TENNESSEE VALLEY AUTHORITY

TENNESSEE VALLEY AUTHORITY - FORM 10-K/A

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

AMENDMENT NO. 1

(MARK ONE)


þ		ANNUAL REPORT PURSUANT TO SECTION 13, 15(d), OR 37 OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended September 30, 2006


o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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		62-0474417
an act of Congress		(I.R.S. Employer Identification No.)
(State or other jurisdiction of incorporation or organization)

400 W. Summit Hill Drive		37902
Knoxville, Tennessee		(Zip Code)
(Address of principal executive offices)

(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 whether the registrant is a well-known, seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes o No þ

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 Exchange Act. Yes o No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) 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 o No þ

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. þ

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

Large accelerated filer o Accelerated filer o Non-accelerated filer þ

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

Explanatory Note

This Amendment No. 1 to the Annual Report on Form 10-K/A for the fiscal year ended September 30, 2006, is being filed for the purpose of making the following changes:

	•		Revising Item 1, Business — Regulation — Securities and Exchange Commission to address the exemption of TVA securities from certain securities laws.

	•		Revising Item 1, Business — Regulation — Federal Energy Regulatory Commission to expand the discussion of the Federal Energy Regulatory Commission’s regulation of TVA’s activities.

	•		Revising Item 1A, Risk Factors to disclose the risks posed by purchased power volatility and provider unreliability, as well as certain risks related to TVA securities.

	•		Removing all references to non-GAAP financial measures.

	•		Revising Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations to provide more detail on TVA’s outstanding debt securities and its obligations to the U.S. Treasury.

	•		Revising Note 1 in Item 8, Financial Statements and Supplementary Data to explain why TVA accounts for allowance for funds used during construction as a component of cash investing activities.

	•		Revising Item 3, Legal Proceedings and Note 13 — Legal Proceedings to clarify how the amounts of the claims set forth in those sections relate to the legal proceedings.

	•		Revising Item 9A, Controls and Procedures to clarify the evaluations of and changes to TVA’s internal controls.

	•		Replacing the “Audit Committee” and “Other Committees” disclosures in Item 10, Directors, Executive Officers and Corporate Governance, with a disclosure entitled “Committees of the TVA Board.”

	•		Revising Item 11, Executive Compensation and Item 13, Certain Relationships and Related Transactions, and Director Independence to early adopt the new executive compensation disclosure rules contained in Item 402 of Regulation S-K, the related party disclosure rules of Item 404 of Regulation S-K, and the director independence disclosure rules of Item 407(a) of Regulation S-K.

Additionally, TVA has corrected certain immaterial errors.

For the convenience of the reader, TVA is refiling its entire Annual Report via this Form 10-K/A. However, the only changes to the original Form 10-K being made by this Form 10-K/A are the changes described above. Unless specifically noted herein, this Form 10-K/A does not reflect events occurring after December 15, 2006, the date the original Form 10-K was filed. Any information not affected by the amendment is unchanged and reflects the disclosures made at the time the original Form 10-K was filed.

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Table of Contents


Explanatory Note			2
Forward-Looking Information			5
General Information			6

Part I
Item 1. Business			7
The Corporation			7
Governance			7
Service Area			7
Customers			9
Rate Authority			11
Rate Actions			12
Power and Energy Forecasts			12
Power Supply			12
Nuclear			16
Fuel Supply			17
Transmission Operations			19
Stewardship Activities			20
Seasonality			20
Competition			21
Regulation			22
Payments in Lieu of Taxes			24
Environmental Matters			24
Employee Relations			28
Item 1A. Risk Factors			28
Strategic Risks			28
Operational Risks			30
Financial Risks			32
Risks Related to TVA Securities			35
Item 1B. Unresolved Staff Comments			35
Item 2. Properties			35
Generating Properties			35
Transmission Properties			36
Resource Stewardship Properties			36
Buildings			36
Disposal of Property			36
Item 3. Legal Proceedings			37
Item 4. Submission of Matters to a Vote of Security Holders			39

Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			40
Item 6. Selected Financial Data			40
Statements of Income Data			40
Balance Sheets Data			41
Financial Obligations			41
Comparative Five-Year Data Statistical and Financial Summaries			42
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			43
Business Overview			43
Liquidity and Capital Resources			46
Results of Operations			54
Off-Balance Sheet Arrangements			59
Critical Accounting Policies and Estimates			60
New Accounting Standards and Interpretations			64
Legislative and Regulatory Matters			67
Environmental Matters			68

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Legal Proceedings			71
Risk Management Activities			71
Management Changes			77
Subsequent Events			77
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			77
Item 8. Financial Statements and Supplementary Data			78
Statements of Income			78
Balance Sheets			79
Statements of Cash Flows			80
Statements of Changes in Proprietary Capital			81
Notes to Financial Statements			82
Report of Independent Registered Public Accounting Firm			122
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure			123
Item 9A. Controls and Procedures			123
Item 9B. Other Information			124

Part III
Item 10. Directors, Executive Officers and Corporate Governance			125
Directors			125
Executive Officers			126
Code of Ethics			129
Committees of the TVA Board			129
Item 11. Executive Compensation			130
Compensation Discussion and Analysis			130
Executive Compensation Tables and Narrative Disclosures			135
Other Agreements			142
Director Compensation			142
Compensation Committee Interlocks and Insider Participation			144
Compensation Committee Report			144
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			145
Item 13. Certain Relationships and Related Transactions, and Director Independence			145
Director Independence			145
Related Party Transactions			145
Item 14. Principal Accountant Fees and Services			147

Part IV
Item 15. Exhibits and Financial Statement Schedules			148

Signature			151
Exhibit Index			152
EX-31.1 SECTION 302 CERTIFICATION OF THE CEO
EX-31.2 SECTION 302 CERTIFICATION OF THE CFO
EX-32.1 SECTION 906 CERTIFICATION OF THE CEO
EX-32.2 SECTION 906 CERTIFICATION OF THE CFO

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FORWARD-LOOKING INFORMATION

This Annual Report on Form 10-K (“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.

Examples of forward-looking statements include, but are not limited to:

	•		Statements regarding strategic objectives;

	•		Projections regarding potential rate actions;

	•		Estimates of costs of certain retirement obligations;

	•		Estimates regarding power and energy forecasts;

	•		Expectations about the adequacy of TVA’s pension plans and nuclear decommissioning trust;

	•		Estimates regarding the reduction of bonds, notes, and other evidences of indebtedness, lease/leaseback commitments, and power prepayment obligations;

	•		The impact of new accounting pronouncements and interpretations, including Statement of Financial Accounting Standards No. 158, “Employers Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106, and 132(R);”

	•		Estimates of amounts to be reclassified from Other Comprehensive Income to earnings over the next year;

	•		TVA’s plans to continue using short-term debt to meet current obligations; and

	•		The anticipated cost and timetable for returning Browns Ferry Unit 1 to service.

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 laws, regulations, and administrative orders, especially those related to:

	—		TVA’s protected service area,

	—		The sole authority of the TVA Board to set power rates,

	—		Various environmental and nuclear matters,

	—		TVA’s management of the Tennessee River system,

	—		TVA’s credit rating, and

	—		TVA’s debt ceiling;

	•		Performance of TVA’s generation and transmission assets;

	•		Availability of fuel supplies;

	•		Purchased power price volatility and provider unreliability;

	•		Compliance with existing environmental laws and regulations;

	•		Significant delays or cost overruns in construction of generation and transmission assets;

	•		Significant changes in demand for electricity;

	•		Legal and administrative proceedings;

	•		Weather conditions;

	•		Failure of transmission facilities;

	•		An accident at any nuclear facility, even one unaffiliated with TVA;

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

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

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

	•		Changes in interest rates;

	•		Creditworthiness of TVA or its counterparties;

	•		Rising pension costs and health care expenses;

	•		Increases in TVA’s financial liability for decommissioning its nuclear facilities;

	•		Limitations on TVA’s ability to borrow money;

	•		Changes in economic environments;

	•		Ineffectiveness of TVA’s disclosure controls and procedures;

	•		Changes in accounting standards;

	•		The loss of TVA’s ability to use regulatory accounting;

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	•		Loss of key personnel;

	•		Changes in technology; and

	•		Unforeseeable events.

Additionally, other risks that may cause actual results to differ from the predicted results are set forth in Item 1A, Risk Factors. 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 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

Unless otherwise indicated, years (2006, 2005, etc.) in this Annual Report refer to TVA’s fiscal years ended September 30. References to years in the biographical information about directors and executive officers in Item 10, Directors, Executive Officers and Corporate Governance are to calendar years.

Notes

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

Available Information

The public may read and copy any reports or other information that TVA files with the Securities and Exchange Commission (“SEC”) at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. TVA’s SEC reports are also available to the public without charge from the website maintained by the SEC at www.sec.gov and 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.

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PART I

ITEM 1. BUSINESS

The Corporation

The Tennessee Valley Authority (“TVA”) is a wholly-owned corporate agency and instrumentality of the United States. TVA was created by the U.S. Congress in 1933 by virtue of the Tennessee Valley Authority Act of 1933, as amended, 16 U.S.C. §§ 831-831ee (2000 & Supp. IV 2004) (as amended, the “TVA Act”). TVA was created to improve navigation on the Tennessee River, reduce flood damage, provide agricultural and industrial development, and provide electric power to the Tennessee Valley region. TVA manages the Tennessee River and its tributaries for multiple river-system purposes, such as navigation; flood damage reduction; power generation; environmental stewardship; shoreline use; and water supply for power plant operations, consumer use, recreation, industry, and other stewardship purposes. TVA’s power system operations, however, constitute the majority of its activities and provide virtually all of its revenues.

Although TVA is similar to power companies in many ways, there are many features that make it different. Some of these include:

	•		TVA was created by an act of the U.S. Congress and is a wholly-owned corporate agency of the United States.

	•		TVA’s board of directors (the “TVA Board”) is appointed by the President with the advice and consent of the U.S. Senate.

	•		TVA holds its real properties as an agent for the United States.

	•		TVA is required to make payments to the U.S. Treasury as a repayment of and a return on the appropriation investment that the United States provided TVA for its power program (the “Appropriation Investment”).

	•		TVA is not authorized to issue equity securities such as common or preferred stock. Accordingly, TVA finances its operations primarily with cash flows from operations and proceeds from issuing debt.

	•		The TVA Board sets the rates TVA charges for power. In setting rates, the TVA Board must have due regard for the objective that power be sold at rates as low as are feasible.

	•		TVA is exempt from paying federal income taxes and state and local taxes but must pay certain states and counties an amount in lieu of taxes equal to five percent of TVA’s gross revenues from the sale of power during the preceding year excluding sales or deliveries to other federal agencies and exchange sales with other utilities, with a provision for minimum payments under certain circumstances.

For a discussion of the more significant of these features, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations — Business Overview.

Governance

TVA is governed by the TVA Board. The Consolidated Appropriations Act, 2005, amended the TVA Act by restructuring the TVA Board from three full-time members to nine part-time members, at least seven of whom must be legal residents of the TVA service area. TVA Board members are appointed by the President of the United Stated with the advice and consent of the U.S. Senate. After an initial phase-in period, TVA Board members serve five-year terms, and at least one member’s term ends each year. The TVA Board’s role, among other things, is to establish broad goals, objectives, and policies for TVA; establish long-range plans to carry out these goals, objectives, and policies; approve annual budgets; and establish 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.

Service Area

TVA operates the nation’s largest public power system. TVA 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 approximately 8.7 million people.

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Subject to certain minor exceptions, TVA may not, without specific authorization by act of the U.S. Congress, enter into contracts which 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 statutory 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.

Correspondingly, the Federal Power Act (“FPA”), primarily through its 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 delivering power to customers within its defined service area. The anti-cherrypicking provision helps to minimize the financial exposure of TVA to loss of revenue.

Sales of electricity accounted for substantially all of TVA’s operating revenues in 2006, 2005, and 2004, amounting to $9.1 billion, $7.7 billion, and $7.4 billion, respectively. TVA’s revenues by state for the last three years are detailed in the table below:

Electricity Sales by State
(in millions)


	2006		2005		2004

Alabama	$	1,268	$	1,054	$	1,033
Georgia		228		186		182
Kentucky		909		832		731
Mississippi		826		674		658
North Carolina		47		39		38
Tennessee		5,764		4,820		4,734
Virginia		7		4		4

		9,049		7,609		7,380
Sale for resale		13		95		59

	$	9,062	$	7,704	$	7,439

TVA SERVICE AREA

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Customers

TVA is primarily a wholesaler of power. TVA sells power at wholesale to distributor customers, consisting of municipalities and cooperatives, that resell the power to their customers at a retail rate. TVA also sells power (1) to directly served customers, consisting primarily of federal agencies and customers with large or unusual loads, and (2) to exchange power customers (electric systems that border TVA’s service area) with which TVA has entered into exchange power arrangements as allowed by the TVA Act.

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

Operating Revenues by Customer Type
(in millions)


	2006		2005		2004

Municipalities and cooperatives	$	7,880	$	6,561	$	6,457
Industries directly served		1,066		962		842
Federal agencies and other
Federal agencies directly served		103		86		81
Exchange sales		13		95		59

Total	$	9,062	$	7,704	$	7,439

Municipalities and Cooperatives

Revenues from distributor customers accounted for 85.8 percent of TVA’s total operating revenues in 2006. At September 30, 2006, TVA had wholesale power contracts with 158 municipalities and cooperatives. All of these contracts require distributor customers to purchase all of their electric power and energy requirements from TVA.

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 2006, and the percentage of TVA’s 2006 total operating revenues represented by these revenues are summarized in the table below.

TVA Distributor Customer Contracts
As of September 30, 2006


	Number of				Percentage of Total
	Distributor		Sales to Distributor		Operating Revenues in
Contract Arrangement	Customers		Customers in 2006		2006
			(in millions)
15-Year Termination Notice		5	$	92		1.0	%
10-Year Termination Notice		48		2,625		28.6	%
5-Year Termination Notice *		99		4,893		53.3	%
Notice Given — Less than 5
Years Remaining*		6		270		2.9	%

		158	$	7,880		85.8	%


*		Ordinarily the distributor customer and TVA have the same termination notice period; however, in contracts with six of the distributor customers with a five-year termination notice, TVA has a 10-year termination notice (which becomes a five-year termination notice if TVA loses its discretionary wholesale rate-setting authority).

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.

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Although no single customer accounted for 10 percent or more of TVA’s total operating revenues in 2006, sales to MLGW and NES accounted for 9.1 percent and 7.7 percent, respectively. In 2004, TVA and MLGW entered into a prepayment agreement under which MLGW prepaid TVA $1.5 billion for the future costs for a portion of the electricity to be delivered by TVA to MLGW over a period of 180 months. See Note 1 — Energy Prepayment Obligations for more information about this prepayment arrangement.

On September 26, 2006, the city of Bristol, Virginia, announced that it had selected TVA as the new power provider for its municipal electric system, Bristol Virginia Utilities (“BVU”), beginning in January 2008. TVA had provided wholesale power to BVU from 1945 to 1997. The contract has a minimum 15-year term, and a five-year termination notice may not be given until January 2018. The rates under this contract are intended to recover the cost of reintegrating BVU into TVA’s power-supply plan and serving its customer load.

All of the power contracts between TVA and the distributor customers provide for purchase of power by the distributor customers at the rates established by the TVA Board, which beginning with the current fiscal year, will be adjusted quarterly to reflect changing fuel and purchased power costs. In addition, most of the power contracts between TVA and the distributor customers specify the resale rates that distributor customers charge their power customers. These resale rates are divided into the classifications of residential, general power, and manufacturing. The general power and manufacturing classifications are further divided into sub-classifications according to their load size. These rates are revised from time to time to reflect changes in costs, including changes in the wholesale cost of power, and are designed to promote the TVA Act’s objective of providing an adequate supply of power at the lowest feasible rates.

Termination Notices

Six of TVA’s distributor customers had notices in effect terminating their power contracts with TVA as of September 30, 2006. On November 3, 2006, TVA announced that distributor customers that have given notice to terminate their power contracts with TVA will have an opportunity to rescind their notices on or before January 10, 2007, without any additional costs. After January 10, 2007, TVA will consider requests for rescission of the notice, but would consider serving the returning distributor customer at the standard prevailing rate plus a reintegration fee for any additional costs necessary to supply the returning load. In December 2006, Warren Rural Electric Cooperative Corporation (“Warren”) announced its intention to take advantage of this opportunity and to enter into a new power supply contract with TVA.

The table below lists the names and locations of the six distributor customers whose termination notices were still in effect, their contract termination dates, the amount of revenues that TVA generated by selling power to these distributor customers in 2006, and the percentage of TVA’s total 2006 operating revenues represented by these revenues.

Distributor Customers with Termination Notices in Effect
As of September 30, 2006
(in millions)


			TVA Sales to
			Distributor		Percentage
		Date of Termination	Customer		of TVA Operating
Distributor Customer	Location	of Power Contract	in 2006		Revenues in 2006
Monticello Electric Plant Board	Kentucky	November 2008	$	6		0.1	%
Glasgow Electric Plant Board	Kentucky	November 2008		21		0.2	%
Warren Rural Electric Cooperative Corporation	Kentucky	April 2009		97		1.0	%
Paducah Power System	Kentucky	December 2009		39		0.4	%
Princeton Electric Plant Board	Kentucky	January 2010		6		0.1	%
Duck River Electric Membership Corporation	Tennessee	August 2010		101		1.1	%

Total			$	270		2.9	%

In 2006, TVA agreed to a one-year extension of the effective date of termination of TVA’s power supply contract with Warren and a two-year extension with Duck River Electric Membership. Warren’s one-year extension includes a surcharge for costs associated with the additional year. (The extended termination dates are shown in the table above.)

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Other Customers

Revenues from directly served industrial customers accounted for 11.6 percent of TVA’s total operating revenues in 2006. Directly served customer contracts are normally for 10-year terms. 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, with sales to USEC for its Paducah, Kentucky, facility representing 3.9 percent of TVA’s total operating revenues in 2006. TVA’s current contract with USEC expires on June 1, 2010. In January 2004, USEC announced it will begin constructing a new commercial centrifuge facility in Piketon, Ohio, which is outside TVA’s service area. Once this new facility is opened (scheduled to be in 2010), it is unclear how much electricity USEC will acquire from TVA for its Paducah, Kentucky, facility, but it is expected to be substantially less than current levels.

Rate Authority

TVA is self-regulated and the TVA Act gives the TVA Board sole responsibility for establishing the rates TVA charges for power. These rates are not subject to review or approval by any state or federal regulatory body.

According to 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;

	•		Debt service on outstanding indebtedness;

	•		Payments to the U.S. Treasury in repayment of and as a return on the Appropriation Investment in TVA’s power facilities; and

	•		Such additional margin as the TVA Board may consider desirable for investment in power system assets, retirement of outstanding indebtedness, additional reduction of the 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.

Revenue Requirements

In conjunction with 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. The DSC method is essentially a measure of an organization’s ability to cover its operating costs and to satisfy its obligations to pay principal and interest on debt. TVA believes this method is appropriate because of TVA’s debt-intensive capital structure. This ratemaking approach is particularly suitable for use by highly leveraged enterprises (i.e., financed primarily, if not entirely, by debt capital). In these enterprises common equity capital does not function, as it does in companies that issue equity, as primary risk capital by providing an adequate buffer against earnings volatility.

The revenue requirements (or projected costs) are typically calculated under the DSC method as the sum of the following components:

	(1)		Fuel and purchased power costs;

	(2)		Operating and maintenance costs;

	(3)		Taxes; and

	(4)		Debt service coverage.

Once the revenue requirements (or projected costs) are determined, this amount is compared to the projected revenues for the test year at existing rates to arrive at the shortfall or surplus of revenues as compared to the projected costs. In the event of a projected shortfall, the rates would be adjusted upward to a level sufficient to produce revenues approximately equal to the projected costs. Conversely, in the event of a projected surplus, the rates would be adjusted downward to a level to produce revenues approximately equal to the projected costs. This

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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.

Rate Actions

On July 22, 2005, the TVA Board approved a 7.52 percent increase in firm wholesale electric rates effective on October 1, 2005. The TVA Board approved the rate adjustment to fund increases in fuel and purchased power costs as well as increased fuel transportation costs. In 2006, fuel and purchased power costs represented about 38 percent of TVA’s total costs. Costs continued to increase significantly, and on February 13, 2006, the TVA Board approved a 9.95 percent increase in firm wholesale electric rates effective on April 1, 2006. The combined rate increases provided additional revenues of approximately $873 million during 2006.

On July 28, 2006, the TVA Board approved a 4.50 percent decrease in firm wholesale electric rates effective on October 1, 2006. In connection with the same rate adjustment, the TVA Board also implemented a fuel cost adjustment (“FCA”) to be applied quarterly as a mechanism to adjust TVA’s rates to reflect changing fuel and purchased power costs beginning in fiscal year 2007. The FCA is initially set to zero and will have its first impact on rates effective January 1, 2007. The FCA amount to be implemented on January 1, 2007, is 0.01 cents per kilowatt-hour and is expected to produce an estimated $3.9 million in revenue.

Power and Energy Forecasts

TVA forecasts future power and energy requirements by producing a range of load forecasts to bound the range of uncertainty associated with load growth. TVA produces the load forecasts using probabilities. TVA believes that there is a 90 percent probability that the actual load will be less than the high load forecast, a 50 percent probability that the actual load will be less than medium load forecast, and a 10 percent probability that the actual load will be less than the low load forecast. TVA’s current forecast through 2007 is a high load forecast of 4.0 percent growth, a medium load forecast of 2.9 percent growth, and a low load forecast of 0.4 percent growth. Numerous factors, such as weather conditions and the health of the regional economy, could cause actual results to differ materially from TVA’s forecasts.

Power Supply

General

TVA’s power generating facilities in operation at September 30, 2006, included 29 conventional hydroelectric plants, one pumped storage hydroelectric plant, 11 coal-fired plants, three nuclear plants, six combustion turbine plants, two diesel generator plants, one wind energy site, one digester gas plant, and 16 solar energy sites. In addition, TVA acquires power under power purchase agreements, as well as through spot market purchases.

TVA-Owned Generation Facilities

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-Owned Generation Facilities
As of September 30
(millions of kWh)


	2006				2005				2004				2003				2002

Coal-fired		99,630	64	%		98,404	62	%		94,648	61	%		90,975	60	%		94,930	63	%
Nuclear		45,313	29	%		45,156	28	%		46,003	30	%		43,167	29	%		45,179	30	%
Hydroelectric		9,961	6	%		15,723	10	%		13,916	9	%		16,103	11	%		10,205	6	%
Combustion turbine and diesel generators		613	<1	%		595	<1	%		278	<1	%		817	<1	%		1,190	1	%
Renewable resources		19	<1	%		18	<1	%		18	<1	%		15	<1	%		18	<1	%

Total		155,536	100	%		159,896	100	%		154,863	100	%		151,077	100	%		151,522	100	%

Coal-Fired. TVA has 11 coal fired power plants consisting of 59 units. At September 30, 2006, these facilities accounted for 15,081 megawatts of winter net dependable capacity. Net dependable capacity is defined as the net power output which can be obtained for a period adequate to satisfy the daily load patterns under expected

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conditions of operation with equipment in an average state of maintenance excluding any fluctuations in capacity that may occur due to planned outages, unplanned outages, and deratings. Each of TVA’s coal-fired units was placed in service between 1951 and 1973.

Nuclear. TVA has three nuclear plants consisting of five units currently in operation. At September 30, 2006, these facilities accounted for 5,770 megawatts of winter net dependable capacity. For a detailed discussion of TVA’s nuclear power program, see Item 1, Business — Nuclear.

Hydroelectric. TVA has 29 conventional hydroelectric plants consisting of 109 units. In addition, TVA has one pumped storage facility consisting of 4 units. At September 30, 2006, these facilities accounted for 5,144 megawatts of winter net dependable capacity. The amount of electricity that TVA is able to generate from its hydroelectric plants depends on a number of factors, including the amount of precipitation, watershed levels, the need for water for competing water management objectives, and the availability of its hydroelectric generation plants. When these factors are unfavorable, TVA must increase its reliance on more expensive generation plants and purchased power.

Combustion Turbines. At September 30, 2006, TVA had six combustion turbine plants consisting of 72 units, and these facilities accounted for 4,663 megawatts of winter net dependable capacity. TVA’s combustion turbines are fueled by natural gas and fuel oil and are quick-start facilities that TVA can use at times of peak demand to supply power to its customers. As of September 30, 2006, 24 of TVA’s combustion turbine units were leased to private entities and leased back to TVA under long-term leases. See Note 11 — Other Financing Obligations. In addition, the TVA Board has authorized the purchase of two additional combustion turbine facilities. In October 2006, the TVA Board authorized the acquisition of a 742 megawatt winter peaking capacity, dual-fuel combustion turbine facility and certain related transmission facilities located in Marshall County, Kentucky from KGen Marshall County LLC. In November 2006, the TVA Board approved the acquisition of a natural gas-fired combustion turbine facility located in Weakley County, Tennessee, from Allegheny Energy Supply Gleason Generating Facility, LLC. This facility can produce 555 megawatts of winter peaking capacity.

Diesel Generators. TVA has two diesel generator plants consisting of nine units. At September 30, 2006, these facilities provided 13 megawatts of winter net dependable capacity.

Renewable Resources. TVA has one wind energy site with three wind turbines, one digester gas cofiring site, and 16 solar energy sites. At September 30, 2006, the digester gas cofiring site provided TVA with five megawatts of winter net dependable capacity. In addition, the wind energy site and the photovoltaic sites provided two megawatts of capacity, but because of the nature of this capacity, it is not considered to be winter net dependable capacity.

Purchased Power

TVA acquires power from a variety of power producers through long-term and short-term power purchase agreements as well as through spot market purchases. During 2006, TVA acquired 31 percent of the power that it purchased on the spot market, 40 percent through short-term power purchase agreements and 29 percent through long-term power purchase agreements that expire more than one year after September 30, 2006.

At September 30, 2006, TVA’s power purchase agreements provided TVA with 4,275 megawatts of winter net dependable capacity. Counterparties to contracts for 3,008 megawatts of this capacity were in bankruptcy, but the counterparties have continued to perform under their power purchase agreements with TVA throughout their bankruptcy proceedings. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations — Risk Management Activities — Credit Risk. A portion of TVA’s winter net dependable capacity provided by power purchase agreements is provided under long-term contracts that expire between 2010 and 2032, and the most significant of these contracts are discussed below.

	•		Tapoco, Inc. Four hydroelectric plants owned by Tapoco, Inc. (“Tapoco”), a subsidiary of Alcoa, Inc. (“Alcoa”), are operated in coordination with the TVA system. Under contractual arrangements with Tapoco which terminate on June 20, 2010, TVA purchases the electric power generated at these facilities and uses it to partially supply Alcoa’s energy needs. TVA’s arrangement with Tapoco provides 362 megawatts of winter net dependable capacity.

	•		Southeastern Power Administration. Under arrangements among TVA, the U.S. Army Corps of Engineers, and the Southeastern Power Administration (“SEPA”), eight hydroelectric plants of the U.S. Army Corps of Engineers on the Cumberland River system are operated in coordination with the TVA system. These arrangements provide for 405 megawatts of winter net dependable capacity as well as

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			all surplus energy from the Cumberland River system to be supplied to TVA by SEPA at the points of generation at a price based on the operating and maintenance expenses and amortization of the power facilities. A portion of the output of the Cumberland River system is also made available to SEPA’s customers outside the TVA region. The agreement with SEPA covering these arrangements for power from the Cumberland River system can be terminated upon three years’ notice, but this notice of termination may not become effective prior to June 30, 2017.

	•		Choctaw Generation, L.P. TVA has contracted with Choctaw Generation L.P. (“Choctaw”) for 440 megawatts of winter net dependable capacity from a lignite-fired generating plant in Chester, Mississippi. TVA’s contract with Choctaw expires on March 31, 2032.

Under the Public Utility Regulatory Policies Act of 1978, as amended (“PURPA”), TVA is obligated to purchase such energy at TVA’s avoided cost as may be “put” to TVA from time to time from qualifying independent, non-utility power producers. At September 30, 2006, TVA had such PURPA-required contracts with seven such producers, with a combined capacity of 906 megawatts, but in October 2006, one of these contracts expired. The expired contract was with a producer with approximately three megawatts of capacity. Because of the nature of TVA’s obligations under these PURPA-required contracts, the capacity of the associated qualifying generation facilities is not included in TVA’s net dependable capacity calculations.

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

Purchased Power
(in millions of kWh)


2006	2005		2004		2003		2002
20,017		16,637		15,148		15,760		12,241

These purchase agreements provide between 7.5 percent and 11.4 percent of TVA’s total power supply during these years.

For more information regarding TVA’s power purchase obligations, see Note 13 — Commitments — Power Purchase Obligations.

Net Dependable Capacity

The following table summarizes the winter net dependable capacity in megawatts TVA had available as of September 30, 2006:

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TVA WINTER NET DEPENDABLE CAPACITY
As of September 30, 2006


				Winter Net			Date First Unit	Date Last Unit
		Number of		Dependable			Placed in	Placed in
Source of Capacity	Location	Units		Capacity (MW) ¹			Service	Service

Coal-Fired
Allen	Tennessee		3		750		1959	1959
Bull Run	Tennessee		1		889		1967	1967
Colbert	Alabama		5		1,201		1955	1965
Cumberland	Tennessee		2		2,524		1973	1973
Gallatin	Tennessee		4		988		1956	1959
John Sevier	Tennessee		4		712		1955	1957
Johnsonville	Tennessee		10		1,254		1951	1959
Kingston	Tennessee		9		1,448		1954	1955
Paradise	Kentucky		3		2,318		1963	1970
Shawnee	Kentucky		10		1,369		1953	1956
Widows Creek	Alabama		8		1,628		1952	1965


Total Coal-Fired			59		15,081

Nuclear
Browns Ferry	Alabama		2		2,269		1974	1977
Sequoyah	Tennessee		2		2,333		1981	1982
Watts Bar	Tennessee		1		1,168		1996	1996


Total Nuclear			5		5,770

Hydroelectric
Conventional Plants	Alabama		36		1,146		1925	1962
	Georgia		2		32		1931	1956
	Kentucky		5		165		1944	1948
	North Carolina		8		536		1940	1956
	Tennessee		58		1,647		1912	1972
Pumped Storage	Tennessee		4		1,618		1978	1979


Total Hydroelectric			113		5,144

Combustion Turbine
Allen	Tennessee		20		575		1971	1972
Colbert	Alabama		8		486		1972	1972
Gallatin	Tennessee		8		730		1975	2000
Johnsonville	Tennessee		20		1,372		1975	2000
Kemper	Mississippi		4		374		2001	2001
Lagoon Creek	Tennessee		12		1,126		2002	2002


Total Combustion Turbine			72		4,663	²

Diesel Generator
Meridian	Mississippi		5		9		1998	1998
Albertville	Alabama		4		4		2000	2000


Total Diesel Generators			9		13

Renewable Resources Owned by TVA					5


Total TVA-Owned Generation Facilities					30,676


Power Purchase Agreements
Tapoco					362
SEPA					405
Choctaw					440
Other Power Purchase Agreements					3,068


Total Power Purchase Agreements					4,275


Total Winter Net Dependable Capacity					34,951

Notes


(1)		Net dependable capacity is the net power output which can be obtained for a period adequate to satisfy the daily load patterns under expected conditions of operation with equipment in an average state of maintenance excluding any fluctuations in capacity that may occur due to planned outages, unplanned outages, and deratings. TVA currently estimates gas, combustion turbine, and diesel generator capacity at 95 degrees Fahrenheit for summer net dependable capacity and at 25 degrees Fahrenheit for winter net dependable capacity. For planning purposes, TVA estimated total summer net dependable capacity at September 30, 2006 to be approximately 33,653 megawatts, including hydroelectric capacity of approximately 5,458 megawatts, coal-fired capacity of approximately 14,709 megawatts, nuclear power capacity of approximately 5,611 megawatts, combustion turbine capacity of approximately 3,708 megawatts, diesel generator capacity of approximately 13 megawatts, capacity from renewable assets of approximately five megawatts, and capacity from power purchase agreements of approximately 4,149 megawatts.

(2)		As of September 30, 2006, 24 of TVA’s combustion turbine units were leased to private entities and leased back to TVA under long-term leases.

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Nuclear

Overview

TVA has five operating nuclear units, one deferred nuclear unit, and one nuclear unit in recovery that is scheduled to be returned to service in 2007. Two units were canceled during 2006. Selected statistics of each of these units are included in the table below.

TVA Nuclear Power
As of September 30, 2006


		Installed
		Capacity		Net Capacity		Date of Expiration of			Date of Expiration of
Nuclear Unit	Status	(Megawatts)		Factor for 2006		Operating License			Construction License

Sequoyah Unit 1	Operating		1,221		88.9		2020			—
Sequoyah Unit 2	Operating		1,221		98.0		2021			—
Browns Ferry Unit 2	Operating		1,190		96.4		2034	³		—
Browns Ferry Unit 3	Operating		1,190		84.7		2036	³		—
Watts Bar Unit 1	Operating		1,270		84.0		2035			—
Watts Bar Unit 2	Deferred ¹		—		—		—			2010
Bellefonte Unit 1	Canceled ²		—		—		—			—
Bellefonte Unit 2	Canceled ²		—		—		—			—
Browns Ferry Unit 1	Recovery ⁴		1,150		—		2033	³		—

Notes


(1)		Per the Nuclear Regulatory Commission’s definition of deferred nuclear units. TVA is planning to perform a detailed scoping, estimating, and planning study at Watts Bar Nuclear Plant Unit 2 during 2007 and 2008 and has budgeted $30 million for the study. Watts Bar Unit 2 is a partially completed nuclear unit similar in design to the operating Watts Bar Unit 1. The purpose of the study is to provide accurate cost, schedule, and risk information to enable a more informed future decision regarding new base load generation. No decision has been made to actually complete Watts Bar Unit 2.

(2)		In September 2006, the Nuclear Regulatory Commission (“NRC”) approved TVA’s request to terminate the construction permits for unfinished Bellefonte Units 1 and 2. The TVA Board approved canceling the Bellefonte construction project in November 2005. Neither of these actions interferes in any way with TVA’s ability to use the site for future projects.

(3)		On May 3, 2006, the NRC approved TVA’s applications for 20-year license extensions for these units. (The expiration dates listed in the table reflect the extensions.)

(4)		Browns Ferry Unit 1 is expected to return to service in 2007 and is expected initially to provide additional generating capacity of approximately 1,150 megawatts and eventually to provide 1,280 megawatts of capacity. At September 30, 2006, the restart construction at Browns Ferry Unit 1 was approximately 94 percent complete.

Spent Nuclear Fuel

Under the Nuclear Waste Policy Act of 1982, TVA (and other domestic nuclear utility licensees) entered into a contract with the U.S. Department of Energy (“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 announced that it will not begin receiving spent nuclear fuel from any domestic nuclear utility until 2010 at the earliest. TVA, like other nuclear utilities, stores spent nuclear fuel in pools of borated water at its nuclear sites. Although TVA would have had sufficient space to continue to store spent nuclear fuel in those storage pools at its Sequoyah and Browns Ferry Nuclear Plants indefinitely had DOE begun accepting spent nuclear fuel, DOE’s failure to do so required TVA to construct dry cask storage facilities at its Browns Ferry and Sequoyah Nuclear Plants and to purchase special storage containers for the spent nuclear fuel. (Watts Bar Nuclear Plant currently has sufficient storage capacity in its spent fuel pool to last until approximately 2018.) The Browns Ferry and Sequoyah dry cask storage facilities have been constructed and approved by the NRC and are now in use. 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 the damages awarded by the Court of Federal Claims. The damages, amounting to almost $35 million, partially offset the construction costs of the dry cask storage facilities that TVA incurred through 2004. The cumulative cost of the capitalized storage facilities totaled approximately $61 million as of September 30, 2006, and is included in Property, plant, and equipment on the Balance Sheets. TVA plans to bring additional claims against DOE to recover costs that TVA has incurred after 2004.

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 contracted to dispose of radwaste at a Barnwell, South Carolina, disposal facility through June 2008. After June 2008, TVA will no longer be able to use this

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disposal facility and will have to consider other options, which may include storing the radwaste at its own facilities as it has done in the past.

Nuclear Decommissioning Trust

TVA maintains a nuclear decommissioning trust to provide money for the ultimate decommissioning of its nuclear power plants. The trust is invested in securities generally designed to achieve a return in line with overall equity market performance. The assets of the trust as of September 30, 2006, totaled $937 million, which is greater than the present value of TVA’s estimated future nuclear decommissioning costs as computed under the NRC funding requirements. See Note 13 — Contingencies — Decommissioning Costs.

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 $300 million of nuclear liability insurance from American Nuclear Insurers (“ANI”) for each plant with an operating license. The second layer, the Secondary Financial Program (“SFP”), would come from an assessment of up to $101 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 $15 million per year per reactor. ANI, under a contract with the NRC, administers the SFP. With its six licensed units, TVA could be required to pay a maximum of $604 million per nuclear incident, but it would have to pay no more than $90 million per incident in any one year. When the contributions of the nuclear plant licensees are added to the insurance proceeds of $300 million, over $10.7 billion would be available. Under the Price-Anderson Act, if the first two layers are exhausted, Congress is required to take action to provide additional funds to cover the additional losses.

TVA carries property, decommissioning, and decontamination insurance of $4.2 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 may require the payment of retrospective premiums up to a maximum of approximately $64 million.

TVA purchases accidental outage (business interruption) insurance for TVA’s nuclear sites from Nuclear Electric Insurance Limited (“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 deductible 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 $23 million. See Note 13 — Contingencies — Nuclear Insurance.

Tritium-Related Services

TVA helps produce tritium at certain nuclear facilities under a contract with DOE. See Note 13 — Commitments — Tritium-Related Services.

Fuel Supply

General

TVA’s consumption of various types of fuel depends on several factors, the most important of which are the demand for electricity by TVA’s customers, the availability of various generating units, and the availability and cost of fuel. The following table indicates TVA’s costs for various fuels for the years indicated:

Fuel cost
(in millions of dollars)


	2006		2005		2004		2003		2002

Coal	$	1,835	$	1,495	$	1,254	$	1,242	$	1,233
Natural Gas		60		63		22		42		50
Fuel Oil		46		28		17		40		14
Uranium		71		44		16		42		38

Total	$	2,012	$	1,630	$	1,309	$	1,366	$	1,335

The following table indicates TVA’s average fuel costs in cents per kilowatt-hours for the years indicated:

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Fuel Cost Per kWh
(cents/kWh)


	2006		2005		2004		2003		2002

Coal		2.02		1.65		1.48		1.43		1.39
Natural gas and fuel oil		10.65		11.44		9.01		7.61		4.65
Nuclear		0.38		0.39		0.39		0.39		0.41
Aggregate fuel cost per kWh net thermal generation		1.54		1.30		1.14		1.14		1.11

Beginning with the implementation of the fuel cost adjustment mechanism on October 1, 2006, TVA’s rates will be adjusted on a quarterly basis to reflect changing fuel and purchased power costs. See Item 1, Business — Rate Actions.

Coal

Coal consumption at TVA’s coal-fired generating facilities during 2006 was 46.4 million tons. As of September 30, 2006, and 2005, TVA had 20 days and 16 days of system-wide coal supply at full burn, respectively, with a net book value of coal inventory of $214 million and $149 million, respectively.

During 2006, TVA had in place coal contracts with terms of more than one year, which supplied 83 percent of TVA’s total coal requirements for 2006. These contracts have expiration dates ranging from October 1, 2006, to September 30, 2017, and TVA plans to continue signing contracts of various lengths, terms, and quality to meet its expected burn requirements. The remaining 17 percent of coal purchased during 2006 was purchased in the spot coal market under contracts with terms of one year or less. During 2006, TVA’s coal supply was acquired as follows:

	•		37 percent from the Illinois Basin;

	•		25 percent from the Powder River Basin in Wyoming;

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

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

During 2006, TVA purchased additional Appalachian Basin and Illinois Basin coals to replace shortages in deliveries from the Powder River Basin and Uinta Basin. By early summer 2006, coal inventories were at or above normal levels. During 2006, 40 percent of TVA’s coal supply was delivered by rail, 21 percent was delivered by barge, and 34 percent was delivered by a combination of barge and rail. The remainder was delivered by truck.

Natural Gas and Fuel Oil

During 2006, TVA purchased substantially all of its natural gas requirements from a variety of suppliers under contracts with terms of one year or less. TVA purchases substantially all of its natural gas to operate combustion turbine peaking units and to supply fuel under power purchase agreements in which TVA is the fuel supplier. At September 30, 2006, all of TVA’s combustion turbines were dual fuel capable, and TVA has fuel oil stored on each site as a backup to natural gas. During 2006, TVA purchased substantially all of its fuel oil on the spot market. At September 30, 2006, and 2005, the net book value of TVA’s natural gas in inventory was $2 million and $0.4 million, respectively, and the net book value of TVA’s fuel oil in inventory was $54 million and $35 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. TVA currently has 100 percent of its forward five-year (2007 through 2011) uranium requirements either in inventory or under contract for its boiling water reactor units at Browns Ferry Nuclear Plant and has 100 percent of its forward five-year (2007 through 2011) uranium requirements under contract for its pressurized water reactor units at Sequoyah and Watts Bar Nuclear Plants. In addition, TVA has 100 percent of its conversion, enrichment, and fabrication needs under contract through 2011. TVA plans to meet future uranium requirements through a combination of term and spot purchase contracts.

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TVA, DOE, and nuclear fuel contractors have entered into agreements providing for surplus DOE uranium that exceeds enrichment levels that can be used in a nuclear power plant 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 a nuclear plant. This fuel was successfully loaded in Browns Ferry Unit 3 in April 2006 and will provide approximately 11 to 12 more reloads for the Browns Ferry reactors. Under the terms of the interagency agreement, DOE supplies off-specification, highly enriched uranium materials to the appropriate third party fuel processors, either by themselves or through subcontractors, 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 product. 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 $272 million under the interagency agreement. TVA anticipates these future payments could begin in 2009. See Note 1 — Blended Low Enriched Uranium Program, for a more detailed discussion of the blended low enriched uranium project.

TVA owns all nuclear fuel held for its nuclear plants. As of September 30, 2006, and 2005, the net book value of this nuclear fuel was $491 million and $340 million, respectively.

For a discussion of TVA’s plans with respect to spent nuclear fuel storage, see Item 1, Business — Nuclear — Spent Nuclear Fuel.

Transmission Operations

The TVA transmission system is one of the largest in North America having delivered nearly 172 billion kilowatt-hours of electricity in 2006 and having maintained 99.999 percent reliability over the last seven years in delivering electricity to customers. This system is comprised of:

	•		Approximately 17,000 circuit miles of transmission lines, including 2,400 miles of extra-high-voltage (500,000 volt) transmission lines;

	•		537 substations, power switchyards, and switching stations;

	•		1,045 individual interchange and customer connection points; and

	•		260,000 right-of-way acres.

The TVA transmission organization offers transmission services, similar to those offered by other transmission operators, in accordance with standards of conduct that separate its transmission functions from TVA’s marketing functions.

Also, TVA is cooperating with other transmission systems to improve regional coordination in the operation of the bulk transmission system. The initial step of this coordination effort was to establish a joint transmission reliability area with other public power systems. In 2002, TVA entered into reliability coordination agreements with Associated Electric Cooperative Inc., Big Rivers Electric Corporation, and East Kentucky Power Cooperative, Inc. In 2004, Electric Energy, Inc. joined this effort, and in 2006, TVA began providing reliability coordination services for Kentucky Utilities Company and Louisville Gas and Electric Company.

TVA has been designated by the North American Electric Reliability Council (“NERC”) to serve as the reliability coordinator for parts of 11 states covering 199,000 square miles with a population of nearly 11 million people. As the reliability coordinator for this region, TVA is responsible for monitoring and helping to ensure the reliable operation of the bulk transmission system in a region that includes portions of Alabama, Georgia, Illinois, Iowa, Kentucky, Mississippi, Missouri, North Carolina, Oklahoma, Tennessee, and Virginia. TVA is one of 17 reliability coordination offices in NERC.

TVA has a joint reliability coordination agreement with the Midwest Independent Transmission System Operator and PJM Interconnection, LLC to improve the reliability of the regional grid. This effort includes a coordinated approach to transmission capacity availability, system outage approval, congestion management, and transmission planning. Similar agreements to develop analysis and operational processes in support of regional transmission reliability have been executed with Entergy Services, Inc., Southwest Power Pool, Inc., and VACAR South RC (a Virginia Carolina reliability group). An agreement is pending with Southern Company Services, Inc.

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Reliability Coordinator Map

Stewardship Activities

TVA is responsible for managing the Tennessee River and its tributaries — the United States’ fifth largest river system — 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 economic development. TVA owns and operates 49 dams, which comprise its integrated reservoir system. Twenty-nine of these dams produce conventional hydroelectric power, and one additional project is solely a pumped storage hydroelectric project. 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, including cooling water for some of TVA’s fossil fuel and nuclear power plants.

TVA reservoirs and public lands provide outdoor recreation opportunities for millions of visitors each year. TVA has stewardship responsibility for 293,000 acres of reservoir land, 11,000 miles of shoreline, and 650,000 acres of reservoir water surface available for recreation and other purposes. TVA owns over 100 recreation facilities such as campgrounds, boat ramps, fishing piers, and picnic areas.

Seasonality

Weather affects both the demand for and the market prices of electricity. TVA’s power system peaks in both the summer and the winter, so TVA typically sells more electricity during the summer and the winter than in the spring and the fall. See Item 1A, Risk Factors, for a discussion of the potential impact of weather on TVA.

TVA uses weather degree days to measure the impact of weather on TVA’s power operations. TVA calculates weather degree days for each of the five largest cities in TVA’s service area. If the average temperature

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for a given day in one of these cities exceeds 65 degrees Fahrenheit, that city will have cooling degree days for that day equal to the amount by which the average temperature for that day exceeds 65 degrees Fahrenheit. Similarly, if the average temperature for a given day in one of these cities is lower than 65 degrees Fahrenheit, that city will have heating degree days for that day equal to the amount by which 65 degrees Fahrenheit exceeds the average temperature for that day.

During 2006, TVA had 162 more heating degree days and 32 more cooling degree days than in 2005. The graph below shows the number of heating and cooling degree days for 2006, 2005, and 2004 as compared to the normal number of heating and cooling degree days.

Heating and Cooling Degree Days

Competition

TVA sells 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: one called the “fence” and one called 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 provide power within the service area because they are not entitled to use the TVA transmission system for the purpose of delivering power to customers within the service area. Bristol, Virginia, was exempted from the anti-cherrypicking provision.

Of the six distributors that had notices terminating their power contracts still in effect at September 30, 2006, five are in Kentucky. See Item 1, Business — Customers — Termination Notices. Power rates in Kentucky are among the lowest in the nation. Warren Rural Electric Cooperative Corporation (“Warren”) and East Kentucky Power Cooperative (“East Kentucky”) have entered into an arrangement under which Warren will become a member of East Kentucky, and East Kentucky will supply Warren after its power contract with TVA expires in 2009. After agreeing to become Warren’s power supplier, East Kentucky asked TVA to provide transmission service to East Kentucky for its service to Warren. TVA denied the request on the basis that, under the anti-cherrypicking provision, it was not required to do so. East Kentucky then asked to interconnect its transmission system with the TVA transmission system in three places that are currently delivery points through which TVA supplies power to Warren. TVA did not agree to provide the interconnections, and East Kentucky asked the Federal Energy Regulatory Commission (“FERC”) to order TVA to provide the interconnections. In January 2006, FERC issued a final order directing TVA to interconnect its transmission facilities with East Kentucky’s system at three locations on the TVA transmission system. TVA believes this order is contrary to the anti-cherrypicking provision, and, on August 11, 2006, TVA filed an appeal in the U.S. Court of Appeals for the District of Columbia Circuit seeking review of this order. See Note 16 — Customers.

In July, 2005, Senator Jim Bunning (R-KY) and Senator Mitch McConnell (R-KY) introduced a bill (S. 1499) that would effectively remove any area within Kentucky from coverage by the anti-cherrypicking provision. If the bill

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were to become law, FERC could require TVA to provide wheeling from other power suppliers to wholesale customers inside that portion of TVA’s service area that is within Kentucky. The bill was referred to and remains in the Senate Energy and Natural Resources Committee.

In 2000, restructuring legislation for competition in the electric power industry appeared imminent. In response, TVA, the Tennessee Valley Public Power Association (“TVPPA”), an association representing distributors of TVA power, and the Tennessee Valley Industrial Committee (“TVIC’’), an organization representing industries that TVA directly serves, reached consensus on draft legislation addressing the relationships between TVA and its customers in a restructured electric power industry. The draft legislation, as revised by TVA, TVPPA, and TVIC in 2003, provides for:

	•		Simultaneous repeal, on the effective date of the restructuring legislation, of the fence and the anti-cherrypicking provision,

	•		A distributor customer option to gradually take up to a maximum of 30 percent of its power requirements from other suppliers with advance notice to TVA,

	•		New limitations on TVA retail sales in TVA’s current service area,

	•		Stranded cost recovery through 2007,

	•		FERC regulation to ensure that TVA charges others transmission service rates and imposes on others terms and conditions of service comparable to those TVA charges and imposes on itself,

	•		TVA to be subject to antitrust laws (with the exception of monetary damages and attorney’s fees),

	•		At individual distributor customer election, a reduction in TVA’s existing regulation of distributor customers, and

	•		New TVA generation to be limited to that needed to meet demand within the current TVA service area.

While earlier versions of this legislation were introduced in Congress, the 2003 version has never been introduced and is not part of any pending or anticipated bill.

Regulation

Congress

TVA exists pursuant to legislation enacted by Congress and carries on its operations in accordance with this legislation. Congress has the authority to change this legislation and thereby expand or reduce TVA’s activities or significantly change TVA’s structure. To allow TVA to operate more flexibly than a traditional government agency, Congress exempted TVA from some general federal laws that govern other agencies, such as laws related to the hiring of 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 the protection of the environment and cultural resources and civil rights laws.

Securities and Exchange Commission

Section 37 was added to the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as part of the Consolidated Appropriations Act, 2005. Section 37 requires TVA to file with the Securities and Exchange Commission beginning with the Annual Report 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. 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 proxies) 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. In addition, 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

TVA is not a “public utility” as defined in the Federal Power Act (“FPA”), which generally includes investor-owned utilities. Therefore, TVA is not subject to the full jurisdiction that the Federal Energy Regulatory Commission

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(“FERC”) exercises over public utilities under the FPA. TVA is, however, an “electric utility” as defined in the FPA and, thus, is directly subject to certain aspects of FERC’s jurisdiction.

	•		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 either 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 may be ordered to transmit power at wholesale provided that the order does not impair the reliability of the TVA and 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. With the exception of wheeling power to Bristol, Virginia, 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 the electric industry generally, 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.

	•		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 TVA and others 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 indicated above that are subject to FERC’s jurisdiction.

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

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 consistent with TVA’s obligations under the TVA Act.

Nuclear Regulatory Commission

TVA operates its nuclear facilities in a highly regulated environment and is overseen by 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.

Environmental Protection Agency

TVA is subject to regulation by the Environmental Protection Agency (“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 United States 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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Governmental Entities

TVA’s activities and records are also subject to review by various entities including TVA’s Office of Inspector General and the following agencies: the Government Accountability Office, the Congressional Budget Office, and the Office of Management and Budget.

Payments in Lieu of Taxes

TVA is not subject to federal income taxes, and neither TVA nor its property, franchises, or income are subject to taxation by states or their subdivisions. However, the TVA Act requires TVA to make payments in lieu of taxes to states and counties in which TVA conducts power operations and in which TVA has acquired properties previously subject to state and local taxation. The 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 exchange sales with other utilities, with a provision for minimum payments under certain circumstances.

TVA In Lieu of Tax Payments by State
(in millions)


	2006		2005		2004

Alabama	$	93	$	89	$	81
Georgia		6		6		5
Illinois		<1		<1		<1
Kentucky		33		30		27
Mississippi		20		20		19
North Carolina		2		2		2
Tennessee		221		218		203
Virginia		<1		<1		<1


	$	376	$	365	$	338

Environmental Matters

As is the case across the utility industry and in other industrial sectors, TVA’s activities are subject to certain federal, state, and local environmental statutes 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.

TVA has incurred and continues to incur substantial capital and operating and maintenance costs in order to comply with evolving environmental requirements. Many of these costs are associated with the operation of TVA’s 59 coal-fired generating units. While it is not possible to predict with any precision how these evolving requirements will impact the operation of existing and new coal-fired and other fossil-fuel generating units, it is virtually certain that environmental requirements placed on the operation of these generating units will continue to become more restrictive. Litigation over emissions from coal-fired generating units is also occurring, including litigation against TVA. See Item 3, Legal Proceedings.

Several existing regulatory programs have been and are being made more stringent in their application to fossil-fuel units, and additional regulatory programs affecting fossil-fuel units were promulgated in 2005, including the Clean Air Interstate Rule (“CAIR”), which requires significant utility reductions of emissions of sulfur dioxide (“SO₂”) and nitrogen oxides (“NO_x”) in the eastern half of the United States (including in all of TVA’s operating area), and the Clean Air Mercury Rule (“CAMR”). TVA had previously estimated its total capital cost for reducing emissions from its power plants from 1977 through 2010 to reach $5.8 billion, $4.6 billion of which had already been spent as of September 30, 2006. TVA estimates that compliance with CAIR and CAMR could lead to additional costs of $3.0 billion to $3.5 billion in the next decade if TVA should continue to operate all of its present coal plants. As discussed in more detail below, there could be additional material costs if reductions of carbon dioxide (“CO₂”) are mandated, or if future legislative, regulatory, or judicial actions lead to more stringent emission reduction requirements, but these costs cannot reasonably be predicted at this time. TVA will continue to monitor those developments and will assess any potential financial impacts as information becomes available.

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Clean Air Developments

Air quality in the United States has significantly improved since the enactment of the modern Clean Air Act (“CAA”) in 1970. These air quality improvements are expected to continue as the CAA continues to be implemented and through the evolution of programs as a result of legislative and regulatory changes. Three substances emitted from coal-fired units have been the focus of emission reduction regulatory programs: SO₂, NO_x, and particulates. Expenditures related to clean air projects during 2006 and 2005 were approximately $182 million and $202 million, respectively. These figures include expenditures in 2006 of $6 million to continue to reduce NO_x emissions through the installation of selective catalytic reduction (“SCR”) systems, and of $146 million for the installation of flue gas desulphurization systems (“scrubbers”) to continue to reduce SO₂ emissions, each of which are explained in more detail below. The aforementioned estimates do not include additional capital costs of $3.0 billion to $3.5 billion that TVA expects to incur over the next decade to comply with CAIR and CAMR. Increasingly stringent regulation of some or all of these substances, and possibly carbon dioxide, will continue to result in significant capital and operating costs for coal-fired generating units, including those operated by TVA.

Sulfur Dioxide

Coal-fired utilities have historically emitted large amounts of SO₂. Utility SO₂ emissions are currently regulated under the Federal Acid Rain Program and state programs designed to meet the National Ambient Air Quality Standards for SO₂ and fine particulate matter. Looking forward, additional regulation of SO₂ emissions from some units will result from implementation of the Regional Haze Program and for more units as a result of the CAIR. In May 2005, EPA finalized CAIR to reduce the interstate transport of fine particulate matter and ozone by requiring large reductions in utility emissions of NO_X and SO₂ from 28 eastern states. CAIR is currently in effect in all of these states as a federal rule. States in TVA’s service area are submitting plans to EPA to implement CAIR as state rules and have only proposed a few minor modifications to the federal model rule which establishes an emission allowance driven program, capping regional emissions of SO₂ and NO_x among the targeted states. SO₂ caps are reduced in two phases, 2010 and 2015.

Since 1977, TVA has reduced its SO₂ emissions by approximately 80 percent by switching to lower-sulfur coals, re-powering a unit at its Shawnee Fossil Plant with the advanced Atmospheric Fluidized Bed Combustion (“AFBC”) technology, and installing scrubbers on six of its larger units. A seventh scrubber at unit 3 of the Paradise Fossil Plant has been constructed and is going through shakedown testing prior to being placed in operation. TVA broke ground in 2005 on its eighth scrubber at its Bull Run Fossil Plant and in 2006 broke ground on two more scrubbers at its Kingston Fossil Plant as part of its previously announced plans to achieve a total SO₂ emission reduction of 80 to 85 percent compared to the 1977 level. Additionally, TVA has switched, or plans to switch, to lower sulfur coal on several additional units in the next few years. These near-term plans are unlikely to change. It is likely that additional emission reduction measures will have to be undertaken after these planned actions are completed to achieve compliance with CAIR and possible future tightening of applicable requirements.

Nitrogen Oxides

Utility NO_x emissions are extensively regulated and will be regulated further under state programs to achieve and maintain EPA’s national ambient air quality standard for ozone, the acid rain control program, the regional haze program (depending on when units commenced operations and their effects on sensitive areas), and CAIR, as discussed above. Since 1995, TVA has reduced its NO_x emissions during the summer (when ozone levels increase) by 81 percent by installing various controls including low-NO_x burners and/or combustion controls on 58 of its coal fired units. (The AFBC unit at Shawnee is inherently low NO_x emitting.) TVA has also installed SCR’s on 21 of its largest units. In 2005, TVA installed Selective Non-Catalytic Reduction (“SNCR”) systems on two units to demonstrate long term technology capability. TVA has continued operating these two new SNCR installations through the 2006 ozone season. SNCRs generally cost less to install than SCRs but have lower NO_x removal capabilities. Early in 2006, TVA began testing a High Energy Reagent Technology (“HERT”) on three units for potential future application. HERT is similar to SNCR, has lower capital costs than SCRs, and appears to have lower NO_x removal capabilities than SCRs but higher removal capabilities than SNCRs. The initial HERT testing program was successful. As a result, in 2007, TVA will install this technology on two coal-fired units that were previously targeted for SNCR installations to demonstrate the HERT technology on a potentially permanent basis. TVA’s NO_x emission reduction program is expected to continue to depend primarily on SCRs, but will also likely incorporate some mix of SNCRs and/or HERTs as TVA gains more experience with these technologies. These plans may change depending on the timing and severity of future regulatory developments potentially affecting power plant emissions. For example, EPA is currently reviewing the existing national ambient air quality standard for ozone and may make it more stringent.

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In 2004, EPA issued final non-attainment designations under the current eight-hour ozone standard. Several counties within the TVA region were designated as not in attainment with that standard. Some of these counties have entered into “Early Action Compacts” with EPA and have taken steps such as instituting vehicle emissions testing, lowering speed limits, and other activities to help reduce summer ozone levels. In exchange, these counties are exempted from some of the negative consequences of a “non-attainment” designation. The TVA NO_x emission reductions described above have been a contributor to improving summer ozone levels in those areas, especially in Tennessee. Current monitoring indicates that all counties are making progress toward meeting the lower standard and achieving an attainment designation. The NO_x reduction requirements of CAIR will continue to help states achieve EPA’s ozone and fine particle standards. CAIR caps and reduces NO_x emissions in two steps, 2009 and 2015.

Particulates/Opacity

Coarse particulates (particulates of 10 micrometers or larger and especially fly ash) have long been regulated by states to meet EPA’s national ambient air quality standard for particulate matter. TVA’s coal-fired units have been equipped with mechanical collectors, electrostatic precipitators, scrubbers, or baghouses, which have reduced particulate emissions from the TVA system by more than 99 percent compared to uncontrolled units. In 1997, the EPA for the first time issued separate national ambient air quality standards for even smaller particles with a size of up to 2.5 micrometers (“fine particles”). In December 2004 and April 2005, EPA issued final determinations regarding which areas of the country are not in attainment with the 1997 fine particles standard. Those non-attainment areas include counties and parts of counties in the Knoxville and Chattanooga, Tennessee metropolitan areas. In September 2006, EPA revised the 1997 standards. The 2006 revisions tighten the 24-hour fine particle standard and retain the current annual fine particle standard. EPA also decided to retain the existing 24-hour standard for coarse particles, but revoked the related annual standard. A preliminary review of the current monitoring data indicates that no additional counties likely will be classified as non-attainment areas under the revised 2006 standards, although actual designations will be based on subsequent year’s monitoring data. CAIR is intended to help states attain the fine particle standards, and actions taken to reduce emissions under CAIR, including those planned by TVA, are expected to continue the reduction in fine particle levels.

Issues regarding utility compliance with state opacity requirements are also increasing. Opacity 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 NO_x emissions can adversely affect opacity performance, and TVA and other utilities are now addressing this issue. There are also disputes with special interest groups over the role of continuous opacity monitors in determining compliance with opacity limitations.

Mercury

In December 2000, the EPA determined that it was appropriate and necessary to regulate mercury emissions from oil and coal-fired power plants as a hazardous air pollutant under the CAA. In March 2005, it reversed that earlier decision, and instead issued CAMR. CAMR establishes caps for overall mercury emissions in two phases, with the first phase becoming effective in 2010 and the second in 2018. It allows the states to regulate mercury emissions through a market-based cap-and-trade program. All of the states in which TVA operates potentially affected sources are expected to adopt CAMR without significant change. In response to a request for reconsideration, EPA confirmed its approach in May 2006. In June 2006, 16 states and several environmental groups filed law suits challenging CAMR. This lawsuit is currently pending. TVA cannot predict the outcome of the pending challenge of CAMR, or what effects any decision may have that would require the EPA to regulate mercury as a hazardous air pollutant. If the EPA’s decisions are upheld and CAMR is implemented, TVA expects to achieve the required mercury reductions at least for Phase I of CAMR as co-benefits of the installation of additional emission control technology in connection with the implementation of CAIR.

CAMR does, however, require the installation of new mercury emission monitoring equipment prior to January 1, 2009. TVA is planning to comply with this requirement by procuring, installing, and certifying approximately 23 monitoring systems by calendar year 2008.

Carbon Dioxide

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sector and other industry sectors to support this initiative. TVA is supporting this effort in cooperation with electric utility industry trade associations and the Department of Energy. In addition to these activities, TVA is a member of the Southeast Regional Carbon Sequestration Partnership and is working with the Electric Power Research Institute and other electric utilities on projects investigating technologies for CO₂ capture and geologic storage, as well as carbon sequestration via reforestation. The previous Administration also asked utilities to voluntarily participate in an effort to reduce, sequester, or avoid greenhouse gases. Under that program, TVA reduced, sequestered, or avoided more than 305 million tons of CO₂ from 1994 through 2005, as reported under Section 1605b of the Energy Policy Act. TVA’s clean air strategy, as it relates to investments on coal-fired generating facilities, allows for continued review of decisions for clean air and other capital investments as potential climate change legislation is developed.

In addition to legislative activity, climate change issues are the subject of several lawsuits including lawsuits against TVA. See Item 3, Legal Proceedings. On November 29, 2006, the United States Supreme Court heard a case concerning whether EPA has the authority and duty to regulate CO₂ emissions under the Clean Air Act. The District of Columbia Circuit Court of Appeals earlier affirmed EPA’s decision not to regulate CO₂. While the case focuses on CO₂ emissions from the transportation industry, it could set a precedent for regulation in other industrial sectors depending upon how the Supreme Court rules. States are also becoming more active on the climate change front. Several northeastern states have formed the Regional Greenhouse Gas Initiative which is in the process of being implemented, and California recently passed a bill capping greenhouse gas emissions in the state. Other states are considering a variety of actions. However, in the southeast, to TVA’s knowledge, only North Carolina, where TVA does not operate any coal-fired generating facilities, is studying initiatives aimed at climate change under the provisions of the state’s Clean Smokestacks Act of 2002. This act required the State Division of Air Quality to study potential control of CO₂ emissions from coal-fired utility plants and other stationary sources. This effort has also prompted actions to develop a climate action plan for North Carolina.

Clean Water Developments

In the second phase of a three-part rulemaking to minimize the adverse impacts from cooling water intake structures on fish and shellfish, as required under Section 316(b) of the Clean Water Act, EPA promulgated a final rule for existing power producing facilities that became effective on September 7, 2004. The new rule requires existing facilities to select among several different compliance options for reducing the number of organisms pinned against and/or drawn into the cooling systems. These include development of a site-specific compliance option based on application of cost/cost or cost/benefit tests. The site specific tests are designed to ensure that a facility’s costs are not significantly greater than cost projections in the rule or the benefits derived from taking mitigation actions. Actions taken to compensate for any impacts by restoring habitat, or pursuing other options such as building hatcheries for fish/shellfish production, count toward compliance. Some northeastern states and environmental groups have challenged the new regulation, especially the compliance flexibility it offers, in federal court.

All of the intakes at TVA’s existing coal-fired and nuclear generating facilities are subject to this rule. Compliance assessments are underway for these facilities to determine what should be done to meet the new requirements. Some capital and/or operating expenditures may have to be made to comply at some or all facilities. The assessments, however, are complicated by the uncertainty created by pending legal action challenging EPA’s rule.

As is the case across the utility industry and in other industrial sectors, TVA is facing more stringent requirements related to protection of wetlands, reductions in storm water impacts from construction activities, water quality degradation and criteria, and laboratory analytical methods. TVA is also following litigation related to the use of herbicides, water transfers, and releases from dams. TVA has a good compliance record and is not facing any substantive requirements related to non-compliance with existing Clean Water Act regulations.

Hazardous Substances

Liability for releases and cleanup of hazardous substances is regulated by the federal Comprehensive Environmental Response, Compensation, and Liability Act, among others, and similar state statutes. In a manner similar to many other industries and power systems, TVA has generated or used hazardous substances over the years. TVA operations at some TVA-owned facilities have resulted in releases of hazardous substances and/or oil which require cleanup and/or remediation. TVA also is aware of alleged hazardous-substance releases at 10 non-TVA areas for which it may have some liability. TVA has reached agreements with EPA to settle its liability at two of the non-TVA areas for a total of less than $0.1 million. There have been no recent assertions of TVA liability for six of the non-TVA areas, and (depending on the site) there is little or no known evidence that TVA contributed any significant quantity of hazardous substances to these six sites. There is evidence that TVA sent materials to the remaining two non-TVA areas. The information necessary to estimate the total cleanup costs, and most of the evidence that might be used to estimate TVA’s allocated share of such costs and evaluate the likely effectiveness of

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TVA’s potential defenses either have not been developed and/or are under the control of parties other than TVA. Consequently, TVA is unable at this time to estimate its liability related to these sites.

As of September 30, 2006, TVA’s estimated liability for environmental cleanup 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.

Coal-Combustion Wastes

Coal combustion waste disposed in landfills and surface impoundments continues to be regulated as non-hazardous. As part of this 2000 regulatory determination, EPA committed to developing stricter standards for the management of coal-combustion wastes. EPA has also been petitioned to develop stringent regulations relative to the disposal of coal combustion waste. EPA now is developing national solid waste management standards to address coal-combustion wastes disposed in unlined landfills and surface impoundments or placed in mines. These standards are likely to include increased groundwater monitoring, more stringent siting requirements, and closure of existing waste-management facilities not meeting minimum standards. EPA is expected to issue these new management standards sometime in 2007 according to its published Regulatory Agenda. TVA is monitoring these developments and will evaluate the potential impact of these rules upon its operations as more information becomes available.

Employee Relations

On September 30, 2006, TVA had approximately 12,600 employees, of whom approximately 5,285 were trades and labor employees. 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 predicted in forward-looking statements. Although the risk factors described below are the ones that TVA management considers significant, additional risk factors that are not presently known to TVA management or that TVA management presently considers insignificant may also impair TVA’s business operations. Although TVA has the authority to set its own rates and thus mitigate some risks by increasing rates, it is possible that partially or completely eliminating one or more of these risks through rate increases might adversely affect TVA commercially or politically. 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.

For ease of reference, the risk factors are presented in four categories: strategic risks, operational risks, financial risks, and risks related to TVA securities.

Strategic Risks

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

Although it is difficult to predict exactly how any new laws and regulations would impact TVA, some of the possible effects are described below.

•

TVA could lose its protected service territory.

TVA’s service area is primarily defined by two provisions of law.

—

The TVA Act provides that, subject to certain minor exceptions, neither TVA nor its distributor customers may be a source of power supply outside of TVA’s defined service area. This provision is often called the “fence” since it limits TVA’s sales activities to a specified service area.

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—

The Federal Power Act prevents FERC from ordering TVA to provide access to its transmission lines for the purpose of delivering power to customers within TVA’s defined service area. This provision is often called the “anti-cherrypicking provision” since it prevents competitors from “cherrypicking” TVA’s customers.

If Congress were to eliminate or reduce the coverage of the anti-cherrypicking provision, TVA could lose a significant number of its customers, and the loss of these customers could adversely affect TVA’s cash flows, results of operations, and financial condition.

•

The TVA Board could 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 review. The loss of this authority could have materially adverse effects on TVA including, but not limited to, the following:

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

	—		TVA might be subject to additional regulatory oversight that could impede TVA’s ability to manage its business.

	•		*TVA could become subject to increased environmental regulation.*

There is a risk that new environmental laws and regulations could become applicable to TVA or its facilities and that existing environmental regulations could be revised or reinterpreted in a way that adversely affects TVA. Any such developments could require TVA to make significant capital expenditures, increase TVA’s operating and maintenance costs, or even lead to TVA’s closing certain facilities. For example, proposals in Congress that would regulate carbon dioxide and other greenhouse gases could require TVA and other electric utilities to incur significant increased costs. See Item 1, Business — Environmental Matters.

•

TVA could become subject to increased regulation by the NRC.

The NRC has broad authority to impose requirements relating to the licensing, operation, and decommissioning of nuclear generation facilities. If the NRC modifies existing requirements or imposes new requirements, TVA could be required to make substantial capital expenditures at its nuclear plants or make substantial contributions to its nuclear decommissioning trust. 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 could lose responsibility for managing the Tennessee River system.

TVA’s management of the rivers 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 river system could negatively affect TVA’s operations.

•

Congress could take actions that lead to a downgrade of TVA’s credit rating.

TVA’s rated securities are currently rated “Aaa” by Moody’s Investors Service and “AAA” by Standard and Poor’s and Fitch Ratings, which are the highest ratings assigned by these rating agencies. TVA’s credit ratings are not based solely on its underlying business or financial condition, which by themselves may not be commensurate with a triple-A rating. TVA’s current ratings are based to a large extent on the body of 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.

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•

TVA’s debt ceiling could become more restrictive.

The TVA Act provides that TVA can issue bonds, notes, and other evidences of indebtedness (“Bonds”) in an amount not to exceed $30 billion outstanding at any time. If Congress either lowers the debt ceiling or broadens the types of financial instruments that are covered by the debt ceiling, TVA might not be able to raise enough capital to, among other things, service its financial obligations, properly operate and maintain its power assets, and provide for reinvestment in its power program.

TVA may lose some of its customers.

As of September 30, 2006, six distributor customers had notices in effect terminating their power contracts with TVA. Although sales to these six distributor customers generated only 2.9 percent of TVA’s total operating revenues in 2006, the loss of additional customers could have a material adverse effect on TVA’s cash flows, results of operations, and financial condition. See Item 1, Business —Customers — Termination Notices.

Operational Risks

TVA’s generation and transmission assets may not operate as planned.

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

	•		Might have to invest a significant amount of resources to repair or replace the assets;

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

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

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

	•		Might have to remediate collateral damage caused by a failure of the assets.

In addition, the failure of TVA’s assets to perform as planned could result in such events as the failure of a dam or a nuclear accident. Any of these potential outcomes could negatively affect TVA’s cash flows, results of operations, and financial condition.

TVA’s fuel supply might be disrupted.

TVA purchases coal, uranium, fuel oil, and natural gas from a number of suppliers. Disruption in the acquisition or delivery of fuel, such as the disruptions TVA experienced in 2006 in acquiring coal, may result from a variety of factors, including, but not limited to, weather, production or transportation difficulties, labor relations, or environmental regulations affecting TVA’s fuel suppliers. These disruptions could adversely affect TVA’s ability to operate its facilities and could require TVA to acquire power at higher prices on the spot market, thereby adversely affecting TVA’s cash flows, results of operations, and financial condition.

Purchased power prices may be highly volatile, and providers of purchased power may fail to perform under their contracts with TVA.

TVA acquires a portion of its electricity needs through purchased power arrangements. The price for purchased power has been quite volatile in recent years, so the price that TVA pays for purchased power may increase significantly in the future. In addition, if one of TVA’s purchased power suppliers fails to perform under the terms of its contract with TVA, TVA might have to purchase replacement power on the spot market, 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. Moreover, if TVA is unable to acquire replacement power on the spot market and does not have enough reserve generation capacity available to offset the loss of power from the purchased power supplier, TVA might be unable to satisfy its own obligations to deliver power. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations — Business Overview — Challenges During 2006 — Increased Fuel and Purchased Power Costs and Risk Management Activities — Credit Risk — Credit of Other Counterparties.

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Compliance with existing environmental laws and regulations may affect TVA’s operations in unexpected ways.

TVA is subject to risks from existing federal, state, and local environmental laws and regulations including, but not limited to, the following:

	•		Compliance with existing environmental laws and regulations may cost TVA more than it anticipates.

	•		At some of TVA’s older facilities, it may be uneconomical for TVA to install the necessary equipment to comply with existing environmental laws, which may cause TVA to shut down those facilities.

	•		TVA may be responsible for on-site liabilities associated with the environmental condition of facilities that it has acquired or developed, regardless of when the liabilities arose and whether they are known or unknown.

	•		TVA may be unable to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals or if TVA fails to obtain, maintain, or comply with any such approval, TVA may be unable to operate its facilities or may have to pay fines or penalties.

See Item 1, Business — Environmental Matters.

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

TVA may incur delays and additional costs in power plant construction.

TVA is in the process of restarting Browns Ferry Unit 1 and may need to construct more generating facilities in the future. The completion of such facilities involves substantial risks of delays and cost overruns. If TVA is unable to complete the development or construction of a facility or decides to delay or cancel construction of 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 reduced plant efficiency and higher operating costs. See Item 1, Business — Nuclear.

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

TVA is involved in various legal proceedings and will become involved in other legal proceedings in the future in the ordinary course of business. 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 could require TVA to change its business practices or procedures, which could also have a material adverse effect on TVA’s cash flows, results of operations, and financial condition. See Item 3, Legal Proceedings.

TVA’s ability to supply power and its customers’ demands for power are influenced by weather conditions.

Extreme peaks in either the summer or winter may increase the demand for power and require TVA to purchase power at high prices in order 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, weather conditions affect TVA’s ability to supply power to its customers, because in periods of low 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 temperatures in the summer may limit TVA’s ability to use water from the Tennessee River system for cooling at its generating facilities, thereby limiting TVA’s ability to operate its generating facilities.

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TVA’s transmission reliability could be affected by problems at other utilities or its own facilities.

TVA’s transmission facilities are directly interconnected with the transmission facilities of neighboring utilities and are thus part of an interstate power transmission grid. Accordingly, problems at other utilities, or at TVA’s own facilities, may cause interruptions in TVA’s transmission service. If TVA were to suffer a transmission service interruption, TVA’s cash flows, results of operations, and financial condition could be negatively affected.

An incident at any nuclear facility, even one unaffiliated with TVA, could result in increased expenses and oversight.

A nuclear incident at a TVA facility could have significant consequences including loss of life and damage to or loss of the facility. Any nuclear incident, even at a facility unaffiliated with TVA, has the potential to impact TVA adversely by obligating TVA to pay up to $90 million per year and a total of $604 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 premiums, reducing the availability 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.

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

TVA could be adversely affected by catastrophic events such as fires, earthquakes, floods, wars, terrorist activities, pandemics, and other similar events. These events, the frequency and severity of which are unpredictable, could directly impact TVA’s power operations and negatively affect TVA’s cash flows, results of operations, and financial condition. Additionally, such events could indirectly impact TVA by, among other things, disrupting supply lines or operations of a contractor or supplier, leading to an economic downturn, or creating instability in the financial markets.

Demand for electricity supplied by TVA could be reduced by changes in technology.

Research and development activities are ongoing to improve existing and alternative technologies to produce electricity, including gas turbines, fuel cells, microturbines, and solar cells. 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, thereby negatively affecting TVA’s cash flows, results of operations, and financial condition.

Financial Risks

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

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

	•		Commodity Price Risk. Prices of commodities critical to TVA’s operations, including coal, uranium, natural gas, fuel oil, emission allowances, and electricity, have been extremely volatile in recent years. If TVA fails to effectively manage its commodity price risk, customers may look for alternative power suppliers.

	•		Investment Price Risk. TVA is exposed to investment price risk in both its nuclear decommissioning trust and its pension fund. If the value of the investments held in the nuclear decommissioning trust or the pension fund decreases significantly, TVA could be required to make substantial unplanned contributions to these funds, which would negatively affect TVA’s cash flows, results of operations, and financial condition.

	•		Interest Rate Risk. Changes in interest rates could negatively affect TVA’s cash flows, results of operations, and financial condition by increasing the amount of interest that TVA pays on new Bonds that it issues, decreasing the return that TVA receives on its short-term investments, decreasing the value of the investments in TVA’s pension fund and nuclear decommissioning trust, and increasing the losses on the mark-to-market valuation of certain derivative transactions into which TVA has entered.

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•

Credit 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 could be adversely affected. In addition, the failure of a counterparty to perform could make it difficult for TVA to perform its obligations, particularly if the counterparty is a supplier of electricity or fuel to TVA.

See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations — Risk Management Activities for more information regarding market risks.

TVA and owners of TVA securities could be impacted by a downgrade of TVA’s credit rating.

A downgrade in TVA’s credit rating could 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 could have the following effects:

	•		A downgrade would increase TVA’s interest expense by increasing the interest rates that TVA pays on new 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.

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

	•		A downgrade below a contractual threshold would prevent TVA from borrowing under two credit facilities totaling $2.5 billion without the consent of the national bank that is the counterparty to the credit facilities.

	•		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.

See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.

TVA may have to make significant unplanned contributions to fund its pension and other postretirement benefit plans.

TVA’s costs of providing pension benefits and other postretirement benefits depend upon a number of factors, including, but not limited to:

	•		Provisions of the pension and postretirement benefit plans;

	•		Changing employee demographics;

	•		Rates of increase in compensation levels;

	•		Rates of return on plan assets;

	•		Discount rates used in determining future benefit obligations;

	•		Rates of increase in health care costs;

	•		Levels of interest rates used to measure the required minimum funding levels of the plans;

	•		Future government regulation; and

	•		Contributions made to the plans.

Any number of these factors could increase TVA’s costs of providing pension and other postretirement benefits and require TVA to make significant unplanned contributions to the plans. Such contributions would negatively affect TVA’s cash flows, results of operations, and financial condition.

TVA may have to make significant unplanned contributions to its nuclear decommissioning trust.

TVA maintains a nuclear decommissioning trust for the purpose of providing funds to decommission TVA’s nuclear facilities. The decommissioning trust is invested in securities generally designed to achieve a return in line with overall equity market performance. TVA might have to make significant unplanned contributions to the trust if, among other things:

•

The value of the investments in the trust declines significantly;

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	•		The laws or regulations regarding nuclear decommissioning change the decommissioning funding requirements;

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

	•		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 TVA anticipates.

If TVA makes unplanned contributions to the trust, the contributions would negatively affect TVA’s cash flows, results of operations, and financial condition.

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

TVA’s cash management policy is to use cash provided by operations together with proceeds from issuing discount notes and drawing on a $150 million note with the U.S. Treasury to fund TVA’s current cash requirements. In addition, TVA has access to $2.5 billion of credit facilities with a national bank. In light of TVA’s cash management policy, it is critical that TVA continue to have access to the debt markets, for if TVA is unable to access the debt markets, TVA might be unable to meet its current 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 the debt markets to raise capital since it is not authorized to issue equity securities.

Approaching or reaching its debt ceiling could limit TVA’s ability to carry out its business.

At September 30, 2006, TVA had approximately $22.9 billion of Bonds outstanding. TVA has a statutorily imposed ceiling of $30 billion on outstanding Bonds. Approaching or reaching this debt ceiling could adversely affect TVA’s business by limiting TVA’s ability to borrow money and increasing the cost of servicing TVA’s debt. In addition, approaching or reaching this debt ceiling could lead to increased legislative or regulatory oversight of TVA’s activities.

TVA’s cash flows, results of operations, and financial condition could be negatively affected by economic downturns.

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

TVA’s financial control system cannot guarantee that all control issues and instances of fraud 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 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. See Item 9A, Controls and Procedures for TVA’s assessment as of September 30, 2006, which includes two material weakness items.

TVA could lose the ability to use regulatory accounting and be required to write off a significant amount of regulatory assets.

TVA is able to use regulatory accounting because it satisfies the requirements set forth in Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation.” Accordingly, TVA records as assets certain costs that would not be recorded as assets under generally accepted accounting principles for non-regulated entities. As of September 30, 2006, TVA had $5.3 billion of regulatory assets. If TVA loses its ability to use regulatory accounting, TVA could be required to write-off its regulatory assets. Any asset write-offs would be required to be recognized in earnings in the period in which regulatory accounting under SFAS No. 71 ceased to apply to TVA.

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Risks Related to TVA Securities

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. Principal and interest on TVA securities are payable solely from TVA’s 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.

The trading market for TVA 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, and the power bonds issued under TVA’s electronotes^® program, which is TVA’s medium-term note 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 of Bonds to sell their Bonds or 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.

If a particular offering of Bonds is sold to or through underwriters, the underwriters may attempt to make a market in the Bonds. The underwriters would not be obligated to do so, however, and could terminate any market-making activity 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.

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 by negotiated purchase or by eminent domain.

Generating Properties

At September 30, 2006, TVA’s generating assets consisted of 59 coal-fired units, five nuclear units, 109 conventional hydroelectric units, four pumped storage units, 72 combustion turbine units, nine diesel generator units, one digester gas site, one wind energy site, and 16 solar energy sites. See Item 1, Business — Power Supply for a chart that indicates the location, capacity, and in-service dates for each of these properties. In addition, TVA is in the process of restarting Browns Ferry Unit 1. Browns Ferry Unit 1 is scheduled to go online in early 2007 and as of September 30, 2006, was 94 percent complete.

Twenty-four of TVA’s combustion turbines are subject to lease-leaseback arrangements. For more information regarding these arrangements, see Note 11 — Other Financing Obligations.

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Transmission Properties

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

	•		Approximately 17,000 circuit miles of transmission lines, including 2,400 miles of extra-high-voltage (500,000 volt) transmission lines;

	•		537 substations, power switchyards, and switching stations;

	•		1,045 individual interchange and customer connection points; and

	•		260,000 right-of-way acres.

The easements and rights-of-way give TVA the right to construct, operate, and maintain the transmission lines, as well as remove trees located outside the rights of way. Fee title to the land remains with the landowner.

In 2003, TVA entered into a lease-leaseback of certain qualified technological equipment and other software related to TVA’s transmission system. For more information regarding this transaction, see Note 11 — Other Financing Obligations.

Resource Stewardship Properties

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

	•		11,000 miles of reservoir shoreline;

	•		293,000 acres of reservoir land;

	•		650,000 surface acres of water; and

	•		Over 100 public recreation areas.

Buildings

TVA owns 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 when it deems appropriate, including its Chattanooga Office Complex. TVA’s lease of the Chattanooga Office Complex expires in 2011, but TVA has the right to extend the lease for up to 30 years. TVA also owns and leases a significant number of buildings in Muscle Shoals, Alabama.

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 to provide 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 or other purposes.

In addition, TVA’s bond covenants prohibit 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.

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ITEM 3. LEGAL PROCEEDINGS

TVA is subject to various legal proceedings and claims that have arisen in the ordinary course of business. These proceedings and claims include the matters discussed below.

Economy Surplus Power Case

On August 31, 1999, suit was filed against TVA in the United States District Court for the Northern District of Alabama by Birmingham Steel Corporation, on behalf of itself and a class of TVA industrial customers who contracted for economy surplus power. While Birmingham Steel Corporation was the original class representative, it filed for bankruptcy and was excluded from the class. Johns Manville Corporation was substituted as the class representative. The lawsuit alleges that TVA overcharged for economy surplus power during the summer of 1998 by improperly including some incremental costs when calculating the price of economy surplus power. The class members seek over $100 million in damages. On April 18, 2006, the district court ruled on motions for summary judgment filed by both sides. The court held that TVA improperly included charges for approximately 500 hours of power purchased in advance and breached the contracts. The court rejected TVA’s position that the additional price charged for all hours represented actual incremental costs incurred by TVA in supplying economy surplus power and thus was an appropriate part of the economy surplus power contract price. The court granted the plaintiffs’ motion for summary judgment on liability, even though it acknowledged that there are disputed factual issues as to TVA’s defenses. TVA filed a motion seeking permission to take an interlocutory appeal of the court’s ruling on summary judgment. On July 31, 2006, the court reconsidered its decision on summary judgment with respect to TVA’s affirmative defenses and held that TVA is entitled to a trial on its affirmative defenses. A mediator has been selected and the parties anticipate engaging in mediation in December 2006. Trial on TVA’s affirmative defenses and the class members’ damages is scheduled for February 5, 2007.

Case Against TVA and 22 Electric Cooperatives

On December 2, 2004, the United States District Court for the Middle District of Tennessee, dismissed a lawsuit filed by John McCarthy, Stan Cooper, Joe Sliger, Mike Bell, Don Rackley, Terry Motley, Billy Borchert, Jim Foster, and Ryan Hargis on behalf of themselves and all others similarly situated against TVA and the Middle Tennessee Electric Membership Cooperative, Appalachian Electric Cooperative, Caney Fork Electric Corporation, Inc., Chickasaw Electric Cooperative, Cumberland Electric Membership Corporation, Duck River Electric Membership Corporation, Fayetteville Public Utilities, Forked Deer Electric Cooperative, Inc., Fort Loudoun Electric Cooperative, Gibson Electric Membership Corporation, Holston Electric Cooperative, Inc., Meriwether Lewis Electric Cooperative, Mountain Electric Cooperative, Inc., Pickwick Electric Cooperative, Plateau Electric Cooperative, Powell Valley Electric Cooperative, Sequachee Valley Electric Cooperative, Southwest Tennessee Electric Membership Corporation, Tennessee Valley Electric Cooperative, Tri-County Electric Membership Cooperation, Tri-State Electric Membership Cooperation, Upper Cumberland Electric Membership Corporation, and Volunteer Energy Cooperative. The lawsuit in part challenged TVA’s practice of setting rates for electric power charged by distributor customers through TVA’s contracts with distributor customers. In granting the defendants’ motions to dismiss, the court held that the claims alleging violations of state law failed because the plaintiffs (consisting of Tennessee residents and customers of certain of the cooperatives) had not completed the steps necessary to bring these claims in court. With respect to the claim against TVA, the court held that the alleged violations of federal law failed as a matter of law because Congress had specifically authorized TVA to set the rates charged by distributor customers through TVA’s contracts with distributor customers. The plaintiffs appealed to the United States Court of Appeals for the Sixth Circuit (“Sixth Circuit”), and on October 17, 2006, the Sixth Circuit affirmed the district court’s decision, and held, among other things, that TVA’s rates were not subject to judicial review and that TVA is not subject to antitrust liability when doing so would interfere with TVA’s purposes.

Global Warming Cases

On July 21, 2004, two lawsuits were filed against TVA in the United States District Court for the Southern District of New York alleging that global warming is a public nuisance and that carbon dioxide 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 companies. The second case, which alleges both public and private nuisance, was filed against the same defendants by Open Space Institute, Inc., Open Space Conservancy, Inc., and the Audubon Society of New Hampshire. There are no Clean Air Act requirements limiting carbon dioxide emissions, and, accordingly, the suits do not involve allegations of regulatory noncompliance. The plaintiffs do not seek monetary damages, but instead seek a court order requiring each defendant to cap its carbon dioxide 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 U.S. Court of Appeals for the Second Circuit (“Second Circuit”). Oral argument was held before the Second Circuit on June 7, 2006, and the parties are awaiting a decision.

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Case Involving Modifications to the Colbert Fossil Plant

The National Parks Conservation Association, Inc. (“NPCA”), and Sierra Club, Inc. (“Sierra Club”), filed suit on February 13, 2001, in the United States District Court for the Northern District of Alabama, alleging that TVA violated the Clean Air Act and implementing regulations at TVA’s Colbert Fossil Plant (“Colbert”), a coal-fired electric generating facility located in Tuscumbia, Alabama. The plaintiffs allege that TVA made major modifications to one of the power generating units, specifically Colbert Unit 5, without obtaining preconstruction permits (in alleged violation of the Prevention of Significant Deterioration (“PSD”) program and the Nonattainment New Source Review (“NNSR”) program) and without complying with emission standards (in alleged violation of the New Source Performance Standards (“NSPS”) program). The plaintiffs seek injunctive relief; civil penalties of $25,000 per day for each violation on or before January 30, 1997, and $27,500 per day for each violation after that date; an order that TVA pay up to $100,000 for beneficial mitigation projects; and costs of litigation, including attorney and expert witness fees. On November 29, 2005, the district court held that sovereign immunity precluded the plaintiffs from recovering civil penalties against TVA. On January 17, 2006, the district court dismissed the action, on the basis that plaintiffs failed to provide adequate notice of NSPS claims and that the statute of limitations curtailed the PSD and NNSR claims. The plaintiffs appealed to the U.S. Court of Appeals for the Eleventh Circuit (“Eleventh Circuit”) on January 25, 2006. Briefing of the appeal to the Eleventh Circuit was completed in July 2006. Oral argument of the appeal is scheduled for January 11, 2007. If the decision is reversed on appeal, there is a reasonable possibility that TVA will be ordered to install additional controls on Colbert Unit 5.

Case Involving Modifications to Bull Run Fossil Plant

The NPCA 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 requirements of the Clean Air Act when TVA modified its Bull Run Fossil Plant (“Bull Run”), a coal-fired electric generating facility located in Anderson County, Tennessee. In March 2005, the district court granted TVA’s motion to dismiss the lawsuit on statute of limitation grounds. The plaintiffs’ motion for reconsideration was denied, and they appealed to the Sixth Circuit. Amicus curiae briefs supporting the plaintiffs’ appeal have been filed by New York, Connecticut, Illinois, Iowa, Maryland, New Hampshire, New Jersey, New Mexico, Rhode Island, Kentucky, Massachusetts, and Pennsylvania. Several Ohio utilities filed an amicus curiae brief supporting TVA. Briefing of the appeal to the Sixth Circuit was completed in May 2006. Oral argument was held on September 18, 2006, and the parties are awaiting a decision.

Case Involving Opacity at Colbert

On September 16, 2002, the Sierra Club and the Alabama Environmental Council filed a lawsuit in the United States District Court for the Northern District of Alabama alleging that TVA violated Clean Air Act opacity limits applicable to Colbert between July 1, 1997, and June 30, 2002. The plaintiffs seek a court order that could require TVA to incur substantial additional costs for environmental controls, and pay civil penalties of up to approximately $250 million. After the court dismissed the complaint (finding that the challenged emissions were within Alabama’s two percent de minimis rule, which provided a safe harbor if emissions did not exceed allowable opacity limits by more than two percent each quarter), the plaintiffs appealed the district court’s decision to the Eleventh Circuit. On November 22, 2005, the Eleventh Circuit affirmed the district court’s dismissal of the claims for civil penalties, but held that the Alabama de minimis rule was not applicable because Alabama had not yet obtained EPA approval of that rule. The case was remanded to the district court for further proceedings, and the plaintiffs filed a motion for summary judgment. On May 23, 2006, the district court issued orders staying the matter until a decision is issued in a Clean Air Act case accepted by the Supreme Court, United States v. Duke Energy; referring the action to mediation to be completed before the close of business on December 15, 2006, unless the district court extends the deadline; and denying as moot the plaintiffs’ motions to hold TVA liable (with leave to file again, if necessary, after the stay is lifted). On May 26, 2006, the plaintiffs asked the district court to reconsider its orders, and in the alternative to allow an interlocutory appeal, and on July 5, 2006, the district court denied plaintiffs’ motion. The parties participated in mediation on September 7, 2006, and for several weeks thereafter. The case remains stayed.

Case Brought by North Carolina Alleging Public Nuisance

On January 30, 2006, North Carolina’s Attorney General 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 constitute public nuisances. On April 3, 2006, TVA moved to dismiss the suit on grounds that the case is not suitable for judicial resolution because of separation of powers principles, including the fact that these matters are based on policy decisions left to TVA’s discretion in its capacity as a government agency and thus are not subject to tort liability (the “discretionary function doctrine”), as well as the Supremacy Clause. In July 2006, the court denied TVA’s motion, and set the trial for the term of court beginning October 2007. On August 4, 2006, TVA filed a motion requesting permission to file an interlocutory appeal with the United States Court of Appeals for the Fourth Circuit (the “Fourth Circuit”) which the district court granted on September 7, 2006. On September 21, 2006, TVA petitioned the Fourth Circuit to allow the interlocutory appeal. The Fourth Circuit has granted the petition and set a briefing schedule, with briefing to be completed in January 2007. The district court did not stay the case during this appeal, and trial remains scheduled for October 2007.

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Case Involving North Carolina’s Petition to the EPA

In 2005, the State of North Carolina petitioned the EPA under Section 126 of the Clean Air Act to impose additional emission reduction requirements for sulfur dioxide and nitrogen oxides emitted by coal-fired power plants in 13 states, including states where TVA’s coal-fired power plants are located. In March 2006, the EPA denied the North Carolina petition primarily on the basis that the Clean Air Interstate Rule remedies the problem. In June 2006, North Carolina filed a petition for review of EPA’s decision with the United States Court of Appeals for the District of Columbia Circuit.

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 residents of Mississippi 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, including TVA and other utilities. The plaintiffs allege 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 are seeking monetary damages among other relief. TVA has moved to dismiss the complaint on grounds that TVA’s operation of its coal-fired plants is not subject to tort liability due to the discretionary function doctrine.

Claim Involving Areva Fuel Fabrication

On November 9, 2005, TVA received two invoices totaling $76 million from Areva (“Areva”) and an affiliated company, the successor of Babcock and Wilcox Company (“B&W”). In 1970, TVA and B&W entered into a contract for fuel fabrication services for its Bellefonte Nuclear Plant. Areva’s invoices are based upon its belief that the 1970 contract required TVA to buy more fuel fabrication services from B&W than TVA actually purchased. A meeting was held between TVA and Areva on May 31, 2006, to discuss the issue. TVA subsequently received a letter from Areva which reasserted its claim, but reduced the value of the claim to $26 million. Areva has not provided any further information concerning the claim nor has it explained the reason for the reduction in the claim amount.

Notification of Potential Liability for Ward Transformer Site

TVA has been notified by one of the parties involved with clean-up of the Ward Transformer (“Ward”) Superfund Site, a facility located in Raleigh, North Carolina, that it considers TVA a potentially responsible party (“PRP”) and intends to pursue a claim against TVA. Under the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), any entity which arranges for disposal of a CERCLA hazardous substance at a site may bear liability for the cost of cleaning up the site. There is evidence that TVA sent transformers to Ward that contained Polychlorinated Biphenyls. Several responsible parties have entered into a settlement agreement with EPA to clean up on-site contamination at the site, and the cost of the on-site cleanup is currently estimated to be $20 million. EPA is also investigating off-site contamination from Ward operations, but TVA has no information as to the estimated costs, if any, of cleaning up off-site contamination. It is unknown at this time what level of liability, if any, TVA will have in these matters, whether it will be required to contribute, and, if so, how much such a contribution would be.

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. Adverse outcomes in these proceedings would not normally be material to TVA’s business, although it is possible that some outcomes could require TVA to change how it handles certain personnel matters or operates its plants.

In accordance with SFAS No. 5, “Accounting for Contingencies,” TVA had accrued approximately $22.9 million with respect to the proceedings described above as of September 30, 2006, as well as approximately $5.1 million with respect to other proceedings that have arisen in the normal course of TVA’s business. 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.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Not applicable.

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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 2002 through 2006 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. In 2003, TVA changed its method for recording interdivisional sales, displacement sales, and limestone used for the production of electricity. Certain reclassifications have been made to the 2002 financial statements to conform to the 2003, 2004, 2005, and 2006 presentation.

Statements of Income Data

For the years ended September 30 (in millions)


	2006			2005			2004			2003			2002
Operating revenues	$	9,185		$	7,794		$	7,533		$	6,953		$	6,798
Operating expenses		(7,582	) ¹		(6,503	) ¹		(5,873	) ²		(5,398	)		(5,323	) ³

Operating income		1,603			1,291			1,660			1,555			1,475
Other income, net⁴		65			52			43			32			19
Unrealized (loss)/gain on derivative contracts, net		(15	)		3			(7	)		(7	)		—
Interest expense, net ⁴		(1,215	)		(1,261	)		(1,310	)		(1,353	)		(1,431	)
Cumulative effect of accounting changes		(109	) ⁵		—			—			217	⁶		—

Total net income	$	329		$	85		$	386		$	444		$	63


Notes

(1)		During 2006 and 2005, TVA recognized a total of $9 million and $24 million, respectively, in impairment losses related to its property, plant, and equipment. The losses included a $2 million and an $8 million write-down in 2006 and 2005, respectively, on one of two buildings in TVA’s Knoxville Office Complex based on TVA’s plans to sell or lease the East Tower of the Knoxville Office Complex. TVA also recognized a $7 million and a $16 million write-down in 2006 and 2005, respectively, of certain Construction in Progress assets related to new pollution-control and other technologies that had not been proven effective and a re-evaluation of other projects due to funding limitations.

(2)		During 2004, TVA was notified by a supplier that it would not proceed with manufacturing of fuel cells to be installed in the partially completed Regenesys energy storage plant in Columbus, Mississippi. Accordingly, TVA recognized a net $20 million loss on the cancellation of the Regenesys project. See Note 1 — Project Cancellation.

(3)		Due to changes in the market forecast, TVA elected not to complete a gas-fired combined cycle plant in 2002. TVA recognized a $154 million loss related to the cancellation of this project.

(4)		Prior to 2006, TVA reported short-term investment interest income with interest expense. Interest income of $19 million, $6 million, $3 million, and $2 million for 2005, 2004, 2003, and 2002, respectively, has been reclassified from Interest expense, net to Other Income.

(5)		During 2006, TVA adopted FIN No. 47, “Accounting for Conditional Asset Retirement Obligations — an interpretation of FASB Statement No. 143,” which resulted in a cumulative effect charge to income of $109 million and an increase in accumulated depreciation of $20 million. See Note 1 — Impact of New Accounting Standards and Interpretations.

(6)		The cumulative effects of $217 million are due to two accounting changes. Effective October 1, 2002, the TVA Board approved a change in the methodology for estimating unbilled revenue from electricity sales. The impact of this change resulted in an increase in accounts receivable of $412 million with a cumulative effect gain for the change in accounting for unbilled revenue. In addition, TVA adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” which resulted in a cumulative effect charge to income of $195 million and an increase in accumulated depreciation of $206 million. See Note 1 — Impact of New Accounting Standards and Interpretations.

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Balance Sheets Data

At September 30 (in millions)


	2006		2005		2004		2003 ¹			2002¹
Assets
Current assets ²	$	2,669	$	2,176	$	2,295	$	2,238		$	1,626
Property, plant, and equipment, net		24,434		23,888		23,699		23,125			22,175
Investment funds		972		858		744		638			510
Regulatory and other long-term assets		6,445		7,551		7,451		7,027			6,522

Total assets	$	34,520	$	34,473	$	34,189	$	33,028		$	30,833


Liabilities and proprietary capital
Current liabilities ²	$	5,203	$	6,724	$	5,420	$	5,819	³	$	4,755
Regulatory and other liabilities		7,074		7,606		7,168		5,114			3,304
Long-term debt, net of discount		19,544		17,751		19,337		20,201			21,358

Total liabilities		31,821		32,081		31,925		31,134			29,417

Retained earnings		1,565		1,244		1,162		783			349
Other proprietary capital		1,134		1,148		1,102		1,111			1,067

Total proprietary capital		2,699		2,392		2,264		1,894			1,416

Total liabilities and proprietary capital	$	34,520	$	34,473	$	34,189	$	33,028		$	30,833


Notes

(1)		Prior to 2004, TVA presented 2 balance sheets — one for its power program and one for all programs. The 2003 and 2002 Balance Sheets presented above are for all programs which is consistent with the presentation for 2004, 2005, and 2006.

(2)		In 2006, TVA began to apply certain customer advances previously reported as Current liabilities as a reduction to Accounts receivable. The advances were $93 million in 2005, $91 million in 2004, $83 million in 2003, and $56 million in 2002 and reduced both Current assets and Current liabilities by the same amount.

(3)		TVA reclassified $5 million related to discounted energy units from a long-term liability to a short-term liability in 2003.

Financial Obligations

As of September 30 (in millions)


	2006		2005		2004		2003		2002
Long-term debt, including current maturities	$	20,529	$	20,444	$	21,337	$	22,537	$	21,358

Other long-term obligations
Capital leases *		128		150		138		151		162
Lease/leaseback commitments		1,108		1,143		1,178		1,238		561
Energy prepayment obligations		1,244		1,350		1,455		47		—

Total other financing obligations		2,480		2,643		2,771		1,436		723

Discount notes		2,376		2,469		1,924		2,080		3,492


Financial obligations	$	25,385	$	25,556	$	26,032	$	26,053	$	25,573


Note

*		Included in Nuclear fuel and Capital leases on the Balance Sheets.

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Comparative Five Year Data

Statistical and Financial Summaries

For the years ended, or as of, September 30, as appropriate


	2006			2005			2004			2003			2002

Sales of electricity (millions of kWh) ¹
Municipalities and cooperatives		143,343			136,640			133,161			130,769			128,600
Industries directly served		30,987			30,872			29,344			27,756			26,478
Federal agencies and other		2,040			3,986			3,353			3,009			3,579

Total sales		176,370			171,498			165,858			161,534			158,657


Operating revenues (millions of dollars)¹
Electric
Municipalities and cooperatives	$	7,880		$	6,561		$	6,457		$	5,974		$	5,856
Industries directly served		1,066			962			842			781			732
Federal agencies and other		116			181			140			120			120
Other		123			90			94			78			90

Total revenues	$	9,185		$	7,794		$	7,533		$	6,953		$	6,798


Electric revenue per kWh (cents)		5.14			4.49			4.49			4.26			4.23

Winter net dependable generating capacity (megawatts) ²
Coal-fired		15,081			15,075			15,076			15,029			15,023
Nuclear units in service		5,770			5,790			5,777			5,776			5,751
Hydroelectric		5,144			5,104			4,981			5,022			4,924
Combustion turbine ³ and other ⁴		4,681			4,675			4,685			4,655			4,643

TVA facilities		30,676			30,644			30,519			30,482			30,341
Power purchase agreements		4,275			3,337			2,670			1,176			1,176

Total available capacity ⁵		34,951			33,981			33,189			31,658			31,517


System peak load (megawatts)—summer		32,008			31,924			29,966			28,530			29,052

System peak load (megawatts)—winter		27,718			29,278			27,997			29,866			26,061

Percent gross generation by fuel source
Coal-fired		64	%		62	%		61	%		60	%		63	%
Nuclear		29	%		28	%		30	%		29	%		30	%
Hydroelectric		6	%		10	%		9	%		11	%		6	%
Combustion turbine and other		<1	%		<1	%		<1	%		<1	%		1	%

Fuel cost per kWh (cents)
Coal		2.02			1.65			1.48			1.43			1.39
Natural gas and fuel oil		10.65			11.44			9.01			7.61			4.65
Nuclear		0.38			0.39			0.39			0.39			0.41
Aggregate fuel cost per kWh net thermal generation		1.54			1.30			1.14			1.14			1.11


Notes

(1)		Sales and revenues have been adjusted to include sales to other utilities and to exclude interdivisional sales.

(2)		See Item I, Business — Power Supply.

(3)		As of September 30, 2006, includes twenty-four 85-megawatt combustion turbine units subject to lease/leaseback arrangements.

(4)		See Item I, Business — Power Supply for a discussion of TVA’s diesel generators and renewable resources.

(5)		Total summer net dependable capacity at September 30, 2006, 2005, 2004, 2003, and 2002 was approximately 33,653 megawatts, 32,259 megawatts, 32,059 megawatts, 30,743 megawatts, and 30,477 megawatts, respectively.

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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

Distinguishing Features of TVA’s Business

TVA operates the nation’s largest public power system. In 2006, TVA provided electricity to large industries and federal agencies and to 158 distributor customers that serve approximately 8.7 million people in seven southeastern states. TVA generates almost all of its revenues from the sale of electricity, and in 2006 revenues from the sale of electricity totaled $9.1 billion. As a wholly-owned agency and instrumentality of the United States, however, TVA is different from electric utilities in a number of ways. A few of the more significant differences are discussed below.

Defined Service Area. TVA has a defined service area established by federal law. Subject to certain minor exceptions, TVA may not, without an act of Congress, enter into contracts which 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. Correspondingly, however, the possibility of sales by others into TVA’s service area is significantly limited. The Federal Power Act, primarily through its anti-cherrypicking provision, prevents the Federal Energy Regulatory Commission (“FERC”) from ordering TVA to provide access to its transmission lines for the purpose of delivering power to customers within its service area.

Rate Authority. Typically, a utility is regulated by a public utility commission, which approves the rates the utility may charge. TVA, however, is self-regulated. The TVA Act gives the TVA Board sole responsibility for establishing the rates TVA charges for power. These rates are not subject to review or approval by any state or federal regulatory body. In setting TVA’s rates, however, the TVA Board is charged by the TVA Act to have due regard for the objective that power be sold at rates as low as are feasible. In addition, the TVA Board cannot ignore competitive pressures in setting rates.

Funding. TVA’s operations were originally funded primarily with appropriations from Congress. In 1959, however, Congress passed legislation that required TVA’s power program to be self-financing from power revenues and proceeds from power program financings. Until 1999, TVA continued to receive some appropriations for certain multipurpose activities and for its stewardship activities. Since 1999, however, TVA has not received any appropriations from Congress for any activities and has funded essential stewardship activities primarily with power revenues in accordance with a statutory directive from Congress.

TVA, unlike most 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. The TVA Act authorizes TVA to issue bonds, notes, and other evidences of indebtedness (collectively, “Bonds”) in an amount not to exceed $30 billion at any time. In June 2005, the Office of Management and Budget transmitted draft legislation to Congress that would expand the type of evidences of indebtedness that count toward TVA’s $30 billion debt ceiling. Under this legislation, long-term obligations that finance capital assets would count toward the debt ceiling, including lease-leaseback arrangements and power prepayment agreements with original terms exceeding one year. If Congress decides to broaden the type of financial instruments that are covered by the debt ceiling or to lower the debt ceiling, TVA might not be able to raise enough capital to, among other things, service its then-existing financial obligations, properly operate and maintain its power assets, and provide for reinvestment in its power program. At September 30, 2006, TVA had approximately $22.9 billion of Bonds outstanding. For additional information regarding TVA’s sources of funding, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Sources of Liquidity.

Stewardship Activities. TVA’s mission includes managing the United States’ fifth largest river system — the Tennessee River and its tributaries — 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 economic development. TVA owns and operates 49 dams, which comprise its 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, including cooling water for some of TVA’s fossil fuel and nuclear power plants.

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Strategy and Performance Indicators

Strategy. In the context of these distinguishing features of TVA’s business, the recently restructured TVA Board is now determining TVA’s broad business goals, objectives, and policies and is developing the long-range plans for carrying out these goals, objectives, and policies. These will, among other things, guide TVA’s strategy for addressing the challenges set out below.

Performance Indicators. TVA will, in the interim, be guided by the 2007 performance indicators that the TVA Board approved in November 2006. TVA will work to achieve measurable numeric goals established for each of these indicators, which are designed to relate activity at the operational level to excellence in four key areas: finances, customers, operations, and people. These performance indicators are described in the table below.


Category	Performance Indicator	Description of Performance Indicator

Financial	Delivered Cost of Power Excluding FCA * Costs	Measures the cost per megawatt-hour of power sold to customers excluding costs covered by the FCA

Financial	FCA Costs	Measures costs covered by the FCA per megawatt-hour of power sold

Financial	Productivity	Measures total TVA labor costs and contract labor costs

Customer	Connection Point Interruptions	Measure interruptions of power caused by TVA’s transmission system

Customer	Customer Satisfaction Survey	Measures the satisfaction of TVA’s customers with TVA in a variety of areas

Customer	Economic Development	Measures job growth, the quality of jobs, and capital invested by economic development partners in the TVA service area

Operations	Equivalent Availability Factor	Measures availability of generation

Operations	Environmental Impact	Measures 23 environmental elements to assess the impact of TVA’s operations on air quality, water quality, land, waste production, and energy consumption

People	Safe Workplace	Measures recordable injuries per hours worked


Note

*		FCA — Fuel Cost Adjustment

Challenges During 2006

TVA faced several challenges during 2006 that impacted its cash flows, results of operations, and financial condition. The three most significant of these were the performance challenges at some of TVA’s generation plants, increased fuel and purchased power costs, and adverse weather conditions.

Performance of Certain Generation Assets During the Summer. Many of TVA’s generation assets have been operating since the 1950’s and have been in near constant service since they were completed. In 2006, some of TVA’s generating assets failed to operate as planned during times of high summer demand, and TVA thus had to purchase more power than expected when purchased power prices were high. Significant outages during 2006 included the following:

	•		On May 30, 2006, operators at Unit 1 of Watts Bar Nuclear Plant (“Watts Bar”) detected a problem involving the main turbine and took the reactor offline safely without further incident. The low-pressure turbine from Unit 2 at Watts Bar, which has never been put in service, was modified and used to repair the damaged turbine. The unit returned to service on June 25, 2006. Watts Bar Unit 1 was taken offline again on July 31, 2006, when the main generator shut down, and it returned to full power operation on August 4, 2006. Watts Bar Unit 1 has a net winter dependable capacity of approximately 1,168 megawatts.

	•		Bull Run Fossil Plant (“Bull Run”), which has a winter net dependable capacity of approximately 889 megawatts, was taken offline on July 25, 2006, due to a broken turbine stub shaft. The plant returned to service on August 5, 2006, following replacement of the stub shaft and associated repairs and inspection.

Increased Fuel and Purchased Power Costs. During 2006, TVA’s fuel and purchased power costs increased $732 million, or 28.1 percent, over TVA’s fuel and purchased power costs in 2005. To recover these increased fuel and purchased power costs, TVA implemented two rate increases during 2006, a 7.52 percent rate

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increase effective October 1, 2005, and a 9.95 percent rate increase effective April 1, 2006. The combined rate increases provided additional revenues of approximately $873 million during 2006. To more effectively manage fuel and purchased power costs in the future, the TVA Board approved a fuel cost adjustment (“FCA”) mechanism that will adjust TVA’s rates on a quarterly basis to reflect changing fuel and purchased power costs beginning in 2007. The FCA for the first quarter of 2007 is 0.00 cents per kilowatt-hour, and the FCA for the second quarter of 2007 is 0.01 cents per kilowatt-hour. In connection with approving the FCA, the TVA Board approved a 4.5 percent rate decrease effective on October 1, 2006.

Weather. During 2006, TVA was negatively affected by low rainfall. Water runoff was 63 percent of the planned amount for the TVA basin for 2006, which reduced TVA’s hydroelectric generation, as well as the amount of water available for cooling TVA’s nuclear and coal-fired plants. Hydroelectric generation decreased from 10 percent of TVA’s total generation in 2005 to six percent of TVA’s total generation in 2006. Because of the lower hydroelectric generation, TVA had to rely more than anticipated on purchased power, as well as on generation from TVA’s other generation units, which are more costly to operate than TVA’s hydroelectric units.

Future Challenges

As TVA looks to the future, TVA faces challenges in addition to the ones that significantly impacted TVA during 2006. Some of the more significant challenges relate to new generation, Bonds and other financial obligations, retention of customers, TVA’s service area, and legislation.

New Generation. TVA is considering the proper balance between using purchased power and TVA’s own generation to meet the TVA service area’s growing power supply needs. At September 30, 2006, 4,275 megawatts, or 12.2 percent, of TVA’s winter net dependable capacity was provided under power purchase agreements. Prices for purchased power have been volatile in recent years. In addition, parties that collectively provide 3,008 megawatts of TVA’s winter net dependable capacity under power purchase agreements are in bankruptcy, although each of these parties has continued to perform under its power purchase agreement with TVA during the bankruptcy proceedings.

In light of an expected increase in demand for electricity in TVA’s service area and recent purchased power price volatility and provider unreliability, TVA has taken steps to build or acquire new generation. TVA expects to complete recovery work and return Unit 1 of its Browns Ferry Nuclear Plant to service in 2007 at a cost of $1.8 billion, and this unit is expected to add approximately 1,150 megawatts initially (and approximately 1,280 megawatts potentially) of base-load generation. The TVA Board has also approved the purchase of two combustion turbine generating plants, which together are expected to add approximately 1,297 megawatts of winter peaking capacity. The purchases of these plants are expected to close in December 2006. TVA is currently updating its strategic plan. When completed, the strategic plan could indicate that it is desirable for TVA to acquire additional generation rather than depend on market purchases. Such new generation could require significant capital expenditures in order to meet the needs of the TVA service area. In addition, TVA is studying the cost of completing the unfinished Unit 2 at the Watts Bar Nuclear Plant and considering the possibility of building a new advanced design nuclear unit at its Bellefonte Nuclear Plant site. Additionally, TVA may study acquiring generation from other fuel sources.

Bonds and Other Financial Obligations. As of September 30, 2006, TVA had $22.9 billion of Bonds outstanding. Payments on these obligations do not change with the amount of power sold, and if competition increases, TVA’s obligations to make these payments could limit its ability to adjust to market pressures. The amount of TVA’s Bonds outstanding has been reduced by more than $4 billion since September 30, 1996, when the end of year balance of outstanding Bonds peaked. Since that time, however, TVA has entered into energy prepayment transactions that resulted in $1.6 billion in prepayment obligations and certain lease/leaseback transactions that resulted in $1.3 billion in obligations. The amount of prepayment and lease/leaseback obligations outstanding at September 30, 2006, was $2.4 billion. While prudent management of Bonds and other financial obligations will remain an important strategic consideration in the future, increased capital commitments may make it difficult for TVA to continue its trend of reducing these obligations.

Retention of Customers. It is important that TVA retain its existing customers since TVA cannot acquire new customers outside of its service area to help compensate for the revenues that TVA loses from customers that begin purchasing power from another power supplier. As of September 30, 2006, six of TVA’s distributor customers had notices terminating their power contracts still in effect, and sales to these six distributor customers generated 2.9 percent of TVA’s total operating revenues in 2006. Five of these distributor customers are located in Kentucky, where power rates are among the lowest in the nation.

Challenges to TVA’s Service Area. There are currently two significant challenges to TVA’s service area involving distributor customers located in Kentucky. The first is the FERC administrative proceeding, which is now in

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litigation, involving the request of East Kentucky Power Cooperative to interconnect its transmission system with TVA’s transmission system in order to serve Warren Rural Electric Cooperative Corporation, a TVA distributor customer that has notified TVA of its decision to terminate its existing power supply contract. TVA believes the interconnection order issued by FERC in that proceeding circumvents the anti-cherrypicking provision. See Note 16 — Customers. The second involves legislation introduced by Kentucky Senators McConnell and Bunning that would exempt any distributor customer located in the Commonwealth of Kentucky from the anti-cherrypicking provision. While the sale of power to all of the distributor customers located in Kentucky generated only 4.6 percent of TVA’s total operating revenues in 2006, a negative resolution to either of these challenges could establish a precedent for reducing TVA’s service area on a piecemeal basis.

Legislation. TVA exists pursuant to legislation enacted by Congress and carries on its operations in accordance with this legislation. Since Congress has the authority to change this legislation, TVA is subject to more legislative risks than most utilities. Given the nature of the legislative process, it is possible that new legislation or a change to existing legislation that has a profound, detrimental impact on TVA’s activities could become law with little or no advance notice. For a discussion of the potential impact of legislation on TVA, see Item 1A, Risk Factors.

Liquidity and Capital Resources

Sources of Liquidity

TVA’s current liabilities exceed current assets because of the continued use of short-term debt as a funding source to meet cash needs as well as scheduled maturities of long-term debt. To meet short-term cash needs and contingencies, TVA depends on various sources of liquidity. TVA’s primary sources of liquidity are cash on hand and cash from operations, proceeds from the issuance of short-term and long-term debt, and proceeds from borrowings under TVA’s $150 million note with the U.S. Treasury. Other sources of liquidity include two $1.25 billion credit facilities with a national bank as well as occasional proceeds from other financing arrangements including call monetization transactions and sales of receivables and loans. Each of these sources of liquidity is discussed below.

Summary Cash Flows. A major source of TVA’s liquidity is operating cash flows resulting from the generation and 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


	2006			2005			2004

Cash provided by (used in):
Operating activities	$	2,014		$	1,462		$	3,290
Investing activities		(1,727	)		(1,188	)		(1,718	)
Financing activities		(289	)		(255	)		(1,586	)

Net (decrease) increase in cash and cash equivalents	$	(2	)	$	19		$	(14	)

Issuance of Debt. The TVA Act authorizes TVA to issue Bonds in an amount not to exceed $30 billion at any time. At September 30, 2006, 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 rank on parity and have first priority 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.

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 test and the bondholder protection test.

•

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,

Page 46

	—		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 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 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.

•

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 Appropriation Investment) or

	—		investment in power assets.

TVA must next meet the bondholder protection test for the five-year period ending September 30, 2010.

As discussed above, TVA uses proceeds from the issuance of discount notes, in addition to other sources of liquidity, to fund working capital requirements. During 2006, 2005, and 2004, the average outstanding balance of discount notes was $2.0 billion, $2.1 billion, and $1.1 billion, respectively, and the weighted average interest rate on discount notes was 4.47 percent, 2.70 percent, and 1.14 percent, respectively. At September 30, 2006, $2.4 billion of discount notes were outstanding with a weighted average interest rate of 5.21 percent. The discount notes are not listed on any exchange.

TVA issues power bonds primarily to refinance previously-issued power bonds as they mature. During 2006, 2005, and 2004, TVA issued $1.1 billion, $1.7 billion, and $0.8 billion of power bonds, respectively, and redeemed $1.2 billion, $2.4 billion, and $2.3 billion of power bonds, respectively. At September 30, 2006, outstanding power bonds (including current maturities of long-term debt) consisted of the following:

Page 47


CUSIP or Other			Principal
Identifier	Maturity	Coupon Rate	Amount¹			Exchange Listings
electronotes^®	01/15/2008 - 02/15/2026	2.450% -	$	1,090		None
		6.125%²
880591CQ3	01/15/2007	6.643%³		385	⁴	New York
880591DS8	12/15/2016	4.875%		600	⁴	New York
880591DB5	11/13/2008	5.375%		2,000		New York, Hong Kong, Luxembourg, Singapore
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%		990		New York, Luxembourg
880591DY5	06/15/2015	4.375%		1,000		New York, Luxembourg
880591CU4	12/15/2017	6.250%		750		New York
880591DC3	06/07/2021	5.805%³		374		New York, Luxembourg
880591CJ9	11/01/2025	6.750%		1,350		New York, Hong Kong, Luxembourg, Singapore
880591300	06/01/2028	5.490%		466		New York
880591409	05/01/2029	5.618%		410		New York
880591DM1	05/01/2030	7.125%		1,000		New York, Luxembourg
880591DP4	06/07/2032	6.587%³		468		New York, Luxembourg
880591DV1	07/15/2033	4.700%		472		New York, Luxembourg
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
880591BL5	04/15/2042	8.250%		1,000		New York
880591DU3	06/07/2043	4.962%³		281		New York, Luxembourg
880591CF7	07/15/2045	6.235%		140		New York
880591DZ2	04/01/2056	5.375%		1,000		New York

Subtotal				20,707


Unamortized discounts, premiums, and other				(178	)


Total outstanding power bonds, net			$	20,529


Notes

⁽¹⁾		The above table includes net translation losses from currency transactions of $195 million at September 30, 2006.

⁽²⁾		The weighted average interest rate of TVA’s outstanding electronotes^® was 4.74 percent at September 30, 2006.

⁽³⁾		The coupon rate represents TVA’s effective interest rate.

⁽⁴⁾		Because these power bonds either mature or are able to be put back to TVA in 2007, they are considered to be short-term debt as of September 30, 2006, and are thus included in the Short-Term Debt table as of September 30, 2006, in Note 9 — Debt Outstanding.

As of September 30, 2006, all of TVA’s Bonds were rated by at least one rating agency except for two issues of power bonds and TVA’s discount notes. TVA’s rated Bonds are currently rated “Aaa” by Moody’s Investors Service and/or “AAA” by Standard & Poor’s and/or Fitch Ratings, which are the highest ratings assigned by these agencies. The ratings are not recommendations to buy, sell, or hold any TVA securities and may be subject to revision or withdrawal at any time by the rating agencies. Ratings are assigned independently, and each should be evaluated as such.

For additional information about TVA debt issuance activity and debt instruments issued and outstanding as of September 30, 2006 and 2005, including identifiers, rates, maturities, outstanding principal amounts, and redemption features, see Note 9 — Debt.

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$150 Million Note with U.S. Treasury. TVA has access to financing arrangements with the U.S. Treasury, whereby the U.S. Treasury is authorized to accept a short-term note with the maturity of one year or less in an amount not to exceed $150 million. TVA may draw any portion of the authorized $150 million during the year. Interest is accrued daily and paid quarterly at a rate determined by the U.S. Secretary of the Treasury each month based on the average of outstanding obligations of the United States with maturities of one year or less. During 2006, 2005, and 2004, the daily average amounts outstanding were approximately $131 million, $103 million, and $35 million, respectively. The outstanding balances were repaid quarterly. See Note 7 and Note 9 —Debt — Short-Term Debt.

Credit Facilities. In the event of shortfalls in cash resources, TVA has short-term funding available in the form of revolving credit facilities. In May 2006, TVA converted its $2.5 billion short-term revolving credit facility with a national bank into two $1.25 billion short-term revolving credit facilities with the same national bank. In order to provide greater flexibility going forward, TVA staggered the maturities of the two credit facilities to November 12, 2006, and May 16, 2007. See Note 16 — Subsequent Events — Revolving Credit Facility Agreement. The interest rate on any borrowing under either of these facilities is variable and based on market factors and the rating of TVA’s senior unsecured long-term non-credit enhanced debt at the time TVA draws on either facility. TVA is required to pay an unused facility fee on the portion of the total $2.5 billion against which TVA has not borrowed. The fee may fluctuate depending upon the rating of TVA’s senior unsecured long-term non-credit enhanced debt. There were no outstanding borrowings under the facilities at September 30, 2006. TVA anticipates renewing each credit facility from time to time.

Call Monetization Transactions. From time to time 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, 2006, TVA has entered into four swaption transactions that generated proceeds of $261 million.

	•		In 2002, TVA monetized the call provisions on a $1 billion Bond issue by entering into a swaption agreement with a third party in exchange for $175 million.

	•		In 2003, TVA monetized the call provisions on a second Bond issue of $476 million by entering into a swaption agreement with a third party in exchange for $81 million.

	•		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 8 — Swaptions and Related Interest Rate Swap.

Sales of Receivables/Loans. From time to time TVA obtains proceeds from selling receivables and loans. During 2006, TVA sold $22 million of receivables at par such that TVA did not recognize a gain or loss on the sale. Of this amount, $11 million represents receivables from power customers related to the construction of a substation and other energy conservation projects, which is included within the Cash Flow Statement under the caption Cash Flows from Investing Activities.

During 2005, TVA sold $60 million of receivables. Of this amount, $1 million represented receivables from power customers related to the construction of a substation and other energy-conservation projects, which is included within the Cash Flow Statement under the caption Cash Flows from Investing Activities. The receivables were sold at par such that TVA did not recognize a gain or loss on the sale. Additionally, TVA sold a portfolio of 51 power distributor customer loans receivable. The portfolio was sold for $55 million, without recourse to TVA, and contained loans with maturities ranging from less than one year to over 34 years. The principal amount due on the loans at the time of the sale was $57 million. The $2 million loss is reported in Other Income, net on the Income Statement for the year ended September 30, 2005.

There were no corresponding sales of receivables during 2004. TVA did not retain any claim on these loans and receivables sold, and they are no longer reported on TVA’s Balance Sheets. For more information regarding TVA’s sales of receivables and loans, see Note 1 — Sales of Receivables/Loans.

2006 Compared to 2005

Net cash provided by operating activities increased $552 million from 2005 to 2006. This increase resulted from:

Page 49

	•		An increase in cash provided by operating revenues of $1.4 billion resulting primarily due to higher average rates from rate actions effective in October 2005 and April 2006 and, to a lesser extent, by increased demand in 2006;

	•		Less cash paid for interest of $46 million in 2006; and

	•		A decrease in expenditures for nuclear refueling outages of $50 million due to the number and timing of outages during 2006.

These items were partially offset by:

	•		An increase in cash paid for fuel and purchased power of $734 million due to higher volume and increased market prices;

	•		An increase in payments in lieu of taxes of $11 million;

	•		An increase in cash outlays for routine and recurring operating costs of $44 million; and

	•		An increase in other deferred items of $55 million primarily due to $22 million of increased contributions to the TVA Retirement System and $15 million related to customer advances for construction.

Net cash used by changes in components of working capital increased $117 million from 2005 primarily from:

	•		A larger increase in accounts receivable of $195 million due to increased sales of the prior year and higher rates in 2006; and

	•		A larger increase in inventories of $108 million due to higher priced coal and natural gas in ending inventory in 2006 and a higher volume of coal on hand at the end of 2006.

These items were partially offset by:

	•		A $125 million increase in accounts payable and accrued liabilities in 2006 compared to a $16 million decrease in 2005 primarily due to changes in the amount of collateral held by TVA of $88 million under terms of a swap agreement and higher costs for fuel and purchased power; and

	•		A $23 million increase in accrued interest in 2006 compared to a $22 million decrease in 2005 due to timing of interest payments on Bonds issued relative to Bonds retired during 2006.

Cash used in investing activities increased $539 million from 2005 to 2006. The increase is primarily due to:

	•		Sales of short-term investments of $335 million in 2005 with no comparable sales in 2006;

	•		An increase in expenditures for the enrichment and fabrication of nuclear fuel of $136 million for the Sequoyah Unit 2 and Watts Bar Unit 1 reloads scheduled to be completed in the first quarter of 2007, and expenditures related to uranium, conversion, and enrichment for Browns Ferry Unit 1;

	•		An increase in expenditures for capital projects of $60 million was primarily due to increases in transmission construction projects related to reliability and load growth on the TVA system, including a substation and a 500-kv transmission line on the bulk transmission system, an increase in expenditures for nuclear projects of $17 million primarily for the Browns Ferry Unit 1 restart, and a corresponding increase in allowance for funds used during construction of $35 million; partially offset by decreases in clean air expenditures of $20 million related to project completions and a decrease in hydro expenditures of $26 million; and

	•		A decrease in proceeds received from the sale of certain receivables/loans of $45 million compared to the same period of 2005.

These items were partially offset by:

	•		A damage award in 2006 of $35 million in TVA’s breach of contract suit against the DOE; and

	•		A smaller increase in collateral deposits in 2006 of $16 million as compared to 2005. See Note 1 — Summary of Significant Accounting Policies — Restricted Cash and Investments.

Net cash used in financing activities was $34 million greater in 2006 than 2005 primarily due to:

•

A decrease in issuance of long-term debt of $518 million;

Page 50

•

Net issuances of short-term debt of $546 million in 2005 compared to net redemptions of short-term debt of $93 million in 2006; and

•

An increase in payments to the U.S. Treasury of $2 million due to changes in interest rates.

These items were partially offset by:

•

A decrease in redemptions of long-term debt of $1.1 billion in 2006 compared to 2005.

2005 Compared to 2004

Net cash provided by operating activities decreased $1.8 billion from 2004 to 2005. The decrease resulted from:

	•		Proceeds of $1.5 billion received in 2004 for energy prepayments with no comparable prepayment in 2005;

	•		Increased cash paid for fuel and purchased power of $521 million due to higher volume and increased market prices;

	•		An increase in expenditures for nuclear refueling outages of $36 million due to the number and timing of outages;

	•		An increase in other deferred items of $28 million primarily due to increased contributions to the TVA Retirement System;

	•		An increase in payments in lieu of taxes of $27 million; and

	•		Decreased cash provided from net income components of $199 million.

These items were partially offset by:

	•		An increase in cash provided by operating revenues of $251 million resulting primarily from increased sales volume;

	•		A decrease in cash outlays for interest of $47 million; and

	•		A decrease in cash outlays for operating and maintenance costs of $38 million primarily due to $33 million in severance and restructuring costs that were recognized in 2004.

Net cash used by changes in working capital components increased $59 million from 2004 to 2005. The working capital fluctuation primarily resulted from:

	•		An increase in accounts receivable of $69 million due to increased sales volume during the summer months of 2005;

	•		A larger payment of accrued interest of $17 million in 2005 than in 2004 due to the timing of interest payments on Bonds issued relative to Bonds retired; and

	•		An increase in inventories and other of $12 million in 2005 compared to a decrease in inventories and other of $10 million in 2004 primarily due to purchases of emission allowances and prepayment of insurance premiums for new programs in 2005.

These items were partially offset by a smaller decrease of $49 million in accounts payable and accrued liabilities primarily due to the receipt of a $107 million collateral deposit and an increase in fuel and purchased power expense of $71 million in 2005 partially offset by the payment of certain 2004 accruals in 2005, including a $41 million payment related to Browns Ferry Nuclear Unit 1, a $10 million litigation settlement, a $6 million annual leave lump sum payment, and a payment of $18 million in performance incentives.

Cash used in investing activities decreased $530 million from 2004 to 2005. The change is primarily due to:

	•		Maturity of short-term investments of $335 million in 2005 compared to an increase in short-term investments of $68 million in 2004;

	•		A decrease in expenditures for capital projects of $213 million primarily due to decreases in clean air expenditures of $210 million partially offset by increases in expenditures for the Browns Ferry Unit 1 restart;

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	•		Proceeds received in 2005 from the sale of certain power distributor customer loans receivable of $55 million (see Note 1 — Sale of Receivables/Loans); and

	•		Cash provided by net collections on loans and long-term receivables of $6 million in 2005 compared to $5 million in 2004, and net proceeds from investment activity of $1 million.

These items were partially offset by:

	•		An increase in expenditures for the enrichment and fabrication of nuclear fuel of $22 million as four nuclear units completed refueling outages in 2005;

	•		A payment of $15 million in 2004 from Regenesys Technologies Limited in connection with cancellation of the Regenesys project due to inability of manufacturer to supply materials; and

	•		An increase in restricted cash of $107 million resulting from collateral deposits in 2005 (see Note 1 — Restricted Cash and Investments).

Net cash used in financing activities decreased $1.3 billion from 2004 to 2005 primarily due to:

	•		An increase in issuances of long-term debt of $878 million in 2005;

	•		Net issuances of short-term debt of $546 million in 2005 compared to net redemptions of short-term debt of $157 million in 2004;

	•		A decrease in payments to the U.S. Treasury of $2 million due to lower interest rates in 2005; and

	•		A decrease in lease payments of $26 million in 2005.

These items were partially offset by:

	•		An increase in redemptions of long-term debt of $117 million primarily due to the refinancing of callable debt at lower interest rates;

	•		A decrease in bond premium received of $97 million in 2005;

	•		A decrease in swap receivable monetization of $55 million in 2005; and

	•		An increase in net financing costs of $14 million in 2005 related to Bond transactions.

Cash Requirements and Contractual Obligations

Due to the nature of the power industry, which requires large multi-year capital investments, using trends and multi-year forecasts are important in assessing the effectiveness of management’s decisions related to capital expenditures, pricing, and accessing capital markets. TVA expects that cash provided by operating activities and new financing activities will be adequate to meet these estimated cash requirements, as well as other cash commitments.

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
	2006		2007		2008		2009		2010		2011

Browns Ferry Unit 1 Restart	$	428	$	76	$	—	$	—	$	—	$	—
Clean Air Expenditures		182		286		357		306		290		368
Transmission Expenditures ²		232		203		231		319		312		278
Other Capital Expenditures ³		406		487		611		510		560		534

Total Capital Projects Requirements⁴	$	1,248	$	1,052	$	1,199	$	1,135	$	1,162	$	1,180


Notes

(1)		This table shows only expenditures that are currently planned. TVA is updating its strategic plan. When completed, the strategic plan could indicate that it is desirable for TVA to acquire additional generation rather than depend on market purchases. Such new generation could require significant capital expenditures in order to meet the needs of TVA’s service area. The table does not include any projects to provide additional generation which may be identified in the strategic planning process.

(2)		Transmission Expenditures include reimbursable projects.

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(3)

Other Capital Expenditures are primarily associated with short lead time construction expenditure projects aimed at the continued safe and reliable operation of generating assets.

(4)

Actual 2006 capital projects requirements excludes allowance for funds used during construction of $151 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. Actual amounts may differ materially based upon a number of factors, including 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, as well as the outcome of the ongoing restructuring of the electric industry.

TVA does not anticipate receiving a financial return on its clean air expenditures because these expenditures neither generate revenues nor reduce costs. In fact, clean air equipment will reduce the operating efficiency and increase the operating costs of TVA’s coal-fired units. In the near term, TVA will be negatively impacted by investments in new generation (i.e., Browns Ferry Unit 1) that are not expected to return a cash contribution until 2007.

TVA also has certain obligations and commitments to make future payments under contracts. The following table sets forth TVA’s estimates of future payments as of September 30, 2006. See Notes 7, 9, and 13 for a further description of these obligations and commitments.

Commitments and Contingencies

Payments Due in the Year Ending September 30


	Total			2007		2008		2009		2010		2011		Thereafter

Debt	$	22,888	*	$	3,361	$	90	$	2,030	$	63	$	1,015	$	16,329
Interest payments relating to debt		21,555			1,188		1,152		1,096		1,042		1,011		16,066
Leases
Non-cancelable operating		135			45		41		26		12		4		7
Capital		272			63		59		57		57		30		6
Power purchase obligations		4,354			205		146		148		152		154		3,549
Purchase obligations
Fuel purchase obligations		3,015			1,083		509		496		400		249		278
Other obligations		327			199		111		5		3		2		7
Payments on other financings		1,557			85		89		85		89		95		1,114
Payment to U.S. Treasury**
Return of Appropriation Investment		150			20		20		20		20		20		50
Return on Appropriation Investment		282			20		23		22		21		20		176
Retirement plans		90			90		—		—		—		—		—

Total	$	54,625		$	6,359	$	2,240	$	3,985	$	1,859	$	2,600	$	37,582


Notes

*		Does not include noncash items of foreign currency valuation loss of $195 million and net discount on sale of bonds of $178 million.

**		TVA has access to financing arrangements with the U.S. Treasury whereby the U.S. Treasury is authorized to accept from TVA a short-term note with the maturity of one year or less in an amount not to exceed $150 million. TVA may draw any portion of the authorized $150 million during the year. Interest is accrued daily at a rate determined by the United States Secretary of the Treasury each month based on the average rate on outstanding marketable obligations of the United States with maturities of one year or less. During 2006, the daily average outstanding balance was $131 million. TVA’s practice is to repay on a quarterly basis the outstanding balance of the note and related interest. Because of this practice, there was no outstanding balance on the note as of September 30, 2006. Accordingly, the Commitments and Contingencies table does not include any outstanding payment obligations to the U.S. Treasury for this note at September 30, 2006. See Note 9 — Short-Term Debt.

Under the terms of an interagency agreement, DOE and other third-party nuclear fuel processors provide nuclear fuel materials and process the materials into usable fuel for TVA nuclear reactors. In exchange, DOE will participate to a degree in the savings generated by TVA’s use of this blended nuclear fuel product. As of September 30, 2006, TVA projects that DOE’s share of savings generated by TVA’s use of this blended nuclear fuel product could result in future payments to DOE of as much as $272 million. TVA anticipates these future payments could begin in 2009. At September 30, 2006, TVA has accrued an obligation of $2 million related to such future potential payments.

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.

Page 53

Energy Prepayment Obligations
Payments Due in the Year Ending September 30


	Total		2007		2008		2009		2010		2011		Thereafter

Energy Prepayment Obligations	$	1,244	$	106	$	106	$	105	$	105	$	105	$	717

Results of Operations

Financial Results

The following table compares operating results and selected statistics for 2006, 2005, and 2004:

Summary Statements of Income
For the years ended September 30


	2006			2005			2004
Operating revenues	$	9,185		$	7,794		$	7,533
Operating expenses		(7,582	)		(6,503	)		(5,873	)

Operating income		1,603			1,291			1,660
Other income		67			56			44
Other expense		(2	)		(4	)		(1	)
Unrealized (loss)/gain on derivative contracts, net		(15	)		3			(7	)
Interest expense, net		(1,215	)		(1,261	)		(1,310	)

Income before cumulative effects of accounting changes		438			85			386
Cumulative effect of change in accounting for conditional asset retirement obligations		(109	)		—			—

Net income	$	329		$	85		$	386

Sales (millions of kWh)		176,370			171,498			165,858

2006 Compared to 2005

Net income for 2006 was $329 million compared with net income of $85 million for 2005. The $244 million increase in net income was mainly attributable to a $1,391 million increase in operating revenues and lower net interest expense of $46 million, partially offset by a $1,079 million increase in operating expenses, a $15 million unrealized loss on derivative contracts, net, in 2006 as compared to an unrealized gain of $3 million in 2005, and a $109 million cumulative expense charge in 2006 for adoption of a new accounting standard related to conditional asset retirement obligations. See Note 4.

Operating Revenues. Electricity sales and operating revenue during 2006 and 2005 consisted of the following:

Page 54

Electricity Sales and Operating Revenue
For the years ended September 30


	Sales of Electricity							Operating Revenues
	(millions of kWh)							(millions of dollars)
					Percent							Percent
	2006		2005		Change			2006		2005		Change

Sales of electricity and operating revenues
Municipalities and cooperatives		143,343		136,640		4.9	%	$	7,880	$	6,561		20.1	%
Industries directly served		30,987		30,872		0.4	%		1,066		962		10.8	%
Federal agencies and other		2,040		3,986		(48.8	%)		116		181		(35.9	%)
Other revenue		—		—		—			123		90		36.7	%

Total sales of electricity and operating revenues		176,370		171,498		2.8	%	$	9,185	$	7,794		17.8	%

Significant items contributing to the $1,391 million increase in operating revenue include:

	•		A $1,319 million increase in revenue from municipalities and cooperatives reflecting increased sales of 4.9 percent and average rates rising 14.5 percent of which $822 million relates to the rate adjustments effective October 1, 2005, and April 1, 2006;

	•		A $104 million increase in revenue from industries attributable to sales increasing 0.4 percent and average rates rising 10.4 percent of which $41 million relates to the rate adjustments effective October 1, 2005, and April 1, 2006; and

	•		A $33 million increase in other revenue primarily due to increased transmission revenues from wheeling activity.

The rate adjustments, effective the first quarter and third quarter of 2006, contributed about $873 million to the increase in revenues on firm-based products during 2006 as compared to 2005. Firm-based products carry higher rates since they offer the most reliable power supply. As a result, customers purchasing these products are the last to have their supply interrupted during a system emergency. An additional $237 million of the increase in revenues is due to higher average rates related to a shift in product and customer mix and higher rates for variable priced products.

The $65 million decrease in Federal agencies and other was primarily due to:

	•		An $82 million decrease in exchange power sales reflecting decreased sales of 90.3 percent and reduced generation of 2.7 percent which includes a 36.6 percent decrease in hydroelectric generation resulting from dry conditions in 2006; offset by

	•		A $17 million increase in revenues from federal agencies directly served due to increased sales of 4.9 percent and average rates rising 14.3 percent of which $10 million relate to the rate adjustments effective October 1, 2005, and April 1, 2006.

Significant items contributing to the 4,872 million kilowatt-hour increase in electricity sales include:

	•		A 6,703 million kilowatt-hour increase in sales to municipalities and cooperatives attributable to 4,707 million kilowatt-hours related to the unbilled estimate methodology used in 2005 (see Note 1 — Accounts Receivable) and a 1,996 million kilowatt-hour increase in sales demand by municipalities and cooperatives during 2006;

	•		A 115 million kilowatt-hour increase in sales to directly served industries as a result of increased firm and Firm Power Interruptible demand of 48.3 percent and 93.6 percent, respectively, offset by decreased Economy Surplus Power/Variable Priced Interruptible and Preferred Interruptible Power/Firm Power Interruptible demand of 29.2 percent and 32.3 percent, respectively; and

	•		An 85 million kilowatt-hour increase in sales to federal agencies primarily due to increased demand of 34.5 percent for other miscellaneous products.

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These items were partially offset by a 2,031 million kilowatt-hour decrease in exchange power sales (included in Federal agencies and Other) mainly reflecting decreased generation available for sale.

Operating Expenses. A table of operating expenses follows:

TVA Operating Expenses
For the years ended September 30


					Percent
	2006		2005		Change

Operating expenses
Fuel and purchased power	$	3,333	$	2,601		28.1	%
Operating and maintenance		2,372		2,359		<1	%
Depreciation, amortization and accretion		1,492		1,154		29.3	%
Payments in lieu of taxes		376		365		3.0	%
Loss on asset impairment/project cancellation		9		24		(62.5	%)

Total operating expenses	$	7,582	$	6,503		16.6	%

Significant drivers contributing to the $1,079 million increase in total operating expenses include:

	•		A $377 million increase in fuel expense attributable to higher aggregate fuel cost per kilowatt-hour net thermal generation of 19.0 percent and increased generation of 1.2 percent, 3.0 percent, and 0.3 percent at the coal-fired, combustion turbine, and nuclear plants, respectively, in part because of lower hydroelectric generation;

	•		A $355 million increase in purchased power expense reflecting increased average purchase price of 16.3 percent and higher volume acquired of 27.7 percent to accommodate for decreased hydroelectric generation and for slightly lower asset availability in 2006 than planned; and

	•		An $11 million increase in payments in lieu of taxes due to increased gross revenues of 3.1 percent from the sale of power (excluding sales or deliveries to other federal agencies and exchange sales with other utilities) during 2005 as compared to 2004. See Item 1, Business — Payments in Lieu of Taxes.

Additionally, amortization expense increased $388 million largely as a result of the amortization of the deferred cost of nuclear generating units at Bellefonte Nuclear Plant. See Note 2.

These items were partially offset by a $51 million decrease in depreciation mainly due to the depreciation rate reduction for Browns Ferry Nuclear Plant reflecting the 20-year license extensions.

Other Income. The $11 million increase in other income is largely attributable to increased interest earnings on the collateral deposit funds held by TVA and interest income from short-term investments. See Note 1—Restricted Cash and Investments.

Other Expense. The $2 million decrease in other expense is due to the loss of $2 million on the sale of distributor customer loan program receivables in 2005 not present in 2006.

Unrealized (Loss)/Gain on Derivative Contracts, Net. The $18 million change in net unrealized (loss)/gain on derivative contracts reflecting a gain of $3 million during 2005 and a loss of $15 million during 2006 is a result of a $177 million net loss on the mark-to-market valuation of an embedded call option. This item was partially offset by:

	•		A $45 million net gain on the mark-to-market valuation adjustment of an interest rate swap contract;

	•		A $108 million net gain on the mark-to-market valuation adjustment of swaption contracts; and

	•		A $6 million unrealized net loss related to the mark-to-market valuation of sulfur dioxide emissions allowance call options during the first quarter of 2005 not present in 2006.

Interest Expense. Interest expense, outstanding debt, and interest rates during 2006 and 2005 were as follows:

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Interest Expense
For the years ended September 30


							Percent
	2006			2005			Change

Interest expense
Interest on debt	$	1,357		$	1,356			(0.0	%)
Amortization of debt discount, issue, and reacquisition costs, net		21			21			0.0	%
Allowance for funds used during construction		(163	)		(116	)		40.5	%

Net interest expense	$	1,215		$	1,261			(3.6	%)


	(percent)
					Percent
	2006		2005		Change
Interest rates (average)
Long-term		6.17		6.25		(1.3	%)
Discount notes		4.47		2.70		65.6	%
Blended		6.02		5.93		1.5	%

Significant items contributing to the $46 million decrease in net interest expense include:

	•		A decrease in the average long-term interest rate from 6.25 percent in 2005 to 6.17 percent in 2006;

	•		A decrease of $407 million in the average balance of long-term outstanding debt in 2006;

	•		A decrease of $75 million in the average balance of discount notes outstanding in 2006; and

	•		A $47 million increase in AFUDC due to a higher level of construction work-in-progress in 2006.

These items were partially offset by an increase in the average discount notes interest rate from 2.70 percent to 4.47 percent between 2005 and 2006.

2005 Compared to 2004

Net income for 2005 was $85 million compared with net income of $386 million for 2004. The $301 million decrease in net income was mainly attributable to a $630 million increase in operating expenses, partially offset by an increase in operating revenues of $261 million, lower net interest expense of $49 million, and a $10 million change in unrealized (loss)/gain on derivative contracts reflecting a $3 million gain in 2005 and a $7 million loss in 2004.

Operating Revenues. A table of electricity sales and operating revenue follows:

Electricity Sales and Operating Revenue
For the years ended September 30


	Sales of Electricity							Operating Revenues
	(millions of kWh)							(millions of dollars)
					Percent							Percent
	2005		2004		Change			2005		2004		Change

Sales of electricity and operating revenue
Municipalities and cooperatives		136,640		133,161		2.6	%	$	6,561	$	6,457		1.6	%
Industries directly served		30,872		29,344		5.2	%		962		842		14.3	%
Federal agencies and other		3,986		3,353		18.9	%		181		140		29.3	%
Other revenue		—		—		—			90		94		(4.3	%)


Total sales of electricity and operating revenue		171,498		165,858		3.4	%	$	7,794	$	7,533		3.5	%

Significant items contributing to the $261 million increase in operating revenues include:

•

A $104 million increase in revenues from municipalities and cooperatives due to increased sales of 2.6 percent although average rates decreased 1.0 percent;

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	•		A $120 million increase in revenues from industries directly served reflecting increased sales of 5.2 percent and average rates rising 8.6 percent;

	•		A $5 million increase in revenues from federal agencies directly served as a result of increased sales of 2.0 percent and average rates rising 4.1 percent; and

	•		A $36 million increase in revenues from exchange power sales (included in Federal Agencies and Other) attributable to increased total generation of 3.3 percent reflecting favorable market conditions. Favorable market conditions relate to electricity demands both inside and outside the TVA service area in addition to advantageous market rates.

Significant items contributing to the 5,640 million kilowatt-hour increase in electricity sales include:

	•		A 3,479 million kilowatt-hour increase in sales to municipalities and cooperatives primarily as a result of increased demand due to warmer summer weather reflecting higher combined degree days of 0.7 percent. During 2005, there were 325, or 18.6 percent, more cooling degree days offset by 291, or 9.0 percent, less heating degree days;

	•		A 1,528 million kilowatt-hour increase in sales to industries directly served largely attributable to increased demand of 19.1 percent from one of TVA’s largest industrial consumers of power;

	•		A 34 million kilowatt-hour increase in sales to federal agencies directly served as a result of increased demand of 3.4 percent by firm-based customers; and

	•		A 599 million kilowatt-hour increase in exchange power sales (included in Federal agencies and other) due to increased total generation of 3.3 percent reflecting favorable market conditions.

Operating Expenses. Operating expenses during 2005 and 2004 were as follow:

TVA Operating Expenses
For the years ended September 30


					Percent
	2005		2004		Change

Operating expenses
Fuel and purchased power	$	2,601	$	2,081		25.0	%
Operating and maintenance		2,359		2,319		1.7	%
Depreciation, amortization, and accretion		1,154		1,115		3.5	%
Payments in lieu of taxes		365		338		8.0	%
Loss on asset impairment/project cancellation		24		20		20.0	%

Total operating expenses	$	6,503	$	5,873		10.7	%

Significant items contributing to the $630 million increase in total operating expenses for 2005 include:

	•		A $269 million increase in fuel expense attributable to higher aggregate fuel cost per kilowatt-hour, net thermal generation of 14.1 percent, increased fuel handling costs of $8 million, and increased generation of 4.0 percent and 114.0 percent at coal-fired and combustion turbine plants, respectively;

	•		A $251 million increase in purchased power expense as a result of the average purchase price increasing 43.6 percent and higher volume acquired of 6.2 percent;

	•		A $77 million increase in pension and post retirement expense due primarily to increased interest cost coupled with increased amortization of actuarial loss (see Note 12);

	•		A $29 million increase in depreciation expense attributable to capital projects placed in service;

	•		A $9 million increase in amortization expense related to the amortization of the capital lease recognized for the blended low enriched uranium program (see Note 1 — Blended Low Enriched Uranium Program); and

	•		A $24 million impairment loss related to the $16 million write-down of certain assets related to a new technology that had not been proven effective and a $8 million loss equal to the difference in the book value and market price of the East Tower of the Knoxville Office Complex (see Note 1 — Impairment of Assets and Note 6 — Asset Impairment).

These items were partially offset by a $33 million reduction in severance expense due to recognition of termination benefit costs in the prior period.

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Other Income. The $12 million increase in other income relates to increased interest income from short-term investments.

Other Expense. The $3 million increase in other expense is primarily due to the loss of over $2 million on the sale of distributor customer loan program receivables in 2005 not present in 2004.

Unrealized Gain on Derivative Contracts, Net. The $10 million change in net unrealized (loss)/gain on derivative contracts reflecting a $7 million loss in 2004 and a $3 million gain in 2005, is a result of a $102 million net gain on the mark-to-market valuation of an embedded call option.

This item was partially offset by:

	•		A $9 million net loss on the mark-to-market valuation adjustment of an interest rate swap contract;

	•		A $71 million net loss on the mark-to-market valuation adjustment of swaption contracts; and

	•		A $12 million unrealized net loss related to the mark-to-market valuation of sulfur dioxide emission allowance call options.

Interest Expense. A table of interest expense follows:

TVA Interest Expense
For the years ended September 30


							Percent
	2005			2004			Change

Interest expense
Interest on debt	$	1,356		$	1,385			(2.1	%)
Amortization of debt discount, issue, and reacquisition costs, net		21			24			(12.5	%)
Allowance for funds used during construction		(116	)		(99	)		17.2	%

Net interest expense	$	1,261		$	1,310			(3.7	%)


	(percent)
					Percent
	2005		2004		Change
Interest rates (average)
Long-term		6.25		6.36		(1.7	%)
Discount notes		2.70		1.14		136.8	%
Blended		5.93		6.12		(3.1	%)

Significant items contributing to the $49 million decrease in net interest expense include:

	•		A decrease in the average long-term interest rate from 6.36 percent to 6.25 percent;

	•		A reduction of approximately $1,089 million in the average balance of long-term debt outstanding; and

	•		A $17 million increase in AFUDC due to a higher level of construction work-in-progress in 2005.

These items were partially offset by:

	•		An increase in the average discount note interest rate from 1.14 percent to 2.70 percent; and

	•		An increase of $995 million in the average balance of discount notes outstanding.

Off-Balance Sheet Arrangements

TVA has entered into one transaction that might constitute an off-balance sheet arrangement. In February 1997, TVA entered into a purchase power agreement with Choctaw Generation, Inc. (subsequently assigned to Choctaw Generation Limited Partnership) to purchase all the power generated from its facility located in Choctaw County, Mississippi. The facility had a committed capacity of 440 megawatts and the term of the agreement was 30 years. Under the accounting guidance provided by FIN 46R, TVA may be deemed to be the primary beneficiary under the contract; however, TVA does not have access to the financial records of Choctaw Generation Limited Partnership. As a result, TVA was unable to determine whether FIN 46R would require TVA to consolidate Choctaw Generation Limited Partnerships’ balance sheet, results of operations, and cash flows for the year ended September 30, 2006. Power purchases for 2006 under the agreement amounted to $121 million, and the remaining financial

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commitment under this agreement is $4.1 billion. TVA has no additional financial commitments beyond the purchase power agreement with respect to the facility.

See the discussion of variable interest entities in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations — New Accounting Standards and Interpretations — Variable Interest Entities.

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 generally accepted accounting principles (“GAAP”), management 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 regards 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 financial position, or results of operations. TVA’s critical accounting policies are also discussed in Note 1 — Summary of Significant Accounting Policies.

Regulatory Accounting

Although TVA’s power rates are not subject to regulation through a public service commission or other similar entity, TVA’s Board is authorized by the TVA Act to set rates for power sold to its customers. This rate-setting authority meets the “self-regulated” provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation,” and TVA meets the remaining criteria of SFAS No. 71 that (1) TVA’s regulated rates are designed to recover its costs of providing electricity and (2) 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. Accordingly, 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. Management 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 this assessment, management 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, TVA could be required to write-off these costs under the provisions of SFAS No. 101, “Regulated Enterprises—Accounting for the Discontinuation of Application of FASB Statement No. 71.” Any asset write-offs would be required to be recognized in earnings in the period in which regulatory accounting under SFAS No. 71 ceased to apply. See Note 5.

Long-Lived Assets

TVA capitalizes long-lived assets such as property, plant, and equipment at historical cost, which includes direct and indirect costs and an allowance for funds used during construction. TVA recovers the costs of these long-lived assets through depreciation of the physical assets as they are consumed in the process of providing products or services. Depreciation is generally computed on a straight-line basis over the estimated productive lives of the various classes of assets. When TVA retires its regulated long-lived assets, it charges the original asset cost plus removal costs, less salvage value, to accumulated depreciation in accordance with utility industry practice.

Long-Lived Asset Impairments

TVA evaluates the carrying value of long-lived assets when circumstances indicate the carrying value of those assets may not be recoverable. Under the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” an asset impairment exists for a long-lived asset to be held and used when the carrying value exceeds the sum of estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset is impaired, the asset’s carrying value is adjusted downward to its estimated fair value with a corresponding impairment loss recognized in earnings.

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Revenue Recognition

Revenues from power sales are recorded as power is delivered to customers. TVA accrues estimated unbilled revenues for power sales provided to customers for the period of time from the end of the billing cycle to the end of the month. The methodology for estimating unbilled revenue from electricity sales uses meter readings for each customer for the current billing period. See Note 1— Revenues.

Asset Retirement Obligations

In accordance with the provisions of SFAS No. 143, “Accounting for Asset Retirement Obligations,” and FIN No. 47, “Accounting for Conditional Asset Retirement Obligations—an Interpretation of FASB Statement No. 143,” TVA recognizes legal obligations associated with the future retirement of certain tangible long-lived assets (see Note 4). TVA records estimates of such disposal costs at the time the legal obligation arises or costs are actually incurred. Based on new engineering studies performed annually in accordance with NRC requirements, revisions to the amount and timing of certain cash flow estimates of nuclear asset retirement obligations may be made. See Note 4.

Nuclear Decommissioning

At September 30, 2006, the present value of the estimated future nuclear decommissioning cost of $1.5 billion was included in Asset Retirement Obligations, and the unamortized regulatory asset of $474 million was included in Other Regulatory Assets. Under the NRC’s regulations, the present value of the estimated future nuclear decommissioning cost was $670 million. 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. Utilities that own and operate nuclear plants are required to use different procedures in estimating nuclear decommissioning costs under SFAS No. 143 than those that are used in estimating nuclear decommissioning costs that are reported to the NRC. Accordingly, the two sets of procedures produce different estimates for the costs of decommissioning.

TVA maintains a nuclear decommissioning trust to provide money 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 fund 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, 2006, is greater than the present value of the estimated future nuclear decommissioning costs.

On May 3, 2006, the NRC approved TVA’s application for license extension at each of TVA’s three Browns Ferry units. The license extension has the effect of improving the funded status of TVA’s nuclear decommissioning trust versus the present value of the estimated decommissioning costs by (1) extending the decommissioning dates of the three Browns Ferry units and thereby pushing the decommissioning liability for these units further into the future and (2) extending the investment horizon for the assets in the trust.

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 expiration of the unit with the latest to expire operating license is typically used for this purpose, 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 for a nuclear facility to be maintained and monitored in a condition that allows the radioactivity to decay, after which the facility is decommissioned. Afterwards, it is 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 — Because of the age of the nuclear plants in the United States, 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

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			estimates to change significantly. The impact of these potential changes is not presently determinable. TVA’s cost studies assume current technology and regulations.

	•		Discount Rate — TVA’s decommissioning fund uses a blended rate of 5.65 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 fund will achieve a rate of return that is five percent greater than the rate of inflation.

	•		Cost Escalation Factors — TVA’s decommissioning estimates include an assumption that decommissioning costs will escalate over present cost levels by 4 percent annually.

Pension and Other Postretirement Benefits

TVA sponsors a defined benefit pension plan with two structures, an average pay structure and a cash balance structure, which cover substantially all employees. Additionally, TVA provides postretirement health care benefits for substantially all 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. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, the costs as reported represent critical accounting estimates for TVA.

Key actuarial assumptions utilized in determining these costs include:

	•		Interest and discount rates used in determining the future benefit obligations;

	•		Projected health care cost trend rates;

	•		Expected long-term rate of return on plan assets; and

	•		Rate of increase in future compensation levels.

TVA reviews these assumptions on an annual basis and adjusts them as necessary. The falling interest rate environment and poor performance of the financial equity markets in recent years have impacted TVA’s funding and reported costs for these benefits. In addition, these trends have caused TVA to make a number of adjustments to its assumptions.

In selecting an assumed discount rate, TVA reviews market yields on high-quality corporate debt and long-term obligations of the U.S. Treasury. Such reviews are made as of the end of the year for use in the development of a bond portfolio designed to meet the maturing obligations of the TVA plan. The instruments selected have outstanding maturity values of at least $25 million or more, are rated Aa or higher, and are non-callable. The resulting portfolio rate of 6.05 percent was utilized along with the end-of-year Moody’s Aa Corporate Bond Index of 5.74 percent to establish an upper and lower limit for consideration by TVA in the selection of its discount rate. TVA selected a discount rate that approximated the midpoint of the determined range which resulted in a discount rate of 5.90 percent for 2006.

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. TVA decreased its expected long-term rate of return on pension plan assets from 8.50 percent at the end of 2003 to 8.25 percent at the end of both 2004 and 2005 but increased the rate to 8.75 percent for the year ended 2006 to better reflect anticipated future plan asset performance. TVA utilized a rate of return of 8.00 percent during 2003 in the aftermath of the market declines of 2002 and 2001.

The TVA Retirement System, a separate legal entity governed by its own board of directors, administers TVA-sponsored retirement plans. The TVA Retirement System targets an asset allocation for its pension plan assets of approximately 60 percent equity securities and 40 percent fixed income securities. Pursuant to its allocation policy, the asset allocations are to be comprised of approximately 45 percent U.S. equities, of which five percent may be private equity or other similar alternative investments; 40 percent fixed income, of which ten percent may be high yield securities; and 15 percent non-U.S. equities. The TVA Retirement System’s policy includes a permissible three percent deviation from these target allocations. The TVA Retirement System Board can take action, as appropriate, to rebalance the system’s assets consistent with the asset allocation policy. See Note 12.

TVA reviews actual recent cost trends and projected future trends in establishing health care cost trend rates. Based on this review process, TVA did not reset its health care cost trend rate assumption used in calculating the 2006 accumulated postretirement benefit obligations. The assumed health care trend rate was 8.5 percent at the

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end of 2006 which represents a 50 basis point reduction from the 9.0 percent trend rate used during 2005. TVA reset its health care cost trend rate at the end of each of the last four years prior to 2006. The health care cost trend rate of 8.5 percent is assumed to gradually decrease each successive year until it reaches a five percent annual increase in health care costs in the year beginning October 1, 2013, and beyond.

TVA does not presently set aside assets dedicated solely to fund its postretirement medical benefits. Instead, TVA pays the costs of its postretirement benefit plan through premiums collected from participating retirees and TVA contributions.

The following chart reflects the sensitivity of pension cost to changes in certain actuarial assumptions:


						Impact on 2006
	Change in			Impact on 2007		Projected Benefit
Actuarial Assumption	Assumption			Pension Cost		Obligation
	(Increase in millions)
Discount rate		(0.25	%)	$	18	$	248
Rate of return on plan assets		(0.25	%)	$	16	NA
Rate of compensation		0.25	%	$	12	$	67

The following chart reflects the sensitivity of postretirement benefit cost to changes in certain actuarial assumptions:


						Impact on 2006
				Impact on 2007		Projected
	Change in			Postretirement		Postretirement
Actuarial Assumption	Assumption			Benefit Cost		Benefit Obligation
	(Increase in millions)
Discount rate		(0.25	%)	$	1	$	14
Health care cost trend		0.25	%	$	1	$	15

Each fluctuation above assumes that the other components of the calculation are held constant.

Accounting Mechanisms. In accordance with SFAS No. 87, “Employers’ Accounting for Pensions,” TVA utilizes a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are amortized into cost only when the accumulated differences exceed ten 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.

Additionally, TVA smoothes 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 2002 and 2001 may have an adverse impact on pension cost in future years depending on whether the actuarial losses at each measurement date exceed the ten percent corridor in accordance with SFAS No. 87.

Costs and Funding. In 2006, TVA’s total pension cost was $244 million. TVA expects 2007 pension cost to decrease to $159 million due in part to an increase in the discount rate from 5.38 percent to 5.90 percent. The impact of the higher discount rate was further enhanced by the recognition of certain actuarial gains. Pension funding amounted to $75 million.

Due to negative pension plan asset returns from 2002 and 2001, TVA’s accumulated benefit obligation at September 30, 2006 and 2005 exceeded plan assets. As a result, TVA was required to recognize an additional minimum pension liability as prescribed in SFAS No. 87. The charge to establish the minimum liability and the subsequent increases and decreases thereto were entered to Other Comprehensive Income, again in accordance with the requirements of SFAS No. 87. However, TVA reclassified all such minimum pension liability changes to a regulatory asset in accordance with SFAS No. 71. The regulatory treatment of the original changes was deemed necessary from the perspective that it would be improper to presume a level of future earnings on pension assets sufficient to fully recover, within a period of one year, all such costs included in Other comprehensive income.

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Total postretirement health care costs for TVA in 2006 were $58 million. The set of assumptions used for the end-of-year actuarial valuation process had no effect on postretirement benefit costs for 2006, 2005, or 2004 but, when coupled with further experience adjustments related to claims and contributions, will decrease postretirement benefits expense for 2007 by approximately $16 million compared to 2006. TVA expects 2007 postretirement health care cost to approximate $42 million, which represents a decrease of $16 million over 2006 costs, excluding special termination benefits.

In 2006, Medicare began providing prescription drug coverage to Medicare-eligible beneficiaries under Medicare Part D. Under the “Medicare Prescription Drug, Improvement and Modernization Act of 2003,” employers that provide retiree prescription drug coverage, which is “actuarially equivalent” to standard coverage under Medicare Part D, may receive retiree drug subsidies for retirees who enroll in the employer’s retiree prescription drug plan instead of Medicare Part D. TVA determined that its retiree prescription drug coverage did not qualify for retiree drug subsidy. As a result, through its prescription benefit manager, TVA implemented for 2006 an employer-sponsored prescription drug plan (“PDP”). By providing an employer-sponsored PDP, TVA’s prescription benefit manager receives subsidies from Medicare which are passed through to retirees in the form of lower premiums. (See further description in Note 12 — Medicare Prescription Drug, Improvement and Modernization Act of 2003).

New Accounting Standards and Interpretations

Variable Interest Entities

In January 2003, the Financial Accounting Standards Board (“FASB”) published FASB Interpretation No. 46, “Consolidation of Variable Interest Entities,” which was revised by FASB Interpretation No. 46R (“46R”) in December 2003. FIN 46R establishes consolidation criteria for entities for which “control” is not easily discernable under Accounting Research Bulletin (“ARB”) 51, “Consolidated Financial Statements,” which is based on the premise that holders of the equity of an entity control the entity by virtue of voting rights. FIN 46R provides guidance for identifying the party with a controlling financial interest resulting from arrangements or financial interests rather than from voting interests. FIN 46R defines the term “variable interest entity” (“VIE”) and is based on the premise that if a business enterprise absorbs a majority of the VIE’s expected losses and/or receives a majority of its expected residual returns (measures of risk and reward), that enterprise (the primary beneficiary) is deemed to have a controlling financial interest in the VIE. An enterprise that bears the majority of the economic risk is considered to have a controlling financial interest in a VIE, even if it has no decision making (voting) authority or equity interest. TVA adopted FIN 46 and FIN 46R effective October 1, 2005, for VIEs created before December 31, 2003, and immediately for VIEs created after December 31, 2003.

In February 1997, TVA entered into a purchase power agreement with Choctaw Generation, Inc. (subsequently assigned to Choctaw Generation Limited Partnership) to purchase all the power generated from its facility located in Choctaw County, Mississippi. The facility had a committed capacity of 440 megawatts and the term of the agreement was 30 years. Under the accounting guidance provided by FIN 46R, TVA may be deemed to be the primary beneficiary under the contract; however, TVA does not have access to the financial records of Choctaw Generation Limited Partnership. As a result, TVA was unable to determine whether FIN 46R would require TVA to consolidate Choctaw Generation Limited Partnerships’ balance sheet, results of operations, and cash flows for the year ended September 30, 2006. Power purchases for 2006 under the agreement amounted to $121 million, and the remaining financial commitment under this agreement is $4.1 billion. TVA has no additional financial commitments beyond the purchase power agreement with respect to the facility.

On April 13, 2006, the FASB issued FASB Staff Position FIN 46R-6, “Determining the Variability to Be Considered in Applying FASB Interpretation No. 46R,” which addresses how a reporting enterprise should determine the variability to be considered in applying FASB Interpretation No. 46. FIN 46R-6 is to be applied prospectively to all entities with which that enterprise first becomes involved and to all entities previously required to be analyzed under FIN 46R when a reconsideration event has occurred pursuant to paragraph seven of FIN 46R beginning the first day of the first reporting period after June 15, 2006. TVA began applying this guidance with the reporting period ending September 30, 2006. The adoption of this guidance did not have a material impact on TVA’s results of operations or financial condition.

Conditional Asset Retirement Obligations

In March 2005, the FASB issued FIN No. 47, “Accounting for Conditional Asset Retirement Obligations—an interpretation of FASB Statement No. 143.” This interpretation clarifies that the term conditional asset retirement obligation (“conditional ARO”) as used in SFAS No. 143, "Accounting for Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the

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asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Thus, the timing and (or) method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional ARO if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional ARO should be recognized when incurred. This interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an ARO. On September 30, 2006, TVA began applying FIN 47, “Accounting for Conditional Asset Retirement Obligations,” which resulted in the recognition of additional ARO liabilities for asbestos and Polychlorinated Biphenyls abatement costs. The effect of the adoption of FIN No. 47 during 2006 included a cumulative effect charge to income of $109 million, a recognition of a corresponding additional long-term liability of $132 million, a recognition of an increase in assets of $43 million, and related accumulated depreciation of $20 million.

Accounting Changes and Error Corrections

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3,” which replaces Accounting Principles Board (“APB”) Opinion No. 20, “Accounting Changes,” and FASB Statement No. 3, “Reporting Accounting Changes in Interim Financial Statements.” This statement applies to all voluntary changes in accounting principles and also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. This statement requires, unless impracticable, retrospective application to prior periods’ financial statements of changes in accounting principles. If it is impracticable to determine the period-specific effects of an accounting change on one or more individual prior periods presented, this statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings for that period rather than being reported in an income statement. When it is impracticable to determine the cumulative effect of applying a change in accounting principle to all prior periods, this statement requires that the new accounting principle be applied as if it were adopted prospectively from the earliest date practicable. This statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate effected by a change in accounting principle. The statement will become effective for TVA beginning in 2007 with early adoption permitted for accounting changes and corrections of errors made in fiscal years beginning after May 2005, the date the statement was issued.

Accounting for Inventory Transactions

At its September 28, 2005, meeting, the FASB reached consensus on Emerging Issues Task Force (“EITF”) Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” In certain situations, a company may enter into a nonmonetary transaction to sell inventory to another company in the same line of business from which it also purchases inventory. Questions have arisen regarding how the guidance in APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” should be applied in these situations. The consensus reached states that inventory purchase and sales transactions with the same counterparty that are entered into in contemplation of one another should be combined for purposes of applying APB Opinion 29. The EITF also agreed that the issuance of invoices and the exchange of offsetting cash payments is not a factor in determining whether two or more inventory transactions with the same counterparty should be considered as a single nonmonetary inventory transaction within the scope of Opinion 29. The Task Force also reached a consensus that a nonmonetary exchange within the same line of business involving the transfer of raw materials in exchange for the receipt of raw materials should not be recognized at fair value. This EITF should be applied to transactions completed in reporting periods beginning after March 15, 2006, whether pursuant to arrangements that were in place at the date of initial application of the consensus or arrangements executed subsequent to that date. The carrying amount of the inventory that was acquired under these types of arrangements prior to the initial application of the consensus, and that still remains in an entity’s statement of financial position at the date of initial application of the consensus, should not be adjusted for this consensus. TVA adopted EITF Issue No. 04-13 beginning in the second quarter of 2006. The adoption of this guidance did not have a material impact on TVA’s results of operations or financial condition.

Put and Call Options

In September 2005, the Derivatives Implementation Group (“DIG”) of the FASB discussed several issues related to the settlement of a debtor’s obligation on the exercise of a call or put option and the exercise only by the debtor of the right to accelerate settlement of a debt with an embedded call option. DIG Implementation Issue No. B38, “Embedded Derivatives: Evaluation of Net Settlement with Respect to the Settlement of a Debt Instrument through Exercise of an Embedded Put Option or Call Option,” addresses whether the settlement of a debtor’s obligation on exercise of a call or put option meets the net settlement criterion in paragraph 9(a) of SFAS No. 133, as amended. DIG Implementation Issue No. B39, “Embedded Derivatives: Application of Paragraph 13(b) to Call

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Options That Are Exercisable Only by the Debtor,” addresses whether or not Paragraph 13(b) of SFAS No. 133, as amended, applies to a call option embedded with a debt host if the right to accelerate settlement of the debt can be exercised only by the debtor. The effective date of the implementation guidance in these issues was the first day of the first fiscal quarter beginning after December 15, 2005. The issue became effective for TVA beginning in the second quarter of 2006. The adoption of this guidance did not have a material impact on TVA’s results of operations or financial condition.

Accounting for Rental Costs

On October 6, 2005, the FASB issued FSP FAS 13-1, “Accounting for Rental Costs Incurred during a Construction Period.” The FASB concludes in this FSP that rental costs associated with ground or building operating leases that are incurred during a construction period should be expensed. FASB Technical Bulletin (“FTB”) No. 88-1, “Issues Relating to Accounting for Leases,” requires that rental costs associated with operating leases be allocated on a straight-line basis in accordance with FASB Statement No. 13, “Accounting for Leases,” and FTB 85-3, “Accounting for Operating Leases with Scheduled Rent Increases,” starting with the beginning of the lease term. The FASB believes there is no distinction between the right to use a leased asset during the construction period and the right to use that asset after the construction period. TVA began applying this guidance beginning with the quarterly reporting period ended March 31, 2006. The adoption of this guidance did not have a material impact on TVA’s results of operations or financial condition.

Impairment of Investments

On November 3, 2005, the FASB released FSP FAS 115-1 and FAS 124-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments.” This FSP addresses the determination as to when an investment is considered impaired, whether that impairment is other than temporary, and the measurement of an impairment loss. The FSP also includes accounting considerations subsequent to the recognition of an “other-than-temporary” impairment and requires certain disclosures about unrealized losses that have not been recognized as “other-than-temporary” impairments. TVA began applying this guidance beginning with the quarterly reporting period ending March 31, 2006. The adoption of this guidance did not have a material impact on TVA’s results of operations or financial condition.

Fair Value Measurements

In September 2006, FASB issued SFAS No. 157, “Fair Value Measurements.” This standard provides guidance for using fair value to measure assets and liabilities. The standard 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. Statement 157 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. SFAS No. 157 establishes a fair value hierarchy that prioritizes the information used to develop measurement assumptions. The provisions of SFAS No. 157 are effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Earlier application is encouraged, provided that the reporting entity has not yet issued financial statements for that fiscal year, including any financial statements for an interim period within that fiscal year. At this time, TVA continues the process of evaluating the requirements of this statement and does not yet know the impact of its implementation, which may or may not be material to TVA’s results of operations or financial position.

Accounting for Defined Benefit Pension and Other Postretirement Plans

On September 29, 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106, and 132(R).” This standard will require employers to fully recognize the obligations associated with single-employer defined benefit pension, retiree healthcare and other postretirement plans in their financial statements. The standard will make it easier for investors, employees, retirees and others to understand and assess an employer’s financial position and its ability to fulfill the obligations under its benefit plans. Specifically, the new standard requires an employer to: recognize in its statement of financial position an asset for a plan’s overfunded status or a liability for a plan’s underfunded status; measure a plan’s assets and its obligations that determine its funded status as of the end of the employer’s fiscal year (with limited exceptions); and recognize changes in the funded status of a defined benefit postretirement plan in the year in which the changes occur. Those changes will be reported in comprehensive income of a business entity and in changes in net assets of a not-for-profit organization.

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and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008. TVA plans to apply the new standard for its 2007 year-end financial statements and recognize on its 2007 Balance Sheets the funded status of its pension and other postretirement benefit plans. However, had TVA been required to adopt the standard as of its last actuarial valuation date (September 30, 2006), TVA would have recorded the following amounts on its Balance Sheet for the year then ended: a regulatory asset of $795 million, additional pension and postretirement obligations of $368 million and $152 million, respectively, and the reclassification to the regulatory asset of an intangible asset with a balance of $275 million representing unamortized prior service cost. The net effect of recognizing such amounts would have been to increase total assets and liabilities by $520 million at that date.

Accounting for Misstatements

On September 13, 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements.” This bulletin provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. Application of the guidance is effective for TVA beginning with the first interim period of fiscal year 2007.

Legislative and Regulatory Matters

In July 2005, Senator Jim Bunning (R-KY) and Senator Mitch McConnell (R-KY) introduced S.1499, a bill that would effectively remove any area within Kentucky from coverage by the anti-cherrypicking provision. See Item 1, Business — Competition for further discussion of the anti-cherrypicking provision. If the bill were to become law, FERC could require TVA to wheel power from a supplier other than TVA for use inside that portion of TVA’s service area that is within Kentucky. The bill was referred to and remains in the Senate Energy and Natural Resources Committee.

In June 2005, the Office of Management and Budget (“OMB”) transmitted draft legislation to Congress that would expand the type of evidences of indebtedness that count toward TVA’s $30 billion debt ceiling. Under this legislation, long-term obligations that finance capital assets would count toward the debt ceiling, including lease-leaseback arrangements and power prepayment agreements with original terms exceeding one year. This legislation, which would be effective for transactions into which TVA entered after December 31, 1999, has not yet been introduced in Congress.

Congressman Whitfield has introduced H.R. 6087 directing the U.S. Army Corps of Engineers to extend summer pool levels on Lake Barkley through Labor Day for a two-year trial period starting in July 2007. After the trial period, the Corps is required to report findings to Congress with a recommendation on whether to extend the summer pool levels permanently. The bill has been referred to the House Committee on Transportation and Infrastructure, but this referral does not preclude it from being attached to some other piece of legislation that is adopted before Congress adjourns for 2006. The bill, if enacted, could potentially impact operation of TVA’s Kentucky Reservoir and Lake Barkley, which are connected by an unregulated canal. In particular, the bill could have environmental effects, adverse impacts to hydroelectric power production, and adverse downstream effects on flood control and commercial navigation on the lower Ohio and Mississippi Rivers.

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

TVA can control neither what legislation becomes law nor what regulations are promulgated. Even legislation or regulations of which TVA has been made aware may be changed in ways which are difficult to predict or which have unforeseen consequences. TVA cannot therefore predict with certainty or with any accuracy whether the initiatives discussed above will become law in the future and in what form, and what their impact would be on TVA. Moreover, given the nature of the legislative process, it is possible that new legislation or a change to existing legislation that has a profound, detrimental 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.

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Environmental Matters

Clean Air Developments

Sulfur Dioxide

Coal-fired utilities have historically emitted large amounts of SO₂. Utility SO₂ emissions are currently regulated under the Federal Acid Rain Program and state programs designed to meet the National Ambient Air Quality Standards for SO₂and fine particulate matter. Looking forward, additional regulation of SO₂ emissions from some units will result from implementation of the Regional Haze Program and for more units as a result of the CAIR. In May 2005, EPA finalized CAIR to reduce the interstate transport of fine particulate matter and ozone by requiring large reductions in utility emissions of NO_X and SO₂ from 28 eastern states. CAIR is currently in effect in all of these states as a federal rule. States in TVA’s service area are submitting plans to EPA to implement CAIR as state rules and have only proposed a few minor modifications to the federal model rule which establishes an emission allowance driven program, capping regional emissions of SO₂ and NO_x among the targeted states. SO₂ caps are reduced in two phases, 2010 and 2015.

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sulfur coal on several additional units in the next few years. These near-term plans are unlikely to change. It is likely that additional emission reduction measures will have to be undertaken after these planned actions are completed to achieve compliance with CAIR and possible future tightening of applicable requirements.

Nitrogen Oxides

Utility NO_x emissions are extensively regulated and will be regulated further under state programs to achieve and maintain EPA’s national ambient air quality standard for ozone, the acid rain control program, the regional haze program (depending on when units commenced operations and their effects on sensitive areas), and CAIR, as discussed above. Since 1995, TVA has reduced its NO_x emissions during the summer (when ozone levels increase) by 81 percent by installing various controls including low-NO_x burners and/or combustion controls on 58 of its coal-fired units. (The AFBC unit at Shawnee is inherently low NO_x emitting.) TVA has also installed SCR’s on 21 of its largest units. In 2005, TVA installed Selective Non-Catalytic Reduction (“SNCR”) systems on two units to demonstrate long term technology capability. TVA has continued operating these two new SNCR installations through the 2006 ozone season. SNCRs generally cost less to install than SCRs but have lower NO_x removal capabilities. Early in 2006, TVA began testing a High Energy Reagent Technology (“HERT”) on three units for potential future application. HERT is similar to SNCR, has lower capital costs than SCRs, and appears to have lower NO_x removal capabilities than SCRs but higher removal capabilities than SNCRs. The initial HERT testing program was successful. As a result, in 2007, TVA will install this technology on two coal-fired units that were previously targeted for SNCR installations to demonstrate the HERT technology on a potentially permanent basis. TVA’s NO_x emission reduction program is expected to continue to depend primarily on SCRs, but will also likely incorporate some mix of SNCRs and/or HERTs as TVA gains more experience with these technologies. These plans may change depending on the timing and severity of future regulatory developments potentially affecting power plant emissions. For example, EPA is currently reviewing the existing national ambient air quality standard for ozone and may make it more stringent.

Particulates/Opacity

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Mercury

In December 2000, the EPA determined that it was appropriate and necessary to regulate mercury emissions from oil and coal-fired power plants as a hazardous air pollutant under the CAA. In March 2005, it reversed that earlier decision, and instead issued CAMR. CAMR establishes caps for overall mercury emissions in two phases, with the first phase becoming effective in 2010 and the second in 2018. It allows the states to regulate mercury emissions through a market-based cap-and trade program. All of the states in which TVA operates potentially affected sources are expected to adopt CAMR without significant change. In response to a request for reconsideration, EPA confirmed its approach in May 2006. In June 2006, 16 states and several environmental groups filed law suits challenging CAMR. This lawsuit is currently pending. TVA cannot predict the outcome of the pending challenge of CAMR, or what effects any decision may have that would require the EPA to regulate mercury as a hazardous air pollutant. If the EPA’s decisions are upheld and CAMR is implemented, TVA expects to achieve the required mercury reductions at least for Phase I of CAMR as co-benefits of the installation of additional emission control technology in connection with the implementation of CAIR.

Carbon Dioxide

The causes and importance of climate change observed over recent decades continue to be widely debated. CO₂ is a greenhouse gas and is believed by some to contribute to global warming. Legislation has been introduced in Congress to require reductions of CO₂ and, if enacted, could result in significant additional costs for TVA and other coal-fired utilities. The current Administration has proposed a voluntary initiative that established a goal of reducing the greenhouse gas intensity of the U.S. economy by 18 percent and has asked the electric utility sector and other industry sectors to support this initiative. TVA is supporting this effort in cooperation with electric utility industry trade associations and the Department of Energy. In addition to these activities, TVA is a member of the Southeast Regional Carbon Sequestration Partnership and is working with the Electric Power Research Institute and other electric utilities on projects investigating technologies for CO₂ capture and geologic storage, as well as carbon sequestration via reforestation. The previous Administration also asked utilities to voluntarily participate in an effort to reduce, sequester, or avoid greenhouse gases. Under that program, TVA reduced, sequestered, or avoided more than 305 million tons of CO₂ from 1994 through 2005, as reported under Section 1605b of the Energy Policy Act. TVA has also brought on line about 3,850 megawatts of non CO₂-emitting generation since 1990, and is in the process of adding another 1,800 megawatts of non CO₂-emitting generation. TVA’s clean air strategy, as it relates to investments on coal-fired generating facilities, allows for continued review of decisions for clean air and other capital investments as potential climate change legislation is developed.

Clean Water Developments

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hatcheries for fish/shellfish production, count toward compliance. Some northeastern states and environmental groups have challenged the new regulation, especially the compliance flexibility it offers, in federal court.

Hazardous Substances

As of September 30, 2006, TVA’s estimated liability for environmental cleanup for those sites for which sufficient information is available to develop a cost estimate (primarily the TVA sites) is approximately $23 million and is included in Other Liabilities on the Balance Sheet.

Coal-Combustion Wastes

Legal Proceedings

For a discussion of TVA’s current legal proceedings and anticipated outcomes, see Item 3, Legal Proceedings.

Risk Management Activities

Risk Governance

The Enterprise Risk Council (“ERC”) was created in August 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 (chair), the Chief Financial Officer, the

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Executive Vice President and General Counsel, the Chief Risk Officer (“CRO”), and a designated representative from the Office of the Inspector General (“OIG”) (advisory).

In addition to the ERC, TVA has established subordinate risk committees, Financial, Operational, and Strategic, to manage risks based on natural groupings. Each of the subordinate committees reports directly to the ERC. Membership in the subordinate committees includes senior management from organizations that manage the applicable risks, the CRO, and advisory representatives from the OIG and from the Office of the General Counsel. The ERC and the risk committees meet at least quarterly.

The ERC and risk committees spent much of 2006 cataloging the major enterprise level risks for TVA into three main categories: strategic risks, operational risks and financial risks. A discussion of significant risk factors under each of these categories, as well as risk factors related to TVA securities, is presented in Item 1A, Risk Factors. In addition, a discussion of derivative instruments that TVA uses to hedge certain of these risks is contained in Note 8. It is TVA’s policy to enter into derivative transactions solely for hedging purposes and not for speculative purposes.

Commodity Price Risk

TVA is exposed to commodity price risk for a variety of commodities that are critical to TVA’s operations. These commodities include electricity, coal, uranium, natural gas, fuel oil, and emission allowances. In October 2006, TVA implemented the FCA mechanism that will significantly limit TVA’s exposure to fluctuations in the prices of these commodities. The FCA mechanism enables TVA to adjust its rates on a quarterly basis for fuel and purchased power costs. Accordingly, with the implementation of the FCA mechanism, the commodity price risks that TVA faces are more timely shared by both TVA and its customers. See Note 8 for a discussion of activities that TVA uses to hedge commodity price risk.

TVA measures price risk associated with the commodities that are critical to its operations using either a Value at Risk (“VaR”) methodology or sensitivity analysis. Following is an explanation of these methods along with their calculated measures of TVA’s commodity price risk.

Value at Risk

TVA uses a VaR methodology to measure the amount of price risk that exists within certain of its commodity portfolios. Price risk is quantified using what is referred to as the variance-covariance technique of measuring VaR, which provides a consistent measure of risk across diverse energy markets and products. This technique requires the selection of a number of assumptions including a confidence level for losses, price volatility, market liquidity, and a specified holding period. This methodology uses standard statistical techniques to predict market movements in light of historical prices, volatilities, and risk correlations.

The VaR calculation gives TVA a dollar amount which reflects the maximum potential loss in the fair value of its portfolios due to adverse market movements over a ten-day period within a specified confidence level. TVA’s VaR calculations are based on a 95 percent confidence level, which means that there is a five percent probability that TVA’s portfolios will incur a loss in value in ten days at least as large as the reported VaR. For example, if the VaR is calculated at $5 million, there is a 95 percent probability that if prices move against current positions, the reduction in the value of the portfolio resulting from such 10-day price movements would be less than $5 million. There would also be a five percent probability that the reduction in the value of the portfolio resulting from such price movements would be greater than $5 million.

The following table illustrates the potential unfavorable price impact on TVA’s electricity, natural gas, SO₂emission allowance, and NO_x emission allowance portfolios as measured by the VaR model based on a ten-day holding period and a 95 percent confidence level. The high and low valuations represent the highest and lowest VaR values during 2006, and the average calculation represents the average of the VaR values during 2006.

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Value at Risk


	September 30,
	2006		Average		High		Low

Electricity ¹	$	45	$	75	$	124	$	19
Natural Gas ²		34		26		61		3
SO₂ Emission Allowances ³		21		20		59		3
NO_x Emission Allowances ⁴		1		5		10		1


Notes

1		TVA’s VaR calculations for electricity are based on its on-peak electricity portfolio, which includes electricity forwards and option contracts.

2		TVA’s VaR calculations for natural gas are based on TVA’s natural gas portfolio, which includes natural gas forwards, futures, and options on futures contracts.

3		TVA’s VaR calculations for SO₂ emission allowances are based on TVA’s portfolio of SO₂ emission allowances.

4		TVA’s VaR calculations for NO_x emission allowances are based on TVA’s portfolio of NO_x emissions allowances.

VaR has several limitations as a measure of portfolio risk, including, but not limited to, its inability to adequately reflect (1) the risk of a portfolio with significant option exposure, (2) the risk of extreme price movements, and (3) the significant regulatory and legislative risks facing TVA.

Electricity. TVA enters into electricity forward contracts in order to hedge its economic risks directly associated with meeting its power supply obligations. During 2006, TVA supplied approximately 8.9 percent of system energy requirements with power purchased under electricity forward contracts.

TVA’s average electricity market risk exposure has increased annually since 2003. The increases have resulted primarily from TVA’s increased purchases of power to meet growing demand and, to a lesser extent, from increased volatility in the electricity markets.

As shown in the Value at Risk table above, at a 95 percent confidence level, the average VaR for TVA’s electricity portfolio for 2006 for a 10-day holding period was $75 million.

Natural Gas. TVA purchases a substantial portion of its physical natural gas requirements under long-term transportation contracts with prices which are primarily settled on the spot market. TVA uses the natural gas to operate combustion turbine peaking units and to supply fuel under power purchase agreements in which TVA is the fuel supplier. TVA hedges a portion of its natural gas needs by entering into futures contracts and options on futures contracts under a financial hedging program. At September 30, 2006, TVA had derivative positions outstanding under the program equivalent to about 1,158 contracts, made up of 429 futures contracts and 729 swap future contracts, with an approximate net market value of $40 million.

TVA has tracked natural gas Value at Risk exposure since 2001. The average natural gas VaR decreased from 2001 through 2004, but increased in 2005 and 2006. The increase in 2005 and 2006 resulted primarily from an increase in TVA’s natural gas needs because of the increase in the volume of electricity contracts that are indexed to natural gas.

As shown on the Value at Risk table above, at a 95 percent confidence level, the average VaR for TVA’s natural gas portfolio for 2006 for a 10-day holding period was $26 million.

Emission Allowances. TVA acquires both SO₂ emission allowances and NO_x emission allowances to help TVA comply with the emission requirements of the CAA and its implementing regulations. In addition to meeting TVA’s emissions requirements, TVA also uses the emissions market to attempt to optimize the value of its emission allowance portfolio. As shown in the VaR table above, at a 95 percent confidence level, the average VaR for 2006 for a 10-day holding period for TVA’s SO₂ emission allowance portfolio and NO_x emission allowance portfolio was $20 million and $5 million, respectively.

Fuel Oil. TVA purchases fuel oil as a substitute fuel source for TVA’s combustion turbines. Thus, TVA’s hedge against market risk for fuel oil is the use of natural gas and is captured in the natural gas VaR.

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Sensitivity Analysis

TVA uses sensitivity analysis to measure the potential impact that selected hypothetical changes in certain commodity prices would have on TVA over a selected period of time. The selected hypothetical changes in commodity prices are intended to reflect reasonably possible near-term changes.

Coal. During 2006, TVA purchased 83 percent of its coal requirements under term coal contracts and 17 percent of its coal requirements in the spot coal market. If the rates that TVA paid for coal in the spot market during 2006 were 10 percent higher than the rates TVA actually paid, TVA’s coal expense would have increased by $34 million in 2006.

Uranium. During 2006, TVA did not have to purchase any uranium on the spot market, and as of September 30, 2006, TVA had all of its uranium requirements through 2011 either in inventory or under contract. Accordingly, a hypothetical 10 percent change in uranium prices during 2007 would have no material effect on TVA’s financial position, results of operations, or cash flows. See Item 1, Business — Fuel Supply — Nuclear Fuel.

Cash Flow at Risk

Cash Flow at Risk (“CFaR”) is a modeled portfolio risk metric that measures the amount of potential variability around forecasted cash flows that could be caused by changes in market conditions, hydroelectric generation and availability, and load. Although the FCA will serve to limit the amount of cash flow variability to which TVA is exposed, TVA will continue to manage CFaR for the mutual benefit of TVA and its customers.

TVA forecasts CFaR using a computer model. The rolling 12 month forecast is used to pinpoint months with greater amounts of CFaR that need to be hedged to limit price exposure. At September 30, 2006, TVA estimated its 2007 CFaR at $322 million based on a 90 percent confidence level.

Investment Price Risk

TVA’s investment price risk relates primarily to investments in TVA’s nuclear decommissioning trust and pension fund.

Nuclear Decommissioning Trust

The nuclear decommissioning trust 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 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, and currencies. As of September 30, 2006, the value of the investments in the trust was $937 million, and 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. 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 nuclear decommissioning trust.

Pension Fund

The TVA Retirement System Board targets an asset allocation for its pension fund of approximately 60 percent equity securities and 40 percent fixed income securities. The pension fund is invested in equity securities, debt securities, and derivative instruments such as futures, options, and swaps, and through these investments the fund has exposure to U.S. equities, international equities, real estate investment trusts, investment-grade debt, high-yield debt, U.S. Treasury-inflation protected securities, commodities, and currencies. As of September 30, 2006, the value of the investments in the pension fund was $7.3 billion, and an immediate 10 percent decrease in the value of the investments in the fund would have reduced the value of the fund by $730 million. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates — Pension and Other Postretirement Benefits and Note 12 for additional information regarding TVA’s pension fund.

Interest Rate Risk

TVA’s interest rate risk is related primarily to its short-term investments, its Bonds, and TVA’s swaption transactions and an interest rate swap related to one of TVA’s swaption transactions.

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Short-Term Investments

At September 30, 2006, TVA had $536 million of cash and cash equivalents, and the average balance of cash and cash equivalents for 2006 was $541 million. If the rates of interest that TVA received on its short-term investments during 2006 were one percentage point lower that the rates of interest that TVA actually received on these investments, TVA would have received approximately $5 million less in interest from its short-term investments during 2006. In addition, changes in interest rates could affect the value of TVA’s investments in its pension fund and nuclear decommissioning fund. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations — Risk Management Activities — Investment Price Risk.

Debt Portfolio

Short-Term Debt. At September 30, 2006, TVA’s short-term borrowings were $2.4 billion, and the current maturities of long-term debt were $1.0 billion. Based on TVA’s interest rate exposure at September 30, 2006, an immediate 1 percentage point increase in interest rates would have resulted in an increase of $29 million in TVA’s short-term interest expense during 2007. This calculation assumes that the balance of short-term debt during 2007 equals the short-term debt balance at September 30, 2006, plus an amount representing the refinancing of current maturities of long-term debt.

Long-Term Debt. At September 30, 2006, 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, 2006, the average life of TVA’s debt portfolio was 17 years. A schedule of TVA’s debt maturities is contained in Note 9.

Swaption Agreements and Related Interest Rate Swap

Changes in interest rates also affect the amount of gains and losses on the mark-to-market valuation of TVA’s three swaption agreements and the related interest rate swap. Gains and losses on these transactions are recorded in earnings as Unrealized Gain/Loss on Derivative Transactions, Net and are non-cash in nature. Based on TVA’s interest rate exposure at September 30, 2006, an immediate one percentage point decrease in interest rates would have created a non-cash charge to earnings of $286 million during 2007 and a corresponding increase in Other Liabilities.

Currency Exchange Rate Risk

As of September 30, 2006, TVA had three issues of Bonds outstanding whose principal and interest payments are 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, 2006, 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.

Inflation Risk

As of September 30, 2006, TVA had outstanding $385 million of Bonds whose principal amounts fluctuate based on the rate of inflation. When TVA issued these Bonds, it hedged its inflation exposure by entering into an inflation swap agreement. Accordingly, as of September 30, 2006, a 10 percent change in the rate of inflation would not have had a material impact on TVA’s cash flows, results of operations, or financial position.

Credit Risk

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 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 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.

The table below summarizes TVA’s customer credit risk from trades accounts receivable as of September 30, 2006:

Customer Credit Risk
As of September 30


Trade Accounts Receivable ¹
Municipalities and Cooperative Distributor Customers
Investment Grade	$	845
Internally Rated — Investment Grade		433
Industries and Federal Agencies Directly Served
Investment Grade		37
Non-investment Grade		(1	)
Internally Rated — Investment Grade		4
Internally Rated — Non-investment Grade		10
Exchange Power Arrangements
Investment Grade		4
Non-investment Grade		—
Internally Rated — Investment Grade		1
Internally Rated — Non-investment Grade		1

Subtotal		1,334
Other Accounts Receivable
Miscellaneous Accounts		35
Provision for Uncollectible Accounts		(10	)

Subtotal		25

Total	$	1,359


(1)		Includes unbilled power receivables of $1,031 million.

TVA has concentrations of accounts receivable from seven customers that represented 42 percent of total accounts receivable as of September 30, 2006.

Credit of Other Counterparties

In addition to being exposed to economic loss on account of the nonperformance of TVA’s customers, TVA is exposed to economic loss on account of the nonperformance of its other counterparties, including suppliers and counterparties to its derivative contracts.

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 of September 30, 2006, counterparties with which TVA had power purchase agreements for 3,008 megawatts of capacity were in bankruptcy. Each of these parties has continued to perform under its power purchase agreement with TVA throughout the bankruptcy proceedings, and all of these agreements are secured with either cash or letters of credit. Accordingly, TVA has not experienced any economic or cash losses as a result of the counterparties’ bankruptcy proceedings.

Credit of Derivative Counterparties. TVA has entered into derivative contracts for hedging purposes, and TVA’s nuclear decommissioning trust 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 nuclear decommissioning trust and the pension fund have entered for investment purposes defaults, the value of the investment could decline significantly, or perhaps become worthless.

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Credit of TVA

	•		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.

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

	•		A downgrade below a contractual threshold would prevent TVA from borrowing under two credit facilities totaling $2.5 billion without the consent of the national bank that is the counterparty to the credit facilities.

	•		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.

Management Changes

On November 13, 2006, Chief Financial Officer and Executive Vice President, Financial Services Michael E. Rescoe announced that he was leaving TVA. John Hoskins, who has more than 28 years of experience in finance and accounting at TVA and most recently served as Senior Vice President and Treasurer, was appointed to serve as Interim Chief Financial Officer, effective as of November 13, 2006. In addition, Tammy Wilson, who has more than 16 years of experience in finance and accounting and most recently served as Senior Manager, Finance at TVA, was appointed as Interim Senior Vice President and Treasurer, also effective as of November 13, 2006.

Subsequent Events

See Note 16.

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.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

TENNESSEE VALLEY AUTHORITY

STATEMENTS OF INCOME

For the years ended September 30
(in millions)


	2006			2005			2004

Operating revenues
Sales of electricity
Municipalities and cooperatives	$	7,880		$	6,561		$	6,457
Industries directly served		1,066			962			842
Federal agencies and other		116			181			140
Other revenue		123			90			94

Total operating revenues		9,185			7,794			7,533

Operating expenses
Fuel and purchased power		3,333			2,601			2,081
Operating and maintenance		2,372			2,359			2,319
Depreciation, amortization and accretion (Note 1 and Note 2)		1,492			1,154			1,115
Tax-equivalents		376			365			338
Loss on asset impairment/project cancellation		9			24			20

Total operating expenses		7,582			6,503			5,873

Operating income		1,603			1,291			1,660

Other income		67			56			44

Other expense		(2	)		(4	)		(1	)

Unrealized (loss)/gain on derivative contracts, net		(15	)		3			(7	)

Interest expense
Interest on debt		1,357			1,356			1,385
Amortization of debt discount, issue, and reacquisition costs, net		21			21			24
Allowance for funds used during construction		(163	)		(116	)		(99	)

Net interest expense		1,215			1,261			1,310


Income before cumulative effects of accounting changes		438			85			386


Cumulative effect of change in accounting for conditional asset retirement obligations		(109	)		—			—


Net income	$	329		$	85		$	386

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)


	2006			2005

ASSETS
Current assets
Cash and cash equivalents	$	536		$	538
Restricted cash and investments		198			107
Accounts receivable, net		1,359			1,052
Inventories and other		576			479

Total current assets		2,669			2,176

Property, plant, and equipment (Note 3)
Completed plant		35,652			35,215
Less accumulated depreciation		(15,331	)		(14,407	)

Net completed plant		20,321			20,808
Construction in progress		3,539			2,643
Nuclear fuel and capital leases		574			437

Total property, plant, and equipment, net		24,434			23,888

Investment funds		972			858

Regulatory and other long-term assets
Deferred nuclear generating units		3,521			3,912
Other regulatory assets (Note 5)		1,809			2,367

Subtotal		5,330			6,279
Other long-term assets		1,115			1,272

Total deferred charges and other assets		6,445			7,551


Total assets	$	34,520		$	34,473


LIABILITIES AND PROPRIETARY CAPITAL
Current liabilities
Accounts payable	$	890		$	740
Accrued liabilities		211			194
Collateral funds held		195			107
Accrued interest		403			380
Current portion of lease/leaseback obligations		37			35
Current portion of energy prepayment obligations		106			106
Short-term debt, net		2,376			2,469
Current maturities of long-term debt (Note 9)		985			2,693

Total current liabilities		5,203			6,724

Other liabilities
Other liabilities		2,305			2,500
Regulatory liabilities (Note 5)		575			897
Asset retirement obligations		1,985			1,857
Lease/leaseback obligations		1,071			1,108
Energy prepayment obligations		1,138			1,244

Total other liabilities		7,074			7,606

Long-term debt, net (Note 9)		19,544			17,751


Total liabilities		31,821			32,081


Commitments and contingencies (Note 13)

Proprietary capital
Appropriation investment		4,763			4,783
Retained earnings		1,565			1,244
Accumulated other comprehensive income		43			27
Accumulated net expense of stewardship programs		(3,672	)		(3,662	)

Total proprietary capital		2,699			2,392


Total liabilities and proprietary capital	$	34,520		$	34,473

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)


	2006			2005			2004

Cash flows from operating activities
Net income	$	329		$	85		$	386
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization, and accretion		1,513			1,175			1,140
Refueling amortization		89			105			100
Amortization of deferred nuclear refueling costs		128			131			132
Loss on project cancellations/asset impairment		9			24			20
Cumulative effect of change in accounting principle		109			—			—
Net realized and unrealized mark-to-market and hedging transactions		15			(3	)		7
Non-cash retirement benefit expense		302			289			207
Prepayment credits applied to revenue		(105	)		(105	)		(96	)
Other, net		(7	)		7			13
Changes in current assets and liabilities
Accounts receivable, net		(214	)		(19	)		50
Inventories and other		(120	)		(12	)		10
Accounts payable and accrued liabilities		125			(16	)		(65	)
Accrued interest		23			(22	)		(5	)
Proceeds from energy prepayments		—			—			1,504
Deferred nuclear refueling outage costs		(72	)		(122	)		(86	)
Other, net		(110	)		(55	)		(27	)

Net cash provided by operating activities		2,014			1,462			3,290

Cash flows from investing activities
Construction expenditures		(1,399	)		(1,339	)		(1,552	)
Proceeds from project cancellation settlement (Note 1)		—			—			15
Nuclear fuel expenditures		(277	)		(141	)		(119	)
Change in restricted cash and investments		(91	)		(107	)		—
Short-term investments, net		—			335			(68	)
Loans and other receivables
Advances		(17	)		(12	)		(17	)
Repayments		13			18			22
Proceeds from sale of receivables/loans (Note 1)		11			56			—
Proceeds from settlement of litigation related to capital expenditures		35			—			—
Other, net		(2	)		2			1

Net cash used in investing activities		(1,727	)		(1,188	)		(1,718	)

Cash flows from financing activities
Long-term debt
Issues		1,132			1,650			772
Redemptions and repurchases (Note 10)		(1,241	)		(2,368	)		(2,251	)
Short-term (redemptions)/borrowings, net		(93	)		546			(157	)
Proceeds from call monetizations		—			5			—
Bond premium received		—			—			97
Proceeds from swap receivable monetization		—			—			55
Payments on lease/leaseback financing		(28	)		(29	)		(32	)
Payments on equipment financing		(6	)		(6	)		(29	)
Financing costs, net		(14	)		(17	)		(3	)
Payments to U.S. Treasury		(38	)		(36	)		(38	)
Other		(1	)		—			—

Net cash used in financing activities		(289	)		(255	)		(1,586	)

Net change in cash and cash equivalents		(2	)		19			(14	)
Cash and cash equivalents at beginning of period		538			519			533


Cash and cash equivalents at end of period	$	536		$	538		$	519

See Note 10 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)


										Accumulated
							Accumulated			Net Expense
							Other			of
	Appropriation			Retained			Comprehensive			Stewardship						Comprehensive
	Investment			Earnings			Income (Loss)			Programs			Total			Income

Balance at September 30, 2003	$	4,823		$	783		$	(74	)	$	(3,638	)	$	1,894		$	—
Net income (loss)		—			397			—			(11	)		386			386
Return on appropriated investment		—			(18	)		—			—			(18	)		—
Accumulated other comprehensive income (Note 7)		—			—			22			—			22			22
Return of appropriated investment		(20	)		—			—			—			(20	)		—


Balance at September 30, 2004		4,803			1,162			(52	)		(3,649	)		2,264			408
Net income (loss)		—			98			—			(13	)		85			85
Return on appropriated investment		—			(16	)		—			—			(16	)		—
Accumulated other comprehensive income (Note 7)		—						79			—			79			79
Return of appropriated investment		(20	)		—			—			—			(20	)		—


Balance at September 30, 2005		4,783			1,244			27			(3,662	)		2,392		$	164
Net income (loss)		—			339			—			(10	)		329			329
Return on appropriated investment		—			(18	)		—			—			(18	)		—
Accumulated other comprehensive income (Note 7)		—			—			16			—			16			16
Return of appropriated investment		(20	)		—			—			—			(20	)		—


Balance at September 30, 2006	$	4,763		$	1,565		$	43		$	(3,672	)	$	2,699		$	345

The accompanying notes are an integral part of these financial statements.

Page 81

NOTES TO FINANCIAL STATEMENTS

(Dollars in millions except where noted)

1. Summary of Significant Accounting Policies

General

Substantially all TVA revenues and assets are attributable to the power program. TVA provides 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 approximately 8.7 million people. 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 “Appropriation Investment”). Until 2000, most of the funding for TVA’s stewardship programs was provided by congressional appropriations. These programs are now funded largely with power revenues. Certain stewardship activities are also funded with various revenues and user fees. These activities related to stewardship properties do not meet the criteria of an operating segment, pursuant to Statement of Financial Accounting Standard (“SFAS”) No. 131, “Disclosures About Segments of an Enterprise and Related Information.” Accordingly, these assets and properties are included as part of the power program, TVA’s only operating segment.

Power rates are established by the TVA Board of Directors (“TVA Board”) as authorized by 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 Appropriation Investment in TVA’s power facilities; and such additional margin as the TVA Board may consider desirable for investment in power system assets, retirement of outstanding indebtedness, additional reduction of the 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

Unless otherwise indicated, years (2006, 2005, etc.) refer to TVA’s fiscal years ended September 30.

Cost-Based Regulation

The rate-setting authority vested in the TVA Board by the TVA Act meets the “self-regulated” provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” and TVA meets the remaining criteria for the application of SFAS No. 71 that (1) TVA’s regulated rates are designed to recover its costs of providing electricity and (2) in view of the 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. Accordingly, TVA records certain assets and liabilities that result from the regulated ratemaking process that would not be recorded under generally accepted accounting principles (“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. Management 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 this assessment, management believes the existing

Page 82

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, TVA could be required to write-off these costs. Any asset or liability write-offs would be required to be recognized in earnings in the period in which future recovery ceases to be probable.

Management Estimates

TVA prepares its financial statements in conformity with generally accepted accounting principles (“GAAP”) in the United States of America applied on a consistent basis. In some cases, management may make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the related amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

Reclassifications

Certain reclassifications have been made to the 2005 and 2004 financial statements to conform to the 2006 presentation, including the 2005 Balance Sheet reclassifications of estimated legal liabilities of $13 million from Accounts Payable to Accrued Liabilities, separation of Collateral Funds Held of $107 million from Accounts Payable, and reclassifications of customer prepayments of $93 million from Accrued Liabilities to Accounts Receivable, Net.

Interest income of $19 million and $6 million for 2005 and 2004, respectively, was previously included in Interest on Debt on the Statements of Income. Interest income is now included in Other Income.

The cash flow statement has been changed to conform to the 2006 presentation by reducing Accounts Receivable and Accounts Payable for customer prepayments of $93 million and $91 million in 2005 and 2004, respectively. In addition, $1 million in proceeds from the sale of a receivable in 2005 related to a construction project was reclassified from Construction expenditures to Proceeds from the sale of receivables/loans.

These reclassifications had no effect on previously reported results of operations and net cash flows.

Revision to Statements of Cash Flows

As of September 30, 2006, TVA began reporting the allowance for funds used during construction (“AFUDC”) related to construction expenditures as a component of cash investing activities rather than as a component of operating activities. The revised classification is consistent with guidance for the cash flow presentation of capitalized interest. The previous method of reporting AFUDC was consistent with the industry practice for the combined reporting of debt and equity AFUDC. The result of this reclassification is an increase in cash from operating activities of $116 million and $99 million for 2005 and 2004, respectively, and an increase in funds used by investing activities of $116 million and $99 million, respectively.

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.

Restricted Cash and Investments

As of September 30, 2006 and 2005, TVA had $198 million and $107 million, respectively, in Restricted Cash and Investments on its Balance Sheets primarily related to collateral posted with TVA by a swap counterparty in accordance with certain credit terms included in the swap agreement, which result in the funds being reported in Restricted Cash and Investments.

Accounts Receivable

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

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Accounts Receivable
As of September 30


	2006			2005

Power receivables billed	$	303		$	286
Power receivables unbilled		1,031			731

Total power receivables		1,334			1,017

Other receivables		35			42
Allowance for uncollectible accounts		(10	)		(7	)

Net accounts receivable	$	1,359		$	1,052

Effective September 2006, TVA implemented a change in the methodology for estimating unbilled revenue for electricity sales. The change in calculating unbilled revenue was from a method that estimated unbilled revenue on an aggregated distributor basis to a method that estimates unbilled revenue for each distributor and sums the results to arrive at the total estimated unbilled revenue. The change also involves moving from an aggregate generation-based estimate to an estimate based on wholesale meter readings for each specific distributor. The impact of this change resulted in an increase in the September 2006 sales estimate of 4,497 million kilowatt-hours and an increase in September 2006 accounts receivable and revenue of $232 million. In addition, the former method was used in calculating the unbilled revenue estimate for 2005, resulting in a lower sales estimate compared to actual sales and revenue.

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. TVA’s corporate credit department is consulted to assess the financial condition of a customer and the credit quality of the accounts. The allowance for uncollectible accounts was $10 million and $7 million at September 30, 2006, and 2005, respectively, for accounts receivable and $15 million at September 30, 2006, and 2005 for loans receivable.

Revenues

Revenues from power sales are recorded as power is delivered to customers. TVA accrues estimated unbilled revenues for power sales provided to customers for the period of time from the end of the billing cycle to month end. Components of the unbilled revenue estimates may include total electricity supply available from generation or purchases, estimated total electricity lost in delivery, and applicable rates. These components can fluctuate as a result of a number of factors including weather, generation patterns, delivery volume, and other operational constraints. These factors can be unpredictable and can vary from historical trends. As a result, the overall estimate of unbilled revenues may be significantly affected, which could have a material impact on TVA’s results of operations.

Exchange power sales are presented in the accompanying Statements of Income 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 direct 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.)

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. At September 30, 2006, and 2005, TVA had $270 million and $185 million, respectively, in fuel inventories and $288 million and $283 million, respectively, in materials and supplies inventory.

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

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obsolescence. The allowance for surplus and obsolete inventory was $38 million and $36 million at September 30, 2006 and 2005, respectively.

Emission Allowances. TVA has emission allowances for sulfur dioxide and nitrogen oxide (“NO_x”) which are accounted for as inventory. The average cost of allowances used each month is charged to operating expense based on tons of sulfur dioxide and NO_x emitted. NO_x emission allowances are only used during the ozone season, which occurs from May through September. Allowances granted to TVA by the Environmental Protection Agency (“EPA”) are recorded at zero cost.

Property, Plant, and Equipment, and Depreciation

Additions to plant are recorded at cost, which includes direct and indirect costs and an allowance for funds used during construction. 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 is calculated on a units-of-production basis and is included in fuel expense. TVA accounts for its properties using the composite convention of accounting. Accordingly, the original cost of property retired, together with removal costs less salvage value, is charged to accumulated depreciation. 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 3.15 percent for 2006, 3.33 percent for 2005, and 3.32 percent for 2004. Depreciation rates (percent) by asset class are as follows:

TVA Property, Plant, and Equipment Depreciation Rates
As of September 30


	2006		2005		2004

Asset Class
Nuclear		3.00		3.40		3.37
Coal-Fired		3.53		3.53		3.51
Hydroelectric		1.79		1.78		1.72
Combustion turbine/diesel generators		4.54		4.55		4.41
Transmission		2.57		2.52		2.53
Other		5.45		5.60		6.05

Depreciation expense for the years ended September 30, 2006, 2005, and 2004, was $1,082 million, $1,132 million, and $1,103 million, respectively. The major single reason for the reduction in depreciation expense for 2006 was the rate change for Browns Ferry Nuclear Plant. The rate change was the result of the Nuclear Regulatory Commission (“NRC”) granting TVA a 20-year operating license extension.

Property, plant, and equipment also includes assets recorded under capital lease agreements which primarily consist of office facilities of $39 million and $47 million for 2006 and 2005, respectively, and fabrication and blending facilities of $45 million and $51 million for 2006 and 2005, respectively.

Blended Low Enriched Uranium Program

On December 5, 2004, TVA received the first fuel assembly under the blended low enriched uranium (“BLEU”) fuel program for loading into Browns Ferry Unit 2. This fuel was loaded in the reactor during its most recent refueling outage in April 2005, which initiated the amortization of the costs of the BLEU fuel assemblies to nuclear fuel expense.

The BLEU fuel program is implemented, in part, through agreements with counterparties, including an interagency agreement with the Department of Energy (“DOE”) to provide nuclear fuel materials to be processed into usable fuel for TVA nuclear reactors, and other contracts with third-party nuclear fuel processors under which the nuclear fuel processors, either by themselves or through subcontractors, acquire land, construct facilities, and process the materials from DOE into usable fuel for TVA nuclear reactors.

Under the terms of the interagency agreement, 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. At September 30, 2006, TVA had accrued an obligation of $2 million related to the portion of the ultimate future payments estimated to be attributable to the BLEU fuel currently in use. TVA will accrue additional amounts each time BLEU fuel is inserted into a reactor thereby increasing the obligation over future periods.

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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. There is no provision for TVA to own or otherwise take title to the facilities, materials, or equipment now or at any time in the future. However, in accordance with the requirements of EITF No. 01-08, “Determining Whether an Arrangement Contains a Lease,” and SFAS No. 13, “Accounting for Leases,” TVA recognized a capital lease asset and corresponding lease obligation related to amounts paid or payable to a third party fuel processor. Accounting recognition of the capital lease asset and obligation recharacterization resulted from contract modifications to the pre-existing fuel fabrication contract.

During the quarter ended March 31, 2005, TVA recorded a capital lease asset of $60 million comprised of $23 million of contract payments made before the lease was recharacterized as a capital lease and $37 million in contract payments either paid or payable after the lease was recharacterized as a capital lease. Also during the quarter, TVA recorded an initial capital lease obligation of $37 million. This obligation has subsequently been reduced by principal payments, leaving an unpaid capital lease obligation of $13 million and $18 million at September 30, 2006, and 2005, respectively. Additionally, TVA has recognized asset amortization expense of $6 million and $9 million and internal expense of $1 million and $2 million related to the capital lease obligation through September 30, 2006, and 2005, respectively.

Investment Funds

Investment funds consist primarily of trust funds designated to fund nuclear decommissioning requirements (see Note 13 — Contingencies — Decommissioning Costs) and the supplemental executive retirement plan (“SERP”) (see Note 12 — Other Non-Qualified Retirement and Deferred Compensation Plans). 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.

Other Long-Term Assets

The year-end balances of TVA’s Other long-term assets are as follows:

Other Long-Term Assets
As of September 30


	2006		2005

Loans and long-term receivables, net	$	102	$	93
Intangible asset related to pension prior service cost		280		312
Valuation of currency swaps		246		76
Valuation of commodity contracts		487		791

	$	1,115	$	1,272

For additional information on the components of Other long-term assets, see Note 1 — Allowance for Uncollectible Accounts, Note 8 — Overview of Accounting Treatment, Commodity Contracts, and Swaps, Note 11 — Loans and Other Long-term Receivables, and Note 12 — Components of Pension and Postretirement Benefits and Other Non-Qualified Retirement and Deferred Compensation Plans.

Energy Prepayment Obligations

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 entitled the purchaser to a $0.025/kilowatt-hour discount on a specified quantity of firm power over a period of years (five, ten, 15, or 20) for each kilowatt-hour in the prepaid block. The remainder of the price of the kilowatt-hours delivered to the customer was due upon billing.

TVA did not offer the DEU program in 2006 or 2005. Sales for the 2004 program included 5.5 DEUs totaling $5.5 million over a 10-year period and 1.75 DEUs totaling $1.75 million over a five-year period. Total sales for the program since inception have been $54.5 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, 2006, and 2005 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, 2006, $20.2 million has been applied against power billings on a cumulative basis during the life of the program, of which nearly $5.6 million was recognized as noncash revenue during both 2006 and 2005, and $5.5 million was recognized as noncash revenue in 2004.

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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, 2006, and 2005, 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, 2006, $290.4 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 both 2006 and 2005 and $90.4 million of which was recognized as noncash revenue during 2004.

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. Consulting actuaries assist TVA in determining certain liabilities for self-assumed claims. TVA recovers the costs of losses 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 13 — Contingencies — Nuclear Insurance.

TVA does not currently purchase commercial general liability, auto liability, or workers’ compensation insurance. TVA recovers the costs of losses through power rates. The Federal Employees’ Compensation Act governs liability to employees for service-connected injuries.

TVA purchases property and business interruption/outage insurance for its conventional non-nuclear assets. TVA also purchases liability insurance which provides coverage for its directors and officers, subject to the terms and conditions of the policy.

Sale of Receivables/Loans

From time to time TVA obtains proceeds from selling receivables and loans. During 2006, TVA sold $22 million of receivables at par such that TVA did not recognize a gain or loss on the sale. Of this amount, $11 million represents receivables from power customers related to the construction of a substation and other energy conservation projects, which is included within the Cash Flow Statement under the caption Cash Flows from Investing Activities.

There were no corresponding sales of receivables during 2004. TVA did not retain any claim on these loans and receivables sold, and they are no longer reported on TVA’s Balance Sheets.

Asset Retirement Obligations

In accordance with the provisions of SFAS No. 143, “Accounting for Asset Retirement Obligations,” TVA recognizes legal obligations associated with the future retirement of certain tangible long-lived assets. TVA only records estimates of such disposal costs at the time the legal obligation arises. See Note 4.

Based on updating assumptions in the engineering studies annually in accordance with NRC requirements, revisions to the amount and timing of certain cash flow estimates of nuclear asset retirement obligations may be made. TVA recognizes as incurred all obligations related to closure and removal of its nuclear units. TVA measures the liability for closure at the present value of the weighted estimated cash flows required to satisfy the related obligation, discounted at the credit adjusted rate of interest in effect at the time the liability was actually incurred or originally accrued, and subsequently modified to comply with SFAS No. 143. Earnings from decommissioning fund

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investments, amortization of the decommissioning regulatory asset, and interest expense on the decommissioning liability are deferred as a regulatory asset. See Note 13 — Contingencies — Decommissioning Costs. Beginning in 2003, TVA evaluated the nature and scope of its decommissioning policy as it relates to all electric plant. The evaluation was used to determine the need for recognition of additional asset retirement obligations as described in SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 became effective for TVA at the beginning of 2003. See Note 4. On September 30, 2006, TVA began applying the guidance of Financial Accounting Standards Board (“FASB”) Interpretation (“FIN”) No. 47, “Accounting for Conditional Asset Retirement Obligations—an Interpretation of FASB Statement No. 143.” See Note 4 for the effects of applying this interpretation.

Discounts on Sales

TVA’s DEU program (see Note 1 — Energy Prepayment Obligations) allows 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’s largest customer, MLGW, also has a power prepayment agreement (see Note 1 — Energy Prepayment Obligations) under which it has prepaid $1.5 billion for a fixed amount of power. TVA repays MLGW in the form of a monthly credit sufficient for MLGW to pay debt service on its prepayment bonds plus a return on investment.

Discounts for these programs amounted to $47 million, $47 million, and $43 million for the years ended September 30, 2006, 2005, and 2004, respectively.

Allowance for Funds Used During Construction

TVA capitalizes an allowance for funds used during construction based on the average interest rate of TVA’s outstanding debt. The allowance is applicable to construction in progress and nuclear fuel fabrication.

Research and Development Costs

Research and development costs are expensed when incurred. During 2006, 2005, and 2004 research and development costs of $20 million, $21 million, and $24 million were expensed and included in the statements of income caption Operating and Maintenance.

Payments In Lieu of Taxes

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 sale of power during the preceding year excluding sales or deliveries to other federal agencies and exchange sales with other utilities, with a provision for minimum payments under certain circumstances.

Project Cancellation

In December 2003, TVA was notified that Regenesys Technologies Limited (“RTL”) would not proceed with manufacturing of the fuel cells to be installed in the partially completed Regenesys energy storage plant in Columbus, Mississippi. TVA had invested approximately $35 million in the Regenesys project. RTL reimbursed TVA for early termination of the contract in the amount of $15 million, which reduced the net loss to $20 million on the cancellation of the Regenesys project.

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Impairment of Assets

TVA evaluates long-lived assets for impairment in accordance with the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” 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. See Note 6.

Reduction in Workforce

During 2004, organizations within TVA performed program and staffing reviews to identify surplus staffing situations. In areas where surplus staffing existed, TVA provided the opportunity for certain qualifying employees to apply for voluntary resignations beginning in February 2004. In conjunction with the voluntary reduction process, TVA also instituted an involuntary reduction in force for certain employees. As of September 30, 2006, there were approximately 700 employees impacted by the combined voluntary and involuntary actions. TVA recognized total expense of approximately $41 million for termination costs incurred through September 30, 2006. Payout of benefits occurs as employees retire from TVA. Substantially all affected employees had left by the end of 2006.

Impact of New Accounting Standards and Interpretations

Variable Interest Entities. In January 2003, the FASB published FASB Interpretation No. 46, “Consolidation of Variable Interest Entities,” which was revised by FASB Interpretation No. 46R (“46R”) in December 2003. FIN 46R establishes consolidation criteria for entities for which “control” is not easily discernable under Accounting Research Bulletin (“ARB”) 51, “Consolidated Financial Statements,” which is based on the premise that holders of the equity of an entity control the entity by virtue of voting rights. FIN 46R provides guidance for identifying the party with a controlling financial interest resulting from arrangements or financial interests rather than from voting interests. FIN 46R defines the term “variable interest entity” (“VIE”) and is based on the premise that if a business enterprise absorbs a majority of the VIE’s expected losses and/or receives a majority of its expected residual returns (measures of risk and reward), that enterprise (the primary beneficiary) is deemed to have a controlling financial interest in the VIE. An enterprise that bears the majority of the economic risk is considered to have a controlling financial interest in a VIE, even if it has no decision making (voting) authority or equity interest. TVA adopted FIN 46 and FIN 46R effective October 1, 2005, for VIEs created before December 31, 2003, and immediately for VIEs created after December 31, 2003.

In February 1997, TVA entered into a purchase power agreement with Choctaw Generation, Inc. (subsequently assigned to Choctaw Generation Limited Partnership) to purchase all the power generated from its facility located in Choctaw County, Mississippi. The facility had a committed capacity of 440 megawatts and the term of the agreement was 30 years. Under the accounting guidance provided by FIN 46R, TVA may be deemed to be the primary beneficiary under the contract; however, TVA does not have access to the financial records of Choctaw Generation Limited Partnership. As a result, TVA was unable to determine whether FIN 46R would require TVA to consolidate Choctaw Generation Limited Partnerships’ balance sheet, results of operations, and cash flows for the year ended September 30, 2006. Power purchases for 2006 under the agreement totaled $121 million. TVA has no additional financial commitments beyond the purchase power agreement with respect to the facility.

On April 13, 2006, the FASB issued FASB Staff Position FIN 46R-6, “Determining the Variability to Be Considered in Applying FASB Interpretation No. 46R,” which addresses how a reporting enterprise should determine the variability to be considered in applying FASB Interpretation No. 46. FSP FIN 46R-6 is to be applied prospectively to all entities with which that enterprise first becomes involved and to all entities previously required to be analyzed under FIN 46R when a reconsideration event has occurred pursuant to paragraph seven of FIN 46R beginning the first day of the first reporting period after June 15, 2006. TVA began applying this guidance with the reporting period ending September 30, 2006. The adoption of this guidance did not have a material impact on TVA’s results of operations or financial condition.

Conditional Asset Retirement Obligations. In March 2005, the FASB issued FIN No. 47, “Accounting for Conditional Asset Retirement Obligations—an interpretation of FASB Statement No. 143.” This interpretation clarifies that the term conditional asset retirement obligation (“conditional ARO”) as used in SFAS No. 143, “Accounting for Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing and (or)

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method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Accordingly, an entity is required to recognize a liability for the fair value of a conditional ARO if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional ARO should be recognized when incurred. This interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an ARO. On September 30, 2006, TVA began applying FIN 47, “Accounting for Conditional Asset Retirement Obligations,” which resulted in the recognition of additional ARO liabilities for asbestos and Polychlorinated Biphenyls abatement costs.

The following table sets forth TVA’s net income for the years ended September 30, 2006, 2005, and 2004, adjusted as if FIN 47 had been applied during these periods. FIN 47 had an adoption date of September 30, 2006. For a discussion of the effects of the adoption of FIN No. 47, see Note 4.

ProForma Effects of Adoption of FIN 47
For the years ended September 30


	2006			2005			2004

Reported income before cumulative effect of change in accounting principle	$	438		$	85		$	386

FIN 47 pro forma earnings effects		(7	)		(7	)		(7	)


Proforma income before cumulative effect of change in accounting principle	$	431		$	78		$	379

Accounting Changes and Error Corrections. In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3,” which replaces Accounting Principles Board (“APB”) Opinion No. 20, “Accounting Changes,” and FASB Statement No. 3, “Reporting Accounting Changes in Interim Financial Statements.” This statement applies to all voluntary changes in accounting principles and also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. This statement requires, unless impracticable, retrospective application to prior periods’ financial statements of changes in accounting principles. This statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate effected by a change in accounting principle. The statement will become effective for TVA beginning in 2007 with early adoption permitted for accounting changes and corrections of errors made in fiscal years beginning after May 2005, the date the statement was issued.

Accounting for Inventory Transactions. At its September 28, 2005, meeting, the FASB reached consensus on Emerging Issues Task Force (“EITF”) Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” The consensus reached states that inventory purchase and sales transactions with the same counterparty that are entered into in contemplation of one another should be combined for purposes of applying APB Opinion 29. The Task Force also reached a consensus that a nonmonetary exchange within the same line of business involving the transfer of raw materials in exchange for the receipt of raw materials should not be recognized at fair value. This EITF should be applied to transactions completed in reporting periods beginning after March 15, 2006, whether pursuant to arrangements that were in place at the date of initial application of the consensus or arrangements executed subsequent to that date. The carrying amount of the inventory that was acquired under these types of arrangements prior to the initial application of the consensus, and that still remains in an entity’s statement of financial position at the date of initial application of the consensus, should not be adjusted for this consensus. TVA adopted EITF Issue No. 04-13 beginning in the second quarter of 2006. The adoption of this guidance did not have a material impact on TVA’s results of operations or financial condition.

Put and Call Options. In September 2005, the Derivatives Implementation Group (“DIG”) of the FASB discussed several issues related to the settlement of a debtor’s obligation on the exercise of a call or put option and the exercise only by the debtor of the right to accelerate settlement of a debt with an embedded call option. DIG Implementation Issue No. B38, “Embedded Derivatives: Evaluation of Net Settlement with Respect to the Settlement of a Debt Instrument through Exercise of an Embedded Put Option or Call Option,” addresses whether the settlement of a debtor’s obligation on exercise of a call or put option meets the net settlement criterion in paragraph 9(a) of SFAS No. 133, as amended. DIG Implementation Issue No. B39, “Embedded Derivatives: Application of Paragraph 13(b) to Call Options That Are Exercisable Only by the Debtor,” addresses whether or not Paragraph 13(b) of SFAS No. 133, as amended, applies to a call option embedded with a debt host if the right to accelerate settlement of the debt can be exercised only by the debtor. The effective date of the implementation guidance in these issues is the first day of the first fiscal quarter beginning after December 15, 2005. The issue became effective for TVA beginning in the

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second quarter of 2006. The adoption of this guidance did not have a material impact on TVA’s results of operations or financial condition.

Accounting for Rental Costs. On October 6, 2005, the FASB issued FSP FAS 13-1, “Accounting for Rental Costs Incurred during a Construction Period.” The FASB concludes in this FSP that rental costs associated with ground or building operating leases that are incurred during a construction period should be expensed. TVA began applying this guidance beginning with the quarterly reporting period ending March 31, 2006. The adoption of this guidance did not have a material impact on TVA’s results of operations or financial condition.

Impairment of Investments. On November 3, 2005, the FASB released FSP FAS 115-1 and FAS 124-1,“The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments.” This FSP addresses the determination as to when an investment is considered impaired, whether that impairment is other than temporary, and the measurement of an impairment loss. The FSP also includes accounting considerations subsequent to the recognition of an “other-than-temporary” impairment and requires certain disclosures about unrealized losses that have not been recognized as “other-than-temporary” impairments. TVA began applying this guidance beginning with the quarterly reporting period ending March 31, 2006. The adoption of this guidance did not have a material impact on TVA’s results of operations or financial condition.

Fair Value Measurements. In September 2006, FASB issued SFAS No. 157, “Fair Value Measurements.” This standard provides guidance for using fair value to measure assets and liabilities. The standard 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. Statement 157 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. SFAS No. 157 establishes a fair value hierarchy that prioritizes the information used to develop measurement assumptions. The provisions of SFAS No. 157 are effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. At this time, TVA continues the process of evaluating the requirements of this statement and does not yet know the impact of its implementation, which may or may not be material to TVA’s results of operations or financial position.

Accounting for Defined Benefit Pension and Other Postretirement Plans. On September 29, 2006 the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106, and 132(R).” This standard will require employers to fully recognize the obligations associated with single-employer defined benefit pension, retiree healthcare and other postretirement plans in their financial statements. The standard will make it easier for investors, employees, retirees and others to understand and assess an employer’s financial position and its ability to fulfill the obligations under its benefit plans. Specifically, the new standard requires an employer to: recognize in its statement of financial position an asset for a plan’s overfunded status or a liability for a plan’s underfunded status; measure a plan’s assets and its obligations that determine its funded status as of the end of the employer’s fiscal year (with limited exceptions); and recognize changes in the funded status of a defined benefit postretirement plan in the year in which the changes occur. Those changes will be reported in comprehensive income of a business entity and in changes in net assets of a not-for-profit organization.

The requirement to recognize the funded status of a benefit plan and the disclosure requirements are effective for TVA as of the end of the fiscal year ending after June 15, 2007. The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008. TVA plans to apply the new standard for its 2007 year-end financial statements and recognize on its 2007 Balance Sheets the funded status of its pension and other postretirement benefit plans. However, had TVA been required to adopt the standard as of its last actuarial valuation date (September 30, 2006), TVA would have recorded the following amounts on its Balance Sheet for the year then ended: a regulatory asset of $795 million, additional pension and postretirement obligations of $368 million and $152 million, respectively, and the reclassification to the regulatory asset of an intangible asset with a balance of $275 million representing unamortized prior service cost. The net effect of recognizing such amounts would have been to increase total assets and liabilities by $520 million at that date.

In August 2006, the Pension Protection Act of 2006 (the “Pension Act”) became law. The Pension Act amends the Employee Retirement Income Security Act (“ERISA”) and Section 412 of the Internal Revenue Code to provide new minimum funding rules for defined benefit plans. The Tennessee Valley Authority Retirement System (“TVARS”) defined benefit plan, as a governmental plan, is not subject to the minimum funding rules under ERISA and Section 412 of the Internal Revenue Code, and it is unlikely the Pension Act will have any material effect on the TVARS defined benefit plan.

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Accounting for Misstatements. On September 13, 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements.” This bulletin provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. Application of the guidance is effective for TVA beginning with the first interim period of fiscal year 2007.

2. Nuclear Power Program

At September 30, 2006, TVA’s nuclear power program consisted of nine units — five operating (commercially generating electricity), one in recovery (being returned to service), one in deferred status (construction halted but still licensed by NRC), and two which were canceled (licensed surrendered to NRC) during 2006 (discussed below). The operating and recovery units are in three locations with investments in property, plants and equipment as follows and in the status indicated:

Nuclear Production Plants
As of September 30


	Completed		Construction in		Fuel
	Plant, Net		Progress		Investment

Browns Ferry *	$	1,952	$	1,993	$	229
Sequoyah		1,648		32		118
Watts Bar		5,317		191		62
Raw materials		–		–		82

Total Nuclear Production	$	8,917	$	2,216	$	491


Notes

*		Browns Ferry Unit 1, a unit in recovery, is discussed below.

Browns Ferry Unit 1 was taken offline in 1985 for plant modifications and regulatory improvements and will continue to remain in an inoperative status until recovered. In May 2002, the TVA Board initiated activities for the return of Unit 1 to service in order to meet long-term power requirements. It is anticipated the Unit 1 recovery project will add approximately 1,150 megawatts of generation initially with an eventual 1,280 megawatts of generation at a cost of approximately $1.8 billion, exclusive of AFUDC and estimated asset retirement obligation. Unit 1 is expected to return to service in 2007. At September 30, 2006, TVA had incurred approximately $1.6 billion of costs, and AFUDC of $182 million, on the restart project.

In 1988, TVA suspended construction activities on Watts Bar Unit 2 and it remains a partially completed nuclear plant similar in design to the operating Watts Bar Unit 1. Because of projected demand in its service area, TVA is studying options which will provide accurate cost, schedule, and risk information to enable a more informed future decision regarding new base load generation. Accordingly, TVA has contracted for a detailed scoping, estimating and planning study of Watts Bar Unit 2 during 2007 and 2008. Watts Bar’s Unit 2 construction permit expires in 2010 and as of September 30, 2006, no decision has been made to actually complete Watts Bar Unit 2.

Bellefonte Units 1 and 2 were deferred in 1988 and 1985, respectively. In December 1994, TVA determined that it would not, by itself, complete Bellefonte Unit 1 and Unit 2 and in September 2006, the NRC approved TVA’s request to terminate the construction permits for unfinished Bellefonte Units 1 and 2. NRC determined that terminating the construction permits, which were originally issued in 1974, would not have a significant effect on the quality of the environment. TVA’s Board of Directors approved canceling the Bellefonte Nuclear Plant (“Bellefonte”) construction project in November 2005.

The TVA Board determined as of the end of 2001 that the values of some of its existing assets were impaired and should be reduced. Certain nuclear assets — portions of Bellefonte Unit 1 and Unit 2 and Watts Bar Unit 2 in its entirety — were identified as assets for which the estimated cash flows expected to be provided through future rates were less than recorded book values. In 2001 TVA revalued certain nuclear assets — Watts Bar Unit 2 in its entirety and portions of Bellefonte Unit 1 and Unit 2 – downward by $2.2 billion and recognized an impairment loss. During 2004, the TVA Board approved the reclassification of approximately $203 million of Bellefonte assets from Deferred Nuclear Generating Units to Completed Plant. In July 2005, the TVA Board approved the amortization of TVA’s remaining investment in the deferred generating units at Bellefonte over a 10-year period beginning in 2006. See Note 1 — Cost-Based Regulation. TVA began amortizing and recovering in rates the investment of the $3.9 billion in deferred nuclear generating units at Bellefonte Nuclear Plant on October 1, 2005. See Note 5. None of these actions interfere in any way TVA’s ability to use the site for future projects.

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In September 2005, NuStart Development LLC (“NuStart”) selected Bellefonte as one of the two sites in the country for a new advanced design nuclear plant. NuStart is an industry consortium comprised of nine utilities and two reactor vendors whose purpose is to satisfactorily demonstrate the new NRC licensing process for new nuclear plants. NuStart intends to seek a combined construction and operating license for the site for the new Advanced Passive 1000 reactor design by Westinghouse Electric Co. TVA intends to be the license applicant for NuStart when the combined license application is submitted to the NRC. TVA has been a participant in NuStart since its inception and intends to become a full member of NuStart. No decision has been made to actually build an advanced reactor at the site.

On May 4, 2006, the NRC approved TVA’s application for license extension at each of its three reactors at Browns Ferry Nuclear Plant. As a result of the NRC’s action, each unit’s license has been extended 20 years. See Note 4. The depreciable lives of these units were therefore extended in 2006. Current expiration dates of the operating licenses for the Browns Ferry units are now:

TVA Nuclear Unit Operating License Expiration Dates
As of September 30


	Operating License
Nuclear Unit	Expiration Date

Browns Ferry Unit 1		2033
Browns Ferry Unit 2		2034
Browns Ferry Unit 3		2036

3. Completed Plant

Completed plant consisted of the following at September 30:

TVA Completed Plant
As of September 30


	2006						2005
			Accumulated						Accumulated
	Cost		Depreciation		Net		Cost		Depreciation		Net

Fossil	$	10,567	$	5,249	$	5,318	$	10,164	$	4,912	$	5,252
Combustion turbine		1,168		500		668		1,176		447		729
Nuclear		15,437		6,520		8,917		15,517		6,128		9,389
Transmission		4,360		1,607		2,753		4,227		1,512		2,715
Hydroelectric		1,879		683		1,196		1,861		648		1,213
Other electrical plant		1,235		428		807		1,264		426		838

Subtotal		34,646		14,987		19,659		34,209		14,073		20,136

Multipurpose dams		962		336		626		962		326		636
Other stewardship		44		8		36		44		8		36

Subtotal		1,006		344		662		1,006		334		672


Total	$	35,652	$	15,331	$	20,321	$	35,215	$	14,407	$	20,808

4. Asset Retirement Obligations

Effective October 1, 2002, TVA adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” which requires the recognition of a liability, and capitalization of the associated asset retirement cost as part of the carrying amount of the long-lived asset, for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and/or normal operation of long-lived assets. TVA identified and reviewed all relevant information in the determination of its potential asset retirement obligations (“AROs”). TVA identified three categories of AROs which represent legal obligations of TVA under the requirements set forth in the standard. Costs associated with retirement of coal-fired (including ash/waste ponds) and gas/oil combustion turbine generating plants are being expensed as period costs while costs associated with retirement of nuclear generating plants are receiving SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” treatment based on the partially funded status of the nuclear decommissioning obligation (see Note 1 — Cost-Based Regulation).

When TVA adopted SFAS No. 143, its accounting requirement was to incur only the minimum legally required costs related to plant shut-down and to consider certain assets as perpetually-lived. TVA adopted a

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containment strategy through plant maintenance related to asbestos and Polychlorinated Biphenyls (“PCBs”), and due to uncertainty surrounding the timing of estimated plant closures, did not record an ARO for the complete removal costs. FIN 47, “Accounting for Conditional Asset Retirement Obligations,” clarifies that even though the timing or method of settlement of an obligation may be conditional on a future event, the obligation to perform the asset retirement activity is unconditional. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation when incurred if the liability fair value can be reasonably estimated.

On September 30, 2006, TVA began applying FIN 47, “Accounting for Conditional Asset Retirement Obligations,” which resulted in the recognition of additional ARO liabilities for asbestos and PCB abatement costs. The effect of the adoption of FIN 47 during 2006 included a cumulative effect charge to income of $109 million, a recognition of a corresponding additional long-term liability of $132 million, a recognition of an increase in assets of $43 million, and related accumulated depreciation of $20 million.

Asset Retirement Obligations
As of September 30


							Fair Market		Estimated
			Pro-Forma				Value of		Future
	Pro-Forma		September 30,		September		Investment		Liability at
	October 1, 2004		2005		30, 2006		Funds at Sept		Sept 30,
FIN 47 ARO Category	Obligation		Obligation		Obligation		30, 2006		2006

Fossil Plants	$	106	$	111	$	117	$	—	$	449
Office and Other Facilities		2		2		2		—		42
Hydroelectric Plants		5		5		5		—		32
Transmission Facilities		8		9		8		—		21


Total	$	121	$	127	$	132	$	—	$	544

TVA has identified but not recognized conditional AROs related to items that contain PCBs such as electromagnets, voltage regulators, and small capacitors. These items reside in numerous larger pieces of equipment throughout TVA’s integrated system and generally require retirement action only upon failure or malfunction. The conditional AROs related to these items are not currently estimable because TVA does not have a comprehensive inventory of such items and does not have the historical data available to develop a reasonable estimate of when such items will fail or malfunction. If material, TVA will recognize a conditional ARO associated with these items at the time the information becomes available to develop a reasonable estimate.

Nuclear Generating Plants. Prior to implementing SFAS No. 143, TVA had recognized a decommissioning liability related to its nuclear generating plants in accordance with NRC funding requirements. The adoption of SFAS No. 143 resulted in a change in the methodology of quantifying this nuclear decommissioning obligation in accordance with the new accounting standard. TVA has increased the nuclear decommissioning liability on the balance sheet to reflect the new methodology but has retained its regulatory accounting treatment of capturing all changes in the liability, investment funds, and certain other deferred charges as changes in the regulatory asset instead of recording these items on the income statement because recovery of these net costs is probable in future revenues.

Coal-Fired Generating Plants. The activities associated with coal-fired plant retirement include plant shutdown, securing the physical property, closure of storage and/or waste areas (including ash/waste ponds), maintenance of stack lights, security patrols, and measures to contain asbestos and other hazardous materials from release into the environment. The estimated costs of these activities have been included in the calculation of TVA’s coal-fired plant AROs. Certain ash ponds and waste areas have estimated useful lives that are independent of the lives of the coal plants themselves. Accordingly, these specific ash/waste pond areas were quantified as separate AROs based on their specific estimated useful lives.

Gas/Oil Turbine Generating Plants. The activities associated with gas and oil turbine plant retirement include annual operating costs for site security, lighting, powerhouse and grounds maintenance, containment of asbestos, paint, and other materials, and groundwater monitoring. The estimated costs of these activities have been identified to be included in the calculation of TVA’s combustion turbine plant AROs.

For each ARO identified, TVA calculated the net present value of the obligation as of the current period, the original and incremental cost of the long-lived asset at the time of initial operation, the cumulative effect of depreciation on the adjusted asset base, and accretion of the liability from the date of initial operation to the current period.

During the first quarter of 2005, there was a change in the estimated closure date related to the Bellefonte diesel generators. The original estimate assumed asset retirement in 2029 and a six year waiting period before

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closure work would begin in 2035. The new estimate assumes that closure work will begin at the date the assets cease to operate in 2029. This change in estimate resulted in a decrease in the total future liability of nearly $1 million, and an increase in the current net present value of the ARO asset liability of less than $0.1 million.

In March 2006 and 2005, TVA made revisions to the amount and timing of certain cash flow estimates related to its nuclear AROs. The revisions in cost were based on new engineering analyses of certain components of the cost performed annually in accordance with requirements of the NRC. The effect of the changes in estimates produced obligations that were less than the amounts originally recorded on an accreted basis. Accordingly, TVA made adjustments in the recorded amounts to properly reflect such revised balances based on the latest cost estimates. In 2006, the adjustments resulted in an aggregate decrease of $89 million in the ARO, a $29 million reduction in the asset base, a $12 million reduction in accumulated depreciation, and a decrease of $72 million in the originally recorded regulatory asset which TVA recorded in accordance with SFAS No. 71. In 2005, the adjustments resulted in an aggregate decrease of $25 million in the ARO, a $7 million reduction in the asset base, a $3 million reduction in accumulated depreciation, and a decrease of $21 million in the originally recorded regulatory asset. Therefore, the result of the change described did not impact net income for 2006 and 2005.

In May 2006, the NRC granted a 20-year license extension for the operation of each of the 3 units at its Browns Ferry Nuclear Plant. The license extension changes the timing of certain cash flow estimates utilized by TVA in the determination of the Browns Ferry ARO. Accordingly, TVA made adjustments to the Browns Ferry ARO and related accounts to reflect the revised cost estimates. TVA previously calculated the Browns Ferry ARO utilizing two equally weighted sets of estimated cash flows; one set based on a 40-year license life and a second set based on a 60-year license life. The cash flow estimates represented by the 40-year life are no longer applicable. The adjustments made are cumulative for the year and include reductions in the nuclear ARO of $153 million, a reduction in the incremental asset base of $31 million, a reduction in the asset’s accumulated depreciation of $44 million, and a reduction in the regulatory asset of $166 million. The result of the changes described does not impact net income for any of the periods presented.

During 2005, TVA’s total ARO liability increased $75 million due to accretion expense of $100 million, partially offset by the $25 million revision in cash flows described above. The nuclear accretion expense of $87 million was deferred and charged to a regulatory asset in accordance with SFAS No. 71. The remaining accretion expense of $13 million, related to coal-fired and gas/oil combustion turbine plants, was expensed in 2005. During 2006, TVA’s total ARO increased $128 million, net of all cumulative adjustments, due to combined accretion expense of $100 million and a recognition of a conditional ARO of $132 million and $138 million due to the application of FIN 47 and SFAS 143, respectively, partially offset by the $242 million in revisions to the nuclear ARO. The nuclear accretion expense of $87 million was deferred and charged to a regulatory asset in accordance with SFAS No. 71. The remaining accretion expense of $13 million, related to coal-fired and gas/oil combustion turbine plants, was expensed in 2006.

Reconciliation of Asset Retirement Obligation Liability
As of September 30


	2006			2005

Balance at beginning of year	$	1,857		$	1,782
Liabilities settled		—			—
Accretion expense		100			100
Recognition of conditional asset retirement obligations		132			—

Revisions in estimated cash flows		(104	)		(25	)

Balance at end of year	$	1,985		$	1,857

5. Regulatory Assets and Liabilities

Regulatory assets capitalized under the provisions of SFAS No. 71 are included in Deferred Nuclear Generating Units and Other Regulatory Assets on the September 30, 2006, and 2005 Balance Sheets. Components of Other Regulatory Assets include certain charges related to the closure and removal from service of nuclear generating units, debt reacquisition costs, deferred outage costs, unrealized losses related to power purchase contracts, deferred capital lease asset costs, a deferred loss relating to TVA’s financial trading program, and an adjustment to accrue the minimum pension liability. All regulatory assets are probable of recovery in future revenues. Components of Regulatory liabilities include unrealized gains on coal purchase contracts and capital lease liabilities. See Note 1 — Cost-Based Regulation and Note 2.

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The year-end balances of TVA’s regulatory assets and liabilities are as follows:

TVA Regulatory Assets and Liabilities
As of September 30


	2006		2005

Regulatory Assets:
Minimum pension liability	$	914	$	1,158
Nuclear decommissioning costs		474		716
Reacquisition costs		232		264
Deferred purchased power costs		6		–
Deferred outage costs		85		103
Capital leases		76		84
Unrealized losses on purchased power contracts		22		42

Subtotal		1,809		2,367

Deferred nuclear generating units		3,521		3,912


Total	$	5,330	$	6,279


Regulatory Liabilities:
Unrealized gain on coal purchase contracts	$	487	$	791
Capital lease liability		88		106


Total	$	575	$	897

TVA’s accumulated pension benefit obligation at September 30, 2006, and 2005, exceeded plan assets. As a result, TVA was required to recognize an additional minimum pension liability as prescribed by SFAS No. 87, “Employers’ Accounting for Pensions.” These future pension costs will be funded through a combination of the pension investment funds already set aside by TVA, future earnings on those pension investment funds, and, if recommended by the TVARS Board under the rules and regulations of TVARS and approved by TVA, future TVA cash contributions to the pension plan which will be recovered in TVA’s rates when incurred.

Nuclear decommissioning costs include certain deferred charges related to the future closure and decommissioning of TVA’s nuclear generating units under NRC requirements and liability recognition under the accounting rules for asset retirement obligations. These future costs will be funded through a combination of investment funds already set aside by TVA, future earnings on those investment funds, and if necessary, additional TVA cash contributions to the investment funds. See Note 1 — Investment Funds and Note 4.

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 FERC’s 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, the TVA Act requires TVA to keep accounts in accordance with the requirements established by FERC.)

Deferred power purchase costs resulting from TVA’s financial trading program represent unrealized gains and losses on futures and options at September 30, 2006. The program is used to reduce TVA’s economic risk exposure associated with electricity generation, purchases, and sales. Due to the implementation of a fuel cost adjustment mechanism to be effective October 1, 2006, TVA changed its accounting for these unrealized gains and losses as of September 30, 2006. Prior to this, gains and losses were reported on the income statement as an offset to purchased power. Unrealized losses as of September 30, 2006, were approximately $6 million. The new accounting treatment reflects TVA’s ability and intent to recover the cost of these commodity contracts in future periods through the TVA Board approved fuel cost adjustment.

TVA’s investment in the fuel used in its nuclear units is being amortized and accounted for as a component of fuel expense. See Note 2. Nuclear refueling outage and maintenance costs already incurred are deferred and amortized on a straight-line basis over the estimated period until the next refueling outage. The amounts of deferred outage costs for 2006, 2005, and 2004 were $85 million, $103 million, and $86 million, respectively.

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Deferred capital lease costs represent the difference between FERC’s Uniform System of Accounts model balances recovered in rates and the SFAS No. 13, “Accounting for Leases,” model balances. Under the FERC Uniform System of Accounts, TVA recognized the initial capital lease asset and liability at inception of the lease in accordance with SFAS No. 13; however, the annual expense is equal to the annual lease payments, which differs from SFAS No. 13 accounting treatment. This practice results in TVA’s capital lease asset balances being higher than they otherwise would have been under the SFAS No. 13 model, 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.

Unrealized losses on a power purchase contract represent the estimated unrealized loss related to the mark-to-market valuation of the contract. Under the accounting rules contained in SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities, as amended,” this contract qualifies as a derivative contract but does not qualify for cash flow hedge accounting treatment. As a result, TVA recognizes the changes in the market value of this derivative contract as a regulatory asset. This treatment reflects TVA’s ability and intent to recover the cost of this commodity contract on a settlement basis for ratemaking purposes. TVA has historically recognized the actual cost of purchased power received under this contract in purchased power expense at the time of settlement. The contract expires in 2007. See Note 8.

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 period beginning in 2006. The TVA Board determined that a ten-year recovery period would not place an undue burden on rates while still ensuring the probability of cost recovery during that ten-year period. See Note 2 — Nuclear Power Program.

Regulatory liabilities accounted for under the provisions of SFAS No. 71 consist of mark-to-market valuation gains on coal purchase contracts and capital leases.

Unrealized gains on coal purchase contracts represent the estimated unrealized gains related to the mark-to-market valuation of coal purchase contracts. Under the accounting rules contained in SFAS No. 133, as amended, 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. This treatment reflects TVA’s ability and intent to recover the cost of these commodity contracts on a settlement basis for ratemaking purposes. 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 2017. See Note 8.

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 costs are being amortized over the lease term.

6. Asset Impairment

During 2006 and 2005, TVA recognized a total of $9 million and $24 million, respectively, in impairment losses related to its Property, Plant, and Equipment. The losses included a $2 million and an $8 million write-down in 2006 and 2005, respectively, of one of two buildings in TVA’s Knoxville Office Complex based on quoted market price. TVA’s plans to sell or lease the East Tower of the Knoxville Office Complex. TVA also recognized a $7 million and a $16 million write-down in 2006 and 2005, respectively, of certain Construction in Progress assets related to new pollution-control and other technologies that had not been proven effective and a re-evaluation of other projects due to funding limitations.

7. Proprietary Capital

Appropriation Investment

TVA’s power program and stewardship program were originally funded primarily with appropriations from Congress. In 1959, however, 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 appropriations after it became self-financing, TVA continued to receive appropriations for certain multipurpose activities as well as for its stewardship activities. TVA has not received any appropriations from Congress for any

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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 table below summarizes TVA’s activities related to these funds. The balance of the Congressional Appropriation Investment at September 30, 2006, is as follows:

Appropriations
As of September 30


	Power			Stewardship
	Program			Program			Total

Congressional appropriations and transfers of property from other federal agencies (net)	$	1,443		$	9,622		$	11,065
Program expenditures					(5,221	)		(5,221	)
Less repayments to the U.S. Treasury		(1,035	)		(46	)		(1,081	)

Total	$	408		$	4,355		$	4,763

Payments to the U.S. Treasury

Section 15d of the TVA Act requires TVA to make annual payments to the U.S. Treasury from net power proceeds as a return on the net appropriation investment that Congress made in the power system and as a repayment of such investment, beginning in 1961.

TVA paid $20 million each year for 2006, 2005, and 2004 as a repayment of the Appropriation Investment. In addition, of the $1 billion portion of the Appropriation Investment TVA is obligated to repay, $150 million remains unpaid at September 30, 2006. The payments required by Section 15d may be deferred under certain circumstances for not more than two years.

The amount of return payable during each year is based on the Appropriation Investment 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. TVA paid the U.S. Treasury $18 million in 2006, $16 million in 2005, and $18 million in 2004 as a return on the Appropriation Investment. The interest rate payable by TVA on the Appropriation Investment was 4.24 percent, 3.71 percent, and 3.82 percent for 2006, 2005, and 2004, respectively.

Accumulated Other Comprehensive Income

SFAS No. 130, “Reporting Comprehensive Income,” requires the disclosure of comprehensive income or loss to reflect changes in capital that result from transactions and economic events from nonowner sources. The items included in accumulated other comprehensive income (loss) consist of market valuation adjustments for certain derivative instruments (see Note 8). The accumulated other comprehensive income (loss) as of September 30, 2006, 2005 and 2004, was $43 million, $27 million, and $(52) million, respectively.

Total Other Comprehensive Income (Loss) Activity
As of September 30


Accumulated other comprehensive loss, October 1, 2003	$	(74	)
Changes in fair value:
Inflation		4
Foreign currency swaps		18

Accumulated other comprehensive loss, September 30, 2004		(52	)

Changes in fair value:
Inflation		4
Foreign currency swaps		75

Accumulated other comprehensive income, September 30, 2005		27

Changes in fair value:
Inflation		(11	)
Foreign currency swaps		27


Accumulated other comprehensive income, September 30, 2006	$	43

Note: Foreign currency swap changes are shown net of reclassifications from Other comprehensive income to earnings.

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TVA records exchange rate gains and losses in debt and earnings and marks its currency swap assets to market through other comprehensive income. TVA then reclassifies an amount out of other comprehensive income into earnings which offsets the earnings gain/loss from recording the exchange gain/loss on the debt. The amounts reclassified from other comprehensive income equaled a charge to earnings of $143 million in 2006, an increase to earnings of $61 million in 2005, and a charge to earnings of $148 million in 2004. These reclassifications, coupled with the recording of the exchange gain/loss on the debt, result in a net effect on earnings of zero for 2006, 2005, and 2004. 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.

8. 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 credit 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. Following is a general overview of the accounting treatment for these derivative transactions as well as a more detailed discussion of certain of these derivative transactions. It is TVA’s policy to enter into derivative transactions solely for hedging purposes and not for speculative purposes.

Overview of Accounting Treatment

Prior to October 1, 2000, TVA accounted for hedging activities using the deferral method, and gains and losses were recognized in the financial statements when the related hedged transaction occurred. During 2001, TVA adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities,” and SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.”

The recorded amounts of certain derivative financial instruments are as follows:

Mark-to-Market Values of TVA Derivatives
As of September 30


	2006			2006 Balance Sheet	2005			2005 Balance Sheet	2006 Notional	Year of
	Balance			Presentation	Balance			Presentation	Amount	Expiration

Inflation swap	$	22		Other long-term assets	$	17		Other long-term assets	$300 million		2007
Interest rate swap		(131	)	Other liabilities		(158	)	Other liabilities	$476 million		2044

Currency swaps:
Deutschemark		—				(69	)	Other long-term assets	DM1.5 billion		2006
Sterling		47		Other long-term assets		20		Other long-term assets	£200 million		2021
Sterling		133		Other long-term assets		89		Other long-term assets	£250 million		2032
Sterling		66		Other long-term assets		36		Other long-term assets	£150 million		2043

Swaptions:
$1 billion notional		(296	)	Other liabilities		(314	)	Other liabilities	$1 billion		2042
$28 million notional		(3	)	Other liabilities		(4	)	Other liabilities	$28 million		2022
$14 million notional		(2	)	Other liabilities		(2	)	Other liabilities	$14 million		2022

Coal contracts with volume options		487		Other long-term assets		791		Other long-term assets	115 million tons		2017

Purchase power option contracts		(22	)	Other liabilities		(42	)	Other liabilities	500 MW		2007

In accordance with SFAS No. 133, as amended, the inflation and foreign currency swap contracts are accounted for on a mark-to-market basis and resulted in a gain of $170 million, $14 million, and $166 million for 2006, 2005, and 2004, respectively. Since these contracts represent cash flow hedges of certain Bond transactions, the gains have been recognized in Accumulated Other Comprehensive Income (Loss). Because of the highly effective nature of these hedging transactions, TVA was not required to recognize unrealized gains from these transactions in the Statements of Income. If any loss/(gain) were to be incurred as a result of the early termination of the inflation swap contract or a foreign currency swap contract, any resulting charge/(income) would be amortized over the remaining life of the associated Bond as a component of interest expense.

The inflation and foreign currency swap contracts are the only derivative transactions that receive hedge accounting treatment. Following is a table that describes the accounting treatment for these transactions as well as a

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table that describes the accounting treatment for derivative transactions that do not qualify for hedge accounting treatment.

Summary of Derivative Instruments That Receive Hedge Accounting Treatment
As of September 30, 2006


Derivative
Hedging		Purpose of Hedge	Type of Hedge–	Accounting for Derivative	Accounting for the
Instrument	Hedged Item	Transaction	Cash Flow (CF)	Hedging Instrument	Hedged Item

Inflation Swap	Variable-principal debt	To fix the debt’s variable cash flows to a fixed flow	CF	Cumulative unrealized gains and losses are recorded in Other comprehensive income	No adjustment is made to the basis of the hedged item.

Currency Swaps	Anticipated payment denominated in a foreign currency	To protect against changes in cash flows caused by changes in foreign-currency exchange rates	CF	Cumulative unrealized gains and losses are recorded in Other comprehensive income and reclassified to earnings to the extent they are offset by cumulative gains and losses on the hedged transaction.	No adjustment is made to the basis of the hedged item.

Summary of Derivative Instruments That Do Not Receive Hedge Accounting Treatment
As of September 30, 2006


Derivative Type	Purpose of Derivative	Accounting for Derivative Instrument

Coal Contracts with Volume Options	To protect against fluctuations in market prices of the item to be purchased	Gains and losses are recorded as regulatory assets or liabilities until settlement at which time they are recognized in fuel and purchased power expense.

Purchase Power Option Contracts	To protect against fluctuations in market prices of the item to be purchased	Gains and losses are recorded as regulatory assets or liabilities until settlement at which time they are recognized in fuel and purchased power expense.

Interest Rate Swap	To fix short-term debt variable rate to a fixed rate	Gains and losses are recorded in earnings as unrealized gains/losses on derivative contracts.

Swaptions	To protect against decreases in value of the embedded call	Gains and losses are recorded in earnings as unrealized gains/losses on derivative contracts.

Futures and Options on Futures	To protect against fluctuations in the price of the item to be purchased	Realized gains and losses are recorded in earnings as purchased power expense; unrealized gains and losses are recorded as a regulatory asset/liability.

Commodity Contracts

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, and electricity. TVA expects to take or make delivery, as appropriate, under these forward contracts. Accordingly, these contracts qualify for normal purchases and normal sales accounting under SFAS No. 133, as amended.

Swaps

To hedge certain market risks to which TVA is subject, TVA has entered into four currency swaps and one inflation swap. Each of these swaps is discussed in more detail below.

Currency Swaps. During 1996, TVA entered into a currency swap contract as a hedge for a foreign currency denominated Bond transaction. TVA issued DM1.5 billion of Bonds and entered into a currency swap to hedge fluctuations in the DM-U.S. Dollar exchange rate. The overall effective cost to TVA of these Bonds and the associated swap was 7.13 percent. In 2006, the Bonds matured and the related swap agreement expired.

In addition, TVA entered into currency swap contracts during 2003, 2001, and 1999 as hedges for sterling-denominated Bond transactions in which TVA issued £150 million, £250 million, and £200 million of Bonds, respectively. The overall effective cost to TVA of these Bonds and the associated swaps was 4.96 percent, 6.59

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percent, and 5.81 percent, respectively. Any gains or losses on the Bonds due to the foreign currency transactions are offset by losses or gains on the swap contracts. At September 30, 2006, and 2005, the currency transactions had resulted in net translation losses of $195 million and of $52 million, respectively, which are included in Current Maturities of Long-Term Debt, Net and Long-Term Debt, Net. However, the net translation losses were offset by corresponding gains on the swap contracts, which are reported as a deferred asset.

Inflation Swap. In 1997, TVA issued $300 million of inflation-indexed accreting principal Bonds. The 10-year Bonds have a fixed coupon rate that is paid on the inflation-adjusted principal amount. TVA hedged its inflation exposure under the securities through a receive-floating, pay-fixed inflation swap agreement. The overall effective cost to TVA of these Bonds and the associated swap was 6.64 percent. On September 21, 2004, TVA received a payment of $55 million from the swap counterparty representing the present value of the accretion as of that date. The present value of the accretion is recorded as a long-term receivable on the September 30, 2006, and 2005 Balance Sheets. At the termination of the swap, TVA will receive the additional accretion from September 22, 2004, through the end of the swap.

Swaptions and Related Interest Rate Swap

TVA has entered into four 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.

	•		In 2002, TVA monetized the call provisions on a $1 billion Bond issue by entering into a swaption agreement with a third party in exchange for $175 million (the “2002 Swaption”).

	•		In 2003, TVA monetized the call provisions on a second Bond issue of $476 million by entering into a swaption agreement with a third party in exchange for $81 million (the “2003 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 February 2004, the counterparty to the 2003 Swaption transaction exercised its option to enter into a swap with TVA, effective April 10, 2004, 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. These payments are based on a notional principal amount of $476 million, and the parties began making these payments on June 15, 2004.

The 2002 Swaption is recorded in Other Liabilities on the September 30, 2006 Balance Sheet and is designated as a hedge of future changes in the fair value of the original call provision. Under SFAS No. 133, as amended, TVA records the changes in market value of both the swaption and the embedded call. These values historically have been highly correlated; however, to the extent that the values do not perfectly offset, any differences will be recognized currently through earnings. In the third quarter of 2006, the hedge related to the 2002 Swaption ceased to be effective and continued to be ineffective during the fourth quarter from an accounting perspective. As a result, TVA did not receive hedge accounting treatment on the 2002 swaption for the last two quarters of 2006. Changes in the market value of the 2002 Swaption and the embedded call resulted in an unrealized noncash loss of $43 million for the year-ended September 30, 2006, and an unrealized noncash gain of $27 million for the year-ended September 30, 2005.

The swap entered into pursuant to the 2003 Swaption and the 2005 Swaptions are also recorded in Other Liabilities on the September 30, 2006 Balance Sheet, and the changes in market value are recognized currently in earnings. TVA did not elect hedge accounting treatment for the 2005 Swaptions. These changes amounted to a $28 million noncash gain for the year ended September 30, 2006, and a $19 million noncash loss for the year ended September 30, 2005.

Futures and Options on Futures

In 2005, the TVA Board approved a financial trading program under which TVA can purchase swaps, options on swaps, futures, and options on futures to hedge TVA’s exposure to natural gas and fuel oil prices. At September 30, 2006, TVA had derivative positions outstanding under the program equivalent to about 1,158 contracts, made up of 429 futures contracts and 729 swap futures contracts, with an approximate net market value of $40 million. For the year ended September 30, 2006, TVA recognized realized losses of $24 million which were recorded as an increase to purchased power expense. Unrealized losses at the end of the year were $6 million which TVA deferred as a regulatory asset in accordance with its 2007 Fuel Cost Adjustment recovery process.

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Accordingly, TVA will continue to defer all hedge program unrealized gains or losses and record only realized gains or losses as purchased power costs at the time the positions actually settle.

Financial Trading Program Activity
As of September 30


	2006						2005
	Notional						Notional
	Amount			Contract			Amount			Contract
	(in mmBtu)			Value			(in mmBtu)			Value

Futures contracts
Financial positions, beginning of period, net		880,000		$	9			—		$	—
Purchased		18,160,000			146			4,370,000			33
Settled		(14,750,000	)		(97	)		(3,490,000	)		(27	)
Realized (losses)/gains		—			(23	)		—			3

Net positions-long		4,290,000			35			880,000			9

Swap Futures
Financial positions, beginning of period, net		—			—			—			—
Fixed Portion		1,977,500			12			—			—
Floating Portion — realized		(155,000	)		(1	)		—			—
Realized (losses)		—			—			—			—

Net positions-long		1,822,500			11			—			—

Options contracts
Financial positions, beginning of period, net		240,000			—			—			—
Calls Purchased		—			—			580,000			1
Calls and puts sold		—			—			980,000			(1	)
Positions closed or expired		(240,000	)		—			(1,320,000	)		—

Net positions-long		—			—			240,000			—

Holding gains (losses)
Unrealized gain at beginning of period, net		—			1			—			—
Unrealized(loss)/gain for the period		—			(7	)		—			1

Unrealized (losses)/gains at end of period, net		—			(6	)		—			1


Financial positions at end of period, net		6,112,500		$	40			1,120,000		$	10

Concentration of Credit Risk. Seven customers, which represented an aggregate of 33 percent of TVA’s total power sales in 2006 and 2005, purchased power from TVA under contracts that require either five or 10 years’ notice to terminate. Outstanding accounts receivable for these customers at September 30, 2006, were $561 million, or 42 percent of total outstanding accounts receivable, and at September 30, 2005, were $399 million, or 39 percent, of total outstanding accounts receivable.

9. Debt

Borrowing Authority

The TVA Act authorizes TVA to issue bonds, notes, and other evidences of indebtedness (“Bonds”) up to a total of $30 billion outstanding at any one time. TVA must meet certain financial tests that are contained in the TVA Act and TVA’s bond covenants. Debt service on these obligations, which is payable solely from TVA’s net power proceeds, has precedence over payments to the U.S. Treasury. See Note 7 — Appropriation Investment. TVA Bonds are not obligations of the United States, and the United States does not guarantee the payments of the principal of or the interest on Bonds.

Short-Term Debt

The weighted average rates applicable to short-term debt outstanding in the public market as of September 30, 2006, 2005, and 2004, were 5.21 percent, 3.64 percent, and 1.70 percent, respectively. During 2006, 2005, and 2004, the maximum outstanding balances of TVA short-term borrowings held by the public were $2.8 billion, $3.1 billion, and $2.1 billion, respectively. For these same years, the average amounts (and weighted average interest rates) of TVA short-term borrowings were approximately $2.0 billion (4.47 percent), $2.1 billion (2.70 percent), and $1.1 billion (1.14 percent), respectively.

TVA also has access to a financing arrangement with the U.S. Treasury whereby it is authorized to accept a short-term note with the maturity of 1 year or less in an amount not to exceed $150 million. TVA may draw any portion of the authorized $150 million during the year. Interest is accrued daily and paid quarterly at a rate

Page 102

determined by the United States Secretary of the Treasury each month based on the average rate on outstanding marketable obligations of the United States with maturities of one year or less. During 2006, 2005, and 2004, the daily average amounts outstanding (and average interest rates) were approximately $131 million (4.33 percent), $103 million (2.46 percent), and $35 million (1.06 percent), respectively.

In May 2006, TVA converted its $2.5 billion short-term revolving credit facility agreement with a national bank into two $1.25 billion short-term revolving credit facilities with the same national bank. In order to provide greater flexibility going forward, TVA staggered the maturities of the two credit facilities to November 12, 2006, and May 16, 2007, respectively. See Note 16 — Subsequent Events — Revolving Credit Facility Agreement. The two facilities provide TVA with unsecured revolving lines of credit of up to $2.5 billion. The interest rate on any borrowing under either of these agreements is variable and based on market factors and the rating of TVA’s senior unsecured long-term non-credit enhanced debt at the time TVA draws on either facility. TVA is required to pay an unused facility fee on the portion of the total $2.5 billion against which TVA has not borrowed. This fee may fluctuate depending upon the rating of TVA’s senior unsecured long-term non-credit enhanced debt. There were no outstanding borrowings under the facilities at September 30, 2006. TVA anticipates renewing each facility from time to time.

Put and Call Options

Bond issues of $2.2 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. Additionally, as of September 30, 2006, TVA had a Bond issue of $600 million, which matures in December 2016 and is redeemable in December 2006 at the option of the bondholders. The Bond issue is reported in the debt schedule with a maturity date corresponding to the earliest redemption date. Sixty-two Bond issues totaling $1.1 billion, with maturity dates ranging from 2008 to 2026, 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 TVA PARRS is based on a calculation. For either series of PARRS, the coupon rate will reset downward on the reset date if the rate calculated is below the 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. 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 bond issue as noted above. If the expected reset rate is less than the coupon on the bond, the PARRS are included in current maturities. Otherwise, the PARRS are included in long-term debt. At September 30, 2006, the expected reset rate is higher than the current coupon on each issue of PARRS issues, therefore the par amount outstanding is classified as long-term debt.

One PARRS issue totals $466 million, matures in June 2028, and had its first reset date in June 2003. The rate reset to 5.95 percent from 6.75 percent in June 2003, at which time $23 million of the original $575 million of the 1998 Series D PARRS were redeemed at par, and reset again to 5.49 percent from 5.95 percent in June 2005, at which time $86 million of the 1998 Series D PARRS were redeemed at par. The second issue of PARRS totals $410 million, matures in May 2029, and had its first rate reset date in May 2004. The rate reset in May 2004 to 5.62 percent from 6.50 percent, and $115 million of the original $525 million 1999 Series A PARRS were redeemed at par.

Debt Securities Activity

The table below summarizes TVA’s Bond activity for the period from October 1, 2005, to September 30, 2006.

Page 103

Debt Securities Activity from October 1, 2005 to September 30, 2006


	Principal Amount
	2006			2005

Redemptions/Maturities:
electronotes^®
First quarter	$	152		$	3
Second quarter		3			75
Third quarter		4			101
Fourth quarter		4			3
2000E QUINTS		—			100
1998D PARRS		—			86
1995 Series A		—			2,000
1996 Series C		1,000			—
2003 Series B		28	*		—
2005 Series A		64	*		—

Total	$	1,255		$	2,368


Issues
electronotes^®
First quarter	$	49		$	—
Second quarter		19			25
Third quarter		37			105
Fourth quarter		27			20
2006 Series A		1,000			—
2005 Series A		—			500
2005 Series B		—			1,000

Total	$	1,132		$	1,650

Inflation indexed bond accretion	$	15		$	11


Note

*		Includes $13 million gain on redemption — See Note 10.

Debt Outstanding

Debt outstanding at September 30, 2006, consisted of the following:

Short-Term Debt
As of September 30


			Call/(Put)			Coupon			2006		2005 Par
CUSIP or Other Identifier	Maturity		Date			Rate			Par Amount		Amount

Discount Notes (net of discount)									$	2,376	$	2,469
Current maturities of long-term debt:
88059TAE1		06/15/2021		10/02/2005			6.350	%		—		28
88059TAJ0		08/15/2021		10/02/2005			6.100	%		—		23
88059TAZ4		05/15/2017		10/02/2005			6.000	%		—		40
88059TCM1		10/15/2023		10/02/2005			5.625	%		—		15
88059TCG4		08/15/2018		10/02/2005			5.500	%		—		44
880591CK6		04/01/2036		(04/03/2006	)		5.980	%		—		121
880591CM2		09/18/2006					7.125	%		—		922
880591CS9		04/01/2036		(04/03/2006	)		5.880	%		—		1,500
880591CQ3		01/15/2007					6.643	%*		385		—
880591DS8		12/15/2016		(12/15/2006	)		4.875	%		600		—

Current maturities of long-term debt										985		2,693

Total short-term debt, net									$	3,361	$	5,162


Note

*		The coupon rate represents TVA’s effective interest rate.

Page 104

Long-Term Debt¹
As of September 30


			Call/(Put)			Coupon			2006		2005 Par
CUSIP or Other Identifier	Maturity		Date			Rate			Par Amount		Amount

880591CQ3		01/15/2007					6.643	% ²	$	—	$	370
880591DS8		12/15/2016		(12/15/2006	)		4.875	%		—		600

Maturing in 2007										—		970

88059TBQ3		01/15/2008		01/15/2004			3.050	%		10		10
88059TBS9		01/15/2008		01/15/2004			3.300	%		40		40
88059TCB5		05/15/2008		05/15/2004			2.450	%		40		41

Maturing in 2008										90		91

880591DB5		11/13/2008					5.375	%		2,000		2,000
88059TCW9		03/15/2009		03/15/2005			3.200	%		30		31

Maturing in 2009										2,030		2,031

88059TDP3		04/15/2010		04/15/2007			5.125	%		21		—
88059TDD0		06/15/2010		06/15/2006			4.125	%		42		42

Maturing in 2010										63		42

880591DN9		01/18/2011					5.625	%		1,000		1,000
88059TDQ1		05/15/2011		05/15/2007			5.250	%		6		—
88059TDR9		06/15/2011		06/15/2007			5.250	%		9		—

Maturing in 2011										1,015		1,000

880591DL3		05/23/2012					7.140	%		29		29
880591DT6		05/23/2012					6.790	%		1,486		1,486
88059TBH3		09/15/2012		09/15/2004			4.375	%		10		10

Maturing in 2012										1,525		1,525

880591CW0		03/15/2013					6.000	%		1,359		1,359
88059TBR1		01/15/2013		01/15/2005			4.375	%		14		14
88059TBW0		03/15/2013		03/15/2005			4.000	%		23		23
88059TBX8		03/15/2013		03/15/2004			4.250	%		13		13
88059TCD1		06/15/2013		06/15/2004			3.500	%		12		12
880591DW9		08/01/2013					4.750	%		990		990
88059TCF6		07/15/2013		07/15/2005			4.350	%		17		18
88059TDS7		07/15/2013		07/15/2008			5.625	%		9		—

Maturing in 2013										2,437		2,429

88059TCL3		10/15/2013		10/15/2005			4.500	%		12		12
88059TCQ2		12/15/2013		12/15/2005			4.700	%		8		8
88059TBJ9		10/15/2014		10/15/2004			4.600	%		22		22
88059TBN0		12/15/2014		12/15/2004			5.000	%		54		55
88059TBY6		04/15/2015		04/15/2005			4.600	%		20		20
88059TDB4		04/15/2015		04/15/2007			5.000	%		50		50
880591DY5		06/15/2015					4.375	%		1,000		1,000
88059TDE8		07/15/2015		07/15/2007			4.500	%		7		7
88059TCH2		08/15/2015		08/15/2005			5.125	%		34		35
88050TBK6		10/15/2015		10/15/2005			5.050	%		19		19
88059TDH1		10/15/2015		10/15/2007			5.000	%		28		—
88059TBL4		11/15/2015		11/15/2005			4.800	%		27		27
88059TCR0		12/15/2015		12/15/2005			4.875	%		11		11
88059TDK4		12/15/2015		12/15/2006			5.375	%		10		—
88059TBU4		02/15/2016		02/15/2006			4.550	%		9		9
88059TCV1		02/15/2016		02/15/2006			4.500	%		3		3
88059TDN8		03/15/2016		03/15/2008			5.375	%		8		—
88059TCC3		06/15/2016		06/15/2006			3.875	%		4		4
88059TDT5		08/15/2016		08/15/2007			5.625	%		4		—
88059TCJ8		09/15/2016		09/15/2006			4.950	%		11		11
88059TDU2		09/15/2016		09/15/2007			5.375	%		14		—
88059TCS8		01/15/2017		01/15/2007			5.000	%		29		29
880591CU4		12/15/2017					6.250	%		750		750
88059TCA7		05/15/2018		05/15/2004			4.750	%		24		24
88059TCE9		07/15/2018		07/15/2004			4.700	%		35		36
88059TCN9		11/15/2018		11/15/2006			5.125	%		18		19
88059TCT6		01/15/2019		01/15/2005			5.000	%		28		28
88059TCX7		03/15/2019		03/15/2007			4.500	%		13		13
88059TDF5		08/15/2020		08/15/2008			5.000	%		10		10
88059TDG3		09/15/2020		09/15/2008			4.800	%		3		3
88059TDJ7		11/15/2020		11/15/2008			5.500	%		11		—

Page 105

Long-Term Debt, continued


								2006
CUSIP or Other Identifier	Maturity		Call/(Put) Date		Coupon Rate			Par Amount			2005 Par Amount

88059TDL2		01/18/2021		01/15/2009		5.125	%	$	5		$	–
880591DC3		06/07/2021				5.805	% ²		374			352
88859TAN1		12/15/2021		12/15/2005		6.000	%		25			25
88059TAR2		01/15/2022		01/15/2006		6.125	%		28			28
88059TAX9		04/15/2022		04/15/2006		6.125	%		14			14
88059TBE0		08/15/2022		08/15/2006		5.500	%		28			29
88059TBM2		11/15/2022		11/15/2006		5.000	%		11			11
88059TBP5		12/15/2022		12/15/2006		5.000	%		20			20
88059TBT7		01/15/2023		01/15/2007		5.000	%		11			12
88059TBV2		02/15/2023		02/15/2007		5.000	%		17			18
88059TBZ3		05/15/2023		05/15/2004		5.125	%		15			15
88059TCK5		10/15/2023		10/15/2007		5.200	%		14			14
88059TCP4		11/15/2023		11/15/2004		5.250	%		12			12
88059TCU3		02/15/2024		02/15/2008		5.125	%		9			9
88059TCY5		04/15/2024		04/15/2005		5.375	%		14			15
88059TCZ2		02/15/2025		02/15/2006		5.000	%		18			19
88059TDA6		03/15/2025		03/15/2009		5.000	%		6			6
88059TDC2		05/15/2025		05/15/2009		5.125	%		14			14
880591CJ9		11/01/2025				6.750	%		1,350			1,350
88059TDM0		02/15/2026		02/15/2010		5.500	%		7			–
880591300³		06/01/2028				5.490	%		466			466
880591409³		05/01/2029				5.618	%		410			410
880591DM1		05/01/2030				7.125	%		1,000			1,000
880591DP4		06/07/2032				6.587	% ²		468			441
880591DV1		07/15/2033				4.700	%		472			500
880591DX7		06/15/2035				4.650	%		436			500
880591CK6		04/01/2036				5.980	%		121			–
880591CS9		04/01/2036				5.880	%		1,500			–
880591CP5		01/15/2038				6.150	%		1,000			1,000
880591BL5		04/15/2042		04/15/2012		8.250	%		1,000			1,000
880591DU3		06/07/2043				4.962	% ²		281			265
880591CF7		07/15/2045		07/15/2020		6.235	%		140			140
880591DZ2		04/01/2056				5.375	%		1,000			–

Maturing 2014-2056									12,562			9,890

Subtotal									19,722			17,978

Unamortized discounts, premiums, and other									(178	)		(227	)


Total long-term debt, net								$	19,544		$	17,751


Notes

1		The above table includes net translation losses from currency transactions of $195 million and $52 million at September 30, 2006, and 2005, respectively.

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 Note 9 — Put and Call Options.

10. Supplemental Cash Flow Information

Interest paid was $1,260 million in 2006, $1,351 million in 2005, and $1,382 million in 2004. This differs from interest expense due to the timing of payments and interest capitalized of $163 million in 2006, $116 million in 2005, and $99 million in 2004 as a part of major capital expenditures.

TVA had non-cash activity related to financing activities on the 2005 Statements of Cash Flows related to a capital lease for BLEU fuel of $36.2 million. See Note 1 — Blended Low Enriched Uranium Program. In 2006 TVA had non-cash activity related to financing activities of $13 million related to a gain on the repurchase of Bonds.

11. Fair Value of Financial Instruments

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, 2006, may not be representative of the actual gains or losses that will be recorded when these instruments mature or if they are called or presented for early redemption.

Page 106

The estimated values of TVA’s financial instruments at September 30 are as follows:

Estimated Values of Financial Instruments
As of September 30


	2006				2005
	Carrying		Fair		Carrying
	Amount		Value		Amount		Fair Value

Cash and cash equivalents	$	536	$	536	$	538	$	538
Restricted cash and investments		198		198		107		107
Investment funds		972		972		858		858
Loans and other long-term receivables		102		102		93		93
Short-term debt, net of discount		2,376		2,376		2,469		2,469
Long-term debt (including current portion), net of discount		20,529		22,037		20,444		22,552
Other financing obligations		1,108		1,108		1,143		1,143

Cash and Cash Equivalents, Short-Term Investments, and Short-Term Debt

Because of the short-term maturity of these instruments, the carrying amount approximates fair value.

Restricted cash and investments

Because of the short-term maturity of these instruments, the carrying amount approximates fair value.

Investment Funds

Information on investments by major type at September 30 is as follows:

TVA Investments By Type
As of September 30


	2006		2005

Securities held as trading	$	966	$	853
Other		6		5

Total investment funds	$	972	$	858

Gains and losses on trading securities are recognized in current earnings. The gains and losses on the nuclear decommissioning trust are subsequently reclassified to a regulatory asset account in accordance with TVA’s decommissioning accounting policy. See Note 1 — Decommissioning Costs. The nuclear decommissioning trust had unrealized losses of $24 million in 2006, unrealized gains of $48 million in 2005, and $29 million in 2004.

Loans and Other Long-Term Receivables

Fair values for loans and long-term receivables are estimated by determining the present value of future cash flows using a discounted rate equal to lending rates for similar loans made to borrowers with similar credit ratings and for the same remaining maturities. The carrying amount approximates fair value.

Long-Term Debt

Fair value of long-term debt traded in the public market is determined by multiplying the par value of the Bonds by the indicative market price at the Balance Sheet date.

Other Financing Obligations

In 2003, 2002, and 2000, TVA received approximately $325 million, $320 million, and $300 million, respectively, in proceeds by entering into lease/leaseback transactions for 24 new peaking combustion turbine units. TVA also received approximately $389 million in proceeds by entering into a lease/leaseback transaction for qualified technological equipment and software in 2003. Due to the nature of the transactions, the carrying amount of the obligation and the fair market value are equal. At September 30, 2006, and 2005, the total balances of the obligations were $1,108 million and $1,143 million, respectively.

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Due to TVA’s continuing involvement in the operation and maintenance of the leased units and equipment, and its control over the distribution of power produced by the facilities during the leaseback term, TVA accounted for the respective lease proceeds of $714 million, $320 million, and $300 million as financing obligations as required in accordance with SFAS No. 66, “Accounting for Sales of Real Estate,” and SFAS No. 98, “Accounting for Leases.” Accordingly, the outstanding lease/leaseback obligations of $1,108 million at September 30, 2006, and $1,143 million at September 30, 2005, are included in Current Portion of Lease/Leaseback Obligations ($37 million and $35 million, respectively) and Lease/Leaseback Obligations ($1,071 million and $1,108 million, respectively) in TVA’s 2006 and 2005 year-end Balance Sheets.

12. Benefit Plans

Overview

TVA sponsors a defined benefit pension plan that covers most of its full-time employees, an unfunded postretirement medical plan that provides for non-vested contributions toward the cost of certain retirees’ medical coverage, and other postemployment benefits such as workers’ compensation. During 2006, 2005, and 2004, TVA recognized pension expense of $244 million, $243 million, and $178 million, respectively, postretirement benefit expense of $58 million, $46 million, and $36 million (which includes $7 million in special termination costs), respectively, and $44 million, $71 million, and $66 million of postemployment benefit expense, respectively. TVA’s reported costs of providing these benefits are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various assumptions, the most significant of which are described below.

Discount Rate. In selecting an assumed discount rate, TVA reviews market yields on high-quality corporate debt and long-term obligations of the U.S. Treasury. Based on recent market trends, TVA increased its discount rate from 5.81 percent and 5.38 percent at the end of 2004 and 2005, respectively, to 5.90 percent at the end of 2006.

Health Care Costs. TVA reviews actual recent cost trends and projected future trends in establishing health care cost trend rates. Based on this review process, TVA did not reset its health care cost trend rate assumption used in calculating the 2006 accumulated postretirement benefit obligations. The assumed health care trend rate used for 2006 is 8.5 percent which represents a one-half percent reduction to the 9.0 percent trend rate used during 2005. Prior to 2006, TVA used a health care cost trend rate of 9.0 percent during each of the four prior years. The 2006 health care cost trend rate of 8.5 percent is assumed to gradually decrease each successive year until it reaches a five percent annual increase in health care costs in the year beginning October 1, 2013, and beyond.

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. TVA utilized a rate of return of 8.00 percent during 2003 in the aftermath of the market declines of 2002 and 2001. TVA increased its expected long-term rate of return on pension plan assets to 8.25 percent at the end of 2004 and 2005. However, TVA has increased its expected rate of return to 8.75 percent at the end of 2006 based on revisions to future expected returns as provided by third party professional asset managers.

Actuarial Assumptions. TVA utilizes professional actuaries to perform valuation services related to the areas of pension, postretirement, and postemployment benefits. Net periodic pension cost is determined using assumptions as of the beginning of each year. Funded status is determined using assumptions as of the end of each year. The valuations performed at the end of 2006 were based on applications of actuarial assumptions that were consistent for all of TVA’s benefit plans.

Pension Benefits. TVA sponsors a defined benefit plan for most of its full-time employees that provides two benefit structures: the Original Benefit Structure and the Cash Balance Benefit Structure. The plan is controlled and administered by a legal entity separate from TVA, the TVA Retirement System (“TVARS”), which is governed by its own independent board of directors. The plan assets are primarily stocks and bonds. 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.

The pension benefit for a member participating in the Original Benefit Structure is based on the member’s years of creditable service, the member’s average base pay for the highest three consecutive years, and the pension rate for the member’s age and years of service, less a Social Security offset. 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 6.0 percent of his or her straight-time earnings. The account also increases at an interest rate equal to the change in the Consumer Price Index (“CPI”) plus 3.0 percent, with the provision that the rate may not be less than 6.0 percent or more than 10.0 percent. The

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actual change in the CPI for 2006 and 2005 was 3.37 percent and 3.00 percent, which resulted in interest rates of 6.37 percent and 6.00 percent, respectively.

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. TVARS also administers a defined contribution plan, a 401(k) plan to which TVA makes matching contributions of 25 cents on the dollar (up to 1.5 percent of pay) for members participating in the Original Benefit Structure and of 75 cents on the dollar (up to 4.5 percent of pay) for members participating in the Cash Balance Benefit Structure. TVA made matching contributions of about $19 million to the plan during 2006, $17 million during 2005, and $16 million during 2004.

Pension Results

Effective for the end of year measurement date and the calculation of funded status, the discount rate was increased from 5.38 percent for 2005 to 5.90 percent for 2006. The cost of living rate was adjusted upward from the 2005 rate of 2.50 percent to 3.0 percent for 2006 to reflect current market and demographic conditions. Additionally, TVA continued to use its assumption related to mortality based on results of an experience study performed during the prior year which underlies the use of 1983 mortality tables. Based on the use of the assumptions described, the projected benefit obligation (“PBO”) at September 30, 2006, increased approximately $167 million compared to the PBO at September 30, 2005. The PBO increased a total of $167 million comprised, in part, of an increase of $163 million due to normal operation of the plan (primarily in the form of service cost and interest accruals), a decrease of $170 million in the PBO due to changes in the discount rate (from 5.38 percent to 5.90 percent) and changes in the cost of living assumptions (from 2.5 percent to 3.0 percent), and incurred liability losses of $173 million related primarily to more-than-assumed early retirements. The assumptions used in the 2006 end-of-year actuarial valuation process had no effect on pension costs for 2006, 2005, or 2004. The accumulated benefit obligation at September 30, 2006 and September 30, 2005 was $8.2 billion and $8.0 billion, respectively.

Other Postretirement Benefits

TVA sponsors an unfunded postretirement plan that provides for non-vested contributions toward the cost of certain retirees’ medical coverage. This plan formerly covered all eligible retirees participating in the TVA medical plan, and TVA’s contributions were a flat dollar amount based on the participants’ ages and years of service and certain payments toward the plan costs. This plan now operates on a much more limited basis, covering only certain retirees and surviving dependents who do not qualify for TVARS benefits, including the vested supplemental pension benefit.

The initial annual assumed cost trend for covered benefits was 8.5 percent in 2006, decreasing by one-half percent per year to a level of 5.0 percent beginning on October 1, 2013, and thereafter. For 2005 and 2004, annual trend rates of 9.0 percent and 9.0 percent, respectively, were assumed. The effect of the change in assumptions on the cost basis was not significant. Increasing/(reducing) the assumed health-care cost trend rates by one percent would increase/(reduce) the accumulated postretirement benefit obligation (“APBO”) as of September 30, 2006, by $61 million/($65 million) and the aggregated service and interest cost components of net periodic postretirement benefit cost for 2006 by $4 million/($5 million). The weighted average discount rate used in determining the end-of-year APBO was 5.90 percent for 2006, 5.38 percent for 2005, and 5.81 percent for 2004. Any net unrecognized gain or loss resulting from experience different from that assumed or from changes in assumptions, and exceeding ten percent of the APBO, is amortized over the average remaining service period of active plan participants.

Based on the use of the assumptions described, the 2006 APBO for postretirement benefits decreased approximately $93 million. The change in the obligation was comprised of a $16 million increase due to normal operation of the plan (primarily in the form of service cost and interest accruals) and a decrease of $109 million due to other actuarial and experience adjustments including gains and losses. The $109 million decrease in the obligation is comprised of two components. The first component of the actuarial and experience adjustments is comprised of an actuarial gain of approximately $30 million related to the actuarial discount rate which was increased to 5.90 percent in 2006 from 5.38 percent in 2005. The second component includes a combined gain of approximately $79 million due to actuarial gains resulting from claims experience more favorable than expected combined with a reduction in expected plan retiree medical credits.

The set of assumptions used for the end-of-year actuarial valuation process had no effect on postretirement benefit costs for 2006, 2005, or 2004 but, when coupled with further experience adjustments related to claims and contributions, is expected to decrease postretirement benefits expense for 2007 by approximately $16 million compared to 2006. TVA expects 2007 postretirement health care cost to approximate $42 million, a decrease of $16 million over 2006 costs.

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Components of Pension and Other Postretirement Benefits

The components of pension expense and other postretirement benefits expense for the years ended September 30 were:

Components of Pension and Other Postretirement Benefits


	Pension Benefits						Other Postretirement Benefits

	2006			2005			2006			2005

Change in benefit obligation
Benefit obligation at beginning of year	$	8,433		$	7,754		$	544		$	447
Service cost		127			117			9			6
Interest cost		440			428			29			25
Plan participants’ contributions		35			41			64			63
Amendments, including special events		—			—			—			—
Actuarial loss		3			489			(108	)		91
Net transfers from variable fund/401(k) plan		9			24			—			—
Expenses paid		(4	)		(4	)		—			—
Benefits paid		(443	)		(416	)		(87	)		(88	)

Benefit obligation at end of year	$	8,600		$	8,433		$	451		$	544


Change in plan assets
Fair value of plan assets at beginning of year	$	7,015		$	6,415		$	—		$	—
Adjustment to reconcile to system asset value		—			—			—			—
Actual return on plan assets		641			902			—			—
Plan participants’ contributions		35			41			64			63
Net transfers from variable fund/401(k) plan		9			24			—			—
Employer contributions		75			53			23			25
Expenses paid		(4	)		(4	)		—			—
Benefits paid		(443	)		(416	)		(87	)		(88	)

Fair value of plan assets at end of year	$	7,328		$	7,015		$	—		$	—


Funded status	$	(1,272	)	$	(1,418	)	$	(451	)	$	(544	)
Unrecognized net actuarial loss		1,275			1,554			113			237
Unrecognized prior service cost		275			311			39			44
Unrecognized transition obligations		—			—			—			—

Prepaid (accrued) benefit cost	$	278		$	447		$	(299	)	$	(263	)


Amount recognized on balance sheet
Prepaid benefit cost	$	—		$	—		$	—		$	—
Accrued benefit liability		(903	)		(1,010	)		(299	)		(263	)
Other long-term asset		275			311			—			—
Accumulated other comprehensive income reclassified to regulatory assets		906			1,146			—			—

Net amount recognized	$	278		$	447		$	(299	)	$	(263	)


Weighted average assumptions as of September 30		2006			2005			2006			2005


Discount rate		5.90	%		5.38	%		5.90	%		5.38	%
Expected return on plan assets		8.75	%		8.25	%	NA			NA
Rate of compensation increase		3.3% – 10.1	%		3.3% – 10.1	%	NA			NA
Initial health care trend rate	NA			NA				8.50	%		9.00	%
Ultimate health care trend rate	NA			NA				5.00	%		5.00	%
Ultimate trend rate is reached in year beginning	NA			NA				2013			2013

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Components of Pension and Other Postretirement Benefits


										Other Postretirement
	Pension Benefits									Benefits
	2006			2005			2004			2006			2005			2004
Components of net periodic benefit cost
Service cost	$	127		$	117		$	112		$	9		$	6		$	5
Interest cost		440			429			406			28			25			18
Expected return on plan assets		(490	)		(457	)		(464	)	NA			NA			NA
Amortization of prior service cost		36			36			36			5			5			5
Amortization of transition obligation		—			—			—			—			—			—
Recognized net actuarial loss		131			118			88			16			10			1

Net periodic benefit cost		244			243			178			58			46			29
Special events		—			—			—			—			—			7

Total benefits cost	$	244		$	243		$	178		$	58		$	46		$	36


Weighted average assumptions used to determine expense
Discount rate		5.38%			5.81%			6.00%			5.38	%		5.81	%		6.00	%
Expected return on plan assets		8.25%			8.25%			8.50%		NA			NA			NA
Rate of compensation increase		3.3%-10.1	%		3.3%-10.1	%		3.3%-10.1	%	NA			NA			NA
Initial health care trend rate	NA			NA			NA				9.00	%		9.0	%		8.50	%
Ultimate health care trend rate	NA			NA			NA				5.00	%		5.00	%		5.00	%
Ultimate trend rate is reached in year beginning	NA			NA			NA				2013			2012			2010

Sensitivity to the Assumed Health Care Cost Trend Rates for 2006


	1% Increase		1% Decrease

Effect on total of service and interest cost components		4		(5	)
Effect on end-of-year accumulated postretirement benefit obligation		61		(65	)

Estimated Future Benefit Payments


	Pension		Other

2007	$	534,125	$	21,715
2008	$	544,053	$	24,016
2009	$	559,152	$	26,116
2010	$	572,454	$	28,073
2011	$	584,788	$	30,140
2012-2016	$	3,160,924	$	159,368

Plan Investments

Investments held in the TVA Retirement System are stated at fair value, which is determined by the Trustee of the pension trust fund.

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U.S. equity holdings of about 43 percent, non-U.S. equity holdings of about 16 percent, and private equity holdings of about two percent), plus fixed income securities of about 39 percent.

Plan Contributions

TVA contributed $75 million to its qualified pension plan in 2006, and $53 million in 2005. For 2007, TVA plans to contribute $90 million to its retirement plans.

Other Non-Qualified Retirement and Deferred Compensation Plans

In 1995, TVA established a Supplemental Executive Retirement Plan (“SERP”) to provide additional benefits to specified individuals in addition to those available under the qualified pension plan because of Internal Revenue Service (“IRS”) limits applicable to qualified plans. The SERP funds are invested in securities generally designed to achieve a return in line with overall equity market performance. The nature of these investments comprises commingled funds. Commingled funds are similar in nature to a mutual fund. Investments held in the SERP are stated at fair value, which is determined by the trustee of the fund. TVA has historically funded the annual calculated expense. Due to the immaterial amounts related to the SERP, TVA has elected to not make full SFAS No. 132R disclosures, but rather has disclosed amounts related to recorded balances and expense as determined through the application of SFAS No. 87, “Employers’ Accounting for Pensions.” As of and for the year ended September 30, 2006, TVA recognized certain amounts related to the plan including plan assets in trust of $30 million, a regulatory asset of $7 million, an intangible asset of $5 million, an estimated accrued and minimum pension plan obligation of $38 million, expense of $7 million, and current year gains on plan assets of $2 million, of which $0.6 million was realized. In addition, $3 million in benefit payments were made from the plan during the year, and TVA made contributions of $13 million to the plan. As of and for the year ended September 30, 2005, TVA recognized certain amounts related to the plan including plan assets in trust of $17 million, a regulatory asset of $12 million, an intangible asset of $1 million, an estimated accrued and minimum pension plan obligation of $35 million, expense of $6 million, and current year gains on plan assets of $1 million of which all was realized. In addition, $2 million in benefit payments were made from the plan during the year. TVA did not make contributions to the plan during 2005.

Other Postemployment Benefits

Other postemployment benefits include workers’ compensation provided to former or inactive employees and their beneficiaries and covered dependents for the period after employment but before retirement. TVA employees injured in work-related incidents are covered by the TVA’s workers’ compensation program for federal employees administered through the Department of Labor by the Office of Workers’ Compensation Programs (“OWCP”) 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.

Postemployment benefit cost estimates are revised to properly reflect changes in actuarial assumptions made at the end of the year. For 2006, TVA has determined to utilize a discount rate of 4.64 percent representing the risk-free rate corresponding to the U.S. Treasury Constant Maturities rate for a 10 year maturity. Use of the 10 year maturity corresponds to calculated average durations of TVA’s future estimated postemployment claims payments. The use of a 4.64 percent discount rate resulted in the recognition of 2006 annual expense of approximately $44 million and an unpaid benefit obligation of about $413 million at year end. TVA utilized a discount rate of 4.34 percent and 5.75 percent in 2005 and 2004 respectively. The changes in 2006 assumptions had no effect on postemployment expense for 2005 and 2004.

Medicare Prescription Drug Improvement and Modernization Act of 2003

In 2006, Medicare began providing prescription drug coverage to Medicare-eligible beneficiaries under Medicare Part D. Under the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which created Medicare Part D, employers that provide retiree prescription drug coverage, which is “actuarially equivalent” to standard coverage under Medicare Part D, may receive retiree drug subsidies for retirees who enroll in the employer’s retiree prescription drug plan instead of Medicare Part D. TVA determined that its retiree prescription drug coverage did not qualify for retiree drug subsidy and accordingly has not included or utilized any manner of subsidy in the determination of APBO or postretirement benefit cost, for the current or prior periods, in accordance with the requirements contained within the FASB Staff Position (“FSP”), FSP FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” After analyzing a number of options available to plan sponsors for integration with the new Medicare Part D, TVA elected to provide an employer-sponsored Part D prescription drug plan (“PDP”), with alternative coverage over and above Medicare standard Part D coverage, for Medicare-eligible retirees who participate in TVA’s Medicare supplement. By

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providing an employer-sponsored PDP, any Medicare subsidies will be passed through to retirees in the form of lower participant premiums and should not affect TVA’s cost of providing prescription drug coverage.

13. Commitments and Contingencies

Commitments

As of September 30, 2006, the amounts of contractual cash commitments maturing in each of the next five years and beyond are shown below:

Commitments
Payments Due in the Year Ending September 30


	2007		2008		2009		2010		2011		Thereafter		Total

Debt	$	3,361	$	90	$	2,030	$	63	$	1,015	$	16,329	$	22,888	*
Leases
Non-cancelable operating		45		41		26		12		4		7		135
Capital		63		59		57		57		30		6		272
Power purchase obligations		205		146		148		152		154		3,549		4,354
Purchase obligations
Fuel purchase obligations		1,083		509		496		400		249		278		3,015
Other obligations		199		111		5		3		2		7		327

Total	$	4,956	$	956	$	2,762	$	687	$	1,454	$	20,176	$	30,991


*		Does not include noncash items of foreign currency valuation loss of $195 million and net discount on sale of bonds of $178 million.

Under the terms of an interagency agreement, DOE and other third-party nuclear fuel processors provide nuclear fuel materials and process the materials into usable fuel for TVA nuclear reactors. In exchange, DOE will participate to a degree in the savings generated by TVA’s use of this blended nuclear fuel product. TVA anticipates these future payments could begin in 2009. At September 30, 2006, TVA has accrued an obligation of $2 million related to the portion of the ultimate future payments estimated to be attributable to the BLEU fuel currently in use.

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


	2007		2008		2009		2010		2011		Thereafter		Total

Energy Prepayment Obligations	$	106	$	106	$	105	$	105	$	105	$	717	$	1,244

Debt. At September 30, 2006, TVA had outstanding discount notes of $2.4 billion and long-term debt (including current maturities) at varying maturities and interest rates of $20.5 billion for total outstanding indebtedness of $22.9 billion. See Note 9.

Leases. TVA leases certain property, plant, and equipment under agreements with terms ranging from one to 30 years. Obligations under capital lease agreements in effect at September 30, 2006, totaled $63 million for 2007, $59 million for 2008, $57 million for 2009, $57 million for 2010, $30 million for 2011 and an aggregate of $6 million thereafter, for a total commitment of $272 million. Of this amount, $55 million represents the cost of financing. Obligations under non-cancelable operating lease agreements (primarily related to facilities and equipment) in effect at September 30, 2006, total $45 million for 2007, $41 million for 2008, $26 million for 2009, $12 million for 2010, $4 million for 2011, and $7 million thereafter for a total commitment of $135 million.

Power Purchase Obligations. TVA has contracted with various independent power producers and power distributor customers for additional capacity to be made available to TVA. In total, these agreements provide 4,275 megawatts of winter net dependable capacity and 29 megawatts of capacity from renewable resources that are not included in the determination of winter net dependable capacity. The total financial commitment for non-renewable contracts is approximately $4.3 billion. As of September 30, 2006, counterparties to contracts for 3,008 megawatts of this capacity were in bankruptcy, but the counterparties have continued to perform under their power purchase

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agreements with TVA throughout their bankruptcy proceedings. Costs under TVA’s power purchase agreements are included in the Statements of Income for 2006, 2005, and 2004 as Fuel and Purchased Power expense and are expensed as incurred in accordance with the normal purchases and sales exemption described in SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended.

Under the Public Utility Regulatory Policies Act of 1978 as amended by the Energy Policy Acts of 1992 and 1995, TVA is obligated to purchase power from qualifying facilities. At September 30, 2006, there were seven suppliers, with a combined capacity of 906 megawatts, which qualify under this program.

In addition, under arrangements among TVA, the U.S. Army Corps of Engineers, and the Southeastern Power Administration (“SEPA”), eight hydroelectric plants of the U.S. Army Corps of Engineers on the Cumberland River system are operated in coordination with the TVA system. These arrangements provide for 405 megawatts of winter net dependable capacity as well as all surplus energy from the Cumberland River system to be supplied to TVA by SEPA at the points of generation at a price based on the operating and maintenance expenses and amortization of the power facilities. The agreement with SEPA covering these arrangements for power from the Cumberland River system can be terminated upon three years’ notice, but this notice of termination may not become effective prior to June 30, 2017.

Fuel Purchase Obligations. TVA has approximately $1.5 billion in long-term fuel purchase commitments ranging in terms of up to four years for the purchase and transportation of coal and approximately $1.5 billion of long-term commitments ranging in terms of up to ten years for the purchase of enriched uranium and fabrication of nuclear fuel assemblies.

Other Obligations. Other obligations of $327 million consist of contracts as of September 30, 2006, for goods and services primarily related to capital projects as well as other major recurring operating costs. TVA has approximately $234 million in long-term construction commitments consisting primarily of the construction of generating assets (including Browns Ferry Unit 1), and emission control equipment. In addition to construction commitments, TVA is committed under various other contracts for recurring goods and services of $93 million with terms extending into 2010.

Bear Creek Dam. Bear Creek Dam is experiencing foundation problems as evidenced by seepage through the foundation of the dam. The environmental and engineering study to identify a long term solution for the Bear Creek Dam leakage problem is continuing.

Bondholder Protection Test. The TVA Act and the Basic Bond Resolution each contain a bondholder protection test. Under this test, TVA must, in successive five-year periods, use an amount of net power proceeds at least equal to the sum of:

	•		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 Appropriation Investment); or

	•		investment in power assets.

TVA must next meet this test for the five-year period ending on September 30, 2010.

Tritium-Related Services. In December 1999, TVA and DOE entered into a long-term interagency agreement under which TVA will utilize Watts Bar and Sequoyah Nuclear Plants to irradiate tritium-producing burnable absorber rods to assist DOE in producing tritium, which is used in nuclear weapons. 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 entire operating cycle in which the tritium-producing rods are irradiated.

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In September 2002, the NRC issued amendments to the operating licenses for the Watts Bar and Sequoyah Nuclear Plants, allowing TVA to provide irradiation services for the DOE at these plants. The Watts Bar license amendment currently permits TVA to install up to 240 tritium-producing rods in the Watts Bar Unit 1. Planned future license amendments would allow TVA to irradiate up to approximately 2,000 tritium-producing rods in the Watts Bar reactor.

In general, tritium-producing rods are irradiated for a full 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 the 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.

TVA began irradiating tritium-producing rods at Watts Bar Unit 1 in the fall of 2003. TVA removed these rods from the reactor in the spring of 2005. DOE subsequently successfully shipped them to its tritium-extraction facility. At this time, no tritium-related services have been scheduled at the Sequoyah Nuclear Plant.

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 $300 million of nuclear liability insurance from American Nuclear Insurers (“ANI”) for each plant with an operating license. The second layer, the Secondary Financial Program (“SFP”), would come from an assessment of up to $101 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 $15 million per year per reactor. ANI, under a contract with the NRC, administers the SFP. With its six licensed units, TVA could be required to pay a maximum of $604 million per nuclear incident, but it would have to pay no more than $90 million per incident in any one year. When the contributions of the nuclear plant licensees are added to the insurance proceeds of $300 million, over $10.7 billion would be available. Under the Price-Anderson Act, if the first two layers are exhausted, Congress is required to take action to provide additional funds to cover the additional losses.

TVA carries property, decommissioning, and decontamination insurance of $4.2 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 may require the payment of retrospective premiums up to a maximum of approximately $64 million.

TVA purchases accidental outage (business interruption) insurance for TVA’s nuclear sites from Nuclear Electric Insurance Limited (“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 $23 million.

Decommissioning Costs. 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.

TVA recognizes as incurred all obligations related to closure and removal of its nuclear units. The liability for closure is measured as the present value of the weighted estimated cash flows required to satisfy the related obligation and discounted at the credit adjusted rate of interest in effect at the time the liability was actually incurred or originally accrued, and subsequently modified to comply with the prevailing accounting provisions. The charge to recognize the additional obligation is effected by adjusting the corresponding regulatory asset. Earnings from decommissioning fund investments, amortization expense of the decommissioning regulatory asset, and interest expense on the decommissioning liability are deferred in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” At September 30, 2006, the present value of the estimated future decommissioning cost of $1.5 billion was included in Asset Retirement Obligations, and the unamortized regulatory asset of $474 million was included in Other Regulatory Assets. This decommissioning cost estimate is based on amounts prescribed by the NRC 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, among other things, changes in 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 SFAS No. 143 than those that are used in calculating nuclear decommissioning costs when reporting to the NRC. Accordingly, the two sets of procedures produce different estimates for the costs of decommissioning. See Note 4.

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TVA maintains a nuclear decommissioning trust to provide money for the ultimate decommissioning of its nuclear power plants. The fund is invested in securities generally designed to achieve a return in line with overall equity market performance. The assets of the fund are invested in debt and equity securities and certain derivative instruments. These derivative instruments are used across various asset classes to achieve a desired investment structure and are comprised of 2,343 contracts. These contracts include futures, options on futures, and swap agreements. Investments held in the decommissioning fund are stated at fair value, which is determined by the Trustee of the fund. Futures and options on futures positions are marked to market on a daily basis. The swap agreements are marked to market on a monthly basis. The assets of the fund as of September 30, 2006, totaled $937 million including total gains of $101 million of which a loss of $24 million was unrealized. The assets of the fund as of September 30, 2005, totaled $835 million including total gains of $115 million of which $48 million was unrealized. The balance as of September 30, 2006 is greater than the present value of the estimated future nuclear decommissioning costs. TVA monitors the monetary value of its nuclear decommissioning trust 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 the units with approval from the NRC.

On May 3, 2006, the NRC approved TVA’s application for license extension at each of TVA’s three Browns Ferry units. As a result of the NRC’s action, each unit’s license has been extended 20 years. The license extension has the effect of improving the funded status of TVA’s nuclear decommissioning trust versus the present value of the estimated decommissioning costs by (1) extending the decommissioning dates of the three Browns Ferry units and thereby pushing the decommissioning liability for these units further into the future and (2) extending the investment horizon for the assets in the trust. This had the effect of reducing the present value of the estimated future decommissioning costs by approximately $500 million. Because of the improved funded status of the trust due to the license extensions, the $25 million TVA contribution budgeted for 2006 was not made.

Environmental Matters. TVA’s activities are subject to certain federal, state, and local environmental statutes 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. Some of the more comprehensive requirements which TVA is required to comply include:

	•		The Clean Air Act (“CAA”) and the Clean Air Interstate Rule (“CAIR”) and Clean Air Mercury Rule (“CAMR”)

	•		The Clean Water Act and regulations under Sections 316a and 316b

	•		The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”)

TVA has incurred and continues to incur substantial capital and operating and maintenance costs in order to comply with evolving environmental requirements. Many of these costs are associated with the operation of TVA’s 59 coal-fired generating units. While it is not possible to predict how these evolving requirements will impact the operation of existing and new coal-fired and other fossil-fuel generating units, it is virtually certain that environmental requirements placed on the operation of these generating units will continue to become more restrictive. Litigation over emissions from coal-fired generating units is also occurring, including litigation against TVA. See Legal Proceedings below.

The total cost of compliance with future clean air regulations beyond CAIR and CAMR cannot reasonably be determined at this time because of the unknowns and uncertainties surrounding emerging EPA regulations, resultant compliance strategies, the potential for the development of new emission control technologies, litigation, and future amendments to the Clean Air Act. However, TVA does estimate that spending on emission controls for CAIR and CAMR into the next decade could cost between $3.0 billion to $3.5 billion. There could be other substantial costs if reductions of carbon dioxide are mandated. Predicting how and when carbon dioxide may be regulated is very difficult, even more so than the future regulation of other substances. TVA will continue to monitor this issue and will assess and respond to potential financial impacts as they become more certain.

TVA’s total cost related to emission reduction regulatory programs for sulfur dioxide, nitrogen oxide, and particulates from 1977 through 2010 is expected to reach $5.8 billion, $4.6 billion of which had already been spent as of September 30, 2006. (The cost estimates for complying with CAIR and CAMR, above, are in addition to these costs.) Increasingly stringent regulation of some or all of these substances will continue to result in significant capital and operating costs for coal-fired generating units, including those operated by TVA.

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years. TVA operations at some TVA-owned facilities have resulted in releases of hazardous substances and/or oil which require cleanup and/or remediation. TVA also is aware of alleged hazardous-substance releases at 10 non-TVA areas for which it may have some liability. TVA has reached agreements with EPA to settle its liability at two of the non-TVA areas for a total of less than $0.1 million. There have been no recent assertions of TVA liability for six of the non-TVA areas, and (depending on the site) there is little or no known evidence that TVA contributed any significant quantity of hazardous substances to these six sites. There is evidence that TVA sent materials to the remaining two non-TVA areas. The information necessary to estimate the total cleanup costs, and most of the evidence that might be used to estimate TVA’s allocated share of such costs and evaluate the likely effectiveness of TVA’s potential defenses either have not been developed and/or are under the control of parties other than TVA. Consequently, TVA is unable at this time to estimate its liability related to these sites.

Legal Proceedings

TVA is subject to various legal proceedings and claims that have arisen in the ordinary course of business. These proceedings and claims include the matters discussed below.

Economy Surplus Power Case

On August 31, 1999, suit was filed against TVA in the United States District Court for the Northern District of Alabama by Birmingham Steel Corporation, on behalf of itself and a class of TVA industrial customers who contracted for economy surplus power. While Birmingham Steel Corporation was the original class representative, it filed for bankruptcy and was excluded from the class. Johns Manville Corporation was substituted as the class representative. The lawsuit alleges that TVA overcharged for economy surplus power during the summer of 1998 by improperly including some incremental costs when calculating the price of economy surplus power. The class members seek over $100 million in damages. On April 18, 2006, the district court ruled on motions for summary judgment filed by both sides. The court held that TVA improperly included charges for approximately 500 hours of power purchased in advance and breached the contracts. The court rejected TVA’s position that the additional price charged for all hours represented actual incremental costs incurred by TVA in supplying economy surplus power and thus was an appropriate part of the economy surplus power contract price. The court granted the plaintiffs’ motion for summary judgment on liability, even though it acknowledged that there are disputed factual issues as to TVA’s defenses. TVA filed a motion seeking permission to take an interlocutory appeal of the court’s ruling on summary judgment. On July 31, 2006, the district court reconsidered its decision on summary judgment with respect to TVA’s affirmative defenses and held that TVA is entitled to a trial on its affirmative defenses. A mediator has been selected and the parties anticipate engaging in mediation in December 2006. Trial on TVA’s affirmative defenses and the class members’ damages is scheduled for February 5, 2007.

Case Against TVA and 22 Electric Cooperatives

On December 2, 2004, the United States District Court for the Middle District of Tennessee, dismissed a lawsuit filed by John McCarthy, Stan Cooper, Joe Sliger, Mike Bell, Don Rackley, Terry Motley, Billy Borchert, Jim Foster, and Ryan Hargis on behalf of themselves and all others similarly situated against TVA and the Middle Tennessee Electric Membership Cooperative, Appalachian Electric Cooperative, Caney Fork Electric Cooperative, Inc., Chickasaw Electric Cooperative, Cumberland Electric Membership Corporation, Duck River Electric Membership Corporation, Fayetteville Public Utilities, Forked Deer Electric Cooperative, Inc., Fort Loudoun Electric Cooperative, Gibson Electric Membership Corporation, Holston Electric Cooperative, Inc., Meriwether Lewis Electric Cooperative, Mountain Electric Cooperative, Inc., Pickwick Electric Cooperative, Plateau Electric Cooperative, Powell Valley Electric Cooperative, Sequachee Valley Electric Cooperative, Southwest Tennessee Electric Membership Corporation, Tennessee Valley Electric Cooperative, Tri-County Electric Membership Cooperation, Tri-State Electric Membership Cooperation, Upper Cumberland Electric Membership Corporation, and Volunteer Energy Cooperative. The lawsuit in part challenged TVA’s practice of setting rates for electric power charged by distributor customers through TVA’s contracts with distributor customers. In granting the defendants’ motions to dismiss, the court held that the claims alleging violations of state law failed because the plaintiffs (consisting of Tennessee residents and customers of certain of the cooperatives) had not completed the steps necessary to bring these claims in court. With respect to the claim against TVA, the court held that the alleged violations of federal law failed as a matter of law because Congress had specifically authorized TVA to set the rates charged by distributor customers through TVA’s contracts with distributor customers. The plaintiffs appealed to the United States Court of Appeals for the Sixth Circuit (“Sixth Circuit”), and on October 17, 2006, the Sixth Circuit affirmed the district court’s decision, and held, among other things, that TVA’s rates were not subject to judicial review and that TVA is not subject to antitrust liability when doing so would interfere with TVA’s purposes.

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Global Warming Cases

Case Involving Modifications to the Colbert Fossil Plant

The National Parks Conservation Association, Inc. (“NPCA”), and Sierra Club, Inc. (“Sierra Club”), filed suit on February 13, 2001, in the United States District Court for the Northern District of Alabama, alleging that TVA violated the Clean Air Act and implementing regulations at TVA’s Colbert Fossil Plant (“Colbert”), a coal-fired electric generating facility located in Tuscumbia, Alabama. The plaintiffs allege that TVA made major modifications to one of the power generating units, specifically Colbert Unit 5, without obtaining preconstruction permits (in alleged violation of the Prevention of Significant Deterioration (“PSD”) program and the Nonattainment New Source Review (“NNSR”) program) and without complying with emission standards (in alleged violation of the New Source Performance Standards (“NSPS”) program). The plaintiffs seek injunctive relief; civil penalties of $25,000 per day for each violation on or before January 30, 1997, and $27,500 per day for each violation after that date; an order that TVA pay up to $100,000 for beneficial mitigation projects; and costs of litigation, including attorney and expert witness fees. On November 29, 2005, the district court held that sovereign immunity precluded the plaintiffs from recovering civil penalties against TVA. On January 17, 2006, the district court dismissed the action, on the basis that plaintiffs failed to provide adequate notice of NSPS claims and that the statute of limitations curtailed the PSD and NNSR claims. The plaintiffs appealed to the United States Court of Appeals for the Eleventh Circuit (“Eleventh Circuit”) on January 25, 2006. Briefing of the appeal to the Eleventh Circuit was completed in July 2006. Oral argument of the appeal is scheduled for January 11, 2007. If the decision is reversed on appeal, there is a reasonable possibility that TVA will be ordered to install additional controls on Colbert Unit 5.

Case Involving Modifications to Bull Run Fossil Plant

Case Involving Opacity at Colbert

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interlocutory appeal, and on July 5, 2006, the district court denied plaintiffs’ motion. The parties participated in mediation on September 7, 2006, and for several weeks thereafter. The case remains stayed.

Case Brought by North Carolina Alleging Public Nuisance

On January 30, 2006, North Carolina’s Attorney General 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 constitute public nuisances. On April 3, 2006, TVA moved to dismiss the suit on grounds that the case is not suitable for judicial resolution because of separation of powers principles, including the fact that these matters are based on policy decisions left to TVA’s discretion in its capacity as a government agency and thus are not subject to tort liability (the “discretionary function doctrine”), as well as the Supremacy Clause. In July 2006, the district court denied TVA’s motion, and set the trial for the term of court beginning October 2007. On August 4, 2006, TVA filed a motion requesting permission to file an interlocutory appeal with the United States Court of Appeals for the Fourth Circuit (the “Fourth Circuit”) which the district court granted on September 7, 2006. On September 21, 2006, TVA petitioned the Fourth Circuit to allow the interlocutory appeal. The Fourth Circuit has granted the petition and set a briefing schedule, with briefing to be completed in January 2007. The district court did not stay the case during this appeal, and trial remains scheduled for October 2007.

Case Involving North Carolina’s Petition to the EPA

Case Arising out of Hurricane Katrina

Claim Involving Areva Fuel Fabrication

Notification of Potential Liability for Ward Transformer Site

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14. 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. Although TVA’s Bonds are not guaranteed by the federal government, they are included in the federal budget. TVA’s Bonds are supported solely by the net power proceeds of the TVA power system.

TVA currently receives no appropriations from Congress and funds its business using internally generated power system revenues, power financings, and other revenues. TVA is a source of cash to the federal government. Until TVA meets its remaining obligation to pay $150 million, of the government’s Appropriation Investment under the self-financing amendment to the TVA Act, TVA will continue to repay a portion of the government’s investment in the TVA power system. TVA will also continue to pay a return on the outstanding balance of this investment indefinitely. See Note 7 — Appropriation Investment. 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
	2006		2005		2004

Sales of electricity services	$	181	$	168	$	153
Other revenues		24		15		16
Other expenses		226		222		202
Receivables at September 30		21		26		18
Payables at September 30		123		131		203
Return on appropriation investment (Note 7)		18		16		18
Repayment of appropriation investment (Note 7)		20		20		20

15. Unaudited Consolidated Quarterly Financial Information

A summary of the unaudited quarterly results of operations for the years 2006 and 2005 follows. It 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.


	2006
(in millions)	First			Second		Third		Fourth			Total

Operating revenues	$	2,052		$	2,048	$	2,250	$	2,835		$	9,185
Operating expenses		1,827			1,766		1,874		2,115			7,582
Operating income		225			282		376		720			1,603
Income before cumulative effect of accounting changes		(53	)		14		162		315			438
Cumulative effect of accounting changes		—			—		—		(109	)		(109	)
Net (loss)/income	$	(53	)	$	14	$	162	$	206		$	329

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Unaudited Consolidated Quarterly Financial Information


	2005
(in millions)	First		Second			Third			Fourth		Total

Operating revenues	$	1,834	$	1,839		$	1,881		$	2,240	$	7,794
Operating expenses		1,435		1,562			1,553			1,953		6,503
Operating income		399		277			328			287		1,291
Net income (loss)	$	90	$	(24	)	$	(15	)	$	34	$	85

16. Subsequent Events

Debt Securities

In October 2006, TVA issued $9 million of electronotes^® with an interest rate of 5.5 percent which mature in 2027 and are callable in 2011.

New Generation

The TVA Board, during its October 13, 2006, meeting, authorized the acquisition of a 742 megawatt winter peaking capacity, dual-fuel, combustion turbine electric generating facility and certain related transmission facilities from KGen Marshall County LLC, located in Marshall County, Kentucky.

In November 2006, the TVA Board approved the acquisition of a natural gas-fired combustion turbine facility located in Weakley County, Tennessee, from Allegheny Energy Supply Gleason Generating Facility, LLC. This facility can produce 555 megawatts of winter peaking capacity.

Revolving Credit Facility Agreement

In November 2006, TVA renewed the credit facility with the November 12, 2006, maturity date. The new maturity date for this credit facility is November 11, 2007. The terms are similar to those in the credit facility maturing on May 16, 2007.

Customers

On December 7, 2006, Warren Rural Electric Cooperative Corporation announced its intention to withdraw its notice to terminate its existing power contract with TVA.

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Report of Independent Registered Public Accounting Firm

To the Board of Directors of the Tennessee Valley Authority:

In our opinion, the accompanying balance sheets and the related statements of income, of changes in proprietary capital and of cash flows present fairly, in all material respects, the financial position of Tennessee Valley Authority at September 30, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended September 30, 2006 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule appearing under Item15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements 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 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in note 1 to the financial statements, effective September 30, 2006, Tennessee Valley Authority adopted Financial Accounting Standards Board Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations—an Interpretation of FASB Statement No. 143.

PricewaterhouseCoopers LLP
Knoxville, Tennessee
December 14, 2006

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

During 2006, there were no changes in or disagreements with TVA’s independent auditors on accounting matters or financial disclosure.

ITEM 9A. CONTROLS AND PROCEDURES

TVA maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in reports it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized, and reported within the time periods specified in Securities and Exchange Commission rules and forms including controls and procedures designed to ensure that such information is accumulated and communicated to TVA management, including the President and Chief Executive Officer, the Disclosure Control Committee, and the Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

An evaluation has been performed under the supervision of TVA management (including the President and Chief Executive Officer, Tom D. Kilgore, who served as Acting President and Chief Executive Officer from March 31, 2006, until October 13, 2006, when he became President and Chief Executive Officer) and members of the Disclosure Control Committee (including the Interim Chief Financial Officer and the Vice President and Controller) of the effectiveness of TVA’s disclosure controls and procedures as of September 30, 2006. Based on that evaluation, the President and Chief Executive Officer and members of the Disclosure Control Committee (including the Interim Chief Financial Officer and the Vice President and Controller) concluded that, as a result of two material weaknesses identified (described below), TVA’s disclosure controls and procedures were not effective as of September 30, 2006. However, to assess the financial statement impact of these internal control deficiencies, TVA performed additional analyses, interim supplemental procedures, and monitoring activities subsequent to year end. As a result of these supplemental procedures, the President and Chief Executive Officer, the Interim Chief Financial Officer, and the Vice President and Controller have determined that there is reasonable assurance that the financial statements included in this Annual Report fairly present, in all material respects, TVA’s financial condition, results of operations, and cash flows as of, and for, the periods presented.

TVA management has identified a material weakness in internal controls related to TVA’s end use billing arrangements with wholesale power customers. Under these arrangements, TVA relies on the distributor customers to calculate major components of their own power bills. TVA requested annual Statement on Auditing Standards (“SAS”) 70 Type II internal control reports on 12 specific control objectives from distributor customers and their third party billing processors. Based on the evaluation of these SAS 70 Type II reports, TVA determined that distributor customers who represent a material amount of TVA’s 2006 revenue either had qualified opinions and/or internal control test results that negatively impact their ability to meet TVA’s control objectives. However, subsequent to year end TVA has also performed additional revenue analysis by comparing various metrics from billing data for distributor customers with similar characteristics and benchmarking those with control weaknesses against those with strong controls. As a result of this analysis, TVA has determined that reported revenues are not materially misstated.

TVA management has also identified a material weakness related to controls over the completeness, accuracy, and authorization of TVA’s property, plant, and equipment transactions and balances; the calculation of the allowance for funds used during construction (“AFUDC”); and the review of construction work-in-progress (“CWIP”) accounts for proper closure to completed plant. To remediate this control weakness, TVA has developed a new process for project approval to include the determination of proper project cost classification and has made changes in staffing for fixed asset accounting. TVA is also formalizing the accounting review of account balances and transactions and improving the documentation of management review and approval. TVA has completed a full review of the 2006 CWIP accounts in question and has taken corrective action to ensure the accurate disposition of the costs. Additional analysis has also been performed to ensure that property, plant, and equipment is not materially misstated.

During the most recent fiscal quarter, there were 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. These changes are described in the preceding two paragraphs.

TVA management believes that a control system, no matter how well designed and operated, cannot provide absolute assurance that the objectives of the control system are met, and no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a company can be detected. TVA’s controls and procedures can provide reasonable, but not absolute, assurance that the objectives will be met. It

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should be noted that the design of any system of 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.

ITEM 9B. OTHER INFORMATION

Not applicable.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Directors

Prior to March 31, 2006, TVA was administered by a full-time board of three persons appointed by the President of the United States with the advice and consent of the Senate, although there were only two Board members in office during almost the entire first six months of 2006.

The Consolidated Appropriations Act, 2005 included provisions that resulted in the restructuring of the TVA Board and the appointment of a Chief Executive Officer. The legislation restructured the TVA Board by increasing the number of directors from three full-time members to nine part-time members. As with the previous TVA Board structure, members are appointed by the President with the advice and consent of the Senate. Following a transition period, members will serve five-year terms. The Chairman of the TVA Board is selected by the members of the TVA Board.

On March 31, 2006, six new directors were sworn in, joining William W. Baxter and Skila S. Harris as members of the TVA Board. The six new directors are: William B. Sansom, elected to serve as Chairman, Dennis C. Bottorff, Donald R. DePriest, Robert M. Duncan, Howard A. Thrailkill, and Susan Richardson Williams. A ninth director, Bishop William Graves, was sworn in as a director of TVA on October 10, 2006.

The TVA Board at December 15, 2006, consisted of the following individuals with their ages and terms of office provided:


Directors	Age		Year Appointed		Year Term Expires

William B. Sansom, Chairman		65		2006		2009
Bishop William Graves		70		2006		2007
Susan Richardson Williams		61		2006		2007
Skila S. Harris		56		1999		2008
Donald R. DePriest		67		2006		2009
Howard A. Thrailkill		67		2006		2010
William W. Baxter		53		2001		2011
Dennis C. Bottorff		62		2006		2011
Robert M. Duncan		55		2006		2011

Mr. Sansom of Knoxville, Tennessee, joined the TVA Board in March 2006 and was elected Chairman by the TVA Board in March 2006. He is Chairman and Chief Executive Officer of The H.T. Hackney Co., a diversified company involved in wholesale grocery, gas and oil, and furniture manufacturing, 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 a director of Mid-America Apartment Communities, Inc. From 1994 to 2006, he was a director of Martin Marietta Materials, Inc., a company based in Raleigh, North Carolina, that supplies minerals, chemicals, and composites for various industries.

Bishop Graves of Memphis, Tennessee, joined the TVA Board in October 2006. He is presiding Bishop of the Christian Methodist Episcopal Church in Memphis, Tennessee. Previously, he was pastor of the Phillips Temple CME Church of Los Angeles, California. He is the immediate Past President of the Board of the National Congress of Black Churches, and from September 1993 to July 2004 Bishop Graves was a member of the Board of Memphis Light, Gas and Water, a TVA distributor customer.

Ms. Williams of Knoxville, Tennessee, joined the TVA Board in March 2006. Since June 2004, she has been the owner of Susan Williams Public Affairs in Knoxville, Tennessee, and is affiliated with SRW & Associates, where, along with five other independent contractors involved with SRW & Associates, she provides public relations consulting services for various clients. From 1999 to 2004, she managed the Knoxville, Tennessee, office of the Ingram Group, a statewide public-relations firm. In addition, Ms. Williams serves on the Board of Trustees of the University of Tennessee.

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Ms. Harris joined the TVA Board in November 1999. Prior to her current position, she served at the Department of Energy as Executive Director of the Secretary of Energy Advisory Board. From 1993 until 1997, she was a Special Assistant to Vice President Gore and Mrs. Gore’s Chief of Staff.

Mr. DePriest of Columbus, Mississippi, joined the TVA Board in March 2006. He is President of MCT Investors L.P, an Alexandria, Virginia, venture capital firm that he founded in 1987 and that develops telecommunications and healthcare ventures. He has founded other companies, including Boundary Healthcare Products Corporation in 1987, where he served as Chairman until 1992. He also founded Charisma Communications Corporation in 1982, a telecommunications company, where he served as Chairman and President.

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, which supplies equipment for telecommunications service providers and corporate end-users. He joined Adtran, Inc., in 1992.

Mr. Baxter of Knoxville, Tennessee, joined the TVA Board in November 2001. Prior to joining the TVA Board, Mr. Baxter was Chairman and Chief Executive Officer of Holston Gases Inc. of Knoxville, Tennessee, a company that sells propane and other types of gas. Mr. Baxter joined Holston Gases, Inc., in 1981. On April 1, 2006, Mr. Baxter was reappointed as Chairman of Holston Gases, Inc.

Mr. Bottorff of Nashville, Tennessee, joined the TVA Board in March 2006. Since January 2001, he has served as Chairman and 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 has served since 1998 as a director of Dollar General, a variety store company. In addition, he is a director of Ingram Industries, a privately held provider of wholesale distribution, inland marine transportation, and insurance services; a director of AppForge, a privately held developer of multi-platform mobile and wireless application solutions; a director of Lancope, Inc., a privately held developer of behavioral-based intrusion detection systems for network security; and a member of the Board of Trustees of Vanderbilt University.

Mr. Duncan of Inez, Kentucky, joined the TVA Board in March 2006. 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); and General Counsel of the Republican National Committee (since July 2002). Since 1998, Mr. Duncan has also been 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 Prestonburg, Kentucky, which manages a regional hospital.

Executive Officers

TVA’s executive officers as of December 15, 2006, their titles, their ages, and the date their employment commenced are as follows:

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				Employment
Executive Officers	Title	Age		Commenced

Tom D. Kilgore	President and Chief Executive Officer		58		2005
John M. Hoskins	Interim Chief Financial Officer & Executive Vice President, Financial Services		51		1978
William S. Orser	Interim Chief Operating Officer		62		2006
Maureen H. Dunn	Executive Vice President and General Counsel		57		1978
John E. Long, Jr.	Chief Administrative Officer and Executive Vice President, Administrative Services		54		1980
Kenneth R. Breeden	Executive Vice President, Customer Resources		58		2004
Terry Boston	Executive Vice President, Power System Operations		56		1972
Karl Singer	Chief Nuclear Officer and Executive Vice President, TVA Nuclear		50		1993
Kathryn Jackson	Executive Vice President, River System Operations and Environment and the Environmental Executive		49		1991
Joseph Bynum	Executive Vice President, Fossil Power Group		59		1972
Ashok S. Bhatnagar	Senior Vice President, Nuclear Operations		50		1999
Peyton T. Hairston, Jr.	Senior Vice President, Communications		51		1993
Janet C. Herrin	Senior Vice President, River Operations		52		1978
Preston Swafford	Senior Vice President, Nuclear Support		46		2006
Tammy W. Wilson	Interim Senior Vice President and Treasurer		38		1990
Edwin E. Freeman	Vice President, Fossil Operations		47		1994
Randy Trusley	Vice President and Controller		50		1978

Mr. Kilgore was named President and 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 (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. Hoskins, Interim Chief Financial Officer & Executive Vice President, Financial Services, joined TVA in 1978 and worked in several areas of TVA business including accounting, audit, and revenue before joining the Treasurer’s office in 1987. He was named Vice President and Treasurer in 1994, Senior Vice President and Treasurer in 2000, and Interim Chief Financial Officer and Executive Vice President, Financial Services in November 2006 following the departure of Michael E. Rescoe from TVA. He has also served on the TVA Retirement System Board of Directors since 2003.

Mr. Orser was named Interim Chief Operating Officer in September 2006. Mr. Orser retired in 2005 as President, Energy Supply Group for Progress Energy, a position he had held since 2000. He was Senior Vice President of Nuclear Generation for Detroit Edison Company from December 1989 to April 1993. He also held management positions with Portland General Electric from 1979 to 1986 and with Southern California Edison from 1986 to 1993.

Ms. Dunn joined TVA as an attorney in May 1978, assumed the position of Assistant General Counsel in September 1986, and assumed the position of Executive Vice President and General Counsel in January 2001.

Mr. Long was named Executive Vice President, Administrative Services in September 2005. From October 2000 to September 2005 he was Executive Vice President, Human Resources. Mr. Long joined TVA in 1980 as a Personnel Officer in the Engineering Division and has held various human resource positions with TVA. From 1992 to 2005 he served on the TVA Retirement System Board.

Mr. Breeden was named Executive Vice President, Customer Resources in September 2006 and joined TVA as Executive Vice President, Customer Service and Marketing in August 2004. From 1995 to 2004, he was President of TXU Energy Services, Enterprise Division, in Dallas, Texas, where he was responsible for sales, marketing, delivery and operations, finance, strategic planning, regulatory affairs, supply, and all administrative

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functions. Mr. Breeden had joined TXU Corporation in 1995 as Senior Vice President of TXU Electric & Gas, where he was responsible for marketing and sales.

Mr. Boston is Executive Vice President, Power System Operations, a position he has held since May 1999. He joined TVA as a Power Supply Engineer in 1972 and held various technical and managerial positions until becoming Division Manager of Electric System Reliability in May 1991. In December 1996, he was named Senior Manager, Pricing and held that position until April 1999. Mr. Boston serves as Vice President of CIGRE-U.S., the International Council on Large Electric Systems, and as a member of the Board of Directors/Stakeholders of the North American Electric Reliability Council, and as Vice President of the Consortium of Electric Reliability Technology Solutions.

Mr. Singer was named Chief Nuclear Officer and Executive Vice President, TVA Nuclear, in June 2004. Mr. Singer joined TVA in March 1993 as Plant Project Engineer at Browns Ferry Nuclear Plant (“Browns Ferry”). He became the TVA Nuclear Process Improvement and Total Quality Manager in December 1994, Browns Ferry Maintenance and Modifications Manager in August 1996, Browns Ferry Plant Manager in June 1997, and Browns Ferry Site Vice President in September 1998. In June 1999, he was named Senior Vice President, Nuclear Operations.

Ms. Jackson has been the Executive Vice President, River System Operations and Environment since 1998 and the Environmental Executive at TVA since 1999. She joined TVA in June 1991 as a Project Engineer in TVA Nuclear. She subsequently served as Vice President of Technical Applications, Resource Group from January 1993 to September 1994, as Senior Vice President, Resource Group from 1994 to 1996, and as Executive Vice President, Resource Group from 1996 to 1998.

Mr. Bynum is Executive Vice President, Fossil Power Group, a position he has held since August 2000. He previously served as Executive Vice President, Fossil and Hydro Power from August 1998 to August 2000, as Vice President, Fossil Operations from July 1998 to August 1998, and as Vice President, Fossil Power Group from May 1993 to July 1998. He joined TVA in 1972 as a Start-up Engineer at Browns Ferry. Mr. Bynum served a three-year term as Chairman of the Electric Power Research Institute Generation Council and was a member of the National Coal Council.

Mr. Bhatnagar was named Senior Vice President, Nuclear Operations, in June 2004. He joined TVA in August 1999 as Site Support Manager at Browns Ferry, and became Browns Ferry Plant Manager in July 2000, and Site Vice President in July 2001.

Mr. Hairston was named Senior Vice President, Communications, in March 2006. From October 2002 to March 2006, he held the position of Senior Vice President, Employee Relations and Diversity. Mr. Hairston served as Senior Vice President, Labor Relations, from October 2000 to October 2002, and had held that position previously from June 1994 to June 1998. From August 1998 to October 2000, he was Senior Vice President, Strategic Initiatives. Mr. Hairston also served as Senior Manager, Strategic Planning and Support from May 1993 to June 1994.

Ms. Herrin is the Senior Vice President, River Operations, a position she has held since February 1999. Ms. Herrin is responsible for establishing river operations policies, procedures, and standards for TVA and serves as TVA’s Dam Safety Officer. She began her career at TVA in 1978 as a Civil Engineer. She has also served on the TVA Retirement System Board since 2005.

Mr. Swafford joined TVA in May 2006 as Senior Vice President, Nuclear Support. From December 1995 to April 2006, Mr. Swafford held various positions at Exelon Corporation, an energy company, 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.

Ms. Wilson joined TVA in September 1990 as an accountant in TVA’s nuclear business office and has held a variety of financial positions, including Supervisor of Revenue Billing. In January 1995, she joined the Treasurer’s office and was subsequently named Senior Manager in July 2001. As Senior Manager, she was responsible for management of TVA’s short-term and long-term financing programs, investments, investor relations, and TVA’s nuclear decommissioning trust. She was named Interim Senior Vice President and Treasurer in November 2006.

Mr. Freeman is Vice President, Fossil Operations, a position he has held since July 2005. From July 2003 to July 2005, Mr. Freeman worked as Site General Manager for Cumberland Fossil Plant. From 1991 to 2003, he

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worked in several positions in TVA Nuclear, including Operations Manager and Maintenance and Modifications Manager at Sequoyah Nuclear Plant and Maintenance Engineering Supervisor at Watts Bar Nuclear Plant.

Mr. Trusley is TVA’s Vice President and Controller, a position he has held since January 2001. He joined TVA in October 1978 as an auditor and was budget officer from July 1981 until March 1984, at which time he briefly left TVA. He returned to TVA in January 1988 as a financial analyst, and he held the positions of Accounting Manager from April 1989 to September 1994 and Business Manager from October 1994 to December 2001.

Code of Ethics

TVA has a Disclosure and Financial Ethics Code (“Ethics Code”) that applies to all executive officers and directors of TVA as well as to all employees who certify information contained in quarterly reports, annual reports, or information statements or who have responsibility for internal control self-assessments. The 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 Ethics Code. The Ethics Code is posted on TVA’s website at: www.tva.gov. TVA will provide a current copy of the 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 Ethics Code 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

TVA does not have a Nominating Committee. Each member of the TVA Board is appointed by the President of the United States by and with the advice and consent of the U.S. Senate. To be eligible to be appointed as a member of the TVA Board, an individual must (1) be a citizen of the United States, (2) have management expertise relative to a large for-profit or nonprofit corporate, government, or academic structure, (3) not be an employee of TVA, (4) make full disclosure to Congress of any investment or other financial interest that the individual holds in the energy industry, and (5) affirm support for the objectives and missions of TVA, including being a national leader in technological innovation, low-cost power, and environmental stewardship. At least seven of the Board members must be legal residents of TVA’s service area.

TVA has an Audit and Ethics Committee established in accordance with the TVA Act. TVA’s Audit and Ethics Committee consists of Robert M. Duncan, its chair, Susan Richardson Williams, and Donald R. DePriest. None of the members of the Audit and Ethics Committee has been determined to be an “audit committee financial expert” under applicable SEC rules, as none of the appointed TVA Board members was required by the TVA Act to meet the criteria of an “audit committee financial expert” under applicable SEC rules.

TVA is exempted by section 37 of the Securities Exchange Act from complying with section 10A(m)(3) of the Securities 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. Notwithstanding this exemption, the TVA Act contains certain provisions that are similar to the considerations for independence under section 10A(m)(3) of the Securities 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. These provisions became applicable to the TVA Board members on March 31, 2006.

Under section 10A(m)(2) of the Securities 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.

On May 18, 2006, the TVA Board approved the establishment of the following committees in addition to the Audit and Ethics Committee:

•		Human Resources Committee

•		Corporate Governance Committee

•		Finance, Strategy and Rates Committee

•		Operations, Environment and Safety Committee

•		Community Relations 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 2006 in establishing the level and nature of the compensation provided to the President and Chief Executive Officer (“CEO”), the Chief Financial Officer and Executive Vice President, Financial Services (“CFO”), and the three most highly compensated executive officers other than the CEO and CFO. References to the “Named Executive Officers” throughout this section refer to the executive officers listed in the Summary Compensation Table.

Authority for the Executive Compensation Program

The TVA Act is the primary statutory authority for TVA’s compensation program and places responsibility for establishing the compensation of all TVA employees, including the Named Executive Officers, with the TVA Board. Under section 3 of the TVA Act, the TVA Board had the authority in 2006 to fix the compensation of TVA employees without regard to the civil service laws applicable to other federal employees. This authority has been substantially reinforced by the amendments to the TVA Act contained in the Consolidated Appropriations Act, 2005 (the “Consolidated Appropriations Act”), which became effective on March 31, 2006. These amendments, among other things, removed the statutory cap on the salaries of TVA employees and authorized the TVA Board to establish a compensation plan for all TVA employees based on surveys of the prevailing compensation for similar positions, including those in private industry. A compensation plan for all TVA employees, including the Named Executive Officers and other executives, was approved by the TVA Board at its May 31, 2007 meeting.

Notwithstanding section 3 of the TVA Act and the amendments to the TVA Act contained in the Consolidated Appropriations Act, there are limits on the TVA Board’s authority to set compensation for its employees. One limit is TVA’s statutory obligation to sell power at rates as low as feasible. Implicit in this obligation is the requirement that TVA operate its power system as efficiently and economically as possible, including limiting total compensation for senior executives to that required to recruit, retain, and motivate them. However, providing inadequate compensation levels to such executives could adversely affect TVA’s efficiency and economy to an even greater extent. A second limitation exists as a result of TVA’s capital structure. The United States government is TVA’s sole owner. As a result, TVA does not have equity securities and has no equity-based compensation. Accordingly, TVA is not able to provide some of the types of compensation that many companies typically offer their named executive officers.

Objective of the Executive Compensation Program

Under authority given to it by section 3 of the TVA Act, the previous TVA Board established a compensation program, applicable to compensation paid in 2006, for TVA similar to compensation programs of private sector companies, including companies in the energy services industry. This compensation program is consistent with the requirements of the TVA Act and TVA’s statutory mission and objectives and at the same time addresses the needs of TVA to recruit and retain top talent. This program is designed to fulfill the following purposes:

•		Provide a competitive level of compensation that enables TVA to attract, retain, and motivate highly competent employees. Each position in TVA has a pay level determined by market pricing based on a level needed to attract, retain, and motivate employees critical to TVA’s success in achieving its mission. Overall compensation levels are targeted at the median (50^th percentile) of the relevant labor market for most positions. However, for positions affected by market scarcity, recruitment and retention issues, and other business reasons, overall compensation levels are targeted above the median (typically between the 50^th and 75^th percentile). Certain nuclear and transmission positions, for example, are targeted to higher overall compensation levels because of these factors. Information about TVA’s peer group and benchmarking practices is provided below under the heading “Use of Market Data and Benchmarking.”

•		Encourage and reward senior executives for their performance and contributions to the successful achievement of financial and operational goals. Approximately 40 to 50 percent of overall compensation for senior executives is performance-based compensation. “At risk” incentive pay is directly linked to the achievement of performance goals at the TVA level and the business unit level. In 2006, the TVA Board approved the TVA level performance goals and delegated authority to approve the business level performance goals to its CEO, Mr. Kilgore. This substantial emphasis on performance-based goals provides incentives to senior executives to perform at the highest levels to achieve the goals that are important for TVA.

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•

Provide senior 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 the short-term and long-term success of TVA. The compensation program is designed to achieve this goal by providing a mix of fixed base compensation and at-risk annual and long-term incentive compensation. Base compensation is fixed and designed to provide an immediate financial incentive to executives. Annual and long-term compensation is at-risk based on performance and is designed to focus executives on the short-term and long-term goals of TVA.

•

Improve overall company performance through productivity enhancement. No senior executive can meet the goals of the company and improve performance without the work of all employees of the company. For this reason, the performance goals set at the TVA level and business unit level are the same for both senior executives and all non-executive employees. In this way, all TVA employees receive 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.

Use of Market Data and Benchmarking

TVA seeks to establish overall compensation for executives at a competitive level with respect to the relevant labor market. Competitive compensation levels are established for the Named Executive Officers using relevant market data obtained through surveys and validated through recruitment and periodic supplemental benchmark activities, including reviews of publicly-available proxy statements and annual reports on Form 10-K. In establishing these compensation levels, TVA relies on benchmarking data collected and analyzed by its Human Resources department with the assistance of an independent compensation consultant.

For 2006, TVA’s relevant labor market for most senior management levels, 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. When reviewing comparative compensation information for executives, including the Named Executive Officers, as a part of the survey-based analysis, TVA included the following energy services companies with annual revenues of $3 billion and greater:


AES Corp.	Energy East Corp.	PPL Corp.
Allegheny Energy, Inc.	Entergy Corp.	Progress Energy, Inc.
Ameren Corp.	Exelon Corp.	Public Service Enterprise Group, Inc.
American Electric Power Co., Inc.	FirstEnergy Corp.	Reliant Energy, Inc.
Atmos Energy Corp.	FPL Group, Inc.	SCANA Corp.
CenterPoint Energy, Inc.	MDU Resources, Inc.	Sempra Energy
CMS Energy Corp.	Mirant Corp.	The Southern Company
Consolidated Edison, Inc.	Nicor Inc.	SUEZ Energy North America
Constellation Energy Group, Inc.	NSTAR Electric Co.	TECO Energy, Inc.
Dominion Resources, Inc.	OGE Energy Corp.	TXU Corp.
DTE Energy Co.	ONEOK Inc.	The Williams Companies, Inc.
Duke Energy Corp.	Pacific Gas & Electric Co.	Wisconsin Energy Corp.
Edison International	PacifiCorp	WPS Resources Corp. (now Intergrys Energy Group, Inc.)
El Paso Corp.	Pepco Holdings, Inc.	Xcel Energy, Inc.

Executive Compensation Program Components

TVA’s compensation program for the Named Executive Officers consists primarily of the following components:

	•		base compensation, consisting of salary paid biweekly and additional annual compensation paid in quarterly installments;

	•		annual incentive compensation, which is at-risk and based on the attainment of certain pre-established performance goals;

	•		long-term incentive compensation, which is at-risk and based on the attainment of certain pre-established performance goals;

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	•		long-term deferred compensation, which is awarded to participating executives in the form of annual credits that vest after a specified period of time, typically three to five years; and

	•		pension plans, both qualified and supplemental, which provide compensation beginning with retirement or termination of employment provided certain eligibility and vesting requirements are met.

More information about the value of these various compensation components for the Named Executive Officers is provided below under the Summary Compensation Table and the Grants of Plan-Based Awards Table.

Base Compensation. For the Named Executive Officers, base compensation includes salary plus additional annual compensation. Base compensation received by executives is based on their levels of responsibility, their individual merit performances, and the competitive levels of compensation for executives in similar positions in the energy services industry.

Prior to March 31, 2006, the TVA Act provided that salaries for TVA employees, including the Named Executive Officers, could match but not exceed the salary of a TVA Board member, which was itself set by the TVA Act and by executive order of the President of the United States. In 2006, the salary of a TVA Board member, and thus the maximum salary allowed for any TVA employee, was $143,000. The Consolidated Appropriations Act amendments to the TVA Act removed this statutory salary cap. As of September 30, 2006, the TVA Board had approved, however, only one salary, that of the interim Chief Operating Officer, in excess of the former salary cap.

As a result of the salary cap, in 2006 additional annual compensation was used, in conjunction with salary, to provide a competitive level of base compensation to executives. The amount of additional annual compensation is therefore driven by the executive’s level of responsibility, the executive’s individual merit performance, and the salaries that companies in TVA’s peer group pay for comparable positions. Additional annual compensation was paid in fixed quarterly installments. The total amounts of additional annual compensation paid to the Named Executive Officers in 2006 appear in the “Bonus” column in the Summary Compensation Table.

Base compensation is reviewed periodically by executive officers with the assistance of the Vice President of Human Resources, and any recommended adjustments are submitted to the TVA Board or its delegees for approval.

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 short-term financial and operational goals of TVA and applicable business units. Under the EAIP, an executive’s annual incentive payment is calculated as follows:

EAIP

Base

Annual Incentive

Percent of Opportunity

Payout

Compensation

Opportunity

Achieved

Annual incentive opportunities increase with position and responsibility. The annual incentive opportunity is established for each of the Named Executive Officers based on the opportunities other companies provide to those in comparable positions in the energy services industry. Incentive opportunities are reviewed periodically by executive officers with the assistance of the Vice President of Human Resources, and any recommended adjustments are submitted to the TVA Board or its delegees for approval. The percent of opportunity achieved is determined by a weighted average of the results of a combination of performance measures at the TVA level and the business unit level. Performance measures at the TVA level and their weights are identified in TVA’s Winning Performance Balanced Scorecard. The performance measures and weights that are incorporated into TVA’s Winning Performance Balanced Scorecard are used in determining annual incentive payouts not just for the Named Executive Officers but also for all other participants in the EAIP as well as all other non-executive TVA employees who participate in TVA’s Winning Performance Team Incentive Plan. The performance measures and weights approved by the TVA Board for the 2006 Winning Performance Balanced Scorecard are set forth below:


Performance Measure	Weight
Financial Results		35	%
Availability of Generation Assets		15	%
Labor Productivity		10	%
Customer Impact		10	%
Economic Development		10	%
Environmental Impact		10	%
Worker Safety		10	%

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The Winning Performance Balanced Scorecard also established threshold, target, and maximum achievement levels for each of the performance measures. Performance levels between threshold and target achievement levels, and between target and maximum achievement levels, are calculated using straight line interpolation. Threshold achievement levels were set to recognize normal, satisfactory performance for each performance measure based on the budget and business plans for 2006. Target achievement levels were set to recognize good performance over and above threshold achievement levels. Maximum achievement levels were set to recognize excellent performance substantially above threshold achievement levels. This approach to establishing achievement levels resulted in a good likelihood (approximately 80 percent chance) of meeting threshold achievement levels, a reasonable likelihood (approximately 60 percent chance) of meeting target achievement levels, and a small likelihood (approximately 20 percent chance) of meeting maximum achievement levels.

The Winning Performance Balanced Scorecard represented 30 percent of the potential payout for the Named Executive Officers. The remaining 70 percent was tied to the average composite performance of their appropriate business units or, in the case of Mr. Kilgore and Mr. Rescoe, a composite average of all TVA business units. The calculation of the EAIP awards for the Named Executive Officers was based on the results of the Winning Performance Balanced Scorecard and the performance of applicable business units. Under the EAIP, awards may be adjusted based on the evaluation of individual achievements and performance results; however, in 2006, no discretion was exercised by the TVA Board, CEO, or any other TVA officer or employee to adjust either upward or downward the amount of the payout.

Awards provided to the Named Executive Officers under this plan for the performance period that ended on September 30, 2006, are reported in the “Non-Equity Incentive Plan Compensation” column in the Summary Compensation Table. Additional information regarding the basis of the payouts under the EAIP is presented in the narrative that accompanies the Grants of Plan-Based Awards Table.

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 impact TVA’s long-term strategic objectives. The ELTIP is designed to encourage and reward executives for their contributions to successfully achieving TVA’s long-term financial and operational goals, typically over a three-year performance cycle. The ELTIP performance cycles run concurrently, and participating executives receive awards under the plan on an annual basis if targets are met. Accordingly, in 2006, the ELTIP performed more as an annual incentive with the payout based on the reduction of Bonds, lease financing obligations, and energy prepayment obligations during 2006.

Under the ELTIP, an executive’s incentive payment is calculated as follows:

ELTIP

Base

ELTIP Incentive

Percent of Opportunity

Payout

Compensation

Opportunity

Achieved

The ELTIP incentive opportunity is established for each of the Named Executive Officers at a level that is similar to but more conservative than the opportunities other companies provide to those in comparable positions in the energy services industry. Incentive opportunities are reviewed periodically by executive officers with the assistance of the Vice President of Human Resources, and any recommended adjustments are submitted to the TVA Board or its delegees for approval. The percent of opportunity achieved is determined based on the results of certain measures at the TVA level critical to satisfying TVA’s long-term strategic goals. In 2006, the performance metric used was the aggregate reduction of TVA’s Bonds, lease financing obligations, and energy prepayment obligations.

Awards provided to the Named Executive Officers under this plan for the performance period that ended on September 30, 2006, are reported in the “Non-Equity Incentive Plan Compensation” column in the Summary Compensation Table. Additional information regarding the basis of the payouts under the ELTIP is presented in the narrative that accompanies the Grants of Plan-Based Awards Table.

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 or options as a form of compensation for its employees. In order to provide a benefit similar to restricted stock, TVA enters into agreements with certain executives, including the Named Executive Officers, that are administered under TVA’s Long-Term Deferred Compensation Plan (“LTDCP”). The LTDCP agreements are designed to provide retention incentives to executives to encourage them to remain with TVA and to provide, in combination with base compensation and EAIP and ELTIP incentive awards, a competitive level of total compensation. Under these agreements, 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. Annual credits provided to the Named

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Executive Officers under LTDCP agreements in 2006 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 and do not vest until a predetermined date in a later year.

TVA has also entered into additional LTDCP agreements with Mr. Singer and Mr. Bhatnagar where the amount of annual credits is based on the achievement of certain milestones with respect to the recovery of Browns Ferry Unit 1 (“Browns Ferry Unit 1 Recovery Project”). The annual credits provided to Mr. Singer and Mr. Bhatnagar under these agreements for 2006 are reported in the “Non-Equity Incentive Plan Compensation” column in the Summary Compensation Table and the “Registrant Contributions in Last FY” column in the Nonqualified Deferred Compensation Table.

Descriptions of all the 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 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 these qualified plans is consistent with similar qualified plans provided by other companies in TVA’s comparison groups.

In addition, certain executives in critical positions, as determined by TVA on an individual basis, are eligible to participate in a Supplemental Executive Retirement Plan (“SERP”). Each of the Named Executive Officers participates in the 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. The availability of this supplemental pension plan helps TVA to remain competitive in attracting and retaining top-level executives.

More information regarding these retirement and pension plans is found following the Pension Benefits Table.

Perquisites. TVA provides to certain employees, including two of the Named Executive Officers (Mr. Singer 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 officers and key managers with the approval of the TVA Board or its delegees. Information regarding vehicle allowances granted to the Named Executive Officers is reported in the “All Other Compensation” column in the Summary Compensation Table.

TVA does not provide to the Named Executive Officers any other perquisites.

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 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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Executive Compensation Tables and Narrative Disclosures

Summary Compensation and Grants of Plan-Based Awards

The following table sets forth information regarding compensation received by each of the Named Executive Officers in 2006.

Summary Compensation Table


														Change in
														Pension Value
														and
														Nonqualified
											Non-Equity			Deferred
							Stock		Option		Incentive Plan			Compensation			All Other
			Salary		Bonus ¹		Award(s)		Awards		Compensation			Earnings ²			Compensation			Total
Name and Principal Position	Year		($)		($)		($)		($)		($)			($)			($)			($)
(a)	(b)		(c)		(d)		(e)		(f)		(g)			(h)			(i)			(j)

Tom D. Kilgore		2006	$	140,000	$	511,984		—		—	$	627,861	³	$	169,614	⁸	$	306,300	¹³	$	1,755,759
President and Acting Chief Executive Officer

Michael E. Rescoe		2006	$	140,000	$	286,109		—		—	$	295,096	⁴		—	⁹	$	6,300	¹⁴	$	727,505
Chief Financial Officer and Executive Vice President, Financial Services

Karl W. Singer		2006	$	140,000	$	341,323		—		—	$	580,275	⁵	$	365,355	¹⁰	$	211,250	¹⁵	$	1,638,203
Chief Nuclear Officer and Executive Vice President, TVA Nuclear

Ashok S. Bhatnagar		2006	$	140,000	$	276,070		—		—	$	390,648	⁶	$	160,615	¹¹	$	158,655	¹⁶	$	1,125,988
Senior Vice President, Nuclear Operations

Joseph R. Bynum		2006	$	140,000	$	275,066		—		—	$	279,253	⁷	$	189,639	¹²	$	150,269	¹⁷	$	1,034,227
Executive Vice President, Fossil Power


Notes

⁽¹⁾		Represents additional annual compensation paid in quarterly installments.

⁽²⁾		Represents the aggregate change in pension value under TVA’s qualified defined benefit plan and TVA’s Supplemental Executive Retirement Plan (“SERP”).

⁽³⁾		Includes $334,152 paid out under the EAIP and $293,709 paid out under the ELTIP.

⁽⁴⁾		Includes $195,075 paid out under the EAIP and $100,021 paid out under the ELTIP.

⁽⁵⁾		Includes $283,382 paid out under the EAIP, $216,893 paid out under the ELTIP, and a credit in the amount of $80,000 made to Mr. Singer’s deferred compensation account provided under a LTDCP agreement with Mr. Singer for achievement of major milestones in 2006 associated with the Browns Ferry Unit 1 Recovery Project. See information regarding the details of the LTDCP agreement under “Browns Ferry Unit 1 Recovery Milestone LTDCP Agreements” following the Grants of Plan-Based Awards Table.

⁽⁶⁾		Includes $210,007 paid out under the EAIP, $140,641 paid out under the ELTIP, and a credit in the amount of $40,000 made to Mr. Bhatnagar’s deferred compensation account provided under a LTDCP agreement with Mr. Bhatnagar for achievement of major milestones in 2006 associated with the Browns Ferry Unit 1 Recovery Project. See information regarding the details of the LTDCP agreement under “Browns Ferry Unit 1 Recovery Milestone LTDCP Agreements” following the Grants of Plan-Based Awards Table.

⁽⁷⁾		Includes $154,540 paid out under the EAIP and $124,713 paid out under the ELTIP.

⁽⁸⁾		Includes $8,882 under TVA’s qualified defined benefit plan and $160,732 under the SERP.

⁽⁹⁾		Mr. Rescoe left TVA effective November 13, 2006, and did not meet the minimum five years of creditable service required to become vested in TVA’s qualified retirement plan and TVA’s SERP.

⁽¹⁰⁾		Includes $17,905 under TVA’s qualified defined benefit plan and $347,450 under the SERP.

⁽¹¹⁾		Includes $12,945 under TVA’s qualified defined benefit plan and $147,670 under the SERP.

⁽¹²⁾		Includes $23,824 under TVA’s qualified defined benefit plan and $165,815 under the SERP.

⁽¹³⁾		Includes an unvested annual credit in the amount of $300,000 provided under a LTDCP agreement with Mr. Kilgore and $6,300 in employer matching contributions to the TVA Retirement System’s 401(k) plan based on Mr. Kilgore’s elective contribution. Mr. Kilgore will become vested in the $300,000 credit in accordance with the terms of the agreement. See information regarding the details of the LTDCP agreement under “Long-Term Deferred Compensation Plan Agreements” following the Grants of Plan-Based Awards Table.

⁽¹⁴⁾		Represents employer matching contributions to the TVA Retirement System’s 401(k) plan based on Mr. Rescoe’s elective contribution.

⁽¹⁵⁾		Includes an unvested annual credit in the amount of $200,000 provided under a LTDCP agreement with Mr. Singer, $6,300 in employer matching contributions to the TVA Retirement System’s 401(k) plan based on Mr. Singer’s elective contribution, and $4,950 in vehicle allowance payments (paid at the rate of $450 every two weeks beginning in

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		April 2006). Mr. Singer will become vested in the $200,000 credit in accordance with the terms of the LTDCP agreement. See information regarding the details of the LTDCP agreement under “Long-Term Deferred Compensation Plan Agreements” following the Grants of Plan-Based Awards Table.

⁽¹⁶⁾		Includes an unvested annual credit in the amount of $150,000 provided under a LTDCP agreement with Mr. Bhatnagar, $3,705 in employer matching contributions to the TVA Retirement System’s 401(k) plan based on Mr. Bhatnagar’s elective contribution, and $4,950 in vehicle allowance payments (paid at the rate of $450 every two weeks beginning in April 2006). Mr. Bhatnagar will become vested in the $150,000 credit in accordance with the terms of the LTDCP agreement. See information regarding the details of the LTDCP agreement under “Long-Term Deferred Compensation Plan Agreements” following the Grants of Plan-Based Awards Table.

⁽¹⁷⁾		Includes an unvested annual credit in the amount of $150,000 provided under a LTDCP agreement with Mr. Bynum and $269 in employer matching contributions to the TVA Retirement System’s 401(k) plan based on Mr. Bynum’s elective contribution. Mr. Bynum became vested in the $150,000 credit and all previous unvested credits and earnings received under his five-year LTDCP agreement upon expiration of the agreement on September 30, 2006. See information regarding the details of the LTDCP agreement under “Long-Term Deferred Compensation Plan Agreements” following the Grants of Plan-Based Awards Table.

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 2006.

Grants of Plan-Based Awards Table


														All		All Other
														Other		Option				Grant
														Stock		Awards:				Date
														Awards:		Number of				Fair
														Number		Securities		Exercise		Value of
														of		Underlying		or Base		Stock
		Estimated Possible Payouts Under						Estimated Future Payouts Under						Shares		Options of		Price of		and
		Non-Equity Incentive Plan Awards						Equity Incentive Plan Awards						of Stock		Stock or		Option		Option
	Grant	Threshold		Target		Maximum		Threshold		Target		Maximum		or Units		Units		Awards		Awards
Name	Date	($)		($)		($)		($)		($)		($)		($)		($)		($/Sh)		($)
(a)	(b)	(c)		(d)		(e)		(f)		(g)		(h)		(i)		(j)		(k)		(l)

Tom D. Kilgore	EAIP ¹	$	341,250	$	455,000	$	568,750		—		—		—		—		—		—		—
	ELTIP ²	$	292,500	$	390,000	$	487,500

Michael E. Rescoe	EAIP ¹	$	199,219	$	265,625	$	332,031		—		—		—		—		—		—		—
	ELTIP ²	$	99,610	$	132,813	$	166,016

Karl W. Singer	EAIP ¹	$	252,000	$	336,000	$	420,000		—		—		—		—		—		—		—
	ELTIP ²	$	216,000	$	288,000	$	360,000
	BFNU1-LTDCP ³			$	100,000

Ashok S. Bhatnagar	EAIP ¹	$	186,750	$	249,000	$	311,250		—		—		—		—		—		—		—
	ELTIP ²	$	140,063	$	186,750	$	233,438
	BFNU1-LTDCP ³			$	50,000

Joseph R. Bynum	EAIP ¹	$	170,775	$	227,700	$	284,625		—		—		—		—		—		—		—
	ELTIP ²	$	124,200	$	165,600	$	207,000


Notes

⁽¹⁾		Actual awards earned for performance in 2006 are reported for each of the Named Executive Officers under “Non-Equity Incentive Plan Compensation” in the Summary Compensation Table.

⁽²⁾		Actual awards earned for the performance period ending on September 30, 2006, are reported for each of the Named Executive Officers under “Non-Equity Incentive Plan Compensation” in the Summary Compensation Table.

⁽³⁾		In accordance with agreements administered under TVA’s LTDCP, Mr. Singer and Mr. Bhatnagar were eligible to receive these credits based on the achievement of major milestones in association with the Browns Ferry Unit 1 Recovery Project. The actual credits earned and vested based on the level of achievement in 2006 are reported under “Non-Equity Incentive Plan Compensation” in the Summary Compensation Table.

Executive Annual Incentive Plan Awards. All of the Named Executive Officers were participants in the Executive Annual Incentive Plan (“EAIP”) in 2006. As discussed in the Compensation Discussion and Analysis, the EAIP is designed to encourage and reward executives for their contributions to successfully achieving short-term financial and operational goals of TVA and applicable business units. Incentive opportunities approved by the TVA Board for Mr. Kilgore and Mr. Rescoe and by Mr. Kilgore for Mr. Singer, Mr. Bhatnagar, and Mr. Bynum for the performance period ending on September 30, 2006, were as follows:

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Name	Incentive Opportunity ¹
Tom D. Kilgore		70	%
Michael E. Rescoe		62.5	%
Karl W. Singer		70	%
Ashok S. Bhatnagar		60	%
Joseph R. Bynum		55	%


Note

⁽¹⁾		Represents a percentage of each participant’s base compensation.

The percent of opportunity achieved is determined by a weighted average of the results of a combination of performance measures at the TVA level and business unit level. For 2006, the performance measures at the TVA level were approved by the TVA Board and set forth in TVA’s Winning Performance Balanced Scorecard. The performance measures for TVA’s business units were approved by Mr. Kilgore.

Awards earned under the EAIP for 2006 were made during the first quarter of 2007. All awards were paid in cash with a deferral option. Only Mr. Kilgore elected to defer his EAIP award earned for 2006.

Executive Long-Term Incentive Plan Awards. All of the Named Executive Officers were participants in the Executive Long-Term Incentive Plan (“ELTIP”) in 2006. As discussed in the Compensation Discussion and Analysis, the ELTIP is designed to encourage and reward executives for their contributions to successfully achieving long-term financial and operational goals, typically over a three-year performance cycle. Even though the ELTIP is based on three-year performance cycles, the cycles run concurrently to provide participating executives potential ELTIP awards on an annual basis. As a result, the ELTIP has administratively functioned in a manner similar to an annual incentive plan with targets set and awards made with respect to a one-year period.

Incentive opportunities approved by the TVA Board for Mr. Kilgore and Mr. Rescoe and by Mr. Kilgore for Mr. Singer, Mr. Bhatnagar, and Mr. Bynum under the ELTIP for the performance period ending on September 30, 2006, were as follows:


Name	Incentive Opportunity ¹
Tom D. Kilgore		60	%
Michael E. Rescoe		31.25	%
Karl W. Singer		60	%
Ashok S. Bhatnagar		45	%
Joseph R. Bynum		40	%


Note

⁽¹⁾		Represents a percentage of each participant’s base compensation.

For the performance period ending on September 30, 2006, the threshold, target, and maximum awards were equal to 75 percent, 100 percent, and 125 percent of the participant’s incentive opportunity.

As set forth in the Compensation Discussion and Analysis, the calculation of the ELTIP awards for the performance period ending on September 30, 2006, was based solely on the performance of a financial measure, namely, the aggregate reduction in TVA’s Bonds, lease financing obligations, and energy prepayment obligations. The following goals were established related to the reduction in TVA’s Bonds, lease financing obligations, and energy prepayment obligations: threshold ($340 million reduction), target ($420 million reduction), and maximum ($500 million reduction). In 2006, TVA achieved 75.31 percent of the target goal set forth above. As a result, each of the Named Executive Officers received an ELTIP payout for the performance period ended on September 30, 2006, equal to 75.31 percent of their respective incentive opportunity.

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Payments earned under the ELTIP for the performance period ending on September 30, 2006, were made during the first quarter of 2007. All awards were paid in cash with a deferral option. Mr. Kilgore elected to defer all of his ELTIP award earned for the performance period ending on September 30, 2006, and Mr. Bynum elected to defer 50 percent of his ELTIP award earned for the same performance period.

Long-Term Deferred Compensation Plan Agreements. Agreements administered under TVA’s Long-Term Deferred Compensation Plan (“LTDCP”) are designed to provide retention incentives to executives to encourage them to remain with TVA and to provide, in combination with base compensation and EAIP and ELTIP incentive awards, a competitive level of total compensation. LTDCP agreements act as substitutes for restricted stock awards, which investor-owned utilities in TVA’s comparison group can offer to their executives, but which TVA cannot offer. Under the LTDCP agreements, 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 the vesting period (typically three to five years), the executive becomes vested in the balance of the account, including a return on investment, and receives a distribution in accordance with an earlier deferral election.

In March 2005, TVA entered into a LTDCP agreement with Mr. Kilgore. Under the terms of the agreement, Mr. Kilgore receives annual deferred compensation credits of $300,000 for a period of four years and seven months beginning in March 2005 and ending in September 2009. Pursuant to the agreement, Mr. Kilgore was vested in the first credit of $300,000 at the time the credit was made in March 2005. Mr. Kilgore 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, 2009, after which the account will be distributed in accordance with his deferral election.

In May 2004, TVA entered into a LTDCP agreement with Mr. Singer. Under the terms of the agreement, Mr. Singer receives annual deferred compensation credits of $200,000 for a period of five years beginning in October 2004 and ending in September 2009. Mr. Singer will be vested and eligible to receive payment of one-half of his account balance on September 30, 2007, and one-half of the remaining balance again on September 30, 2008, as long as he remains employed with TVA on each of those vesting dates. Mr. Singer will vest in the remaining balance of his account only if he remains employed with TVA until the expiration of the agreement on September 30, 2009, after which the account will be distributed in accordance with his deferral election.

In September 2004, TVA entered into a LTDCP agreement with Mr. Bhatnagar. Under the terms of the agreement, Mr. Bhatnagar receives annual deferred compensation credits of $150,000 for a period of five years beginning in October 2004 and ending in September 2009. Mr. Bhatnagar will vest in the balance of his account if he remains employed by TVA until the expiration of the agreement on September 30, 2009, after which the account will be distributed in accordance with his deferral elections.

TVA entered into a LTDCP agreement with Mr. Bynum in 2001 that provided annual deferred compensation credits of $140,000 for a period of five years. The agreement was later amended to increase the annual credits from $140,000 to $150,000 for 2004 through 2006. Pursuant to the agreement, Mr. Bynum received the full balance of his account on September 30, 2006, since he remained employed by TVA until that date. The balance of Mr. Bynum’s account, which includes the credits and earnings on such credits provided under this LTCDP agreement, has been deferred based on Mr. Bynum’s previous election.

Browns Ferry Unit 1 Recovery Milestone LTDCP Agreements. In addition to the LTDCP agreement with Mr. Singer described above, TVA has entered into a second LTDCP agreement with Mr. Singer that provides annual credits of up to $100,000 for a period of four years based on the accomplishment of major milestones associated with the Browns Ferry Unit 1 Recovery Project. The actual amount credited each year is based on the achievement of specific milestones established at the beginning of each fiscal year. Under this agreement, credits earned will be vested and credited to a deferred compensation account in Mr. Singer’s name at the end of each fiscal year. For 2006, there were 35 milestone objectives established for Mr. Singer’s agreement, and 80 percent of those objectives (28 out of 35) were met. As a result, Mr. Singer was awarded a credit of $80,000 for 2006, which, under the terms of the agreement, has been placed in a deferred compensation account in his name to be distributed in a lump sum upon termination of employment.

In addition to the LTDCP agreement with Mr. Bhatnagar described above, TVA has entered into a second LTDCP agreement with Mr. Bhatnagar that provides annual credits of up to $50,000 for a period of four years based on the accomplishment of major milestones associated with the Browns Ferry Unit 1 Recovery Project. The actual amount credited each year is based on the achievement of specific milestones established at the beginning of each fiscal year. Under this agreement, credits earned will be vested and credited to a deferred compensation account in Mr. Bhatnagar’s name at the end of each fiscal year. For 2006, there were 35 milestone objectives established for Mr. Bhatnagar’s agreement, and 80 percent of those objectives (28 out of 35) were met. As a result, Mr. Bhatnagar

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was awarded a credit of $40,000 for 2006, which, under the terms of the agreement, has been placed in a deferred compensation account in his name to be distributed in a lump sum upon termination of employment.

Retirement and Pension Plans

The following table provides the actuarial present value of the Named Executive Officer’s accumulated benefits, including the number of years of credited service, under TVA’s retirement and pension plans as of September 30, 2006, determined using interest rate and mortality rate assumptions consistent with those used in the financial statements contained in this Annual Report.

Pension Benefits Table


		Number of			Present Value
		Years of			of			Payments
		Credited			Accumulated			During Last
		Service ¹			Benefit			Fiscal Year
Name	Plan Name	(#)			($)			($)
(a)	(b)	(c)			(d)			(e)

Tom D. Kilgore	(1) Qualified Plan – CBBS		1.58		$	13,489			—
	(2) Non-Qualified – SERP		1.58	²	$	160,732

Michael E. Rescoe	(1) Qualified Plan – CBBS		3.25		$	0	⁴		—
	(2) Non-Qualified – SERP		3.25		$	0	⁴

Karl W. Singer	(1) Qualified Plan – CBBS		13.50		$	169,338			—
	(2) Non-Qualified – SERP		14.50	³	$	1,234,660

Ashok S. Bhatnagar	(1) Qualified Plan – CBBS		7.08		$	82,247			—
	(2) Non-Qualified – SERP		7.08		$	416,081

Joseph R. Bynum	(1) Qualified Plan – OBS		32.17		$	941,581			—
	(2) Non-Qualified – SERP		24.00		$	2,897,627


Notes

⁽¹⁾		Limited to 24 years when determining supplemental benefits available under TVA’s SERP.

⁽²⁾		Mr. Kilgore has been granted three additional years of credited service for pre-TVA employment following five years of actual TVA service. In the event his employment is terminated during the first five years (other than for cause), the five-year vesting requirement will be waived and he will receive credit for eight years of service. In addition, the offset for prior employer pension benefits will be waived, and 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 TVA’s CBBS.

⁽³⁾		TVA has agreed to grant Mr. Singer up to six additional years of credited service at the rate of one year’s service for each year of TVA service, beginning August 17, 2006 (age 50), and continuing through August 17, 2011 (age 55). Therefore, as of September 30, 2006, Mr. Singer has been granted one year of additional service for purposes of the calculation of his benefit under the SERP. Without the one year of additional service, the present value of Mr. Singer’s accumulated benefit would be $1,143,214.

⁽⁴⁾		Mr. Rescoe left TVA in November 2006 and did not have the minimum five years of creditable service required to become vested and receive a retirement benefit under TVA’s qualified plan or TVA’s SERP.

TVA sponsors a qualified defined benefit plan with two structures for all employees, including the Named Executive Officers, which is administered by the TVA Retirement System. The structures are the OBS and the 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.

TVA’s Original Benefit Structure. Mr. Bynum 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 (to the nearest month) of creditable service, 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 the Named Executive Officers, is shown under the column titled “Salary” in the Summary Compensation Table. Creditable

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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 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. Bynum has obtained the Rule of 80. Members must have at least five years of creditable service in order to be eligible for a pension benefit. Members 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 credited service receive the maximum pension factor of 1.3 percent even if they do not have 80 points.

TVA’s Cash Balance Structure. Mr. Kilgore, Mr. Singer, and Mr. Bhatnagar are members of the CBBS, and Mr. Rescoe was a member 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 base salary only for benefit calculation purposes and, for the Named Executive Officers, is shown under the column titled “Salary” in the Summary Compensation Table. 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 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 ten percent unless the TVA Retirement System 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 TVA Retirement System and does not include credit for unused sick leave, forfeited annual leave, or pre-TVA employment military service.

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 comparison groups and is provided to a limited number of TVA 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. Specifically, the plan is designed to replace 60 percent of the amount of a participant’s compensation that is excluded from the calculation of pension benefits under TVA’s qualified defined benefit plan at the time the participant reaches age 62 and has accrued 24 years of service at TVA. The plan recognizes additional annual compensation and annual incentives in the definition of compensation for supplemental benefits.

SERP 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, additional annual compensation, and EAIP for benefit calculation purposes. Normal retirement eligibility is age 62 with five years of vesting service. No benefits are payable prior to age 55, and benefits are reduced for retirements between age 55 and 62. The SERP requires participants to have 24 years of credited service in order to receive full supplemental benefits at age 62. Executives with less credited service, or who retire prior to their normal retirement date, are eligible to receive reduced benefits. Participants must be employed by TVA for five years in order to be eligible to receive benefits under the SERP. Benefits are offset by Social Security benefits, benefits provided under TVA’s defined benefit plan, and prior employer pension benefits when applicable.

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- and/or after-tax basis. For OBS members, TVA provides a matching contribution of 25 cents on every dollar contributed on a before- and/or after-tax 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- and/or after-tax 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 2006 and already reported in the Summary Compensation Table but rather the

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amounts of compensation earned by the Named Executive Officers in 2006 or prior years that was or has been deferred.

Nonqualified Deferred Compensation Table


	Executive			Registrant			Aggregate		Aggregate		Aggregate
	Contributions in			Contributions in			Earnings in		Withdrawals/		Balance at
	Last FY			Last FY			Last FY ¹		Distributions ²		Last FY ³
Name	($)			($)			($)		($)		($)
(a)	(b)			(c)			(d)		(e)		(f)

Tom D. Kilgore	$	627,861	⁴	$	300,000	⁶	$	48,685	$	74,375	$	880,160	¹⁰

Michael E. Rescoe	$	0		$	0		$	40,054	$	147,500	$	428,414	¹¹

Karl W. Singer	$	0		$	280,000	⁷	$	115,002	$	172,000	$	2,403,178	¹²

Ashok S. Bhatnagar	$	0		$	190,000	⁸	$	136,187	$	132,000	$	1,861,863	¹³

Joseph R. Bynum	$	62,356	⁵	$	150,000	⁹	$	98,180	$	142,000	$	1,700,399	¹⁴


Notes

⁽¹⁾		Includes vested and unvested earnings.

⁽²⁾		Represents distribution of monthly deferred compensation credits received in 2005 and paid out in 2006 based on elections made at the beginning of 2005. Recipients were permitted to elect to receive a distribution of up to 50 percent of the monthly deferred compensation credits they received in 2005 in a lump sum cash payment following the end of 2005. Mr. Kilgore elected to receive a distribution equal to 25 percent, and each of the remaining Named Executive Officers elected to receive a distribution equal to 50 percent. Cash distributions were paid during the first quarter of 2006 (October 2005).

⁽³⁾		Includes vested and unvested amounts.

⁽⁴⁾		Mr. Kilgore elected to defer 100 percent of the $334,152 paid out under the EAIP for 2006 and 100 percent of the $293,709 paid out under the ELTIP for the performance period ending on September 30, 2006. These amounts are reported in the “Non-Equity Incentive Plan Compensation” column in the Summary Compensation Table.

⁽⁵⁾		Mr. Bynum elected to defer 50 percent of the $124,713 paid out under the ELTIP for the performance period ending on September 30, 2006. This amount is reported in the “Non-Equity Incentive Plan Compensation” column in the Summary Compensation Table.

⁽⁶⁾		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).

⁽⁷⁾		Represents (1) an unvested annual credit in the amount of $200,000 provided under a LTDCP agreement with Mr. Singer (reported in the “All Other Compensation” column in the Summary Compensation Table) and (2) a vested credit in the amount of $80,000 provided under a second LTDCP agreement with Mr. Singer for achievement of major milestones in 2006 associated with the Browns Ferry Unit 1 Recovery Project (reported in the “Non-Equity Incentive Plan Compensation” column in the Summary Compensation Table).

⁽⁸⁾		Represents (1) an unvested annual credit in the amount of $150,000 provided under a LTDCP agreement with Mr. Bhatnagar (reported in the “All Other Compensation” column in the Summary Compensation Table) and (2) a vested credit in the amount of $40,000 provided under a second LTDCP agreement with Mr. Bhatnagar for the achievement of major milestones in 2006 associated with the Browns Ferry Unit 1 Recovery Project (reported in the “Non-Equity Incentive Plan Compensation” column in the Summary Compensation Table).

⁽⁹⁾		Represents an unvested annual credit in the amount of $150,000 provided under a LTDCP agreement with Mr. Bynum (reported in the “All Other Compensation” column in the Summary Compensation Table). Mr. Bynum became fully vested in this credit, as well as all other credits and earnings on such credits provided under his LTDCP agreement, upon expiration of the agreement on September 30, 2006.

⁽¹⁰⁾		Represents the balance of Mr. Kilgore’s account, including unvested credits and earnings totaling $312,729, as of September 30, 2006. The amount reported in the “Executive Contributions in Last FY” column was credited to his account in the first quarter of 2007 and is not included in the balance.

⁽¹¹⁾		Mr. Rescoe was fully vested in all credits and earnings reflected in the balance of his account as of September 30, 2006.

⁽¹²⁾		Represents the balance of Mr. Singer’s account, including unvested credits and earnings totaling $398,032, as of September 30, 2006. The $80,000 credit provided under the LTDCP agreement with Mr. Singer for the achievement of major milestones in 2006 associated with the Browns Ferry Unit 1 Recovery Project, reported in the “Executive Contributions in Last FY” column, was credited to his account in the first quarter of 2007 and is not included in the balance.

⁽¹³⁾		Represents the balance of Mr. Bhatnagar’s account, including unvested credits and earnings totaling $321,847, as of September 30, 2006. The $40,000 credit provided under the LTDCP agreement with Mr. Bhatnagar for the achievement of major milestones in 2006 associated with the Browns Ferry Unit 1 Recovery Project, reported in the “Executive Contributions in Last FY” column, was credited to his account in the first quarter of 2007 and is not included in the balance.

⁽¹⁴⁾		Mr. Bynum was fully vested in all credits and earnings reflected in the balance of his account as of September 30, 2006. The amount reported in the “Executive Contributions in Last FY” column was credited to his account in the first quarter of 2007 and is not included in the balance.

In order to further assist executives, including the Named Executive Officers, in saving for retirement, TVA allows participants in the EAIP, ELTIP, and LTDCP to elect to defer all or a portion of the compensation earned under those plans. All deferrals are credited to each participant, 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 at the beginning of each fiscal year. Participants may elect to change from either one notional investment option or the TVA interest bearing option to another at any time. Participants do not have the ability to withdraw funds from their accounts prior to termination of employment with TVA.

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Upon termination, funds are distributed in accordance with 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 additional annual compensation in 2006. Participants in the EAIP and ELTIP, including the Named Executive Officers, are permitted to elect annually to defer all or a portion of their awards (25, 50, 75 or 100 percent) received under the plans. As previously noted, in 2006, Mr. Kilgore elected to defer 100 percent of his EAIP and ELTIP awards, and Mr. Bynum elected to defer 50 percent of his ELTIP award.

Other Agreements

In March 2005, TVA entered into an agreement with Mr. Kilgore that provides a lump sum payment equal to one year’s annual compensation if (1) he was not appointed as TVA’s Chief Executive Officer, (2) his duties and/or responsibilities are reduced, (3) his compensation is substantially reduced, and he terminates his employment with TVA, or (4) his employment is terminated for any reason other than “for cause.” For purposes of this agreement, “annual compensation” is defined as annual salary plus additional annual compensation 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. In 2006, this lump sum payment would have been equal to $1,495,000. Nothing triggered the payment of this amount in 2006. Because Mr. Kilgore was appointed Chief Executive Officer in 2006, the portion of this agreement relating to his appointment as TVA’s Chief Executive Officer is no longer operative.

In April 2004, TVA entered into an agreement with Mr. Rescoe that provided a lump sum payment in an amount equal to two years’ compensation in the event that there is a change in his reporting relationship with the TVA Board such that he would report to a Chief Executive Officer or other similarly named executive and is asked to leave TVA employment or is asked to take a position with TVA other than his then current position as Chief Financial Officer and Executive Vice President, Financial Services, prior to July 10, 2008. For purposes of this agreement, “annual compensation” was defined as annual salary plus additional annual compensation 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. Under the agreement, Mr. Rescoe was to receive the lump sum payment in two equal installments: the first installment was to be paid within ten days of the effective date he leaves TVA and the second was to be paid on the one-year anniversary of that date.

Mr. Rescoe left TVA effective November 13, 2006. Pursuant to the agreement, TVA paid Mr. Rescoe the first of two installments in the amount of $823,438 in November 2006. The second installment will be paid to Mr. Rescoe in November 2007.

Other than the arrangements described above, there are no agreements or arrangements regarding salary and bonus with any of the Named Executive Officers.

Director Compensation

At the beginning of 2006, the TVA Board consisted of two full-time members. On March 31, 2006, the TVA Board became a nine-member part-time board in accordance with the provisions of the Consolidated Appropriations Act, which amended the TVA Act. Prior to this restructuring, the two incumbent directors, William W. Baxter and Skila S. Harris, received salaries of $152,000 and $143,000, respectively. Under the TVA Act, as amended by the Consolidated Appropriations Act, each director now receives a stipend of $45,000 per year unless (1) the director is the chair of a TVA Board committee, in which case the stipend is $46,000 per year, or (2) the director is the chairman of the TVA Board, in which case the stipend is $50,000 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.

The annual stipends provided to each director and to the chairman of the TVA Board as of September 30, 2006, were as follows:

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	Annual Stipend
Name	($)
William W. Baxter ¹	$	45,000
Dennis C. Bottorff	$	46,000
Donald R. DePriest	$	46,000
Robert M. Duncan	$	46,000
Bishop William H. Graves ²		—
Skila S. Harris	$	46,000
William B. Sansom	$	50,000
Howard A. Thrailkill	$	46,000
Susan Richardson Williams	$	46,000


Notes

⁽¹⁾		Mr. Baxter resigned as a director as of January 24, 2007.

⁽²⁾		Bishop William H. Graves became a director on October 10, 2006. Director Graves began receiving a stipend at a rate of $45,000 annually at that time.

The following table set outs the compensation received by TVA’s directors during 2006.

Director Compensation


										Change in
										Pension Value
										and
										Nonqualified
	Fees Earned							Non-Equity		Deferred
	or Paid in							Incentive Plan		Compensation		All Other
	Cash			Stock		Option		Compensation		Earnings ¹		Compensation			Total
Name	($)			Awards		Awards		($)		($)		($)			($)
(a)	(b)			(c)		(d)		(e)		(f)		(g)			(h)

William W. Baxter	$	61,737	²		—		—		—		—	$	13,711	⁵	$	75,448
Dennis C. Bottorff	$	21,581			—		—		—		—	$	2,417	⁶	$	23,998
Donald R. DePriest	$	21,581			—		—		—		—	$	1,047	⁶	$	22,628
Robert M. Duncan	$	21,581			—		—		—		—	$	2,417	⁶	$	23,998
Bishop William H. Graves ³		—			—		—		—		—		—			—
Skila S. Harris	$	59,500	⁴		—		—		—		—	$	13,074	⁷	$	72,574
William B. Sansom	$	23,336			—		—		—		—	$	2,614	⁶	$	25,950
Howard A. Thrailkill	$	21,277			—		—		—		—	$	1,275	⁶	$	22,552
Susan Richardson Williams	$	21,607			—		—		—		—	$	2,420	⁶	$	24,027


Notes

⁽¹⁾		TVA directors do not participate in the TVA Retirement System, TVA’s Supplemental Executive Retirement Plan, 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 (“OPM”), and information regarding the value of FERS pension benefits is not available to TVA.

⁽²⁾		Mr. Baxter served as Chairman of the TVA Board in a full-time capacity prior to its restructuring and received a salary at the rate of $149,200 per year until January 8, 2006. He received a salary at the rate of $152,000 per year from January 9, 2006, through March 30, 2006, after which time he began serving as a director in a part-time capacity and receiving a stipend at a rate of $45,000 annually.

⁽³⁾		Bishop William H. Graves did not become a director until October 10, 2006.

⁽⁴⁾		Ms. Harris served as a director of the TVA Board in a full-time capacity prior to its restructuring and received a salary at the rate of $140,300 per year until January 8, 2006. She received a salary at the rate of $143,000 per year from January 9, 2006, through March 30, 2006, after which time she began serving as a director in a part-time capacity and receiving a stipend at a rate of $45,000 annually. On May 18, 2006, she was selected to chair the Human Resources Committee and began receiving a stipend at a rate of $46,000 annually.

⁽⁵⁾		Includes a $1,017 contribution by TVA to the Thrift Savings Plan (“TSP”) (equivalent to one percent of Mr. Baxter’s salary/stipend) and a $12,694 contribution by TVA to OPM to fund Mr. Baxter’s FERS pension.

⁽⁶⁾		Represents amounts contributed by TVA to OPM to fund the director’s FERS pension.

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⁽⁷⁾		Includes a $973 contribution by TVA to TSP (equivalent to one percent of Ms. Harris’s salary/stipend), a $3,892 matching contribution by TVA to TSP, and an $8,208 contribution by TVA to OPM to fund Ms. Harris’s FERS pension.

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. 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 Supplemental Executive Retirement Plan. 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. 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 creditable service, (2) they reach age 60 and have 20 years of creditable service, or (3) they attain the minimum retirement age and accumulate the specified years of service. 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 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 and have accumulated at least 10 years of creditable service. For directors who reach the minimum retirement age and have at least 10 years of creditable service, the annuity will be reduced by five percent for each year the director is under age 62.

Each director is also eligible to participate in the Thrift Savings Plan. The Thrift Savings Plan 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, after a mandatory waiting period, TVA contributes an amount equal to one percent of the director’s stipend into a Thrift Savings Plan 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 Internal Revenue Service (“IRS”) elective deferral limit. Directors receive a matching contribution according to the following schedule: 100 percent of each dollar for the first three percent of the director’s stipend, 50 percent of each dollar for the next two percent of the director’s stipend, and zero percent for contributions above five percent of the director’s stipend.

Compensation Committee Interlocks and Insider Participation

The TVA Board established the Human Resources Committee on May 18, 2006. The committee consists of the following four directors: Skila S. Harris, Chair, Dennis C. Bottorff, Susan Richardson Williams, and Howard A. Thrailkill. The committee reviewed a compensation plan covering all TVA employees, which it submitted to the TVA Board for consideration and which the TVA Board approved on May 31, 2007. Under the compensation plan, the committee will review the compensation of the CEO and his direct reports, monitor the process for approving compensation for TVA employees compensated in excess of the federal government’s Executive Schedule Level IV ($143,000 as of September 30, 2006), monitor TVA executive compensation programs, and periodically review the compensation and benefits programs for all TVA employees.

Under the TVA Act, as amended by the Consolidated Appropriations Act, the TVA Board has the authority to approve salaries in excess of the federal government’s Executive Schedule Level IV. While the Human Resources Committee can recommend that the TVA Board approve compensation, the committee has no authority to approve compensation.

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 compensation philosophy, including the strategy, policies, and decisions, that guided TVA in 2006 in establishing the level and nature of the compensation provided to the Named Executive Officers was established by the former three-person TVA Board before it was restructured into the current nine-person TVA Board. TVA management reviewed the compensation philosophy with the Human Resources Committee in 2006 before incentive

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compensation was paid. The Compensation Discussion and Analysis included in this Annual Report was written in 2007 and reflects this compensation philosophy. It was provided to the Human Resources Committee in 2007 for its review.

THE TVA BOARD

Dennis C. Bottorff
Donald R. DePriest
Robert M. Duncan
Bishop William H. Graves
Skila S. Harris
William B. Sansom
Howard A. Thrailkill
Susan Richardson Williams

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

TVA is exempted by section 37 of the Securities Exchange Act from complying with section 10A(m)(3) of the Securities 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. Notwithstanding this exemption, the TVA Act contains certain provisions that are similar to the considerations for independence under section 10A(m)(3) of the Securities 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. These provisions became applicable to the TVA Board members on March 31, 2006.

Related Party Transactions

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, 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

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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. This additional policy 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:

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:

	o		comprised solely of a right to payment of retirement benefits resulting from former employment or fiduciary relationship,

	o		arising solely by virtue of cooperative membership or similar interest as a consumer in a distributor of TVA power, or

	o		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.

	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 and Ethics Committee. The Audit and Ethics 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 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 review, 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-

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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.

TVA has access to financing arrangements with the U.S. Treasury under which the U.S. Treasury is authorized to accept a short-term note with the maturity of one year or less in an amount not to exceed $150 million. TVA may draw any portion of the authorized $150 million during the year. Interest is accrued daily at a rate determined by the United States Secretary of the Treasury each month based on the average rate on outstanding marketable obligations of the United States with maturities of one year or less. During 2006, the daily average outstanding balance was $131 million. See Note 9 — Short-Term Debt.

In addition, TVA makes payments to the U.S. Treasury as a repayment of and a return on the Appropriation Investment. Under the TVA Act, TVA is required to repay $1 billion of the Appropriation Investment, and $150 million of this amount remained unpaid as of September 30, 2006. Once TVA repays this $150 million, there will still be an outstanding balance on the Appropriation Investment, and TVA is obligated under the TVA Act to pay the U.S. Treasury a return on this remaining balance indefinitely. See Notes 7 and 14.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table presents fees for professional services rendered by PricewaterhouseCoopers LLP for the years ended September 30, 2006 and 2005.

Principal Accountant Fees and Services


	2006		2005

Audit Fees ⁽¹⁾	$	1,110,742	$	948,393
Audit-Related Fees ⁽²⁾		273,368		514,706
All Other Fees⁽³⁾		14,000		—

Total	$	1,398,110	$	1,463,099


Notes

(1)		Audit fees consist of professional services rendered for the audit of TVA’s annual financial statements, the review of the interim financial statements included in TVA’s quarterly reports, and fees for Bond offering comfort letters.

(2)		Audit-related fees are fees for services which are usually performed by the auditor and consist primarily of accounting assistance on proposed transactions and accounting standards, accounting assistance related to reviewing internal control over financial reporting, and assistance in preparing for TVA’s initial Form 10-K filing.

(3)		All other fees relate to in-house training of TVA personnel.

On July 28, 2006, TVA’s Audit and Ethics Committee recommended that the TVA Board select PricewaterhouseCoopers LLP as TVA’s external auditor, and the TVA Board approved this recommendation. TVA had no audit committee until the restructured TVA Board established the current Audit and Ethics Committee on May 18, 2006. Before the establishment of the committee, management informed the TVA Board of the services the auditor would perform. The committee has established a practice that requires pre-approval of each non-audit service by that committee before the service is rendered. Approximately five percent of the fees included in Audit-Related Fees and All Other Fees above were pre-approved by the Audit and Ethics Committee under this practice.

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PART IV

ITEM 15. EXHIBITS AND 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 herein.

Statements of Income
Balance Sheets
Statements of Cash Flow
Statements of Changes in Proprietary Capital
Notes to Financial Statements
Report of Independent Registered Public Accounting Firm
(PricewaterhouseCoopers 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


			Additions
	Balance at		charged to					Balance at
Description	beginning of year		expense		Deductions			end of year

For the year ended September 30, 2006
Allowance for doubtful accounts
Receivables	$	7	$	4	$	—		$	11
Loans		15		1		(1	)		15
Inventories		36		13		(11	)		38


Total allowances deducted from assets	$	58	$	18	$	(12	)	$	64


For the year ended September 30, 2005
Allowance for doubtful accounts
Receivables	$	8	$	—	$	(1	)	$	7
Loans		14		1		—			15
Inventories		36		15		(15	)		36


Total allowances deducted from assets	$	58	$	16	$	(16	)	$	58


For the year ended September 30, 2004
Allowance for doubtful accounts
Receivables	$	8	$	—	$	—		$	8
Loans		14		—		—			14
Inventories		33		11		(8	)		36


Total allowances deducted from assets	$	55	$	11	$	(8	)	$	58

Page 148

(3) List of Exhibits.


Exhibit No.		Description
	3.1	Tennessee Valley Authority Act of 1933, as amended, 16 U.S.C. §§ 831-831ee (2000 & Supp. IV 2004)*

	3.2	By-laws of Tennessee Valley Authority Adopted by the TVA Board of Directors on May 18, 2006*

	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*

	10.1	$1,250,000,000 Fall Maturity Credit Agreement Dated as of May 17, 2006, as Amended, Among TVA, Bank of America, N.A., as Administrative Agent, Bank of America, N.A., as a Lender, and the Other Lenders Party Thereto*

	10.2	$1,250,000,000 Spring Maturity Credit Agreement Dated as of May 17, 2006, Among TVA, Bank of America, N.A., as Administrative Agent, Bank of America, N.A., as a Lender, and the Other Lenders Party Thereto*

	10.3	TVA Discount Notes Selling Group Agreement*

	10.4	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*

	10.5	Commitment Agreement Among Memphis Light, Gas and Water Division, the City of Memphis, Tennessee, and TVA Dated as of November 19, 2003*

	10.6	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*

	10.7	Void Walk Away Agreement Among Memphis Light, Gas and Water Division, the City of Memphis, Tennessee, and TVA Dated as of November 20, 2003*

	10.8	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*

	10.9	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*

	10.10**	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*

	10.11**	Network Lease Agreement Dated as of September 26, 2003, Between NVG Network I Statutory Trust, as Owner Lessor, and TVA, as Lessee*

	10.12**	Head Lease Agreement Dated as of September 26, 2003, Between TVA, as Head Lessor, and NVG Network I Statutory Trust, as Head Lessee*

	10.13**	Leasehold Security Agreement Dated as of September 26, 2003, Made by NVG Network I Statutory Trust to TVA*

	10.14	Description of Compensation of TVA’s Directors and Named Executive Officers*

149


Exhibit No.		Description
	10.15†	Tennessee Valley Authority Supplemental Executive Retirement Plan, Effective as of October 1, 1995*

	10.16†	Tennessee Valley Authority Executive Annual Incentive Plan, Effective in Fiscal Year 1999*

	10.17†	Tennessee Valley Authority Executive Long-Term Incentive Plan, Effective in Fiscal Year 1999*

	10.18†	Tennessee Valley Authority Long Term Deferred Compensation Plan*

	10.19†	Employment Contract Between TVA and Tom D. Kilgore Dated as of January 19, 2005*

	10.20†	Employment Contract Between TVA and Michael E. Rescoe Dated as of April 21, 2004*

	10.21†	First Deferral Agreement Between TVA and Ashok S. Bhatnagar Dated as of September 28, 2004*

	10.22†	Second Deferral Agreement Between TVA and Ashok S. Bhatnagar Dated as of September 28, 2004*

	10.23†	Deferral Agreement Between TVA and Joseph R. Bynum Dated as of March 3, 2004*

	10.24†	Deferral Agreement Between TVA and Tom D. Kilgore Dated as of March 29, 2005*

	10.25†	First Deferral Agreement Between TVA and Karl W. Singer Dated as of May 7, 2004*

	10.26†	Second Deferral Agreement Between TVA and Karl W. Singer Dated as of May 7, 2004*

	14	Disclosure and Financial Ethics Code*

	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

	32.2	Section 1350 Certification Executed by the Chief Financial Officer

† Management contract or compensatory arrangement.

* Previously filed.

** Certain schedules and exhibits have been omitted. The Tennessee Valley Authority hereby undertakes to furnish supplementally copies of any of the omitted schedules and exhibits upon request by the Securities and Exchange Commission.

150

SIGNATURE

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: July 6, 2007	TENNESSEE VALLEY AUTHORITY
	(Registrant)

	By:	/s/ Tom D. Kilgore

	Tom D. Kilgore
	President and Chief Executive Officer
	(Principal Executive Officer)

Page 151

EXHIBIT INDEX


Exhibit No.		Description
	3.1	Tennessee Valley Authority Act of 1933, as amended, 16 U.S.C. §§ 831-831ee (2000 & Supp. IV 2004)*

	3.2	By-laws of Tennessee Valley Authority Adopted by the TVA Board of Directors on May 18, 2006*

	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*

	10.1	$1,250,000,000 Fall Maturity Credit Agreement Dated as of May 17, 2006, as Amended, Among TVA, Bank of America, N.A., as Administrative Agent, Bank of America, N.A., as a Lender, and the Other Lenders Party Thereto*

	10.2	$1,250,000,000 Spring Maturity Credit Agreement Dated as of May 17, 2006, Among TVA, Bank of America, N.A., as Administrative Agent, Bank of America, N.A., as a Lender, and the Other Lenders Party Thereto*

	10.3	TVA Discount Notes Selling Group Agreement*

	10.4	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*

	10.5	Commitment Agreement Among Memphis Light, Gas and Water Division, the City of Memphis, Tennessee, and TVA Dated as of November 19, 2003*

	10.6	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*

	10.7	Void Walk Away Agreement Among Memphis Light, Gas and Water Division, the City of Memphis, Tennessee, and TVA Dated as of November 20, 2003*

	10.8	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*

	10.9	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*

	10.10**	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*

	10.11**	Network Lease Agreement Dated as of September 26, 2003, Between NVG Network I Statutory Trust, as Owner Lessor, and TVA, as Lessee*

	10.12**	Head Lease Agreement Dated as of September 26, 2003, Between TVA, as Head Lessor, and NVG Network I Statutory Trust, as Head Lessee*

	10.13**	Leasehold Security Agreement Dated as of September 26, 2003, Made by NVG Network I Statutory Trust to TVA*

	10.14	Description of Compensation of TVA’s Directors and Named Executive Officers*

152


Exhibit No.		Description
	10.15†	Tennessee Valley Authority Supplemental Executive Retirement Plan, Effective as of October 1, 1995*

	10.16†	Tennessee Valley Authority Executive Annual Incentive Plan, Effective in Fiscal Year 1999*

	10.17†	Tennessee Valley Authority Executive Long-Term Incentive Plan, Effective in Fiscal Year 1999*

	10.18†	Tennessee Valley Authority Long Term Deferred Compensation Plan*

	10.19†	Employment Contract Between TVA and Tom D. Kilgore Dated as of January 19, 2005*

	10.20†	Employment Contract Between TVA and Michael E. Rescoe Dated as of April 21, 2004*

	10.21†	First Deferral Agreement Between TVA and Ashok S. Bhatnagar Dated as of September 28, 2004*

	10.22†	Second Deferral Agreement Between TVA and Ashok S. Bhatnagar Dated as of September 28, 2004*

	10.23†	Deferral Agreement Between TVA and Joseph R. Bynum Dated as of March 3, 2004*

	10.24†	Deferral Agreement Between TVA and Tom D. Kilgore Dated as of March 29, 2005*

	10.25†	First Deferral Agreement Between TVA and Karl W. Singer Dated as of May 7, 2004*

	10.26†	Second Deferral Agreement Between TVA and Karl W. Singer Dated as of May 7, 2004*

	14	Disclosure and Financial Ethics Code*

	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

	32.2	Section 1350 Certification Executed by the Chief Financial Officer

† Management contract or compensatory arrangement.

* Previously filed.

153