as that of individual business units.  The TVA Board believes that the portion of total direct compensation delivered through structured incentive compensation should increase as an employee’s position and level of responsibility within TVA increases.  Accordingly, a significant percentageof total target direct compensation opportunity for the Named Executive Officers (40 percent to 65 percent) is performance-based incentive compensation.

• Provide executives with the focus to achieve short-term and long-term business goals that are important to TVA, TVA’s customers, and the people TVA serves.  TVA seeks to hire and retain executives who are focused on both TVA’s short-term and long-term success.  The Compensation Plan is designed to achieve this goal by providing a mix of salary and performance-based annual and long-term incentive compensation.

• Improve overall company performance through productivity enhancement.  An executive cannot help meet TVA’s goals and improve performance without the work of others.  For this reason, the performance goals set at the corporate level are the same for both executives and all non-executive employees.  This generally translates into all TVA employees receiving compensation in a manner that aligns their work with the same goals and encourages and rewards them for the successful achievement of TVA’s goals.

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Under the Compensation Plan, the compensation programs for the Named Executive Officers consist of the components identified in the following table:

Compensation Program Components for Named Executive Officers
Compensation Component	Objective	Key Features
Annual Salary	Fixed and paid biweekly to executives	Total direct compensation (salary plus annual and long-term incentive compensation plus long-term deferred compensation) is targeted at the median (50th percentile) for similar positions at other companies in TVA’s peer group, or above the median (50th to 75th percentile) for positions affected by market scarcity, recruitment and retention issues, and other business reasons with annual salary targeted to the same ranges Reviewed annually to consider changes in peer group benchmark salaries and/or exceptional individual merit performances in past years
Annual Incentive Compensation	Not-guaranteed, variable, performance-based, and based on the attainment of pre-established performance goals for the fiscal year	Target annual incentive opportunities increase with position and responsibility and are based on the opportunities other companies in TVA’s peer group provided to those in similar positions Annual incentive payouts are based on the results of performance goals at the TVA level and may be adjusted based on the evaluation of performance during the year Annual incentive opportunities are reviewed annually to consider changes in peer group benchmark short-term incentives
Long-Term Incentive Compensation	Not-guaranteed, variable, and based on the attainment of pre-established performance goals for a performance cycle, typically three fiscal years	Target long-term incentive opportunities are limited to executives in critical positions who make decisions that significantly influence developing and attaining TVA’s long-term strategic objectives Target long-term incentive payouts, which may be adjusted, are based on achieving performance goals established for a specific performance cycle Long-term incentive opportunities are reviewed annually to consider changes made in the long-term incentives by companies in TVA’s peer group
Long-Term Deferred Compensation	Awarded in the form of annual credits that vest after a specified period of time, typically three to five years	Awarded to provide retention incentives to executives similar to the retention incentive provided by restricted stock or restricted stock units Executives generally must remain at TVA for the entire length of the agreement in order to receive compensation credits The amount of the annual long-term deferred compensation credit is targeted to be about 20 percent of total long-term compensation (including the long-term incentive compensation described above)
Pension Plans	Both qualified and supplemental, which provide compensation beginning with retirement or termination of employment	Broad-based plans available to full-time employees of TVA that are qualified under IRS rules and that are similar to the qualified plans provided by other companies in TVA’s peer group Certain executives in critical positions also participate in a non-qualified pension plan that provides supplemental pension benefits at compensation levels that exceed the limits permitted by the IRS regulations applicable to qualified plans; these supplemental benefits are comparable to those provided by other companies in TVA’s peer group

TVA’s Chief Risk Officer and the Enterprise Risk Management organization have considered the risks arising from the Compensation Plan and TVA’s policies and practices of compensating its employees, both executive and non-executive, and believe that the Compensation Plan and such policies and practices are not reasonably likely to have a material adverse effect on TVA.

Authority for the Executive Compensation Program

The TVA Act is the authority for establishing the compensation of all TVA employees, including the Named Executive Officers, and places responsibility for doing so with the TVA Board.  Under section 2 of the TVA Act, the TVA Board is directed to establish a compensation plan for all TVA employees which:

• Specifies all compensation (including salary or any other pay, bonuses, benefits, incentives, and any other form of remuneration) for the CEO and TVA employees;

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• Is based on an annual survey of the prevailing compensation for similar positions in private industry, including engineering and electric utility companies, publicly owned electric utilities, and federal, state, and local governments; and

• Provides that education, experience, level of responsibility, geographic differences, and retention and recruitment needs will be taken into account in determining compensation of employees.

The TVA Act also provides that:

• The TVA Board will annually approve all compensation (including salary or any other pay, bonuses, benefits, incentives, and other form of remuneration) of all managers and technical personnel who report directly to the CEO (including any adjustment to compensation);

• On the recommendation of the CEO, the TVA Board will approve the salaries of employees whose salaries would be in excess of Level IV of the Executive Schedule ($155,500 in 2010); and

• The CEO will determine the salary and benefits of employees whose annual salary is not greater than Level IV of the Executive Schedule ($155,500 in 2010).

The philosophy of the Compensation Plan approved by the TVA Board for all TVA employees, including the Named Executive Officers, is based on the TVA Act.  The philosophy recognizes that many employees, including executives, are called on to accomplish specialized aspects of TVA’s mission safely, reliably, and efficiently, and must have the requisite education, experience, and professional qualifications.  These requirements make it necessary for TVA to offer compensation to its specialized employees that makes it possible for TVA to attract highly qualified candidates for positions similar to those in relevant industries and motivates them to stay with TVA.

At the same time, the Compensation Plan provides the TVA Board the discretion to adjust all forms of compensation to respond to unexpected and significant changes to TVA’s mission and business that may occur during the year.  The TVA Board used this discretion in light of the economic conditions and financial challenges the country and TVA faced beginning in late 2008 and continuing into 2010, many of which are described in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.  The TVA Board set the compensation of the Named Executive Officers at the beginning of 2009 based on the philosophy, principles, and targets set forth above.  When TVA was impacted by the economy and other financial challenges as 2009 progressed, however, the TVA Board used its discretion to freeze executive salaries and to reduce or eliminate target incentive compensation from the levels it had established earlier.  For 2010, the TVA Board decided to reinstate the compensation components at levels originally established for 2009 (but not paid in full, or at all in some cases), unless the Named Executive Officer had a significant change in position and responsibility that made a change in compensation appropriate in light of the philosophy, principles, and targets described above.

In establishing the Compensation Plan, the TVA Board delegated to the CEO the authority to approve, or delegate to others the authority to approve, all personnel and compensation actions for which the TVA Board is responsible but has not reserved for itself to approve.  In addition, the TVA Board took two separate actions in 2010 to delegate authority with respect to executive compensation:

On February 11, 2010, the TVA Board approved compensation ranges for the direct reports to the CEO of 80 percent to 110 percent of the median total direct compensation for comparable positions, as established by benchmarking sources outside of TVA, and authorized the CEO to set or adjust compensation for the CEO’s present or future direct reports within such compensation ranges, as well as to approve the parameters under which such executives may participate in certain supplemental benefit plans such as SERP, provided that the CEO may not finally set or adjust such compensation until the appropriate TVA Board committee, or the full TVA Board, has had the opportunity to review the proposed compensation.  This delegation applied for new direct report positions in 2010 and will apply for all direct report positions in 2011 and thereafter.

On June 10, 2010, the TVA Board delegated to the Chairman of the TVA Board, in consultation with the appropriate TVA Board committee and with input from individual members of the TVA Board, the authority to evaluate and rate the performance of the CEO during the year, and the authority to approve any payout to the CEO under the Executive Annual Incentive Plan (“EAIP”) based on, among other things, the CEO’s evaluated performance during the year, and delegated to the CEO, in consultation with the appropriate TVA Board committee and with input from individual members of the TVA Board, the authority to approve the individual performance goals for the CEO’s direct reports and the authority to evaluate and rate the performance of the CEO’s direct reports during the year.

TVA Board Committee Oversight

The Finance, Strategy, Rates, and Administration Committee and after its establishment on June 10, 2010, the People and Performance Committee of the TVA Board (collectively, the “Committee”) were responsible for oversight of executive compensation pursuant to the Compensation Plan, review of this Compensation Discussion and Analysis, and, to the extent applicable, review of performance goal achievement for 2010.  As a result of the TVA Board’s June 2010 delegations, the Committee also (1) reviews proposed actions

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of the CEO to set or adjust the compensation of the CEO’s present and future direct reports within the 80 percent to 110 percent compensation range of the median total direct compensation for comparable positions, as well as to approve the parameters under which such executives may participate in certain supplemental benefit plans such as SERP, (2) consults with the Chairman of the TVA Board about the Chairman of the TVA Board’s proposed evaluation and rating of the performance of the CEO during the year and about the proposed payout to the CEO under the EAIP based on, among other things, the CEO’s evaluated performance during the year, and (3) consults with the CEO about the CEO’s proposed individual performance goals for the CEO’s direct reports and the CEO’s proposed evaluation and rating of the performance of the CEO’s direct reports during the year.  To assist in evaluating competitive levels of compensation for executives, the Committee had previously selected and used Watson Wyatt as its independent compensation consultant. In January 2010, Watson Wyatt merged with Towers Perrin, and the merged compensation consultant businesses now fall under the combined firm named Towers Watson.  Since the merger of the two firms, the Committee has decided to retain Towers Watson as its compensation consultant.

Use of Market Data and Benchmarking

Except to the extent discussed above, TVA generally seeks to target total compensation for executives at a competitive level with respect to the relevant labor market.  Market information for total compensation, as well as each element of compensation, for the Named Executive Officers for 2010 was obtained from:

• Published and customized compensation surveys reflecting the relevant labor markets identified for designated positions; and

• Publicly disclosed information from the proxy statements and annual reports on Form 10-K of energy services companies with revenues of $3.0 billion and greater.

After the competitive market compensation was compiled for the positions at the beginning of 2010, the Human Resources department, with the assistance of its compensation consultant at the time, Towers Perrin, analyzed the data and provided its analysis to TVA management and the Committee.  Except for the Named Executive Officers and others whose compensation was frozen or otherwise affected by actions of the TVA Board in the face of the challenges confronting TVA over the 2008 to 2010 period and described in this Compensation Discussion and Analysis, the Committee, with the assistance of its compensation consultant at the time, Watson Wyatt, used this information to:

• Test target compensation level and incentive opportunity competitiveness;

• Serve as a point of reference for establishing pay packages for recruiting executives; and

• Determine appropriate target compensation levels and incentive opportunities to maintain the desired degree of market competitiveness.

TVA’s relevant labor market for most executives, including the Named Executive Officers, was comprised of both private and publicly owned companies in the energy services industry of similar revenue and scope to TVA.  For the survey-based analysis, TVA looked at the following energy services companies with annual revenues of $3.0 billion and greater from the 2009 Towers Perrin Energy Services Executive Compensation Database:

Allegheny Energy, Inc.	Energy Future Holdings Corp.	Pacific Gas and Electric Co.*
Alliant Energy Corp.	Entergy Corp.*	Pepco Holdings, Inc.*
Ameren Corp.*	Exelon Corp.*	Pinnacle West Capital Corp.
American Electric Power Co., Inc.*	FirstEnergy Corp.*	PPL Corp.*
Calpine Corp.	FPL Group, Inc.*	Progress Energy, Inc.*
CenterPoint Energy, Inc.	GDF SUEZ Energy North America	Public Service Enterprise Group, Inc.*
CMS Energy Corp.*	Integrys Energy Group, Inc.*	Puget Energy, Inc.
Consolidated Edison, Inc.*	Mirant Corporation	Reliant Energy, Inc.*
Constellation Energy Group, Inc.*	Northeast Utilities System*	SCANA Corp.
Dominion Resources, Inc.*	NRG Energy, Inc.	Sempra Energy*
Duke Energy Corp.*	NSTAR Electric Co.	The Southern Company*
Dynegy, Inc.	NV Energy	Wisconsin Energy Corp.
Edison International*	OGE Energy Corp.	Xcel Energy, Inc.*
El Paso Corp.

For the analysis of proxy statements and annual reports on Form 10-K, TVA looked at a subset of the peer group above, identified with asterisks, as well as three additional companies in the energy services industry (AES Corp., DTE Energy Co., and NiSource Inc.), as recommended by Watson Wyatt.  These three companies were added to

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the subset analysis because they are energy services firms with annual revenues of $6.0 billion or higher that did not participate in the 2008 or 2009 Towers Perrin Energy Survey.  National Grid USA and PacifiCorp, which were in last year’s peer group, were not included in this year’s peer group because they did not participate in the 2009 Towers Perrin Energy Services Survey.  Mirant Corporation and NV Energy were added to this year’s peer group because they are energy services firms with annual revenues of $3.0 billion or higher and participated in the 2009 Towers Perrin Energy Services Survey.  In addition, the following government entities were informally considered by the Committee and TVA management: Colorado Springs Utilities, CPS Energy, Energy Northwest, Lower Colorado River Authority, New York Power Authority, Omaha Public Power, Salt River Project, and Santee Cooper.  Each of these government entities, with the exception of New York Power Authority, which reported revenues of $6.0 billion or greater, have revenues of less than $3.0 billion annually.

Executive Compensation Program Components

Background.  Rather than reexamining the compensation of the Named Executive Officers for 2010, the TVA Board reinstated the compensation components at levels originally established for 2009 (but not paid in full, or at all in some cases).  However, as detailed below, the compensation of Ms. Greene, who was appointed Group President, Strategy and External Relations effective January 4, 2010, and Mr. Thomas, who was appointed Chief Financial Officer effective June 7, 2010, was reexamined when they assumed those positions.

Salary.  The salaries of the Named Executive Officers for 2010 were as follows: $850,000 for Mr. Kilgore, $272,000 for Mr. Hoskins, $745,514 for Mr. McCollum, $525,000 for Mr. Swafford, and $456,246 for Mr. Bhatnagar. Each of these salaries was the same as in 2009.  In January 2010, TVA appointed Ms. Greene as Group President, Strategy and External Relations.  Following this appointment, the TVA Board approved a salary of $650,000 for Ms. Greene.  In June 2010, TVA appointed Mr. Thomas as Chief Financial Officer.  Following this appointment, Mr. Kilgore approved a salary of $520,000 for Mr. Thomas.  The salaries established for Ms. Greene and Mr. Thomas placed them near the 50th percentile of the benchmark salaries for similar positions in TVA’s peer group.

Although salary benchmark comparisons were prepared for 2010 and provided to the Committee and to TVA management, as a result of the salary freeze, no salary increases were received for 2010 for the Named Executive Officers except for the ones received by Ms. Greene and Mr. Thomas in connection with their promotions.  The 2010 salary for Mr. Kilgore placed him well below the 50th percentile of the benchmark salaries for CEOs in TVA’s peer group.  The 2010 salaries for Mr. Hoskins and Mr. McCollum placed them near the 50th percentile of the benchmark salaries for similar positions in TVA’s peer group.  The 2010 salaries for Mr. Swafford and Mr. Bhatnagar placed them near the 75th percentile of the benchmark salaries for similar positions in TVA’s peer group.  The 2010 salaries for Mr. Swafford and Mr. Bhatnagar were targeted at a higher percentile because their positions as Executive Vice President and Chief Nuclear Officer, Nuclear Generation, and Senior Vice President, Nuclear Generation Development and Construction, are subject to high demand and scarcity and recruitment and retention issues within the nuclear industry.

Annual Incentive Compensation.  All executives, including the Named Executive Officers, participate in the Executive Annual Incentive Plan (“EAIP”).  The EAIP is designed to encourage and reward executives for their contributions to successfully achieving annual financial and operational goals.  For 2010, the two EAIP goals focused on achieving corporate level goals.  These goals are described below.

Annual incentive opportunities for participants in the EAIP generally increase with position and responsibility.  Target annual incentive opportunities of the Named Executive Officers for 2010 were as follows:

NEO	Annual Target Incentive Opportunity*
Mr. Kilgore	100 %
Mr. Thomas	65 %
Mr. Hoskins	40 %
Ms. Greene	60 %
Mr. McCollum	70 %
Mr. Swafford	80 %
Mr. Bhatnagar	60 %
* Represents a percent of each NEO’s salary.

 The annual incentive opportunity approved for Mr. Kilgore for 2010 was at a level such that a 100 percent target payout (together with salary, 100 percent target payout of long-term incentive opportunities, and long-term deferred compensation credits) placed his total compensation well below the 50th percentile of the benchmark total compensation for similar positions in TVA’s peer group.  The annual incentive opportunities approved for Ms. Greene, Mr. McCollum, Mr. Thomas, and Mr. Hoskins for 2010 (which in the case of Ms. Greene and Mr. Thomas took into account their new positions) were at a level such that a 100 percent target payout (together with salary, 100 percent target payout of long-term incentive opportunities, and long-term deferred compensation credits) placed their total compensation at or below the 50th percentile of the benchmark total compensation for similar

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positions in TVA’s peer group.  The annual incentive opportunities approved for Mr. Swafford and Mr. Bhatnagar for 2010 were at a level such that a 100 percent target payout (together with salary, 100 percent target payout of long-term incentive opportunities, and long-term deferred compensation credits) placed their total compensation near the 75th percentile of the benchmark total compensation for similar positions in TVA’s peer group.  The 2010 total compensation for Mr. Swafford and Mr. Bhatnagar was targeted at a higher percentile because their positions as Executive Vice President and Chief Nuclear Officer, Nuclear Generation, and Senior Vice President, Nuclear Generation Development and Construction are subject to high demand and scarcity and because of recruitment and retention issues within the nuclear industry.

The TVA Board established two corporate performance measures for the EAIP for 2010: Equivalent Availability Factor and Net Cash Flow.  These are the same corporate performance measures used in determining annual incentive payouts for all non-executive TVA employees who participate in TVA’s Winning Performance Team Incentive Plan.  The weight and targets associated with these performance measures, as well as the results for 2010, were as follows:

2010 TVA Corporate Scorecard
			Goals
Performance Measure	Weight	Results Achieved	Threshold (50%)	Target (100%)	Maximum (150%)
Rates
Net Cash Flow ($ Millions)(1)	50%	$689 More Than Budget	$150 Less Than Budget	Budget	$150 More Than Budget
Reliability
Equivalent  Availability Factor (2)	50%	85.8	84.7	86.5	88.5
Notes (1)Net Cash Flow is a non-GAAP measure that is derived from the Statement of Cash Flow.  Net Cash Flow is derived from Net Cash Provided by Operating Activities + Net Cash Used in Investing Activities - Net Cash Flow from Change in Fuel Cost Adjustment Deferral Account +/- Winning Performance Fiscal Year 2010 Budget Variance. (2)Equivalent Availability Factor is a ratio of actual available generation from all TVA coal, combined cycle, and nuclear generating assets in a given period compared to maximum availability.

At its February 11, 2010, meeting, the TVA Board approved a new methodology for determining payments under the EAIP.  Under this new methodology, a pool is established that represents the total amount of funds available to pay all EAIP participants, including the Named Executive Officers, except Mr. Kilgore, whose EAIP payout is determined individually.

The amount of the EAIP award pool is determined by (i) calculating an amount for each EAIP participant in accordance with the formula set forth below, and (ii) adding these amounts together:

EAIP Amount = Annual Salary X Annual Target Incentive Opportunity X Percent of Corporate Goal Achievement (0% to 150%) X Corporate Modifier (-20% to +10%)

Initially, TVA contemplated that the CEO would be part of the EAIP award pool.  However, because the CEO has the authority to apply a corporate modifier to adjust the size of the EAIP award pool downwards up to twenty percent and upwards up to ten percent, TVA removed the CEO from the EAIP award pool so that he would not have the ability to make a compensation decision that affects his own compensation.  TVA intends to continue to exclude the CEO from the EAIP award pool in the future.  Mr. Kilgore and the NEOs participating in the EAIP will receive their EAIP payouts after this Annual Report has been filed.

Based on the results for the corporate performance measures described above for 2010, the corporate goal achievement was equal to 115.28 percent for purposes of calculating the EAIP award pool for 2010.  It was also 115.28 percent for purposes of the baseline for determining Mr. Kilgore’s EAIP award.

The corporate modifier ranges from -20 percent to +10 percent and allows Mr. Kilgore the discretion in adjusting the amount of the EAIP pool based on a subjective assessment and consideration of factors that are significant to TVA but are not easily quantifiable.  For 2010, Mr. Kilgore applied a corporate modifier to reduce the size of the EAIP award pool for all EAIP participants, including the other Named Executive Officers, from 115.28 percent to 105.00 percent, or slightly more than 8.9 percent, because of the loss of output from Browns Ferry due to a foreseeable lack of cooling capacity, the occurrence of fires at various coal-fired facilities, and the number of reportable environmental events (events that occur at a TVA facility that require TVA to notify federal or state environmental agencies).

Once the pool was determined, each EAIP participant’s individual performance during 2010 was evaluated and used to determine whether any adjustment upwards or downwards should be made to the final annual incentive awards of each EAIP participant, including each participating Named Executive Officer.  The individual performance evaluation was conducted by each participant’s supervisor after the end of the year based on a purely subjective review by the supervisor of how the participant performed during the year and/or how the business unit over which the participant had responsibility performed during the year.  Any adjustment to an EAIP pool participant’s final annual incentive award was coordinated across all participants to ensure that the total of all the final annual incentive awards did not exceed the EAIP award pool for 2010.

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Following the end of 2010, pursuant to the February 11, 2010, and June 10, 2010, TVA Board delegations under the Compensation Plan, Mr. Kilgore as CEO, in consultation with the Committee and with input from individual members of the TVA Board, subjectively evaluated the performance of Ms. Greene, Mr. Thomas, and Mr. McCollum as his direct reports during 2010.  Based on his review of Ms. Greene, Mr. Kilgore decided that Ms. Greene’s individual annual incentive award should be adjusted upwards by five percent because of Ms. Greene’s successful results in obtaining the concurrence of TVA’s customers and the approval of the TVA Board for implementing time-of-use rates in 2011.  Also, Ms. Greene has been instrumental in overseeing the critical Integrated Resource Plan that is nearly completed.  Based on his review of Mr. Thomas, Mr. Kilgore decided that Mr. Thomas’s individual annual incentive award should be adjusted upwards by five percent because he oversaw TVA’s successful issuance of a Bond with a fifty-year maturity at TVA’s lowest-ever rate for a Bond with a maturity of 30 years or longer, because he was responsible for defining a new People and Performance organization, and because he was responsible for successfully implementing an initiative to improve TVA’s corporate culture.  Based on his review of Mr. McCollum, Mr. Kilgore decided that Mr. McCollum’s individual annual incentive award should be adjusted downwards by five percent because of loss of output from Browns Ferry due to a foreseeable lack of cooling capacity.

Mr. McCollum subjectively evaluated the performance of Mr. Swafford and Mr. Bhatnagar as his direct reports during 2010.  Based on these reviews, Mr. McCollum decided that Mr. Swafford’s and Mr. Bhatnagar’s annual incentive awards should not be adjusted.

Mr. Thomas subjectively evaluated the performance of Mr. Hoskins as his direct report during 2010.  Based on his review of Mr. Hoskins, Mr. Thomas decided that Mr. Hoskins’s annual incentive award should not be adjusted.

As set forth above, Mr. Kilgore was not a part of the EAIP award pool.  However, as a participant in the EAIP, the performance measures applicable to the EAIP were also applicable to Mr. Kilgore, and the 115.28 percent achievement of these performance measures formed a baseline for his EAIP award.  Following the end of 2010, the Chairman of the TVA Board, in consultation with the Committee and with input from individual members of the TVA Board, subjectively evaluated the performance of Mr. Kilgore as CEO during 2010.  Based on this review, the Chairman of the TVA Board decided that Mr. Kilgore’s final annual incentive award should be adjusted downwards by 10 percent because of the loss of output from Browns Ferry due to a foreseeable lack of cooling capacity, the occurrence of fires at various coal-fired facilities, and the number reportable environmental events.

As a result of the process described above, the Named Executive Officers were awarded the following EAIP payouts for 2010 in comparison to the 2010 target payouts:

2010 EAIP Payouts
NEO	Salary	EAIP Incentive Opportunity	Target EAIP Payout	% Corporate Goal Achievement (with Corporate Modifier)	Individual Performance Adjustment	Final EAIP Payout
Tom Kilgore	$850,000	100%	$850,000	115.28%(1)	(10.0%)	$881,892
John M. Thomas, III	$520,000	65%	$338,000	105.00%(2)	5.0%	$371,876(3)
John M. Hoskins	$272,000	40%	$108,800	105.00%(2)	0.0%	$114,004(3)
Kimberly S. Greene	$650,000	60%	$390,000	105.00%(2)	5.0%	$429,088(3)
William R. McCollum, Jr.	$745,514	70%	$521,860	105.00%(2)	(5.0%)	$519,481(3)
Preston D. Swafford	$525,000	80%	$420,000	105.00%(2)	0.0%	$440,090(3)
Ashok S. Bhatnagar	$456,246	60%	$273,748	105.00%(2)	0.0%	$286,842(3)
Notes (1)A corporate modifier was not included in the award calculation for Mr. Kilgore.  Mr. Kilgore was not included in the EAIP award pool in FY 2010. (2)For FY 2010, the CEO approved a corporate modifier for all other EAIP participants that reduced the percent of corporate goal achievement by 10.28 percentage points based on an assessment of TVA’s health and overall performance during 2010. (3) Calibrated along with payouts to all other EAIP participants to ensure that the total of all awards did not exceed the EAIP award pool.

Awards to the Named Executive Officers under the EAIP for 2010 are reported in the “Non-Equity Incentive Plan Compensation” column in the Summary Compensation Table.

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Long-Term Incentive Compensation.  In addition to the EAIP, certain executives in critical positions, including the Named Executive Officers, participate in the Executive Long-Term Incentive Plan (“ELTIP”).  Executives in critical positions are those who make decisions that significantly influence the development and execution of TVA’s long-term strategic objectives.  The ELTIP has been purposefully designed to properly and competitively reward executives for helping TVA improve in important areas directly related to TVA’s long-term success by:

• Using corporate-level performance criteria that are directly aligned with TVA’s mission;

• Using a “cumulative” performance approach to measure performance achieved for three-year performance cycles;

• Targeting award opportunities in the final year of each performance cycle at levels that approximate median levels of competitiveness with TVA’s peer group and incorporating the Committee’s policy of targeting that (i) approximately 80 percent of each executive’s total long-term incentive opportunity be performance based (under the ELTIP) and (ii) approximately 20 percent of each executive’s total long-term incentive opportunity be retention and security-oriented (under the Long-Term Deferred Compensation Plan (“LTDCP”) as described below under the heading “Long-Term Deferred Compensation”); and

• Utilizing an award opportunity range of 50 percent to 150 percent of salary to enable payment of awards that are commensurate with performance achievements.

Under the ELTIP, an executive’s incentive payment is calculated as follows:

ELTIP Payout = Salary X ELTIP Incentive Opportunity X Percent of Opportunity Achieved

As discussed above, the objective of the ELTIP is to establish incentive opportunities for each of the Named Executive Officers that approximate 80 percent of each Named Executive Officer’s total long-term compensation based on a percentage of his or her base salary rate at the end of the performance cycle.  For the performance cycle ended September 30, 2010, the long-term incentive opportunities of the Named Executive Officers holding the same positions remained at the levels originally established for 2009: 150 percent for Mr. Kilgore, 25 percent for Mr. Hoskins, 100 percent for Mr. McCollum, 100 percent for Mr. Swafford, and 50 percent for Mr. Bhatnagar.  Following the appointment of Ms. Greene as Group President of Strategy and External Relations during 2010, the TVA Board approved a 120 percent long-term incentive opportunity for Ms. Greene for the performance cycle ended September 30, 2010.  Following the appointment of Mr. Thomas as Chief Financial Officer during 2010, Mr. Kilgore approved a 125 percent long-term incentive opportunity for Mr. Thomas for the performance cycle ended September 30, 2010.  These target levels of long-term incentive opportunity placed the total compensation of each Named Executive Officer at the percentage of TVA’s peer group described above in “Annual Incentive Plan.”

2008 - 2010 Performance Cycle

For the three-year cycle ended September 30, 2010, the TVA Board approved two overall measures of TVA performance to be applied to all participants in the ELTIP: connection point interruptions (the number of interruptions of power at connection points caused by TVA’s transmission system) and retail rates (distributor reported retail power revenue and directly served power revenue divided by distributor reported retail sales and directly served power sales).

The goals associated with the two performance measures for the cycle ended September 30, 2010, are based on a comparison of TVA’s performance to the performance of surveyed transmission providers and regional utilities, and rolling three-year target comparisons for the surveyed group are utilized.  The goals approved for the connection point interruptions performance measure for the three-year performance cycle ended September 30, 2010, are as follows:

• The target goal (which will also serve as the threshold goal that must be met before there is any incentive payment under this measure) is established based on the 75th percentile of the performance of the surveyed transmission providers (the “ELTIP CPI Comparison Group”);and

• The maximum goal is established at the 90th percentile of the ELTIP CPI Comparison Group’s performance.

The goals approved for the retail rates performance measure for the three-year performance cycle ended September 30, 2010, are as follows:

• The threshold goal is based on improvement over the last performance cycle;

• The target goal is TVA ranking at or above the 75th percentile of the performance of a comparison group of regional utilities composed of 22 utilities, which are subsidiaries of holding companies with annual revenues greater than $3.0 billion, in the regional proximity of the TVA service territory (the “ELTIP Retail Rates Comparison Group”); and

• The maximum goal is TVA ranking at or above the 90th percentile of the ELTIP Retail Rates Comparison Group’s performance.

For 2010, connection point interruptions performance data came from data provided by SGS Statistical Services based on an analysis of voluntary survey responses solicited from 30 electric utilities (not all of which provided data).  Retail rate data (retail sales and retail revenue) for the ELTIP Retail Rates Comparison Group was obtained from the EIA-826 Monthly Electric Utility Database.

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The following table shows the performance goals and weighting and percent of opportunity achieved for the ELTIP for the three-year cycle ended September 30, 2010:

ELTIPPerformance Goals, Weighting, and Percent of Opportunity
	Goals				Performance Achievement
Performance Measure	Threshold (50%)	Target (100%)	Maximum (150%)	Performance Results	Actual (%)	X	Weight (%)	=	Result (%)
Retail Rate	Improvement Over Last Performance Cycle	Top 25% of Comparison Companies	Top 10% of Comparison Companies	Below Threshold	0.0%		50%		0.0%
Connection Point Interrruption	N/A	Top 25% of Comparison Companies	Top 10% of Comparison Companies	Maximum	150%		50%		75%
				Overall Percent of Opportunity Achieved					75%

As a part of the ELTIP, the TVA Board reserves discretion to review results and peer group comparisons and to approve adjustments in payouts, if appropriate, given the circumstances.  The Board did not decide to adjust any payout for 2010.

As a result, the Named Executive Officers were awarded the following ELTIP payouts for 2010 in comparison to the 2010 target payouts:

2010 ELTIP Payouts
NEO	Salary	ELTIP Incentive Opportunity	Target ELTIP Payout	Percent of Opportunity Achieved	ELTIP Payout
Tom Kilgore	$850,000	150%	$1,275,000	75%	$956,250
John M. Thomas, III	$520,000	125%	$650,000	75%	$487,500
John M. Hoskins	$272,000	25%	$68,000	75%	$51,000
Kimberly S. Greene	$650,000	120%	$780,000	75%	$585,000
William R. McCollum, Jr.	$745,514	100%	$745,514	75%	$559,136
Preston D. Swafford	$525,000	100%	$525,000	75%	$393,750
Ashok S. Bhatnagar	$456,246	50%	$228,123	75%	$171,092

Awards to the Named Executive Officers under the ELTIP for the performance cycle that ended on September 30, 2010, are reported in the “Non-Equity Incentive Plan Compensation” column in the Summary Compensation Table.

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2009 - 2011 Performance Cycle

For the three-year cycle ending September 30, 2011, the TVA Board has approved the following overall measures of TVA performance to be applied to all participants in the ELTIP:

Performance Measure	Weight	Threshold (50%)	Target (100%)	Maximum (150%)
Retail Rates Relative Position(1)	33 1/3%	Improvement Over Last Performance Cycle	Top 25% of Comparison Companies	Top 10% of Comparison Companies
Connection Point Interruptions(2)	33 1/3%	N/A	1.12	0.78
Non-Fuel Operations and Maintenance(3)	33 1/3%	Improvement Over Last Performance Cycle	Top 50% of Comparison Companies	Top 25% of Comparison Companies

Notes

(1) Distributor reported retail power revenue and directly served power revenue divided by distributor reported retail sales and directly served

power sales. TVA compares its retail rates to the retail rates of 23 peer utilities.

 (2) The number of interruptions of power at connection points caused by TVA’s transmission system measured by the number of interruptions

    divided by the number of connection points.

        (3) Defined as total operating and maintenance costs excluding FCA costs, reagents expense, emissions allowance expense, net nuclear outage amortization/deferral

expense, and energy efficiency and demand reduction spending.

2010 - 2012 Performance Cycle

For the three-year cycle ending September 30, 2012, the TVA Board has approved the following overall measures of TVA performance to be applied to all participants in the ELTIP:

Performance Measure	Weight	Threshold (50%)	Target (100%)	Maximum (150%)
Retail Rates Relative Position(1)	50%	12th	8th	6th
System Reliability Load Not Served(2)	30%	7.8	5.9	3.8
Responsibility Organizational Health Index(3)	10%	55.0	58.0	61.0
Stakeholder Survey(4)	10%	78.0	80.0	82.0

Notes
 (1) Distributor reported retail power revenue and directly served power revenue divided by distributor reported retail sales and directly served

power sales. TVA compares its retail rates to the retail rates of 23 peer utilities.

 (2) Load Not Served, which is measured in system minutes, is equal to the product of (1) the percentage of total load not served and (2) the number

of minutes in the period, and excludes events during declared major storms.

 (3) The Organizational Health Index measures and tracks the organizational elements that drive TVA's performance culture.  The performance targets are

based an improvement plan that would result in improvement from the 2009 Organizational Health Index survey (Threshold), second quartile performance

in 2012 (Target), and mid-second quartile performance in 2012 (Maximum).

 (4) The Stakeholder Survey is conducted among residents, public officials, economic development leaders, and business and community leaders in the

Tennessee Valley and measures the external reputation and perception of TVA in how it responds to its strategic objectives.  Threshold is equal to an

increase in performance by one point per year.  Target is equal to a return to 2008 levels by 2012.  Maximum is equal to a return to 2008 levels by 2011

and an increase over 2008 levels by 2012.

Long-Term Deferred Compensation.  Unlike private sector companies in the energy services industry, TVA is a corporate agency and instrumentality of the United States and thus does not have equity securities to provide stock awards, options, or other equity-based awards as a form of compensation for its employees.  Although TVA cannot and does not seek to replicate the type of equity-based compensation available at companies in TVA’s peer group, TVA does enter into agreements with certain executives, including the Named Executive Officers, that are administered under TVA’s long-term deferred compensation plan (“LTDCP”) and provide a retention incentive similar to restricted stock or restricted stock units.  The LTDCP agreements are designed to provide retention incentives to executives to encourage them to remain with TVA and to provide, in combination with salary and EAIP and ELTIP incentive awards, a competitive level of total compensation.  Under the LTDCP, credits (which may be vested or unvested) are made to an account in an executive’s name (typically on an annual basis) for a predetermined period.  If the executive remains employed at TVA until the end of this period (typically three to five years), the executive becomes vested in the balance of the account, including any return on investment on the credits in the account, and receives a distribution in accordance with a deferral election made at the time the LTDCP agreement was entered into.  Annual LTDCP credits are awarded to the Named Executive Officers in amounts targeted to constitute approximately 20 percent of each Named Executive Officer’s total long-term compensation in conjunction with targeted ELTIP compensation described above.  Annual credits provided to the Named Executive Officers under LTDCP agreements in 2010 are reported in the “All Other Compensation” column in the Summary Compensation Table.  These credits are also reported in the “Registrant Contributions in Last FY” column in the Nonqualified Deferred Compensation Table since the credits were placed in deferred compensation accounts in the Named Executives Officers’ names.

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Descriptions of all current LTDCP agreements with the Named Executive Officers are found following the Grants of Plan-Based Awards Table.

Pension Benefits.  All of the Named Executive Officers are eligible to participate in the following qualified plans available to, and on the same terms and conditions applicable to, all annual TVA employees:

•      Defined benefit plan

– Original Benefit Structure (“OBS”) for employees covered under the plan prior to January 1, 1996, with a pension based on a final average pay formula.

– Cash Balance Benefit Structure (“CBBS”) for employees first hired on or after January 1, 1996, with a pension based on an account that receives pay credits equal to six percent of compensation plus interest.

•      401(k) plan

– For OBS members, TVA provides matching contributions of 25 cents on every dollar up to 1.5 percent of annual salary.

– For CBBS members, TVA provides matching contributions of 75 cents on every dollar up to 4.5 percent of annual salary.

The availability of, and level of benefits provided by, these qualified plans are comparable to similar qualified plans provided by other companies in TVA’s peer group.

In addition, certain executives in critical positions, including each of the Named Executive Officers, as determined by TVA on an individual basis, are eligible to participate in TVA’s SERP.  The SERP is a non-qualified pension plan that provides supplemental pension benefits tied to compensation levels that exceed limits imposed by IRS regulations applicable to TVA’s qualified plans.  TVA provides the SERP to certain executives in critical positions, including the Named Executive Officers, under the belief that these executives should receive an appropriate total retirement benefit based on a similar level of compensation credited under TVA’s qualified plans regardless of IRS qualified plan limits.  The availability of, and level of benefit provided by, this supplemental pension plan is comparable to similar non-qualified pension plans provided by other companies in TVA’s peer group and helps TVA to remain competitive in attracting and retaining top-level executives.  Because “compensation” for purposes of SERP includes EAIP, any discretionary action by the TVA Board to eliminate or reduce EAIP payouts to the Named Executive Officers could reduce SERP benefits to the Named Executive Officers in certain circumstances.

More information regarding these retirement and pension plans is found following the Pension Benefits Table.

Perquisites.  In 2010, TVA provided certain executives, including Ms. Greene, Mr. Thomas, Mr. McCollum, Mr. Swafford, and Mr. Bhatnagar, a flat-dollar biweekly vehicle allowance that may be applied toward the purchase or lease of a vehicle, operating fees, excess mileage, maintenance, repairs, and insurance.  Vehicle allowances are granted on a “business need” basis to a very limited number of executives.  The amount of the vehicle allowances granted to the Named Executive Officers is reported in the “All Other Compensation” column in the Summary Compensation Table.

In 2010, TVA offered a Financial Counseling Services Program for a limited number of executives approved by the CEO.  Under the program, participants are eligible to receive personal financial counseling services, such as estate planning, investment planning, income tax planning, income tax preparation, and retirement planning.  TVA pays the cost of the program for each participant and also pays each participant a gross-up amount that reasonably approximates the additional income and employment taxes estimated to be payable as a result of TVA’s payments pursuant to the program. Mr. Thomas and Mr. Swafford are the only Named Executive Officers eligible to participate in the Financial Counseling Services Program.  The amount of any cost incurred by TVA on behalf of Mr. Thomas and Mr. Swafford pursuant to this program, including any gross-up amount, is reported in the “All Other Compensation” column in the Summary Compensation Table.

TVA did not provide any other perquisites to the Named Executive Officers in 2010.

Health and Other Benefits.  TVA offers a group of health and other benefits (medical, dental, vision, life and accidental death and disability insurance, and long-term disability insurance) that are available to a broad group of employees.  The Named Executive Officers and directors are eligible to participate in TVA’s health benefit plans and other non-retirement benefit plans on the same terms and at the same contribution rates as other TVA employees.

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Other Agreements.  In September 2009, Mr. Kilgore approved a performance arrangement that will provide Mr. Swafford, as long as he remains responsible for managing and directing TVA’s Nuclear Generation Group, the opportunity to receive annual performance awards for improvements in the overall performance of any of TVA’s nuclear plants based on nuclear power industry peer evaluations.  Under the arrangement, Mr. Swafford will receive a lump-sum performance award of $100,000 following each fiscal year that at least one nuclear plant in TVA’s generation portfolio achieves an improved performance evaluation.  In the event the performance of any plant drops below that achieved in the most recent evaluation of the plant, no award will be made.  Mr. Swafford is eligible to receive these annual performance awards based on evaluations completed in 2010 and beyond.  All awards will be recommended by the Chief Operating Officer and approved by the CEO at the end of each fiscal year.  Based on an overall peer evaluation, Mr. Swafford did not receive an annual performance award under this arrangement for 2010.

Executive Compensation Tables and Narrative Disclosures

Summary Compensation and Grants of Plan-Based Awards

The following table sets forth information regarding compensation earned by each of the Named Executive Officers in 2010 (and 2009 and 2008 as applicable).

Summary Compensation Table
Name and Principal Position (a)	Year (b)	Salary ($) (c)	Bonus ($) (d)	Stock Awards ($) (e)	Option Awards ($) (f)	Non-Equity Incentive Plan Compensation ($) (g)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($) (h)	All Other Compensation ($) (i)	Total ($) (j)
Tom Kilgore President and Chief Executive Officer	2010 2009 2008	$853,269 $853,270 $655,000	— — —	— — —	— — —	$1,838,142(1) $0 $1,099,426(5)	$595,643(2) $$0(4) $406,152(6)	$311,025(3) $310,350 $310,125	$3,598,079 $1,163,620 $2,470,703
John M. Thomas, III Chief Financial Officer	2010 2009 2008	$410,000 — —	— — —	— — —	— — —	859,376(7) — —	$177,260(8) — —	$91,381(9) — —	$1,538,017 — —
John M. Hoskins Senior Vice President, Treasury	2010 2009 2008	$273,045 — —	$ 40,000(10) — —	— — —	— — —	$165,004 (11) — —	$347,151(12) — —	$63,675(13) — —	$888,875 — —
Kimberly S. Greene Group President, Strategy and External Relations	2010 2009 2008	$603,942 $527,020 $503,847	— — —	— — —	— — —	$1,014,088(14) $393,750(17) $493,838(19)	$536,376(15) $135,091(18) $223,707(20)	$172,770(16) $172,082 $78,797	$2,327,176 $1,227,943 $1,300,189
William R. McCollum, Jr. Chief Operating Officer	2010 2009 2008	$748,381 $748,381 $726,547	— — —	— — —	— — —	$1,078,617(21) $559,136(24) $751,751(26)	$335,712(22) $265,870(25) $126,440(27)	$222,770(23) $222,082 $223,237	$2,385,480 $1,795,469 $1,827,975
Preston D. Swafford Executive Vice President and Chief Nuclear Officer, Nuclear Generation	2010 2009 2008	$527,019 $499,877 —	— $100,000(31) —	— — —	— — —	$833,840(28) $558,390(32) —	$325,208(29) $201,516(33) —	$167,711(30) $147,082 —	$1,853,778 $1,506,865
Ashok S. Bhatnagar Senior Vice President, Nuclear Generation Development and Construction	2010 2009 2008	$458,000 $458,001 $437,863	— — —	— — —	— — —	$457,933(34) $375,609(37) $403,661(39)	$311,861(35) $245,892(38) $29,226(40)	$190,450(36) $165,437 $165,612	$1,418,244 $1,244,939 $1,036,362
Notes                                                                            (1)  Represents $881,892 awarded under the EAIP and $956,250 awarded under the ELTIP. (2)  Reflects increases of $18,637 under the CBBS and $577,006 under the SERP. (3)  Represents a credit in the amount of $300,000 that vests on November 30, 2010, which was provided under a LTDCP agreement with Mr. Kilgore, and $11,025 in 401(k) employer matching contributions.  See information regarding the details of the LTDCP agreement under “Long-Term Deferred Compensation Plan.” (4)  Reflects an increase of $16,929 under the CBBS and a decrease of $133,752 under the SERP. (5)  Represents $374,806 awarded under the EAIP and $724,620 awarded under the ELTIP. (6)  Represents increases of $12,232 under the CBBS and $393,920 under the SERP. (7)  Represents $371,876 awarded under the EAIP and $487,500 awarded under the ELTIP. (8)  Reflects increases of $30,848 under the CBBS and $146,412 under the SERP.

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(9)   Represents a credit in the amount of $50,000 that vests on September 30, 2011, which was provided under a LTDCP agreement with Mr. Thomas, $10,075 in vehicle allowance payments, and $11,025 in 401(k) employer matching contributions, $14,917 in estimated costs incurred by TVA under the Financial Counseling Services Program, and $5,364 in estimated gross-up amounts that reasonably approximate additional income and employment taxes payable as a result of TVA’s payments under to the Financial Counseling Services Program.  See information regarding the details of the LTDCP agreement under “Long-Term Deferred Compensation Plan.”

(10)  Represents a lump sum payment awarded to Mr. Hoskins for assuming additional duties and responsibilities while serving as Interim Chief Financial Officer.

(11)  Represents $114,004 awarded under the EAIP and $51,000 awarded under the ELTIP.

(12)  Reflects increases of $283,265 under the OBS and $63,886 under the SERP.

(13)  Represents a credit in the amount of $60,000 that vests on October 1, 2011, which was provided under a LTDCP agreement with Mr. Hoskins, and $3,675 in 401(k) employer matching contributions.  See information regarding the details of the LTDCP agreement under “Long-Term Deferred Compensation Plan.”

(14)  Represents $429,088 awarded under the EAIP and $585,000 awarded under the ELTIP.

(15)  Represents increases of $27,331 under the CBBS and $509,045 under the SERP.

(16)  Represents credits totaling $150,000, $100,000 of which vests on September 30, 2011, and $50,000 of which vest on September 30, 2012, provided under two separate LTDCP agreements with Ms. Greene, $11,745 in vehicle allowance payments, and $11,025 in 401(k) employer matching contributions.  See information regarding the details of the LTDCP agreements under “Long-Term Deferred Compensation Plan.”

(17)  Represents $393,750 awarded under the ELTIP.

(18)  Represents increases of $20,754 under the CBBS and $114,337 under the SERP.

(19)  Represents $252,298 awarded under the EAIP and $241,540 awarded under the ELTIP.

(20)  Represents increases of $9,529 under the CBBS and $214,178 under the SERP.

(21)  Represents $519,481 awarded under the EAIP and $559,136 awarded under the ELTIP.

(22)  Represents increases of $18,404 under the CBBS and $317,308 under the SERP.

(23)  Represents a credit in the amount of $200,000 that vests on September 30, 2011, which was provided under a LTDCP agreement with Mr. McCollum, $11,745 in vehicle allowance payments, and $11,025 in 401(k) employer matching contributions.  See information regarding the details of the LTDCP agreement under “Long-Term Deferred Compensation Plan.”

(24)  Represents $559,136 awarded under the ELTIP.

(25)  Represents increases of $15,789 under the CBBS and $250,081 under the SERP.

(26)  Represents $376,658 awarded under the EAIP and $375,093 awarded under the ELTIP.

(27)  Represents increases of $10,821 under the CBBS and $115,619 under the SERP.

(28)  Represents $440,090 awarded under the EAIP and $393,750 awarded under the ELTIP.

(29)  Represents increases of $28,526 under the CBBS and $296,682 under the SERP.

(30)  Represents a credit in the amount of $125,000 that vested on September 30, 2010 which was provided under a LTDCP agreement with Mr. Swafford, $11,745 in vehicle allowance payments, $11,025 in 401(k) employer matching contributions, $14,667 in estimated costs incurred by TVA under the Financial Counseling Services Program, and $5,274 in estimated gross-up amounts that reasonably approximate additional income and employment taxes payable as a result of TVA’s payments under to the Financial Counseling Services Program.  See information regarding the details of the LTDCP agreement under “Long-Term Deferred Compensation Plan.”

(31)  Represents a lump sum performance payment awarded for an improved nuclear power industry peer evaluation of Watts Bar Nuclear Plant in 2009.

(32)  Represents $164,640 awarded under the EAIP and $393,750 awarded under the ELTIP.

(33)  Represents increases of $27,674 under the CBBS and $173,842 under the SERP.

(34)  Represents $286,841 awarded under the EAIP and $171,092 awarded under the ELTIP.

(35)  Represents increases of $39,260 under the CBBS and $272,601 under the SERP.

(36)  Represents a credit in the amount of $175,000 that vests on September 30, 2014, which was provided under a LTDCP agreement with Mr. Bhatnagar, $11,745 in vehicle allowance payments, and $3,705 in 401(k) employer matching contributions.  See information regarding the details of the LTDCP agreement under “Long-Term Deferred Compensation Plan.”

(37)  Represents $204,517 awarded under the EAIP and $171,092 awarded under the ELTIP.

(38)  Represents increases of $36,696 under the CBBS and $209,196 under the SERP.

(39)  Represents $258,340 awarded under the EAIP and $145,321 awarded under the ELTIP.

(40)  Represents increases of $14,284 under the CBBS and $14,942 under the SERP.

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The following table provides information regarding non-equity incentive plan awards and the possible range of payouts associated with incentives the Named Executive Officers were eligible to receive for performance in the performance cycles ending in 2010.

Grants of Plan-Based Awards Table
		Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1)
Name (a)	Plan (b)	Threshold (2) ($) (c)	Target (2) ($) (d)	Maximum 2 ($) (e)
Tom Kilgore	EAIP (3) ELTIP (4)	$425,000 $637,500	$850,000 $1,275,000	$1,275,000 $1,912,500
John M. Thomas, III	EAIP (3) ELTIP (4)	$169,000 $325,000	$338,000 $650,000	$507,000 $975,000
John M. Hoskins	EAIP (3) ELTIP (4)	$54,400 $34,000	$108,800 $68,000	$163,200 $102,000
Kimberly S. Greene	EAIP (3) ELTIP (4)	$195,000 $390,000	$390,000 $780,000	$585,000 $1,170,000
William R. McCollum, Jr.	EAIP (3) ELTIP (4)	$260,930 $372,757	$521,860 $745,514	$782,790 $1,118,271
Preston D. Swafford	EAIP (3) ELTIP (4)	$210,000 $262,500	$420,000 $525,000	$630,000 $787,500
Ashok S. Bhatnagar	EAIP (3) ELTIP (4)	$136,874 $114,062	$273,748 $228,123	$410,622 $342,185
Notes (1)  TVA does not have any equity securities and therefore has no equity-based awards. (2)  Threshold, Target, and Maximum represent amounts that could be earned by an NEO based on FY 2010 performance.  Actual EAIP awards earned for performance in 2010 are reported for each of the Named Executive Officers under “Non-Equity Incentive Plan Compensation” in the Summary Compensation Table. (3)  Target incentive opportunities as a percentage of salaries were as follows:  Mr. Kilgore, 100%; Mr. Thomas, 65%; Mr. Hoskins, 40%; Ms. Greene, 60%; Mr. McCollum, 70%; Mr. Swafford, 80%; and Mr. Bhatnagar, 60%.  EAIP performance measures for 2010 were Net Cash Flow and Equivalent Availability Factor.  Actual EAIP awards earned for performance in 2010 are reported for each of the Named Executive Officers under “Non-Equity Incentive Plan Compensation” in the Summary Compensation Table.  See Compensation Discussion and Analysis for a discussion of how each award was determined. (4)  Target incentive opportunities for the three-year performance cycle ended September 30, 2010 as a percentage of salaries were as follows: Mr. Kilgore, 150%; Mr. Thomas, 125%; Mr. Hoskins, 25%; Ms. Greene, 120%; Mr. McCollum, 100%; Mr. Swafford, 100%; and Mr. Bhatnagar, 50%.  ELTIP performance measures for the three-year cycle ended September 30, 2010, were Retail Rates and Connection Point Interruption.  Actual ELTIP awards earned for the performance cycle ended on September 30, 2010, are reported for each of the Named Executive Officers under “Non-Equity Incentive Plan Compensation” in the Summary Compensation Table.  See Compensation Discussion and Analysis for a discussion of how each award was determined.

Awards under the EAIP and ELTIP will be paid in cash during the first quarter of 2011 with a deferral option for the ELTIP.  Mr. McCollum and Mr. Swafford elected to defer 100 percent and 25 percent, respectively, of their ELTIP awards earned for the performance cycle ended on September 30, 2010.

Long-Term Deferred Compensation Plan

The TVA Long-Term Deferred Compensation Plan is designed to provide long-term incentives to executives to encourage them to stay with TVA and to provide competitive levels of total compensation to such executives.  Participating executives enter into deferral agreements with TVA under which deferred compensation credits are made to an account in the participant’s name.  Credits are made on an annual basis for an established period of time.  Interest is credited daily to the balance reflected in the participant’s deferral account.  Interest is calculated based on the composite rate of all marketable U.S. Treasury issues.  In the alternative, participants may choose to have their balance adjusted based on the return on certain mutual funds.  Credits vest after a period fixed in the agreement and are distributed to the participant either at vesting or following termination as provided in the particular agreement.  Set forth below are descriptions of the LTDCP agreements that are reflected in the Summary Compensation Table for the Named Executive Officers.  See also the “Nonqualified Deferred Compensation Table” below, which also includes information with respect to amounts credited under these and prior LTDCP agreements.

In November 2009, TVA entered into a LTDCP agreement with Mr. Kilgore.  Under the terms of the agreement, Mr. Kilgore received a deferred compensation credit of $300,000 on December 1, 2009, and this credit, as well as any earnings on this amount, will vest on November 30, 2010. Mr. Kilgore will also receive deferred compensation credits of $300,000 each on December 1, 2010, December 1, 2011, and December 1, 2012, if he remains employed by TVA on these dates, and these credits, as well as any earnings on these amounts, will vest annually on November 30, 2011, November 30, 2012, and November 30, 2013, respectively.  Each credit, and earnings on such credit, will be distributed to Mr. Kilgore in a lump sum

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at the time of vesting. In the event TVA terminates Mr. Kilgore’s employment during the term of the LTDCP agreement through no act or delinquency of his own, any credit, and earnings on such credit, in Mr. Kilgore’s account that is not vested at the time of termination will become vested and distributed to him in a lump sum.  If Mr. Kilgore voluntarily terminates his employment or TVA terminates Mr. Kilgore’s employment for cause prior to the expiration of the agreement, any credit, and earnings on such credit, in Mr. Kilgore’s account that is not vested will be forfeited.

In September 2007, TVA entered into a LTDCP agreement with Ms. Greene.  Under the terms of the agreement, Ms. Greene received a deferred compensation credit of $280,000 on September 4, 2007, and deferred compensation credits of $100,000 on October 1, 2008, October 1, 2009, and October 1, 2010.  Pursuant to the agreement, Ms. Greene was vested in the first credit of $280,000 at the time the credit was made and vested in any earnings on this amount.  Ms. Greene will vest in the remaining balance of her account only if she remains employed by TVA until the expiration of the agreement on September 30, 2011.  All vested credits, and earnings on such credits, in her account will be distributed to her in five annual installments following the termination of her employment with TVA.  In the event TVA terminates Ms. Greene’s employment during the term of the LTDCP agreement through no act or delinquency of her own, any credits and earnings on those credits in Ms. Greene’s account at the time of termination will become vested and distributed to her in five annual installments.  If Ms. Greene voluntarily terminates her employment or TVA terminates Ms. Greene’s employment for cause prior to the expiration of the agreement, all credits, and earnings on such credits, in Ms. Greene’s account, except the initial $280,000 credit and any earnings on this amount, will be forfeited.

In December 2008, TVA entered into a second LTDCP agreement with Ms. Greene. Under the terms of the agreement, Ms. Greene received deferred compensation credits of $50,000 on December 1, 2008, October 1, 2009, and October 1, 2010.  Ms. Greene will also receive a deferred compensation credit in the amount of $150,000 on October 1, 2011, if she remains employed by TVA on that date.  Ms. Greene will vest in her account only if she remains employed by TVA until the expiration of the agreement on September 30, 2012.  All vested credits, and earnings on such credits, in her account will be distributed to her in a lump sum following the termination of her employment with TVA.  In the event TVA terminates Ms. Greene’s employment during the term of the LTDCP agreement through no act or delinquency of her own, any credits and earnings on those credits in Ms. Greene’s account at the time of termination will become vested and distributed to her in a lump sum.  If Ms. Greene voluntarily terminates her employment or TVA terminates Ms. Greene’s employment for cause prior to the expiration of the agreement, all credits, and earnings on such credits, in Ms. Greene’s account will be forfeited.

In January 2010, TVA entered into a LTDCP agreement with Mr. Hoskins. Under the terms of the agreement, Mr. Hoskins received deferred compensation credits of $60,000 on January 1, 2010, and October 1, 2010.  Mr. Hoskins will also receive a deferred compensation credit in the amount of $60,000 on October 1, 2011, if he remains employed by TVA on that date.  Mr. Hoskins will vest in his account only if he remains employed by TVA until the expiration of the agreement on September 30, 2012.  All vested credits, and earnings on such credits, in his account will be distributed to him in ten annual installments following the termination of his employment with TVA.  In the event TVA terminates Mr. Hoskins’s employment during the term of the LTDCP agreement through no act or delinquency of his own, any credits and earnings on those credits in Mr. Hoskins’s account at the time of termination will become vested and will be distributed to him in ten annual installments following the termination of his employment with TVA.  If Mr. Hoskins voluntarily terminates his employment or TVA terminates Mr. Hoskins’s employment for cause prior to the expiration of the agreement, all credits, and earnings on such credits, in Mr. Hoskins’s account will be forfeited.

In September 2009, TVA entered into a LTDCP agreement with Mr. Thomas. Under the terms of the agreement, Mr. Thomas received deferred compensation credits of $50,000 on October 1, 2009, and October 1, 2010. Mr. Thomas will vest in his account only if he remains employed by TVA until the expiration of the agreement on September 30, 2011.  All vested credits, and earnings on such credits, in his account will be distributed to him in a lump sum following the expiration of the agreement.  In the event TVA terminates Mr. Thomas’s employment during the term of the LTDCP agreement through no act or delinquency of his own, any credits and earnings on those credits in Mr. Thomas’s account at the time of termination will become vested and distributed to him in a lump sum.  If Mr. Thomas voluntarily terminates his employment or TVA terminates Mr. Thomas’s employment for cause prior to the expiration of the agreement, all credits, and earnings on such credits, in Mr. Thomas’s account will be forfeited.

In September 2010, TVA entered into a second LTDCP agreement with Mr. Thomas. Under the terms of the agreement, Mr. Thomas received a deferred compensation credit of $50,000 on October 1, 2010.  Mr. Thomas will also receive deferred compensation credits in the amount of $100,000 each on October 1, 2011, and October 1, 2012, if he remains employed by TVA on these dates. Mr. Thomas will vest in his account only if he remains employed by TVA until the expiration of the agreement on September 30, 2013.  All vested credits, and earnings on such credits, in his account will be distributed to him in a lump sum following the expiration of the agreement.  In the event TVA terminates Mr. Thomas’s employment during the term of the LTDCP agreement through no act or delinquency of his own, any credits and earnings on those credits in Mr. Thomas’s account at the time of termination will become vested and distributed to him in a lump sum.  If Mr. Thomas voluntarily terminates his employment or TVA terminates Mr. Thomas’s employment for cause prior to the expiration of the agreement, all credits, and earnings on such credits, in Mr. Thomas’s account will be forfeited.

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In May 2007, TVA entered into a LTDCP agreement with Mr. McCollum.  Under the terms of the agreement, Mr. McCollum received a deferred compensation credit of $350,000 on May 1, 2007, and deferred compensation credits of $200,000 on October 1, 2007, October 1, 2008, October 1, 2009, and October 1, 2010. Pursuant to the agreement, Mr. McCollum was vested in the first credit of $350,000 at the time the credit was made and vested in any earnings on this amount.  Mr. McCollum will vest in the remaining balance of his account only if he remains employed by TVA until the expiration of the agreement on September 30, 2011.  All vested credits, and earnings on such credits, in his account will be distributed to him in five annual installments following the termination of his employment with TVA.  In the event TVA terminates Mr. McCollum’s employment during the term of the LTDCP agreement through no act or delinquency of his own, any credits and earnings on those credits in Mr. McCollum’s account at the time of termination will become vested and distributed to him in five annual installments.  If Mr. McCollum voluntarily terminates his employment or TVA terminates Mr. McCollum’s employment for cause prior to the expiration of the agreement, all credits, and earnings on such credits, in Mr. McCollum’s account, except the initial $350,000 credit and any earnings on this amount, will be forfeited.

In June 2006, TVA entered into a LTDCP agreement with Mr. Swafford.  Under the terms of the agreement, Mr. Swafford received deferred compensation credits of $125,000 on June 1, 2006, October 1, 2006, October 1, 2007, October 1, 2008, and October 1, 2009.  Mr. Swafford was vested in his account on September 30, 2010, and the entire balance of his account, which includes the credits and earnings on such credits, will be distributed to him in a lump sum following the termination of his employment with TVA.

In November 2010, approval was granted to enter into a new LTDCP agreement with Mr. Swafford. Under the terms of the agreement, Mr. Swafford will receive an initial deferred compensation credit of $150,000 on December 1, 2010.  He will also receive deferred compensation credits of $100,000 each on October 1, 2011 and October 1, 2012.  Mr. Swafford will become vested in his account on September 30, 2013, and the entire balance of the account, which includes the credits and earnings on such credits, will be distributed to him based on the elections he makes at the time the agreement is executed.  The new agreement is intended to extend the annual credits, with minor adjustment, that Mr. Swafford received under the previous agreement that expired on September 30, 2010.

In September 2004, TVA entered into a LTDCP agreement with Mr. Bhatnagar.  Under the terms of the agreement, Mr. Bhatnagar received deferred compensation credits of $150,000 on October 1, 2004, October 1, 2005, October 1, 2006, October 1, 2007, and October 1, 2008.  Mr. Bhatnagar was vested in his account on September 30, 2009, and the entire balance of his account, which includes the credits and earnings on such credits, was distributed to Mr. Bhatnagar in a lump sum in October 2009.

In December 2009, TVA entered into a new LTDCP agreement with Mr. Bhatnagar. Under the terms of the agreement, Mr. Bhatnagar received deferred compensation credits of $175,000 on January 1, 2010, and October 1, 2010.  Mr. Bhatnagar will also receive deferred compensation credits in the amount of $175,000 each on October 1, 2011, October 1, 2012, and October 1, 2013, if he remains employed by TVA on those dates.  Mr. Bhatnagar will vest in his account only if he remains employed by TVA until the expiration of the agreement on September 30, 2014.  All vested credits, and earnings on such credits, in his account will be distributed to him in a lump sum following the expiration of the agreement.  In the event TVA terminates Mr. Bhatnagar’s employment during the term of the LTDCP agreement through no act or delinquency of his own, any credits and earnings on those credits in Mr. Bhatnagar’s account at the time of termination will become vested and distributed to him in a lump sum.  If Mr. Bhatnagar voluntarily terminates his employment or TVA terminates Mr. Bhatnagar’s employment for cause prior to the expiration of the agreement, all credits, and earnings on such credits, in Mr. Bhatnagar’s account will be forfeited.

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Retirement and Pension Plans

The following table provides the actuarial present value of the Named Executive Officers’ accumulated benefits, including the number of years of credited service, under TVA’s retirement and pension plans as of September 30, 2010, determined using a methodology and interest rate and mortality rate assumptions that are consistent with those used in the financial statements contained in this Annual Report as set forth in Note 18.

	Pension Benefits Table
	Name (a)	Plan Name (b)	Number of Years of Credited Service (1) (#) (c)	Present Value of Accumulated Benefit ($) (d)	Payments During Last Year ($) (e)
	Tom Kilgore	(1) Qualified Plan – CBBS (2) Non-Qualified – SERP Tier 1	5.58 8.58(2)	$72,375 $2,422,058	$0 $0
	John M. Thomas, III	(1) Qualified Plan – CBBS (2) Non-Qualified – SERP Tier 1	4.83 4.83	$89,657 $187,851	$0 $0
	John M. Hoskins	(1) Qualified Plan – OBS (2) Non-Qualified – SERP Tier 2	36.78 32.67	$2,297,329 $389,375	$0 $0
	Kimberly S. Greene	(1) Qualified Plan – CBBS (2) Non-Qualified – SERP Tier 1	3.08 18.08(3)	$63,212 $1,074,714	$0 $0
	William R. McCollum, Jr.	(1) Qualified Plan – CBBS (2) Non-Qualified – SERP Tier 1	3.42 13.42(4)	$50,399 $2,704,040	$0 $0
	Preston D. Swafford	(1) Qualified Plan – CBBS (2) Non-Qualified – SERP Tier 1	4.42 9.42(5)	$85,415 $839,533	$0 $0
	Ashok S. Bhatnagar	(1) Qualified Plan – CBBS (2) Non-Qualified – SERP Tier 1	11.08 11.08	$188,517 $1,051,726	$0 $0
Notes (1) Limited to 24 years when determining supplemental benefits available under SERP Tier 1, described below. (2)Mr. Kilgore has been granted three additional years of credited service for pre-TVA employment and the offset for prior employer pension benefits associated with the additional three years of credited service has been waived.  In addition, the offset for benefits provided under TVA’s defined benefit plan will be calculated based on the actual pension benefit he will receive as a participant in the CBBS. (3)  Ms. Greene has been granted 15 additional years of credited service for pre-TVA employment and the offset for prior employer pension benefits has been waived.  The offset for benefits provided under TVA’s defined benefit plan will be calculated based on the benefit she will be eligible to receive as a participant in the CBBS taking into account the additional years of credited service being used for SERP benefit calculation purposes.  In the event that Ms. Greene voluntarily terminates her employment with TVA or is terminated for cause prior to satisfying the minimum five-year vesting requirement, no benefits will be provided under the SERP.  In the event of termination for any other reason, prior to five years of employment, the five-year vesting requirement will be waived and the benefit Ms. Greene will be eligible to receive will be payable no earlier than age 55.  As of September 30, 2010, the present value of this benefit is 1,074,714.   Without the additional years of credited service, the present value of Ms. Greene’s accumulated benefit would be $0.
(4)  Mr. McCollum has been granted 10 additional years of credited service for pre-TVA employment and the offset for prior employer pension benefits has been waived.  The additional years of credited service will be used for SERP benefit calculation purposes only and will not count toward the minimum five-year vesting requirement.  In the event Mr. McCollum voluntarily terminates his employment with TVA or is terminated for cause prior to satisfying the minimum five-year vesting requirement, no benefits will be provided under the SERP.  In the event of termination for any other reason, prior to five years of employment, the five-year vesting requirement will be waived as long as the termination is considered acceptable to TVA, and Mr. McCollum will be eligible to receive benefits payable in five annual installments following termination.  The present value of this benefit as of September 30, 2010, is $2,704,040.  Without waiving and granting the additional years of credited service, the present value of Mr. McCollum’s accumulated benefit would be $0. (5)  Mr. Swafford has been granted five additional years of credited service for pre-TVA employment and the offset for prior employer pension benefits has been waived.  The additional years of credited service will be used for SERP benefit calculation purposes only and will not count toward the minimum five-year vesting requirement.  In addition, the offset for benefits provided under TVA’s defined benefit plan will be calculated based on the benefit he would be eligible to receive as a participant in the CBBS taking into account the additional years of credited service being used for SERP benefit calculation purposes.  In the event Mr. Swafford voluntarily terminates his employment with TVA or is terminated for cause prior to satisfying the minimum five-year vesting requirement, no benefits will be provided under the SERP.  The present value of this benefit as of September 30, 2010, is $839,533.  Without the additional years of credited service, the present value of Mr. Swafford’s accumulated benefit would be $0.

Qualified Defined Benefit Plan.  TVA sponsors a qualified defined benefit plan with two structures for employees, including the Named Executive Officers, which is administered by the TVA Retirement System.  The structures are the Original Benefit Structure (“OBS”) and the Cash Balance Benefit Structure (“CBBS”).  Participation in the OBS is limited to employees who were covered under the plan prior to January 1, 1996.  All employees first hired by TVA on or after January 1, 1996, participate in the CBBS.  As with any other qualified retirement plan, there are limits on employee and employer contributions and compensation that can be counted for benefit calculations set by the TVA Retirement System rules and IRS regulations.

OBS.  Mr. Hoskins is the only Named Executive Officer who participates in the OBS. The pension provided under the OBS is based on a final average pay formula that includes the member’s years of creditable service (to the nearest month), highest average compensation during any three consecutive years of creditable service, and a pension factor, less a small Social Security offset. For executives who are members of the OBS, compensation is defined as annual salary only for benefit calculation purposes and, for Mr. Hoskins is shown under the column titled “Salary” in the Summary Compensation Table, although compensation cannot exceed $245,000 in 2010 pursuant to the IRS annual compensation limit applicable to qualified plans. Creditable service is the length of time spent as a member of the TVA Retirement System and may also include certain military service, some periods of leave without

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pay, forfeited annual leave, and unused sick leave. The pension factor, which can reach a maximum of 1.3 percent, is determined by a member’s age and/or whether the member has obtained the Rule of 80. The Rule of 80 is the sum of a member’s age and creditable service at the time of termination. For example, a member who has reached age 55 and has 25 years of creditable service has obtained the Rule of 80. Mr. Hoskins has obtained the Rule of 80. The Social Security offset is equal to the product of a member’s actual years of service times 1.75 times a factor based on the member’s actual age at retirement. Members must have at least five years of creditable service in order to be eligible for a pension benefit.

Members in the OBS who are 55 with five years of creditable service are eligible to receive an immediate benefit upon retirement. Members whose age plus service, including unused sick leave and forfeited annual leave, equals 80 points or more receive the maximum pension factor of 1.3 percent. Members who reach age 60 with at least five years of creditable service receive the maximum pension factor of 1.3 percent even if they do not have 80 points. The OBS does not provide early retirement benefits to Mr. Hoskins or any other member in the OBS.

CBBS.  All of the other Named Executive Officers are members of the CBBS.  Under the CBBS, each member has a cash balance account that receives pay credits equal to six percent of his/her compensation each pay period (every two weeks).  For executives who are members of the CBBS, compensation is defined as annual salary only for benefit calculation purposes and is shown under the column titled “Salary” in the Summary Compensation Table, although compensation could not exceed $245,000 in 2010 pursuant to the IRS annual compensation limit applicable to qualified plans.  The account is credited with interest each month, and interest is compounded on an annual basis.  The annual interest rate used for interest credits is determined each January 1.  The interest rate is three percent greater than the percentage increase in the 12-month average of the Consumer Price Index for the period ending on the previous October 31.  The minimum interest rate is six percent and the maximum interest rate is 10 percent unless the TVARS Board, with TVA’s approval, selects a higher interest rate.  When a member elects to begin receiving retirement benefits, the cash balance account is converted to a monthly pension payment by dividing the ending value of the cash balance account by a conversion factor set forth in the plan based on the member’s actual age in years and months.

Members with at least five years of CBBS service are eligible to receive an immediate benefit.  CBBS service is the length of time spent as a member of the TVA Retirement System and does not include credit for unused sick leave, forfeited annual leave, or pre-TVA employment military service.  The CBBS does not provide for early retirement benefits to any Named Executive Officer or any other member in the CBBS.

Supplemental Executive Retirement Plan.  The SERP is a non-qualified defined benefit pension plan similar to those typically found in other companies in TVA’s peer group and is provided to a limited number of executives, including the Named Executive Officers.  TVA’s SERP was created to recruit and retain key executives.  The plan is designed to provide a competitive level of retirement benefits in excess of the limitations on contributions and benefits imposed by TVA’s qualified defined benefit plan and IRS code section 415 limits on qualified retirement plans.

The SERP provides two distinct levels of participation, Tier 1 and Tier 2.  Each employee is assigned to one of the two tiers at the time he or she is approved to participate in the SERP.  The level of participation (“Tier”) defines the level of retirement benefits provided under the SERP at the time of retirement.

Under the SERP, normal retirement eligibility is age 62 with five years of vesting service.  No vested and accrued benefits are payable prior to age 55, and benefits are reduced for retirements prior to age 62.  The level of reduction in benefits for retirements prior to age 62 depends on whether a participant’s termination is “approved” or “unapproved.”  In the event of an approved termination of TVA employment, any vested and accrued benefits are reduced by 5/12 percent for each month that the date of benefit commencement precedes the participant’s 62nd birthday up to a maximum reduction of 35 percent.  In the event of an unapproved termination of TVA employment, the participant’s accrued benefits are first subject to a reduced percentage of vesting if the participant’s years of service are between five and ten.  At five years of vesting service, the vested percentage of retirement benefits is 50 percent and increases thereafter by 10 percent for each full additional year of service, reaching 100 percent vesting for ten or more years of vesting service.  Thereafter, any vested and accrued benefits are reduced by 10/12 percent for each month that the date of benefit commencement precedes the participant’s 62nd birthday up to a maximum reduction of 70 percent.

For purposes of the SERP, an “approved” termination means termination of employment with TVA due to (i) retirement on or after the participant’s 62nd birthday, (ii) retirement on or after attainment of actual age 55, if such retirement has the approval of the TVA Board or its delegate, (iii) death in service as an employee, (iv) disability (as such term is defined under TVA’s long-term disability plan), or (v) any other circumstances approved by the TVA Board or its delegate.  For purposes of the SERP, an “unapproved” termination means a termination of employment with TVA when such termination does not constitute an “approved” termination as defined in the preceding sentence.

SERP Tier 1.  All of the Named Executive Officers, except Mr. Hoskins, are participants in Tier 1.  The Tier 1 structure is designed to replace 60 percent of the amount of a participant’s compensation at the time the participant reaches age 62 and has accrued 24 years of service at TVA.

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Tier 1 benefits are based on a participant’s highest average compensation during three consecutive SERP years and a pension multiple of 2.5 percent for each year of credited service up to a maximum of 24 years.  Compensation is defined as salary and EAIP for benefit calculation purposes.  Tier 1 benefits are offset by Social Security benefits, benefits provided under TVA’s defined benefit plan, and prior employer pension benefits when applicable.

SERP Tier 2.  Mr. Hoskins is the only Named Executive Officer who is a participant in Tier 2.  Tier 2 benefits are based on a participant’s highest average compensation during three consecutive SERP years and a pension multiple of 1.3 percent for each year of credited service. Compensation is defined as salary and EAIP for benefit calculation purposes.

The TVA Sponsored 401(k) Plan.  Members of the TVA Retirement System, including the Named Executive Officers, may elect to participate in the TVA Retirement System’s 401(k) plan on a before-tax, after-tax and/or Roth basis.  For OBS members, TVA provides a matching contribution of 25 cents on every dollar contributed on a before-tax, after-tax and/or Roth basis up to 1.5 percent of the participant’s annual salary.  For CBBS members, TVA provides a matching contribution of 75 cents on every dollar contributed on a before-tax, after-tax and/or Roth basis up to 4.5 percent of the participant’s annual salary.

Nonqualified Deferred Compensation

The following table provides information regarding deferred contributions, earnings, and balances for each of the Named Executive Officers.  The amounts reported under this table do not represent compensation in addition to the compensation that was earned in 2010 and already reported in the Summary Compensation Table but rather the amounts of compensation earned by the Named Executive Officers in 2010 or prior years that was or has been deferred.

Nonqualified Deferred Compensation Table
Name (a)	Executive Contributions in Last FY ($) (b)	Registrant Contributions in Last FY ($) (c)	Aggregate Earnings in Last FY (1) ($) (d)	Aggregate Withdrawals/ Distributions ($) (e)	Aggregate Balance at Last FYE (2) ($) (f)
Tom Kilgore	$0	$300,000(3)	$146,485	$0	$3,887,999(4)
John M. Thomas, III	$0	$50,000(5)	$1,462	$0	$51,462(6)
John M. Hoskins	$0	$60,000(7)	$32,807	$0	$1,311,128(8)
Kimberly S. Greene	$0	$150,000(9)	$16,023	$0	$627,445(10)
William R. McCollum, Jr.	$559,136 (11)	$200,000(12)	$182,525	$0	$3,193,267(13)
Preston D. Swafford	$98,438(14)	$125,000(15)	$27,244	$0	$1,088,566(16)
Ashok S. Bhatnagar	$0	$175,000(17)	$107,715	$818,718(18)	$1,762,369(19)
Notes (1)Includes vested and unvested earnings.  Because none of these amounts is above market earnings under SEC rules, none of these amounts is included in the Summary Compensation Table. (2)Includes vested and unvested contributions and earnings. (3)Represents an unvested annual credit in the amount of $300,000 provided under a LTDCP agreement with Mr. Kilgore (reported in the “All Other Compensation” column in the Summary Compensation Table). (4)Includes a total of $306,517 of contributions and earnings that were not vested as of September 30, 2010.  A total of $2,611,522 was reported as compensation to Mr. Kilgore in the Summary Compensation Tables in previous years.  (5) Represents an unvested annual credit in the amount of $50,000 provided under a LTDCP agreement with Mr. Thomas (reported in the “All Other Compensation” column in the Summary Compensation Table). (6)  Contributions and earnings that were not vested as of September 30, 2010. (7)  Represents an unvested annual credit in the amount of $60,000 provided under a LTDCP agreement with Mr. Hoskins (reported in the “All Other Compensation” column in the Summary Compensation Table). (8)  Includes a total of $61,158 of contributions and earnings that were not vested as of September 30, 2010.  A total of $144,579 was reported as compensation to Mr. Hoskins in the Summary Compensation Table in previous years. (9)  Represents an unvested annual credit in the amount of $150,000 provided under two separate LTDCP agreements with Ms. Greene (reported in the “All Other Compensation” column in the Summary Compensation Table). (10) Includes a total of $313,285 of contributions and earnings that were not vested as of September 30, 2010.  A total of $430,000 was reported as compensation to Ms. Greene in the Summary Compensation Tables in previous years. (11)Mr. McCollum elected to defer 100 percent of the $559,136 to be awarded under the ELTIP for the performance cycle that ended on September 30, 2010 (reported in the “Non-Equity Incentive Plan Compensation” column in the Summary Compensation Table). (12)Represents an unvested annual credit in the amount of $200,000 provided under a LTDCP agreement with Mr. McCollum (reported in the “All Other Compensation” column in the Summary Compensation Table). (13)Includes a total of $629,855 of contributions and earnings that were not vested as of September 30, 2010.  The amount reported in “Executive Contributions in Last FY” column will be credited to his account in the first quarter of 2011 and is not included in the balance.  A total of $2,842,486 was reported as compensation to Mr. McCollum in the Summary Compensation Tables in previous years. (14)Mr. Swafford elected to defer 25 percent of the $393,750 to be awarded under the ELTIP for the performance cycle that ended on September 30, 2010 (reported in the “Non-Equity Incentive Plan Compensation” column in the Summary Compensation Table). (15)Represents an unvested annual credit in the amount of $125,000 provided under a LTDCP agreement with Mr. Swafford (reported in the “All Other Compensation” column in the Summary Compensation Table). (16)Includes a total of $696,607 of contributions and earnings that were not vested as of September 30, 2010.  The amount reported in “Executive Contributions in Last FY” column will be credited to his account in the first quarter of 2011 and is not included in the balance.  A total of $223,438 was reported as compensation to Mr. Swafford in the Summary Compensation Tables in previous years. (17)Represents an unvested annual credit in the amount of $175,000 provided under a LTDCP agreement with Mr. Bhatnagar (reported in the “All Other Compensation” column in the Summary Compensation Table). (18)Represents a total of $818,718 of contributions and earnings that were provided under a LTDCP agreement with Mr. Bhatnagar that vested on September 30, 2009 and was paid out in the first quarter of fiscal year 2010. (19)  Includes a total of $178,403 of contributions and earnings that wee not vested as of September 30, 2010.  A total of $683,452 was reported as compensation to Mr. Bhatnagar in the Summary Compensation Tables in previous years.

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TVA normally allows participants in the EAIP, ELTIP, and LTDCP to elect to defer all or a portion of the compensation earned under those plans that is eligible for deferral under the terms of each plan and applicable IRS regulations.  All deferrals are credited to each participant in a deferred compensation account, and the deferral amounts are then funded into a rabbi trust.  Each participant may elect one or more of several notional investment options made available by TVA or allow some or all funds to accrue interest at the rate established by the beginning of each fiscal year equal to the composite rate of all Treasury issues.  Participants may elect to change from either one notional investment option or the TVA interest bearing option to another at any time.  Upon termination, funds are distributed pursuant to elections made in accordance with applicable IRS regulations.

No executives, including the Named Executive Officers, were permitted to defer any portion of their annual salary or EAIP payout in 2010.  Participants in the ELTIP, including the Named Executive Officers, were permitted to elect to defer all or a portion of their awards (25, 50, 75, or 100 percent) received under the plans.  Participants in the LTDCP, including the Named Executive Officers, may be eligible to defer credits awarded under their LTDCP agreements by making an election at the time they enter into the LTDCP agreements.

Potential Payments on Account of Retirement/Resignation, Termination without Cause, Termination with Cause, or Death/Disability

The tables below show certain potential payments that would have been made to each Named Executive Officer if his or her employment had been terminated on September 30, 2010 (except as otherwise indicated), under various scenarios.  All of the Named Executive Officers would also be entitled to payments from plans generally available to TVA employees under the specific circumstances of termination of employment, including the health and welfare and pension plans and amounts in the 401(k) plan.

Tom Kilgore	Retirement/ Resignation	Termination without Cause	Termination with Cause	Death/ Disability
Severance Agreement(1)	$0	$2,975,000	$0	$0
LTDCP	$0	$306,517	$0	$306,517
SERP	$2,422,058(2)	$2,422,058(2)	$2,422,058(2)	$2,422,058(3)
Deferred Compensation(4)	$3,851,482	$3,851,482	$3,851,482	$3,851,482
Total Value of Potential Payments	$6,003,540	$9,285,057	$6,003,540	$6,310,057
Notes (1)In January 2005, TVA entered into an agreement with Mr. Kilgore that provides a lump-sum payment equal to one year’s annual compensation if (1) his duties,responsibilities, or compensation is substantially reduced, and he terminates his employment with TVA, or (2) his employment is terminated for any reason other than “for cause.”  For purposes of this agreement, “annual compensation” is defined as annual salary plus the amount of the annual and long-term incentive awards he would have been eligible to receive based on 100 percent achievement of target performance goals. (2)Represents the present value of the accumulated benefit.  Actual benefit would to be paid in five annual installments. (3)Represents the present value of the accumulated benefit.  In the event of death while employed by TVA, the beneficiary will receive a lump sum payment equal to the actuarial equivalent of the benefit that would have been paid had the participant terminated employment on the date of death and elected a joint and 50 percent survivors benefit. (4)Amounts that Mr. Kilgore earned in past years but elected to defer, which are payable pursuant to elections he made and applicable IRS rules.

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John M. Thomas, III	Retirement/ Resignation	Termination without Cause	Termination with Cause	Death/ Disability
Severance Agreement(1)	$0	$0	$0	$0
LTDCP	$0	$0	$0	$51,462
SERP	$0(2)	$0(2)	$0(2)	$187,851(3)
Deferred Compensation	$0	$0	$0	$0
Total Value of Potential Payments	$0	$0	$0	$239,313
Notes (1)Mr. Thomas does not have a severance agreement with TVA. (2)Mr. Thomas has not yet vested in SERP. (3)Represents the present value of the accumulated benefit.  In the event of death while employed by TVA, the beneficiary will receive a lump sum payment equal to the actuarial equivalent of the benefit that would have been paid had the participant terminated employment on the date of death and elected a joint and 50 percent survivors benefit.

John M. Hoskins	Retirement/ Resignation	Termination without Cause	Termination with Cause	Death/ Disability
Severance Agreement(1)	$0	$0	$0	$0
LTDCP	$0	$61,158	$0	$61,158
SERP	$389,375(2)	$389,375(2)	$389,375(3)	$389,375(4)
Deferred Compensation (5)	$1,249,970	$1,249,970	$1,249,970	$1,249,970
Total Value of Potential Payments	$1,639,345	$1,700,503	$1,639,345	$1,700,503
Notes (1)Mr. Hoskins does not have a severance agreement with TVA. (2)Represents the present value of the accumulated benefit and assumes the termination is an approved termination under SERP.  If the termination had taken place on September 30, 2010, the benefit would, however, have been reduced by 5/12 percent for each month between September 30, 2010, and October 31, 2017 (age 62).  Actual benefit would to be paid in 10 annual installments. (3)  Represents the present value of the accumulated benefit and assumes the termination is an approved termination under SERP.  If the termination is not an approved termination under SERP, the benefit will be reduced in the manner discussed above in Retirement and Pension Plans - Supplemental Executive Retirement Plan.  Actual benefit would be paid in 10 annual installments. (4)Represents the present value of the accumulated benefit.  In the event of death while employed by TVA, the beneficiary will receive a lump sum payment equal to the actuarial equivalent of the benefit that would have been paid had the participant terminated employment on the date of death and elected a joint and 50 percent survivors benefit. (5)Amounts that Mr. Hoskins earned in past years but elected to defer, which are payable pursuant to elections he made and applicable IRS rules.

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Kimberly S. Greene	Retirement/ Resignation	Termination without Cause	Termination with Cause	Death/ Disability
Severance Agreement(1)	$0	$2,080,000	$0	$0
LTDCP	$0	$313,285	$0	$313,285
SERP	$0	$1,074,714(2)	$0	$1,074,714(3)
Deferred Compensation(4)	$314,160	$314,160	$314,160	$314,160
Total Value of Potential Payments	$314,160	$3,782,159	$314,160	$1,702,159
Notes (1)In August 2007, TVA entered into an agreement with Ms. Greene that provides a lump-sum payment in an amount equal to two years’ annual compensation in the event that TVA’s current Chief Executive Officer no longer occupies that position and Ms. Greene is asked to leave TVA employment for any reason other than for cause.  For purposes of this agreement, “annual compensation” is defined as annual salary plus the amount of the annual incentive award based on 100 percent achievement of target performance goals. (2)Represents the present value of the accumulated benefit and assumes the termination is an approved termination under SERP.  If the termination had taken place on September 30, 2010, the benefit would, however, have been reduced by 5/12 percent for each month from October 5, 2021 (age 55) to October 5, 2028 (age 62).  Actual benefit would to be paid in five annual installments. (3)Represents the present value of the accumulated benefit.  In the event of death while employed by TVA, the beneficiary will receive a lump sum payment equal to the actuarial equivalent of the benefit that would have been paid had the participant terminated employment on the date of death and elected a joint and 50 percent survivors benefit. (4)Amounts that Ms. Greene earned in past years but elected to defer, which are payable pursuant to elections she made and applicable IRS rules.

William R. McCollum, Jr.	Retirement/ Resignation	Termination without Cause	Termination with Cause	Death/ Disability
Severance Agreement(1)	$0	$0	$0	$0
LTDCP	$0	$629,855	$0	$629,855
SERP	$0(2)	$0(2)	$0(2)	$2,704,040(3)
Deferred Compensation(4)	$2,563,412	$2,563,412	$2,563,412	$2,563,412
Total Value of Potential Payments	$2,563,412	$3,193,267	$2,563,412	$5,897,307
Notes (1)  Mr. McCollum does not have a severance agreement with TVA. (2)  Mr. McCollum has not yet vested in SERP. (3)  Represents the present value of the accumulated benefit.  In the event of death while employed by TVA, the beneficiary will receive alump sum payment equal to the actuarial equivalent of the benefit that would have been paid had the participant terminated employment on the date of death and elected a joint and 50 percent survivors benefit. (4)  Amounts that Mr. McCollum earned in past years but elected to defer, which are payable pursuant to elections he made and applicable IRS rules.

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Preston D. Swafford	Retirement/ Resignation	Termination without Cause	Termination with Cause	Death/ Disability
Severance Agreement(1)	$0	$0	$0	$0
LTDCP	$696,607	$696,607	$696,607	$696,607
SERP	$0(2)	$0(2)	$0(2)	$839,543(3)
Deferred Compensation(4)	$391,959	$391,959	$391,959	$391,959
Total Value of Potential Payments	$1,088,566	$1,088,566	$1,088,566	$1,928,109
Notes (1)  Mr. Swafford does not have a severance agreement with TVA. (2)  Mr. Swafford has not yet vested in SERP. (3)  Represents the present value of the accumulated benefit.  In the event of death while employed by TVA, the beneficiary will receive a lump sum payment equal to the actuarial equivalent of the benefit that would have been paid had the participant terminated employment on the date of death and elected a joint and 50 percent survivors benefit. (4)  Amounts that Mr. Swafford earned in past years but elected to defer, which are payable pursuant to elections he made and applicable IRS rules.

Ashok S. Bhatnagar	Retirement/ Resignation	Termination without Cause	Termination with Cause	Death/ Disability
Severance Agreement(1)	$0	$0	$0	$0
LTDCP	$0	$178,403	$0	$178,403
SERP	$1,051,726(2)	$1,051,726(2)	$1,051,726(3)	$1,051,726(4)
Deferred Compensation(5)	$1,583,966	$1,583,966	$1,583,966	$1,583,966
Total Value of Potential Payments	$2,635,692	$2,814,095	$2,635,692	$2,814,095
Notes (1)Mr. Bhatnagar does not have a severance agreement with TVA. (2)Represents the present value of the accumulated benefit and assumes the termination is an approved termination under SERP.  If the termination had taken place on September 30,2010, the benefit would, however, have been reduced by 5/12 percent for each month between September 30, 2010, and May 16, 2018 (age 62).  Actual benefit to be paid in 10 annual installments. (3)  Represents the present value of the accumulated benefit and assumes the termination is an approved termination under SERP.  If the termination is not an approved termination under SERP, the benefit will be reduced in the manner discussed above in Retirement and Pension Plans - Supplemental Executive Retirement Plan.  Actual benefit would be paid in 10 annual installments. (4)Represents the present value of the accumulated benefit.  In the event of death while employed by TVA, the beneficiary will receive a lump sum payment equal to the actuarial equivalent of the benefit that would have been paid had the participant terminated employment on the date of death and elected a joint and 50 percent survivors benefit. (5)Amounts that Mr. Bhatnagar earned in past years but elected to defer, which are payable pursuant to elections he made and applicable IRS rules.

Other Agreements

Except as described above and in the Compensation Discussion and Analysis, there are no other agreements between TVA and any of the Named Executive Officers.

Director Compensation

The TVA Act provides for up to nine directors on the TVA Board.  Under the TVA Act, each of TVA’s directors receives certain stipends that are increased annually by the same percentage increase applicable to adjustments under 5 U.S.C. § 5318, which provides for adjustments in the annual rates of pay of employees on the Executive Schedule of the United States Government.  As of September 30, 2010, the base stipend amounted to $48,900 per year unless (1) the director is the chair of a TVA Board committee, in which case the stipend is $50,000 per year, or (2) the director is the Chairman of the TVA Board, in which case the stipend is $54,500 per year.  Directors are also reimbursed under federal law for travel, lodging, and related expenses that they incur in attending meetings and for other official TVA business in the same manner as other persons employed intermittently in federal government service.

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The annual stipends provided by the TVA Act for each director and to the Chairman of the TVA Board as of November 19, 2010, were as follows:

TVA Board Annual Stipends
Name	Annual Stipend ($)
Dennis C. Bottorff	$54,500
Marilyn A. Brown	$50,000
Robert M. Duncan	$50,000
Thomas C. Gilliland	$50,000
Bishop William H. Graves	$50,000
Barbara S. Haskew	$48,900
Neil G. McBride	$48,900
William B. Sansom	$50,000
Howard A. Thrailkill	$48,900

   The following table set outs the compensation received by TVA’s directors during 2010.

Director Compensation
Name (a)	Fees Earned or Paid in Cash ($) (b)	Stock Awards ($) (c)	Option Awards ($) (d)	Non-Equity Incentive Plan Compensation ($) (e)	Change in Pension Value and Nonqualified Deferred Compensation Earnings (1) ($) (f)	All Other Compensation ($) (g)	Total ($) (h)
Dennis C. Bottorff(2)	$51,717					$517	$52,234
Robert M. Duncan(3)	$52,800					$528	$53,328
Thomas C. Gilliland	$50,038					$500	$50,538
Bishop William H. Graves	$50,038					$500	$50,538
William B. Sansom(4)	$11,319					$124	$11,443
Howard A. Thrailkill(5)	$50,038					$2,501	$52,539
Notes (1)  TVA directors do not participate in the TVA Retirement System, TVA’s SERP, or any non-qualified deferred compensation plan available to TVA employees.  However, as appointed officers of the United States government, the directors are members of the Federal Employees Retirement System “FERS”).  FERS is administered by the federal Office of Personnel Management, and information regarding the value of FERS pension benefits is not available to TVA. (2)  Mr. Bottorff became Chairman on May 19, 2010. (3)  Mr. Duncan resigned the Chairmanship of the Board effective May 18, 2010, but continued to served a as a director. (4)  Mr. Sansom’s term as Chairman expired on May 19, 2009, but he continued to serve as a director until the end of the current session of Congress on December 24, 2009.  He began his second term on the TVA Board in October 2010. (5)  Mr. Thrailkill's term as a director expired on May 19, 2010, but he is entitled to remain in office until the end of the current session of Congress or until a successor takes office.

The directors are not eligible to participate in any incentive programs available to TVA employees.  The directors do not participate in the TVA Retirement System and do not participate in TVA’s SERP.  However, as appointed officers of the United States government, the directors are members of the Federal Employees Retirement System (“FERS”).  FERS is a tiered retirement plan that includes three components: (1) Social Security benefits, (2) the Basic Benefit Plan, and (3) the Thrift Savings Plan (“TSP”).  Each director pays full Social Security taxes and makes a small contribution (0.8 percent of salary or stipend) to the Basic Benefit Plan.

The FERS Basic Benefit Plan is a qualified defined benefit plan that provides a retirement benefit based on a final average pay formula that includes age, highest average salary during any three consecutive years of service, and years of creditable service.  A director must have at least five years of creditable service in order to be eligible to receive retirement benefits.  Directors are eligible for immediate, unreduced retirement benefits once (1) they reach age 62 and have five years of FERS creditable service, (2) they reach age 60 and have 20 years of FERS creditable service, or (3) they attain the minimum retirement age and accumulate the specified years of service as set forth in the FERS regulations.  Generally, benefits are calculated by multiplying 1.0 percent of the highest average salary during any three consecutive years of service by the number of years of creditable service.  Directors who retire at age 62 or later with at least 20 years of FERS creditable service receive an enhanced benefit (a factor of 1.1 percent is used rather than 1.0 percent).

Directors may also retire with an immediate benefit under FERS if they reach their minimum retirement age based on type of retirement and years of service and have accumulated at least 10 years of FERS creditable service.  For directors who reach the minimum retirement age and have at least 10 years of FERS creditable service, the annuity will be reduced by 5 percent for each year the director is under age 62.

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Each director is also eligible to participate in the TSP.  The TSP is a tax-deferred retirement savings and investment plan that offers the same type of savings and tax benefits offered under 401(k) plans.  Once a director becomes eligible, TVA contributes an amount equal to one percent of the director’s stipend into a TSP account for the director.  These contributions are made automatically every two weeks regardless of whether the director makes a contribution of his or her own money.  Directors are eligible to contribute up to the IRS elective deferral limit.  Directors receive matching contributions of 100 percent of each dollar for the first three percent of the director’s stipend and 50 percent of each dollar for the next two percent of the director’s stipend.

Compensation Committee Interlocks and Insider Participation

The People and Performance Committee of the TVA Board currently consists of the following three directors: Bishop William H. Graves, Chair, Barbara S. Haskew, and Dennis C. Bottorff.  Howard A. Thrailkill served on the People and Performance Committee until November 4, 2010, at which time Barbara S. Haskew joined the People and Performance Committee.  Since its establishment on June 10, 2010, the People and Performance Committee has been responsible for oversight of executive compensation pursuant to the Compensation Plan, review of the Compensation Discussion and Analysis included in this Annual Report, and, to the extent applicable, review of performance goal achievement for 2010.  As a result of the TVA Board’s June 2010 delegations, the People and Performance Committee also (1) reviews proposed actions of the CEO to set or adjust the compensation of the CEO’s present and future direct reports within the 80 percent to 110 percent compensation range of the median total direct compensation for comparable positions, as well as to approve the parameters under which such executives may participate in certain supplemental benefit plans such as SERP, (2) consults with the Chairman of the TVA Board about the Chairman of the TVA Board’s proposed evaluation and rating of the performance of the CEO during the year and about the proposed payout to the CEO under the EAIP based on, among other things, the CEO’s evaluated performance during the year, and (3) consults with the CEO about the CEO’s proposed individual performance goals for the CEO’s direct reports and the CEO’s proposed evaluation and rating of the performance of the CEO’s direct reports during the year.

No executive officer of TVA serves on the board of an entity which in turn has an executive officer of the entity serving as a director of TVA.

Compensation Committee Report

The People and Performance Committee has reviewed and discussed the Compensation Discussion and Analysis with management, and based on the review and discussions, the People and Performance Committee recommended to the TVA Board that the Compensation Discussion and Analysis be included in this Annual Report.

PEOPLE AND PERFORMANCE COMMITTEE

Bishop William H. Graves, Chair

Barbara S. Haskew

Dennis C. Bottorff

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Not applicable.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Director Independence

The composition of the TVA Board is governed by the TVA Act.  The TVA Act contains certain provisions that are similar to the considerations for independence under section 10A(m)(3) of the Exchange Act, including that to be eligible for appointment to the TVA Board, an individual shall not be an employee of TVA and shall make full disclosure to Congress of any investment or other financial interest that the individual holds in the energy industry.

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Related Party Transactions

Conflict of Interest Provisions

All TVA employees, including directors and executive officers, are subject to the conflict of interest laws and regulations applicable to employees of the federal government.  Accordingly, the general federal conflict of interest statute (18 U.S.C. § 208) and the Standards of Ethical Conduct for Employees of the Executive Branch (5 C.F.R. part 2635) (“Standards of Ethical Conduct”) form the basis of TVA’s policies and procedures for the review, approval, or ratification of related party transactions.  The general federal conflict of interest statute, subject to certain exceptions, prohibits each government employee, including TVA’s directors and executive officers, from participating personally and substantially (by advice, decision, or otherwise) as a government employee in any contract, controversy, proceeding, request for determination, or other official particular matter in which, to his or her knowledge, he or she (or his or her spouse, minor child, general partner, organization with which he or she serves as officer, director, employee, trustee, or general partner, or any person or organization with which he or she is negotiating, or has an arrangement, for future employment) has a financial interest.  Exceptions to the statutory prohibition relevant to TVA employees are (1) financial interests which have been deemed by the Office of Government Ethics, in published regulations, to be too remote or inconsequential to affect the integrity of the employee’s services, or (2) interests which are determined in writing, after full disclosure and on a case by case basis, to be not so substantial as to be deemed likely to affect the integrity of the employee’s services for TVA.  In accordance with the statute, individual waiver determinations are made by the official responsible for the employee’s appointment.  In the case of TVA directors, the determination may be made by the Chairman of the TVA Board, and in the case of the Chairman of the TVA Board, the determination may be made by the Counsel to the President of the United States.

More broadly, Subpart E of the Standards of Ethical Conduct provides that where an employee (1) knows that a particular matter involving specific parties is likely to have a direct and predictable effect on the financial interests of a member of his or her household, or that a person with whom the employee has a “covered relationship” (which includes, but is not limited to, persons with whom the employee has a close family relationship and organizations in which the employee is an active participant) is or represents a party to the matter, and (2) determines that the circumstances would cause a reasonable person with knowledge of relevant facts to question his or her impartiality in the matter, the employee should not participate in the matter absent agency authorization.  This authorization may be given by the employee’s supervising officer, as agency designee, in consultation with the TVA Designated Agency Ethics Official, upon the determination that TVA’s interest in the employee’s participation in the matter outweighs the concern that a reasonable person may question the integrity of TVA’s programs and operations.

The previously described restrictions are reflected in TVA’s Employment Practice 1, Business Ethics, which requires employees, including TVA’s directors and executive officers, to comply with the guidelines outlined in the Standards of Ethical Conduct and which restates the standard of the conflict of interest statute.

Additionally, on November 30, 2006, the TVA Board approved a written conflict of interest policy that applies to all TVA employees, including TVA’s directors and executive officers.  The conflict of interest policy reaffirms the requirement that all TVA employees must comply with applicable federal conflict of interest laws, regulations, and policies.  It also establishes an additional policy that is applicable to TVA’s directors and Chief Executive Officer, which provides as follows:

In addition to the law and policy applicable to all TVA employees, TVA Directors and the Chief Executive Officer shall comply with the following additional policy restricting the holding of certain financial interests:

1.   For purposes of this policy, “financial interest” means an interest of a person, or of a person’s spouse or minor child, arising by virtue of investment or credit relationship, ownership, employment, consultancy, or fiduciary relationship such as director, trustee, or partner.  However, financial interest does not include an interest in TVA or any interest:

•   comprised solely of a right to payment of retirement benefits resulting from former employment or fiduciary relationship;

•   arising solely by virtue of cooperative membership or similar interest as a consumer in a distributor of TVA power; or

•   arising by virtue of ownership of publicly traded securities in any single entity with a value of $25,000 or less, or within a diversified mutual fund investment in any amount.

2.   Directors and the Chief Executive Officer shall not hold a financial interest in any distributor of TVA power.

3.   Directors and the Chief Executive Officer shall not hold a financial interest in any entity engaged in the wholesale or retail generation, transmission, or sale of electricity.

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4.   Directors and the Chief Executive Officer shall not hold a financial interest in any entity that may reasonably be perceived as likely to be adversely affected by the success of TVA as a producer or transmitter of electric power.

5.   Any action taken or interest held that creates, or may reasonably be perceived as creating, a conflict of interest restricted by this additional policy applicable to TVA Directors and the Chief Executive Officer should immediately be disclosed to the Chairman of Board of Directors and the Chairman of the Audit, Governance, and Ethics Committee (now the Audit, Risk, and Regulation Committee).  The Audit, Governance, and Ethics Committee (now the Audit, Risk, and Regulation Committee) shall be responsible for initially reviewing all such disclosures and making recommendations to the entire Board on what action, if any, should be taken.  The entire Board, without the vote of any Director(s) involved, shall determine the appropriate action to be taken.

6.   Any waiver of this additional policy applicable to TVA Directors and the Chief Executive Officer may be made only by the Board, and will be disclosed promptly to the public, subject to the limitations on disclosure imposed by law.

TVA also has a protocol titled the "Obtaining Things of Value From TVA Protocol" (the "Protocol").  The Protocol describes what a TVA employee or a member of the TVA Board should do if a person covered by the Protocol asks for assistance in obtaining something of value from TVA.

TVA relies on the policies, practices, laws, and regulations discussed above to regulate conflicts of interest involving employees, including directors and executive officers.  TVA has no other written or unwritten policy for the approval or ratification of any transactions in which TVA was or is to be a participant and in which any director or executive officer of TVA (or any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law, or sister-in-law of any director or executive officer of TVA) had or will have a direct or indirect material interest.

U.S. Treasury Interim Obligations

TVA has access to a financing arrangement with the U.S. Treasury.  TVA and the U.S. Treasury have a memorandum of understanding under which the U.S. Treasury provides TVA with a $150 million credit facility.  TVA did not borrow under the facility during 2010. This credit facility matures on September 30, 2011 and is expected to be renewed.  This arrangement is pursuant to the TVA Act.  Access to this credit facility or other similar financing arrangements was made possible by the 1959 amendments to the TVA Act.  See Note 11 — Short-Term Debt.

Power Program Appropriation Investment

In addition, TVA makes payments to the U.S. Treasury as a repayment of and a return on the Power Program Appropriation Investment.  Under the TVA Act, TVA is required to repay $1.0 billion of the Power Program Appropriation Investment, and $70 million of this amount remained unpaid as of September 30, 2010.  Once TVA repays this $70 million, there will still be an outstanding balance on the Power Program Appropriation Investment, and TVA is obligated under the TVA Act to pay the U.S. Treasury a return on this remaining balance indefinitely.  See Note 15 – Appropriation Investment.

ITEM 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table shows the fees of Ernst & Young LLP for the audit and audit-related services for the years ended September 30, 2010 and 2009.

Principal Accountant Fees and Services (in actual dollars)
Year	Principal Accountant	Audit Fees(1)	Audit-Related Fees(2)	All Other Fees	Total
2010	Ernst & Young LLP	$2,090,325	$      —	—	$2,090,325
2009	Ernst & Young LLP	$2,125,603	$      —	—	$2,125,603
Notes (1)  Audit fees consist of fees for professional services rendered in connection with the audit of internal control over financial reporting, and of TVA's annual financial statements, review of the interim financial statements included in TVA's quarterly reports, and services relating to Bond offering comfort letters.

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The TVA Board has an Audit, Risk, and Regulation Committee.  Under the TVA Act, the Audit, Risk, and Regulation Committee, in consultation with the Inspector General, recommends to the TVA Board the selection of an external auditor.  TVA’s Audit, Risk, and Regulation Committee, in consultation with the Inspector General, recommended that the TVA Board select Ernst & Young LLP as TVA’s external auditor for the 2008, 2009, and 2010 audits and other related services, and the TVA Board approved these recommendations.

TVA has a policy (the “Policy”) that provides that all auditing services and permissible non-audit services shall be pre-approved by the Audit, Risk, and Regulation Committee unless:

•   The aggregate amount of all such non-audit services provided to TVA does not exceed 5 percent of the total amount TVA pays the external auditor during the fiscal year in which the non-audit services are provided;

•   Such services were not recognized by TVA at the time of the engagement to be non-audit services or non-audit related services; and

•   Such services are promptly brought to the attention of the Audit, Risk, and Regulation Committee and approved at the next scheduled Audit, Risk, and Regulation Committee meeting or by one or more members of the Audit, Risk, and Regulation Committee to whom the authority to grant such approvals has been delegated.

The Policy also lists the following services as ones the external auditor is not permitted to perform.  The prohibited non-audit services are:

•   Bookkeeping or other services related to the accounting records or financial statements of TVA;

•   Financial information system design and implementation;

•   Appraisal or valuation services, fairness opinions, and contribution-in-kind reports;

•   Actuarial services;

•   Internal audit outsourcing services;

•   Management functions or human resources;

•   Broker or dealer, investment adviser, or investment banking services;

•   Legal services and expert services unrelated to the audit; and

•   Any other services that the Public Company Accounting Oversight Board determines, by regulation, is impermissible.

The Policy also delegates to the Chairman of the Audit, Risk, and Regulation Committee the authority to pre-approve a permissible service so long as the amount of the service does not exceed $100,000 and the Chairman reports for informational purposes the services pre-approved at the Audit, Risk, and Regulation Committee’s next meeting.

The Audit, Risk, and Regulation Committee pre-approved all of the audit and audit-related services for 2009 and 2010.

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PART IV

ITEM 15.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)      The following documents have been filed as part of this Annual Report:

(1)           Financial Statements.  The following documents are provided in Item 8, Financial Statements and Supplementary Data herein.

Statements of Operations

Balance Sheets

Statements of Cash Flow

Statements of Changes in Proprietary Capital

Notes to Financial Statements

Report of Independent Registered Public Accounting Firm (Ernst and Young LLP)

(2)           Financial Statement Schedules.

Schedules not included are omitted because they are not required or because the required information is provided in the financial statements, including the notes thereto. Schedule II — Valuation and Qualifying Accounts (in millions)
Description	Balance at beginning of year		Additions charged to expense		Deductions			Balance at end of year
For the year ended September 30, 2010
Allowance for doubtful accounts
Receivables	$	2	$	—	$	—		$	2
Loans		13		1		(1	)		13
Total allowances deducted from assets	$	15	$	1	$	(1	)	$	15
For the year ended September 30, 2009
Allowance for doubtful accounts
Receivables	$	2	$	—	$	—		$	2
Loans		13		1		(1	)		13
Total allowances deducted from assets	$	15	$	1	$	(1	)	$	15
For the year ended September 30, 2008
Allowance for doubtful accounts
Receivables	$	2	$	1	$	(1	)	$	2
Loans		15		4		(6	)		13
Total allowances deducted from assets	$	17	$	5	$	(7	)	$	15

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(3)                 List of Exhibits.

Exhibit  No.	Description
3.1	Tennessee Valley Authority Act of 1933, as amended , 16 U.S.C. §§ 831-831ee (Incorporated by reference to Exhibit 3.1 to TVA’s Quarterly Report on Form 10-Q for the quarter ended December 31, 2007, File No. 000-52313)
3.2	Bylaws of Tennessee Valley Authority, as Amended (Incorporated by reference to Exhibit 3.1 to TVA’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, File No. 000-52313)
4.1	Basic Tennessee Valley Authority Power Bond Resolution Adopted by the TVA Board of Directors on October 6, 1960, as Amended on September 28, 1976, October 17, 1989, and March 25, 1992 (Incorporated by reference to Exhibit 4.1 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
10.1*	Fall Maturity Credit Agreement Dated as of March 26, 2009, Among TVA, Bank of America, N.A., as Administrative Agent, Bank of America, N.A., as a Lender, and the Other Lenders Party Thereto (Incorporated by reference to Exhibit 10.1 to TVA’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, File No. 000-52313)
10.2*	Amendment Dated as of November 9, 2009, to Fall Maturity Credit Agreement Dated as of March 26, 2009, Among TVA, Bank of America, N.A., as Administrative Agent, Bank of America, N.A., as a Lender, and the Other Lenders Party Thereto (Incorporated by reference to Exhibit 99.1 to TVA’s Current Report on Form 8-K filed on November 13, 2009, File No. 000-52313)
10.3	Second Amendment Dated as of October 7, 2010, to Fall Maturity Credit Agreement Dated as of March 26, 2009, and Amended as of November 9, 2009, Among TVA, Bank of America, N.A., as Administrative Agent, Bank of America, N.A., as a Lender, and the Other Lenders Party Thereto (Incorporated by reference to Exhibit 99.1 to TVA’s Current Report on Form 8-K filed on October 12, 2010, File No. 000-52313)
10.4	Spring Maturity Credit Agreement Dated as of July 22, 2010, Among TVA, Bank of America, N.A., as Administrative Agent and Letter of Credit Issuer, Bank of America, N.A., as a Lender, and the Other Lenders Party Thereto (Incorporated by reference to Exhibit 10.5  to TVA’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, File No. 000-52313)
10.5	TVA Discount Notes Selling Group Agreement (Incorporated by reference to Exhibit 10.2 to TVA’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, File No. 000-52313)
10.6	Electronotes® Selling Agent Agreement Dated as of June 1, 2006, Among TVA, LaSalle Financial Services, Inc., A.G. Edwards & Sons, Inc., Citigroup Global Markets Inc., Edward D. Jones & Co., L.P., First Tennessee Bank National Association, J.J.B. Hilliard, W.L. Lyons, Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Morgan Stanley & Co. Incorporated, and Wachovia Securities, LLC (Incorporated by reference to Exhibit 10.4 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
10.7	Assumption Agreement Between TVA and Incapital LLC Dated as of February 29, 2008, Relating to the electronotes® Selling Agent Agreement Dated as of June 1, 2006, Among TVA, LaSalle Financial Services, Inc., A.G. Edwards & Sons, Inc., Citigroup Global Markets Inc., Edward D. Jones & Co., L.P., First Tennessee Bank National Association, J.J.B. Hilliard, W.L. Lyons, Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Morgan Stanley & Co. Incorporated, and Wachovia Securities, LLC (Incorporated by reference to Exhibit 10.1 to TVA’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, File No. 000-52313)
10.8	Commitment Agreement Among Memphis Light, Gas and Water Division, the City of Memphis, Tennessee, and TVA Dated as of November 19, 2003 (Incorporated by reference to Exhibit 10.5 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
10.9	Power Contract Supplement No. 95 Among Memphis Light, Gas and Water Division, the City of Memphis, Tennessee, and TVA Dated as of November 19, 2003 (Incorporated by reference to Exhibit 10.6 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
10.10	Void Walk Away Agreement Among Memphis Light, Gas and Water Division, the City of Memphis, Tennessee, and TVA Dated as of November 20, 2003 (Incorporated by reference to Exhibit 10.7 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
10.11	Power Contract Supplement No. 96 Among Memphis Light, Gas and Water Division, the City of Memphis, Tennessee, and TVA Dated as of November 20, 2003 (Incorporated by reference to Exhibit 10.8 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
10.12*	Joint Ownership Agreement Dated as of April 30, 2008, Between Seven States Power Corporation and TVA (Incorporated by reference to Exhibit 10.3 to TVA’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, File No. 000-52313)

171

10.13	Supplement No. 1 Dated as of September 2, 2008, to the Joint Ownership Agreement Dated as of April 30, 2008, Between Seven States Power Corporation and TVA (Incorporated by reference to Exhibit 10.16 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2008, File No. 000-52313)
10.14	Supplement No. 2 Dated as of September 30, 2008, to the Joint Ownership Agreement Dated as of April 30, 2008, Between Seven States Power Corporation and TVA (Incorporated by reference to Exhibit 10.17 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2008, File No. 000-52313)
10.15	Supplement No. 3 Dated as of April 17, 2009, to the Joint Ownership Agreement Dated as of April 30, 2008, Between Seven States Power Corporation and TVA  (Incorporated by reference to Exhibit 10.15 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2009, File No. 000-52313).
10.16	Supplement No. 4 Dated as of April 22, 2010, to the Joint Ownership Agreement Dated as of April 30, 2008, Between Seven States Power Corporation and TVA (Incorporated by reference to Exhibit 10.2 to TVA’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, File No. 000-52313)
10.17	Lease Agreement Dated as of September 30, 2008, Between TVA and Seven States Southaven, LLC (Incorporated by reference to Exhibit 10.18 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2008, File No. 000-52313)
10.18	First Amendment Dated as of April 17, 2009, to Lease Agreement Dated September 30, 2008, Between TVA and Seven States Southaven, LLC (Incorporated by reference to Exhibit 10.17 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2009, File No. 000-52313)
10.19	Second Amendment Dated as of April 22, 2010, to Lease Agreement Dated September 30, 2008, Between TVA and Seven States Southaven, LLC (Incorporated by reference to Exhibit 10.3 to TVA’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, File No. 000-52313)
10.20	Amended and Restated Buy-Back Arrangements Dated as of April 22, 2010, Among TVA, JPMorgan Chase Bank, National Association, as Administrative Agent and a Lender, and the Other Lenders Referred to Therein (Incorporated by reference to Exhibit 10.4 to TVA’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, File No. 000-52313)
10.21	Overview of TVA’s September 26, 2003, Lease and Leaseback of Control, Monitoring, and Data Analysis Network with Respect to TVA’s Transmission System in Tennessee, Kentucky, Georgia, and Mississippi (Incorporated by reference to Exhibit 10.9 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
10.22*	Participation Agreement Dated as of September 22, 2003, Among (1) TVA, (2) NVG Network I Statutory Trust, (3) Wells Fargo Delaware Trust Company, Not in Its Individual Capacity, Except to the Extent Expressly Provided in the Participation Agreement, But as Owner Trustee, (4) Wachovia Mortgage Corporation, (5) Wilmington Trust Company, Not in Its Individual Capacity, Except to the Extent Expressly Provided in the Participation Agreement, But as Lease Indenture Trustee, and (6) Wilmington Trust Company, Not in Its Individual Capacity, Except to the Extent Expressly Provided in the Participation Agreement, But as Pass Through Trustee (Incorporated by reference to Exhibit 10.10 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
10.23*	Network Lease Agreement Dated as of September 26, 2003, Between NVG Network I Statutory Trust, as Owner Lessor, and TVA, as Lessee (Incorporated by reference to Exhibit 10.11 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
10.24*	Head Lease Agreement Dated as of September 26, 2003, Between TVA, as Head Lessor, and NVG Network I Statutory Trust, as Head Lessee (Incorporated by reference to Exhibit 10.12 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
10.25*	Leasehold Security Agreement Dated as of September 26, 2003, Made by NVG Network I Statutory Trust to TVA (Incorporated by reference to Exhibit 10.13 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
10.26†	TVA Compensation Plan Approved by the TVA Board on May 31, 2007 (Incorporated by reference to Exhibit 99.3 to TVA’s Current Report on Form 8-K filed on December 11, 2007, File No. 000-52313)
10.27†	TVA Vehicle Allowance Guidelines, Effective April 1, 2006 (Incorporated by reference to Exhibit 10.18 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2007, File No. 000-52313)
10.28†	Supplemental Executive Retirement Plan (Incorporated by reference to Exhibit 10.1 to TVA’s Current Report on Form 8-K filed on January 6, 2009, File No. 000-52313)
10.29†	Executive Annual Incentive Plan (Incorporated by reference to Exhibit 10.3 to TVA’s Current Report on Form 8-K filed on January 6, 2009, File No. 000-52313)
10.30†	Executive Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.4 to TVA’s Current Report on Form 8-K filed on January 6, 2009, File No. 000-52313)

172

10.31†	Long - Term Deferred Compensation Plan (Incorporated by reference to Exhibit 10.5 to TVA’s Current Report on Form 8-K filed on January 6, 2009, File No. 000-52313)
10.32†	Deferred Compensation Plan (Incorporated by reference to Exhibit 10.2 to TVA’s Current Report on Form 8-K filed on January 6, 2009, File No. 000-52313)
10.33†	Overview of Financial Counseling Services Program (Incorporated by reference to Exhibit 10.31 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2009, File No. 000-52313)
10.34†	Offer Letter to Tom Kilgore Accepted as of January 19, 2005 (Incorporated by reference to Exhibit 10.19 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
10.35†	Offer Letter to William R. McCollum, Jr., Accepted as of March 9, 2007 (Incorporated by reference to Exhibit 10.26 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2007, File No. 000-52313)
10.36†	Offer Letter to Kimberly S. Greene Accepted as of August 3, 2007 (Incorporated by reference to Exhibit 10.27 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2007, File No. 000-52313)
10.37†	First Deferral Agreement Between TVA and Tom Kilgore Dated as of March 29, 2005 (Incorporated by reference to Exhibit 10.24 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
10.38†	Second Deferral Agreement  Between TVA and Tom Kilgore Dated as of November 24, 2009  (Incorporated by reference to Exhibit 10.39 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2009, File No. 000-52313)
10.39†	Deferral Agreement Between TVA and John M. Thomas, III, Dated as of December 4, 2009  (Incorporated by reference to Exhibit 10.7 to TVA’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, File No. 000-52313)
10.40†	Second Deferral Agreement Between TVA and John M. Thomas, III, Dated as of September 27, 2010
10.41†	Deferral Agreement Between TVA and Ashok S. Bhatnagar Dated as of September 28, 2004 (Incorporated by reference to Exhibit 10.21 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
10.42†	Second Deferral Agreement Between TVA and Ashok S. Bhatnagar Dated as of January 27, 2010 (Incorporated by reference to Exhibit 10.1 to TVA’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 000-52313)
10.43†	Deferral Agreement Between TVA and William R. McCollum, Jr., Dated as of May 3, 2007 (Incorporated by reference to Exhibit 10.33 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2007, File No. 000-52313)
10.44†	First Deferral Agreement Between TVA and Kimberly S. Greene Dated as of September 4, 2007 (Incorporated by reference to Exhibit 10.34 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2007, File No. 000-52313)
10.45†	Second Deferral Agreement Between TVA and Kimberly S. Greene Dated as of December 20, 2008 (Incorporated by reference to Exhibit 10.43 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2009, File No. 000-52313)
10.46†	Deferral Agreement Between TVA and Preston D. Swafford Dated as of May 10, 2006 (Incorporated by reference to Exhibit 10.44 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2009, File No. 000-52313)
10.47†	Deferral Agreement Between TVA and John M. Hoskins Dated as of October 30, 2006 (Incorporated by reference to Exhibit 10.35 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2007, File No. 000-52313)
10.48†	Second Deferral Agreement Between TVA and John M. Hoskins Dated as of January 27, 2010
14	Disclosure and Financial Ethics Code (Incorporated by reference to Exhibit 14 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
31.1	Rule 13a-14(a)/15d-14(a) Certification Executed by the Chief Executive Officer
31.2	Rule 13a-14(a)/15d-14(a) Certification Executed by the Chief Financial Officer
32.1	Section 1350 Certification Executed by the Chief Executive Officer

173

32.2	Section 1350 Certification Executed by the Chief Financial Officer
† Management contract or compensatory arrangement. * Certain schedule(s) and/or exhibit(s) have been omitted.  The Tennessee Valley Authority hereby undertakes to furnish supplementally copies of any of the omitted schedules and/or exhibits upon request by the Securities and Exchange Commission.

174

SIGNATURES

Pursuant to the requirements of Section 13, 15(d), or 37 of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date:  November 19, 2010		TENNESSEE VALLEY AUTHORITY
		(Registrant)
	By:	/s/ Tom Kilgore
		Tom  Kilgore
		President and Chief Executive Officer

175

SIGNATURES

   Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Tom Kilgore	President and Chief Executive Officer	November 19, 2010
Tom  Kilgore	(Principal Executive Officer)
/s/ John M. Thomas, III	Chief Financial Officer	November 19, 2010
John M. Thomas, III	(Principal Financial Officer)
/s/ Steve Byone	Vice President, Controller, and Chief Risk Officer	November 19, 2010
Steve Byone	(Principal Accounting Officer)
/s/ Dennis C. Bottorff	Chairman and Director	November 19, 2010
Dennis C. Bottorff
/s/ Marilyn A. Brown	Director	November 19, 2010
Marilyn A. Brown
/s/ Robert M. Duncan	Director	November 19, 2010
Robert M. Duncan
/s/ Thomas C. Gilliland	Director	November 19, 2010
Thomas C. Gilliland
/s/ Bishop William H. Graves	Director	November 19, 2010
Bishop William H. Graves
/s/ Barbara S. Haskew	Director	November 19, 2010
Barbara S. Haskew
/s/ Neil G. McBride	Director	November 19, 2010
Neil G. McBride
/s/ William B. Sansom	Director	November 19, 2010
William B. Sansom
/s/ Howard A. Thrailkill	Director	November 19, 2010
Howard A. Thrailkill

176

EXHIBIT INDEX

Exhibit  No.	Description
3.1	Tennessee Valley Authority Act of 1933, as amended , 16 U.S.C. §§ 831-831ee (Incorporated by reference to Exhibit 3.1 to TVA’s Quarterly Report on Form 10-Q for the quarter ended December 31, 2007, File No. 000-52313)
3.2	Bylaws of Tennessee Valley Authority, as Amended (Incorporated by reference to Exhibit 3.1 to TVA’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, File No. 000-52313)
4.1	Basic Tennessee Valley Authority Power Bond Resolution Adopted by the TVA Board of Directors on October 6, 1960, as Amended on September 28, 1976, October 17, 1989, and March 25, 1992 (Incorporated by reference to Exhibit 4.1 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
10.1*	Fall Maturity Credit Agreement Dated as of March 26, 2009, Among TVA, Bank of America, N.A., as Administrative Agent, Bank of America, N.A., as a Lender, and the Other Lenders Party Thereto (Incorporated by reference to Exhibit 10.1 to TVA’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, File No. 000-52313)
10.2*	Amendment Dated as of November 9, 2009, to Fall Maturity Credit Agreement Dated as of March 26, 2009, Among TVA, Bank of America, N.A., as Administrative Agent, Bank of America, N.A., as a Lender, and the Other Lenders Party Thereto (Incorporated by reference to Exhibit 99.1 to TVA’s Current Report on Form 8-K filed on November 13, 2009, File No. 000-52313)
10.3	Second Amendment Dated as of October 7, 2010, to Fall Maturity Credit Agreement Dated as of March 26, 2009, and Amended as of November 9, 2009, Among TVA, Bank of America, N.A., as Administrative Agent, Bank of America, N.A., as a Lender, and the Other Lenders Party Thereto (Incorporated by reference to Exhibit 99.1 to TVA’s Current Report on Form 8-K filed on October 12, 2010, File No. 000-52313)
10.4	Spring Maturity Credit Agreement Dated as of July 22, 2010, Among TVA, Bank of America, N.A., as Administrative Agent and Letter of Credit Issuer, Bank of America, N.A., as a Lender, and the Other Lenders Party Thereto (Incorporated by reference to Exhibit 10.5  to TVA’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, File No. 000-52313)
10.5	TVA Discount Notes Selling Group Agreement (Incorporated by reference to Exhibit 10.2 to TVA’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, File No. 000-52313)
10.6	Electronotes® Selling Agent Agreement Dated as of June 1, 2006, Among TVA, LaSalle Financial Services, Inc., A.G. Edwards & Sons, Inc., Citigroup Global Markets Inc., Edward D. Jones & Co., L.P., First Tennessee Bank National Association, J.J.B. Hilliard, W.L. Lyons, Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Morgan Stanley & Co. Incorporated, and Wachovia Securities, LLC (Incorporated by reference to Exhibit 10.4 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
10.7	Assumption Agreement Between TVA and Incapital LLC Dated as of February 29, 2008, Relating to the electronotes® Selling Agent Agreement Dated as of June 1, 2006, Among TVA, LaSalle Financial Services, Inc., A.G. Edwards & Sons, Inc., Citigroup Global Markets Inc., Edward D. Jones & Co., L.P., First Tennessee Bank National Association, J.J.B. Hilliard, W.L. Lyons, Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Morgan Stanley & Co. Incorporated, and Wachovia Securities, LLC (Incorporated by reference to Exhibit 10.1 to TVA’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, File No. 000-52313)
10.8	Commitment Agreement Among Memphis Light, Gas and Water Division, the City of Memphis, Tennessee, and TVA Dated as of November 19, 2003 (Incorporated by reference to Exhibit 10.5 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
10.9	Power Contract Supplement No. 95 Among Memphis Light, Gas and Water Division, the City of Memphis, Tennessee, and TVA Dated as of November 19, 2003 (Incorporated by reference to Exhibit 10.6 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
10.10	Void Walk Away Agreement Among Memphis Light, Gas and Water Division, the City of Memphis, Tennessee, and TVA Dated as of November 20, 2003 (Incorporated by reference to Exhibit 10.7 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
10.11	Power Contract Supplement No. 96 Among Memphis Light, Gas and Water Division, the City of Memphis, Tennessee, and TVA Dated as of November 20, 2003 (Incorporated by reference to Exhibit 10.8 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
10.12*	Joint Ownership Agreement Dated as of April 30, 2008, Between Seven States Power Corporation and TVA (Incorporated by reference to Exhibit 10.3 to TVA’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, File No. 000-52313)

177

10.13	Supplement No. 1 Dated as of September 2, 2008, to the Joint Ownership Agreement Dated as of April 30, 2008, Between Seven States Power Corporation and TVA (Incorporated by reference to Exhibit 10.16 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2008, File No. 000-52313)
10.14	Supplement No. 2 Dated as of September 30, 2008, to the Joint Ownership Agreement Dated as of April 30, 2008, Between Seven States Power Corporation and TVA (Incorporated by reference to Exhibit 10.17 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2008, File No. 000-52313)
10.15	Supplement No. 3 Dated as of April 17, 2009, to the Joint Ownership Agreement Dated as of April 30, 2008, Between Seven States Power Corporation and TVA  (Incorporated by reference to Exhibit 10.15 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2009, File No. 000-52313).
10.16	Supplement No. 4 Dated as of April 22, 2010, to the Joint Ownership Agreement Dated as of April 30, 2008, Between Seven States Power Corporation and TVA (Incorporated by reference to Exhibit 10.2 to TVA’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, File No. 000-52313)
10.17	Lease Agreement Dated as of September 30, 2008, Between TVA and Seven States Southaven, LLC (Incorporated by reference to Exhibit 10.18 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2008, File No. 000-52313)
10.18	First Amendment Dated as of April 17, 2009, to Lease Agreement Dated September 30, 2008, Between TVA and Seven States Southaven, LLC (Incorporated by reference to Exhibit 10.17 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2009, File No. 000-52313)
10.19	Second Amendment Dated as of April 22, 2010, to Lease Agreement Dated September 30, 2008, Between TVA and Seven States Southaven, LLC (Incorporated by reference to Exhibit 10.3 to TVA’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, File No. 000-52313)
10.20	Amended and Restated Buy-Back Arrangements Dated as of April 22, 2010, Among TVA, JPMorgan Chase Bank, National Association, as Administrative Agent and a Lender, and the Other Lenders Referred to Therein (Incorporated by reference to Exhibit 10.4 to TVA’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, File No. 000-52313)
10.21	Overview of TVA’s September 26, 2003, Lease and Leaseback of Control, Monitoring, and Data Analysis Network with Respect to TVA’s Transmission System in Tennessee, Kentucky, Georgia, and Mississippi (Incorporated by reference to Exhibit 10.9 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
10.22*	Participation Agreement Dated as of September 22, 2003, Among (1) TVA, (2) NVG Network I Statutory Trust, (3) Wells Fargo Delaware Trust Company, Not in Its Individual Capacity, Except to the Extent Expressly Provided in the Participation Agreement, But as Owner Trustee, (4) Wachovia Mortgage Corporation, (5) Wilmington Trust Company, Not in Its Individual Capacity, Except to the Extent Expressly Provided in the Participation Agreement, But as Lease Indenture Trustee, and (6) Wilmington Trust Company, Not in Its Individual Capacity, Except to the Extent Expressly Provided in the Participation Agreement, But as Pass Through Trustee (Incorporated by reference to Exhibit 10.10 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
10.23*	Network Lease Agreement Dated as of September 26, 2003, Between NVG Network I Statutory Trust, as Owner Lessor, and TVA, as Lessee (Incorporated by reference to Exhibit 10.11 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
10.24*	Head Lease Agreement Dated as of September 26, 2003, Between TVA, as Head Lessor, and NVG Network I Statutory Trust, as Head Lessee (Incorporated by reference to Exhibit 10.12 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
10.25*	Leasehold Security Agreement Dated as of September 26, 2003, Made by NVG Network I Statutory Trust to TVA (Incorporated by reference to Exhibit 10.13 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
10.26†	TVA Compensation Plan Approved by the TVA Board on May 31, 2007 (Incorporated by reference to Exhibit 99.3 to TVA’s Current Report on Form 8-K filed on December 11, 2007, File No. 000-52313)
10.27†	TVA Vehicle Allowance Guidelines, Effective April 1, 2006 (Incorporated by reference to Exhibit 10.18 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2007, File No. 000-52313)
10.28†	Supplemental Executive Retirement Plan (Incorporated by reference to Exhibit 10.1 to TVA’s Current Report on Form 8-K filed on January 6, 2009, File No. 000-52313)
10.29†	Executive Annual Incentive Plan (Incorporated by reference to Exhibit 10.3 to TVA’s Current Report on Form 8-K filed on January 6, 2009, File No. 000-52313)
10.30†	Executive Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.4 to TVA’s Current Report on Form 8-K filed on January 6, 2009, File No. 000-52313)

178

10.31†	Long - Term Deferred Compensation Plan (Incorporated by reference to Exhibit 10.5 to TVA’s Current Report on Form 8-K filed on January 6, 2009, File No. 000-52313)
10.32†	Deferred Compensation Plan (Incorporated by reference to Exhibit 10.2 to TVA’s Current Report on Form 8-K filed on January 6, 2009, File No. 000-52313)
10.33†	Overview of Financial Counseling Services Program (Incorporated by reference to Exhibit 10.31 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2009, File No. 000-52313)
10.34†	Offer Letter to Tom Kilgore Accepted as of January 19, 2005 (Incorporated by reference to Exhibit 10.19 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
10.35†	Offer Letter to William R. McCollum, Jr., Accepted as of March 9, 2007 (Incorporated by reference to Exhibit 10.26 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2007, File No. 000-52313)
10.36†	Offer Letter to Kimberly S. Greene Accepted as of August 3, 2007 (Incorporated by reference to Exhibit 10.27 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2007, File No. 000-52313)
10.37†	First Deferral Agreement Between TVA and Tom Kilgore Dated as of March 29, 2005 (Incorporated by reference to Exhibit 10.24 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
10.38†	Second Deferral Agreement  Between TVA and Tom Kilgore Dated as of November 24, 2009  (Incorporated by reference to Exhibit 10.39 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2009, File No. 000-52313)
10.39†	Deferral Agreement Between TVA and John M. Thomas, III, Dated as of December 4, 2009  (Incorporated by reference to Exhibit 10.7 to TVA’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, File No. 000-52313)
10.40†	Second Deferral Agreement Between TVA and John M. Thomas, III, Dated as of September 27, 2010
10.41†	Deferral Agreement Between TVA and Ashok S. Bhatnagar Dated as of September 28, 2004 (Incorporated by reference to Exhibit 10.21 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
10.42†	Second Deferral Agreement Between TVA and Ashok S. Bhatnagar Dated as of January 27, 2010 (Incorporated by reference to Exhibit 10.1 to TVA’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 000-52313)
10.43†	Deferral Agreement Between TVA and William R. McCollum, Jr., Dated as of May 3, 2007 (Incorporated by reference to Exhibit 10.33 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2007, File No. 000-52313)
10.44†	First Deferral Agreement Between TVA and Kimberly S. Greene Dated as of September 4, 2007 (Incorporated by reference to Exhibit 10.34 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2007, File No. 000-52313)
10.45†	Second Deferral Agreement Between TVA and Kimberly S. Greene Dated as of December 20, 2008 (Incorporated by reference to Exhibit 10.43 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2009, File No. 000-52313)
10.46†	Deferral Agreement Between TVA and Preston D. Swafford Dated as of May 10, 2006 (Incorporated by reference to Exhibit 10.44 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2009, File No. 000-52313)
10.47†	Deferral Agreement Between TVA and John M. Hoskins Dated as of October 30, 2006 (Incorporated by reference to Exhibit 10.35 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2007, File No. 000-52313)
10.48†	Second Deferral Agreement Between TVA and John M. Hoskins Dated as of January 27, 2010
14	Disclosure and Financial Ethics Code (Incorporated by reference to Exhibit 14 to TVA’s Annual Report on Form 10-K for the year ended September 30, 2006, File No. 000-52313)
31.1	Rule 13a-14(a)/15d-14(a) Certification Executed by the Chief Executive Officer
31.2	Rule 13a-14(a)/15d-14(a) Certification Executed by the Chief Financial Officer
32.1	Section 1350 Certification Executed by the Chief Executive Officer

179

32.2	Section 1350 Certification Executed by the Chief Financial Officer
† Management contract or compensatory arrangement. * Certain schedule(s) and/or exhibit(s) have been omitted.  The Tennessee Valley Authority hereby undertakes to furnish supplementally copies of any of the omitted schedules and/or exhibits upon request by the Securities and Exchange Commission.

180