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Annual Report: 2006 (Form 10-K)
Tennessee Valley Authority - Annual Report: 2006 (Form 10-K)
TENNESSEE VALLEY AUTHORITY - FORM 10-K
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(MARK ONE)
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þ |
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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
OR
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o |
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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)
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A corporate agency of the United States created by
an act of Congress
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62-0474417 |
(State or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.) |
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400 W. Summit Hill Drive
Knoxville, Tennessee
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37902 |
(Address of principal executive offices)
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(Zip Code) |
(865) 632-2101
Registrants 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 registrants 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
Page 1 of 141
Table of Contents
Page 2 of 141
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:
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Statements regarding strategic objectives; |
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Projections regarding potential rate actions; |
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Estimates of costs of certain retirement obligations; |
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Estimates regarding power and energy forecasts; |
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Expectations about the adequacy of TVAs pension plans and nuclear decommissioning trust; |
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Estimates regarding the reduction of total financing obligations; |
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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); |
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Estimates of amounts to be reclassified from Other Comprehensive
Income to earnings over the next year; |
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TVAs plans to continue using short-term debt to meet current obligations; and |
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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:
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New laws, regulations, and administrative orders, especially those related to: |
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TVAs protected service area,
The sole authority of the TVA Board to set power rates,
Various environmental and nuclear matters,
TVAs management of the Tennessee River system,
TVAs credit rating, and
TVAs debt ceiling; |
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Performance of TVAs generation and transmission assets; |
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Availability of fuel supplies; |
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Compliance with existing environmental laws and regulations; |
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Significant delays or cost overruns in construction of generation and transmission assets; |
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Significant changes in demand for electricity; |
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Legal and administrative proceedings; |
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Weather conditions; |
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Failure of transmission facilities; |
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An accident at any nuclear facility, even one unaffiliated with TVA; |
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Catastrophic events such as fires, earthquakes, floods, pandemics, wars, terrorist
activities, and other similar events, especially if these events occur in or near TVAs
service area; |
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Changes in the market price of commodities such as coal, uranium, natural gas, fuel
oil, electricity, and emission allowances; |
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Changes in the prices of equity securities, debt securities, and other investments; |
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Changes in interest rates; |
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Creditworthiness of TVA or its counterparties; |
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Rising pension costs and health care expenses; |
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Increases in TVAs financial liability for decommissioning its nuclear facilities; |
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Limitations on TVAs ability to borrow money; |
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Changes in economic environments; |
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Ineffectiveness of TVAs disclosure controls and procedures; |
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Changes in accounting standards; |
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The loss of TVAs ability to use regulatory accounting; |
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Loss of key personnel; |
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Changes in technology; and |
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Unforeseeable events. |
Page 4 of 141
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 TVAs 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 TVAs
fiscal years ended September 30. References to years in the biographical information about directors and executive
officers in Item 10, Directors and Executive Officers of the Registrant 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 SECs 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. TVAs SEC reports are also available to the
public without charge from the website maintained by the SEC at www.sec.gov and TVAs website at
www.tva.gov. Information contained on TVAs website shall not be deemed incorporated into, or to
be a part of, this Annual Report.
Page 5 of 141
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. TVAs 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:
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TVA was created by an act of the U.S. Congress and is a wholly-owned corporate
agency of the United States. |
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TVAs board of directors (the TVA Board) is appointed by the President with
the advice and consent of the U.S. Senate. |
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TVA holds its real properties as an agent for the United States. |
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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). |
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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. |
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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. |
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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 TVAs 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, Managements
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 members term
ends each year. The TVA Boards 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 TVAs executive officers is discussed in Item 10, Directors and
Executive Officers of the Registrant.
Service Area
TVA operates the nations 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.
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
Page 6 of 141
supply on July 1, 1957. This statutory provision is referred to as the fence because it bounds
TVAs 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 TVAs operating revenues in 2006,
2005, and 2004, amounting to $9.1 billion, $7.7 billion, and $7.4 billion, respectively. TVAs
revenues by state for the last three years are detailed in the table below:
Electricity Sales by State
(in millions)
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2006 |
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2005 |
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2004 |
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Alabama |
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$ |
1,268 |
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$ |
1,054 |
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$ |
1,033 |
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Georgia |
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228 |
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186 |
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182 |
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Kentucky |
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909 |
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832 |
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731 |
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Mississippi |
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826 |
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674 |
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658 |
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North Carolina |
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47 |
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39 |
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38 |
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Tennessee |
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5,764 |
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4,820 |
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4,734 |
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Virginia |
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7 |
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4 |
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4 |
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9,049 |
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7,609 |
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7,380 |
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Sale for resale |
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13 |
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95 |
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59 |
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$ |
9,062 |
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$ |
7,704 |
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$ |
7,439 |
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TVA SERVICE AREA
Page 7 of 141
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 TVAs 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)
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2006 |
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2005 |
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2004 |
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Municipalities and cooperatives |
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$ |
7,880 |
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$ |
6,561 |
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$ |
6,457 |
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Industries directly served |
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1,066 |
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962 |
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842 |
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Federal agencies and other
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Federal agencies directly served |
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103 |
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86 |
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81 |
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Exchange sales |
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13 |
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95 |
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59 |
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Total |
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$ |
9,062 |
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$ |
7,704 |
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$ |
7,439 |
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Municipalities and Cooperatives
Revenues from distributor customers accounted for 85.8 percent of TVAs 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:
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Contracts that require five years notice to terminate; |
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Contracts that require 10 years notice to terminate; and |
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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 TVAs 2006 total operating
revenues represented by these revenues are summarized in the table below.
TVA Distributor Customer Contracts
As of September 30, 2006
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Number of |
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Sales to |
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Percentage of Total |
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Distributor |
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Distributor |
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Operating Revenues |
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Contract Arrangement |
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Customers |
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Customers in 2006 |
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in 2006 |
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(in millions) |
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15-Year Termination Notice |
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5 |
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$ |
92 |
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1.0 |
% |
10-Year Termination Notice |
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48 |
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2,625 |
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28.6 |
% |
5-Year Termination Notice * |
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99 |
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4,893 |
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53.3 |
% |
Notice Given
- Less than 5
Years |
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Remaining* |
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6 |
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270 |
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2.9 |
% |
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158 |
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$ |
7,880 |
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85.8 |
% |
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* |
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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). |
TVAs 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.
Page 8 of 141
Although no single customer accounted for 10 percent or more of TVAs 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 TVAs 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 Acts objective of
providing an adequate supply of power at the lowest feasible rates.
Termination Notices
Six of TVAs 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
TVAs total 2006 operating revenues represented by these revenues.
Distributor Customers with Termination Notices in Effect
As of September 30, 2006
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TVA Sales to |
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Distributor |
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Percentage |
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Date of Termination |
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Customer |
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of TVA Operating |
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Distributor Customer |
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Location |
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of Power Contract |
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in 2006 |
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Revenues in 2006 |
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(in millions) |
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Monticello Electric Plant Board |
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Kentucky |
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November 2008 |
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$ |
6 |
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0.1 |
% |
Glasgow Electric Plant Board |
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Kentucky |
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November 2008 |
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21 |
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0.2 |
% |
Warren Rural Electric
Cooperative Corporation |
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Kentucky |
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April 2009 |
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97 |
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1.0 |
% |
Paducah Power System |
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Kentucky |
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December 2009 |
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39 |
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0.4 |
% |
Princeton Electric Plant Board |
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Kentucky |
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January 2010 |
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6 |
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0.1 |
% |
Duck River Electric Membership
Corporation |
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Tennessee |
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August 2010 |
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101 |
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1.1 |
% |
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Total |
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$ |
270 |
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2.9 |
% |
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In 2006, TVA agreed to a one-year extension of the effective date of termination of TVAs
power supply contract with Warren and a two-year extension with Duck River Electric Membership.
Warrens one-year extension includes a surcharge for costs associated with the additional year.
(The extended termination dates are shown in the table above).
Page 9 of 141
Other Customers
Revenues from directly served industrial customers accounted for 11.6 percent of TVAs 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 customers contract demand and the period of time service has been
provided.
The United States Enrichment Corporation (USEC) is TVAs largest directly served industrial
customer, with sales to USEC for its Paducah, Kentucky, facility representing 3.9 percent of TVAs
total operating revenues in 2006. TVAs 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 TVAs 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:
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Operation, maintenance, and administration of its power system; |
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Payments to states and counties in lieu of taxes; |
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Debt service on outstanding indebtedness; |
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Payments to the U.S. Treasury in repayment of and as a return on the Appropriation
Investment in TVAs power facilities; and |
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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 TVAs power business. |
In setting TVAs 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 organizations 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 TVAs 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
Page 10 of 141
reflects the cause-and-effect relationship between a regulated entitys 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 TVAs 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
TVAs 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. TVAs 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 TVAs forecasts.
Power Supply
General
TVAs 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 TVAs 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
Page 11 of 141
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 TVAs 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 TVAs 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.
TVAs 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 TVAs 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, TVAs 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, Managements Discussion
and Analysis of Financial Condition and Results of Operations Risk Management Activities Credit
Risk. A portion of TVAs 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 Alcoas energy needs. TVAs 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 |
Page 12 of 141
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 SEPAs 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. TVAs 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 TVAs 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 TVAs obligations under these
PURPA-required contracts, the capacity of the associated qualifying generation facilities is not
included in TVAs 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 TVAs total
power supply during these years.
For more information regarding TVAs 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:
Page 13 of 141
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 TVAs combustion turbine units were leased to private
entities and leased back to TVA under long-term leases. |
Page 14 of 141
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 Commissions 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 TVAs 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 TVAs ability to use the site for future projects. |
|
(3) |
|
On May 3, 2006, the NRC approved TVAs 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 TVAs 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, DOEs
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
Page 15 of 141
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
TVAs 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 TVAs 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
TVAs consumption of various types of fuel depends on several factors, the most important of
which are the demand for electricity by TVAs customers, the availability of various generating
units, and the availability and cost of fuel. The following table indicates TVAs 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 TVAs average fuel costs in cents per kilowatt-hours for the
years indicated:
Page 16 of 141
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, TVAs 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 TVAs 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 TVAs 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, TVAs 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 TVAs 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 TVAs 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 TVAs natural gas in inventory was $2 million
and $0.4 million, respectively, and the net book value of TVAs 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.
Page 17 of 141
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 TVAs use of this blended nuclear fuel product. Over the life
of the program, TVA projects that DOEs share of savings generated by TVAs 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 TVAs 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 TVAs 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.
Page 18 of 141
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 TVAs 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. TVAs 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 TVAs power operations. TVA
calculates weather degree days for each of the five largest cities in TVAs service area. If the
average temperature
Page 19 of 141
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 Warrens 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 Kentuckys 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
Page 20 of 141
were to become law, FERC could require TVA to provide wheeling from other power suppliers to
wholesale customers inside that portion of TVAs 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, |
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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, |
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New limitations on TVA retail sales in TVAs current service area, |
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Stranded cost recovery through 2007, |
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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, |
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TVA to be subject to antitrust laws (with the exception of monetary damages and
attorneys fees), |
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At individual distributor customer election, a reduction in TVAs existing
regulation of distributor customers, and |
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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 TVAs activities or significantly change TVAs 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
As part of the Consolidated Appropriations Act, 2005, Congress added Section 37 to the
Securities Exchange Act of 1934, as amended (the Exchange Act). This section requires TVA to
file with the Securities and Exchange Commission beginning with this 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.
Federal Energy Regulatory Commission
Although TVA is not a public utility as defined in the Federal Power Act (FPA) and is thus
not subject to the full jurisdiction of the FERC under the FPA, FERC regulation does affect some of
TVAs activities, including transmission, interconnection, and, potentially, a limited type of
power transaction that TVA does not now use.
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.
Page 21 of 141
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.
Governmental Entities
TVAs activities and records are also subject to review by various entities including TVAs
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)
|
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|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
|
|
Alabama |
|
$ |
93 |
|
|
$ |
89 |
|
|
$ |
81 |
|
Georgia |
|
|
6 |
|
|
|
6 |
|
|
|
5 |
|
Illinois |
|
|
<1 |
|
|
|
<1 |
|
|
|
<1 |
|
Kentucky |
|
|
33 |
|
|
|
30 |
|
|
|
27 |
|
Mississippi |
|
|
20 |
|
|
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20 |
|
|
|
19 |
|
North Carolina |
|
|
2 |
|
|
|
2 |
|
|
|
2 |
|
Tennessee |
|
|
221 |
|
|
|
218 |
|
|
|
203 |
|
Virginia |
|
|
<1 |
|
|
|
<1 |
|
|
|
<1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
376 |
|
|
$ |
365 |
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|
$ |
338 |
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|
Environmental Matters
As is the case across the utility industry and in other industrial sectors, TVAs activities
are subject to certain federal, state, and local environmental statutes and regulations. Major
areas of regulation affecting TVAs 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 TVAs 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 (NOx) in the eastern half of the United States (including in all of TVAs
operating area), and the
Page 22 of 141
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.
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, NOx, 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 NOx 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 NOX
and SO2 from 28 eastern states. CAIR is currently in effect in all of these states as a
federal rule. States in TVAs 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
NOx 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 NOx emissions are extensively regulated and will be regulated further under
state programs to achieve and maintain EPAs 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 NOx emissions during the summer (when ozone levels increase) by 81 percent by
installing various controls including low-NOx burners and/or combustion controls on 58
of its coal fired units. (The AFBC unit at Shawnee is inherently low NOx emitting.) TVA
has also installed SCRs 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 NOx 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 NOx removal capabilities than SCRs but higher removal
capabilities than SNCRs. The initial HERT testing program
Page 23 of 141
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. TVAs NOx 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.
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 NOx 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 NOx reduction
requirements of CAIR will continue to help states achieve EPAs ozone and fine particle standards.
CAIR caps and reduces NOx 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 EPAs national ambient air quality standard for particulate
matter. TVAs 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 years
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 NOx 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 EPAs 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.
Page 24 of 141
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. TVAs 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 EPAs 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 TVAs 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 states 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 facilitys 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 TVAs 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 EPAs 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
Page 25 of 141
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 TVAs allocated share of such costs and evaluate the likely
effectiveness of TVAs 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, TVAs 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 TVAs
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 TVAs
cash flows, results of operations, and financial condition.
For ease of reference, the risk factors are presented in three categories: strategic risks,
operating risks, and financial risks.
Strategic Risks
New laws and regulations may negatively affect TVAs 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.
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TVA could lose its protected service territory. |
Page 26 of 141
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TVAs service area is primarily defined by two provisions of law. |
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|
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 TVAs defined
service area. This provision is often called the fence since it limits TVAs 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 TVAs
defined service area. This provision is often called the anti-cherrypicking
provision since it prevents competitors from cherrypicking TVAs 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 TVAs 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 |
|
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|
TVA might be subject to additional regulatory oversight that could impede TVAs
ability to manage its business. |
|
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|
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 TVAs operating and maintenance costs, or
even lead to TVAs 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 TVAs
operating licenses.
|
|
|
TVA could lose responsibility for managing the Tennessee River system. |
TVAs management of the rivers is important to effective operation of the power system.
TVAs 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 TVAs operations.
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|
|
Congress could take actions that lead to a downgrade of TVAs credit rating. |
TVAs rated securities are currently rated Aaa by Moodys Investors Service and AAA by
Standard and Poors and Fitch Ratings, which are the highest ratings assigned by these
rating agencies. TVAs 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. TVAs
current ratings are based to a large extent on the body of legislation that defines TVAs
business structure. Key characteristics of TVAs business defined by
legislation include
(1) the TVA Boards ratemaking authority, (2) the current competitive environment, which is
defined by the fence and the anti-cherrypicking provision, and (3) TVAs status as a
corporate agency and
Page 27 of 141
instrumentality of the United States. Accordingly, if Congress takes any action that
effectively alters any of these characteristics, TVAs credit ratings could be downgraded.
|
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|
TVAs 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 TVAs total operating revenues in 2006, the loss of additional customers could have a
material adverse effect on TVAs cash flows, results of operations, and financial condition.
See Item 1, Business Customers Termination Notices.
Operational Risks
TVAs generation and transmission assets may not operate as planned.
Many of TVAs 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:
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Might have to invest a significant amount of resources to repair or replace the assets; |
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Might be unable to operate the assets for a significant period of time; |
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Might have to purchase replacement power on the open market; |
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Might not be able to meet its contractual obligations to deliver power; and |
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Might have to remediate collateral damage caused by a failure of the assets. |
In addition, the failure of TVAs 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 TVAs cash flows, results of operations, and financial condition.
TVAs 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 TVAs fuel suppliers. These disruptions could adversely affect TVAs ability to
operate its facilities and could require TVA to acquire power at higher prices on the spot
market, thereby adversely affecting TVAs cash flows, results of operations, and financial
condition.
Compliance with existing environmental laws and regulations may affect TVAs 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:
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Compliance with existing environmental laws and regulations may cost TVA more than it
anticipates. |
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At some of TVAs 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. |
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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. |
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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
TVAs service area increases, TVA is contractually obligated to take steps to meet this increased
demand.
If demand for power in the TVAs 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 TVAs 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, TVAs 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 TVAs 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 TVAs 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 TVAs cash flows, results of
operations, and financial condition. See Item 3, Legal Proceedings.
TVAs 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 TVAs ability to supply power to its customers, because in
periods of low rainfall or drought, TVAs 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 TVAs ability to use water from the Tennessee River system
for cooling at its generating facilities, thereby limiting TVAs ability to operate its
generating facilities.
TVAs transmission reliability could be affected by problems at other utilities or its own
facilities.
TVAs 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 TVAs own facilities, may cause interruptions in TVAs
transmission service. If TVA were to suffer a transmission service interruption, TVAs 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.
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Catastrophic events could affect TVAs 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 TVAs power operations and
negatively affect TVAs 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 TVAs. To the extent
these technologies become a more cost-effective option for certain customers, TVAs sales to
these customers could be reduced, thereby negatively affecting TVAs cash flows, results of
operations, and financial condition.
Financial Risks
TVA is subject to a variety of market risks that could negatively affect TVAs 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.
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Commodity Price Risk. Prices of commodities critical to TVAs 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. |
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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 TVAs cash flows, results of operations, and financial condition. |
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Interest Rate Risk. Changes in interest rates could negatively affect TVAs 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 TVAs 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 TVAs counterparties fail to perform their
obligations, TVAs 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, Managements 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 TVAs credit rating.
A downgrade in TVAs credit rating could have material adverse effects on TVAs 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:
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A downgrade would increase TVAs interest expense by increasing the interest rates that
TVA pays on new debt securities that it issues. An increase in TVAs interest expense
would reduce the amount of cash available for other purposes, which could result in the
need to increase borrowings, to reduce other expenses or capital investments, or to
increase electricity rates. |
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A significant downgrade could result in TVAs having to post collateral under certain
physical and financial contracts that contain rating triggers. |
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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. |
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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, Managements 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.
TVAs costs of providing pension benefits and other postretirement benefits depend upon a
number of factors, including, but not limited to:
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Provisions of the pension and postretirement benefit plans; |
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Changing employee demographics; |
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Rates of increase in compensation levels; |
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Rates of return on plan assets; |
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Discount rates used in determining future benefit obligations; |
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Rates of increase in health care costs; |
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Levels of interest rates used to measure the required minimum funding levels of the plans; |
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Future government regulation; and |
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Contributions made to the plans. |
Any number of these factors could increase TVAs costs of providing pension and other
postretirement benefits and require TVA to make significant unplanned contributions to the
plans. Such contributions would negatively affect TVAs 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 TVAs 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:
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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; |
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The assumed rate of return on plan assets, which is currently five percent, has been
approved by the TVA Board; |
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Changes in technology and experience related to decommissioning cause decommissioning
cost estimates to increase significantly; or |
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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
TVAs 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.
TVAs 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 TVAs
current cash requirements. In addition, TVA has access to $2.5 billion of credit facilities
with a national bank. In light of TVAs 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
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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 TVAs 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 TVAs business by limiting TVAs ability to borrow money
and increasing the cost of servicing TVAs debt. In addition, approaching or reaching this
debt ceiling could lead to increased legislative or regulatory oversight of TVAs activities.
TVAs cash flows, results of operations, and financial condition could be negatively affected by
economic downturns.
Sustained downturns or weakness in the economy in TVAs service area or other parts of the
United States could reduce overall demand for electricity and thus reduce TVAs electricity
sales and cash flows, especially as TVAs industrial customers reduce their operations and thus
their consumption of electricity.
TVAs 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 TVAs 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.
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, TVAs 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 TVAs combustion turbines are subject to lease-leaseback arrangements. For
more information regarding these arrangements, see Note 11 Other Financing Obligations.
Page 32 of 141
Transmission Properties
TVAs transmission system interconnects with systems of surrounding utilities and consists
primarily of the following assets:
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Approximately 17,000 circuit miles of transmission lines, including 2,400 miles of
extra-high-voltage (500,000 volt) transmission lines; |
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537 substations, power switchyards, and switching stations; |
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1,045 individual interchange and customer connection points; and |
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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 TVAs 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:
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11,000 miles of reservoir shoreline; |
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293,000 acres of reservoir land; |
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650,000 surface acres of water; and |
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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. TVAs 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. TVAs primary sources of authority to dispose of real
property are briefly described below:
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Under Section 31 of the TVA Act, TVA has authority to dispose of surplus real
property at a public auction. |
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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. |
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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. |
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Under 40 U.S.C. § 1314, TVA has authority to grant easements for
rights-of-way or other purposes. |
In addition, TVAs 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.
Page 33 of 141
ITEM 3. LEGAL PROCEEDINGS
TVA is involved in various claims amounting to approximately $54 million incidental to the
conduct of its business for which it has assessed the likelihood of gain or loss. The claims,
grouped by likelihood of loss, include (1) claims recorded by TVA in the amount of $28 million
representing probable losses of $27 million and losses deemed reasonably possible of $1 million,
and (2) claims of about $26 million for which a determination of loss cannot be made at this time.
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 TVAs 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 TVAs defenses. TVA filed a motion seeking permission to take an interlocutory appeal of the
courts ruling on summary judgment. On July 31, 2006, the court reconsidered its decision on
summary judgment with respect to TVAs 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 TVAs 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 TVAs practice of setting rates for electric power charged by
distributor customers through TVAs 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 TVAs 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 courts decision, and held, among other things, that
TVAs rates were not subject to judicial review and that TVA is not subject to antitrust liability
when doing so would interfere with TVAs 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
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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.
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 TVAs 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 TVAs 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 Alabamas 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 courts
decision to the Eleventh Circuit. On November 22, 2005, the Eleventh Circuit affirmed the district
courts 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 Carolinas Attorney General filed suit against TVA in the United States
District Court for the Western District of North Carolina alleging that TVAs 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 TVAs 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 TVAs 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,
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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 Carolinas 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 TVAs 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 EPAs 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 Katrinas increased destructive force. The
plaintiffs are seeking monetary damages among other relief. TVA has moved to dismiss the complaint
on grounds that TVAs 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. Arevas
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 TVAs business, although it is possible that some
outcomes could require TVA to change how it handles certain personnel matters or operates its
plants.
It is not possible to predict with certainty whether TVA will incur any liability or to
estimate the damages, if any, that TVA might incur in connection with the lawsuits and claims
described above except as specifically noted. TVA has recognized charges to earnings and actual
costs, including legal fees and expenses, related to litigation. No assurance can be given that
TVA will not be subject to significant additional claims and material additional liabilities.
If actual liabilities significantly exceed the estimates made, the results of operations,
liquidity, and financial condition could be materially adversely affected. In accordance with SFAS
No. 5, Accounting for Contingencies, TVA has accrued approximately $28 million as of September
30, 2006, related to the cases described above.
Page 36 of 141
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
Page 37 of 141
PART II
ITEM 5. MARKET FOR REGISTRANTS 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, net 4 |
|
|
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 TVAs Knoxville Office Complex based on TVAs
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. |
Page 38 of 141
Balance Sheets Data
At September 30
(in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
2004 |
|
2003 1 |
|
2002 1 |
|
|
|
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 |
|
|
$ |
5,8193 |
|
|
$ |
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. |
Reconciliation of Non-GAAP Items Required by Securities and Exchange Commission Rules
Net Cash Flow
TVA uses the non-GAAP net cash flow measure to evaluate its ability to produce cash flow
available to reduce total financing obligations after investing in capital additions and
improvements. The traditional GAAP cash flow statement does not accommodate this focus on total
financing obligations, and TVA has developed the net cash
Page 39 of 141
flow measure for this internal performance measurement purpose. The following is a reconciliation
of non-GAAP disclosure for the respective periods to the most directly comparable GAAP measure.
TVA defines net cash flow as cash from operating activities (excluding energy prepayments and
changes in short-term investments) less cash used in investing activities. By measuring net cash
flow, TVA assesses the debt reduction and investment capacity of its business.
Following is a reconciliation of net cash provided by operating activities to net cash flow:
Non-GAAP Cash Flow
For the years ended September 30
(in millions)
|
|
|
|
|
|
|
2006 |
|
Net change in cash and cash equivalents |
|
$ |
(2 |
) |
Energy prepayment |
|
|
105 |
|
Net cash (used in) provided by financing activities |
|
|
289 |
|
|
|
|
|
Total |
|
$ |
392 |
|
|
|
|
|
Total Financing Obligations
TVA uses the Total Financing Obligations (TFOs) measure as an internal indicator of TVAs
financial flexibility. The components of TFOs include Bonds, lease financing obligations, and
energy prepayment obligations. Long-term debt is adjusted for non-cash foreign currency valuations
and unamortized discounts or premiums on the sale of Bonds because these amounts would not require
a cash outlay upon redemption of the Bonds. Existing capital lease obligations are not included in
the TFOs calculation.
Following is a reconciliation of financial obligations to total financing obligations:
Non-GAAP Financing Obligations
As of September 30
(in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
2002 |
|
|
|
|
Financial Obligations |
|
$ |
25,385 |
|
|
$ |
25,556 |
|
|
$ |
26,032 |
|
|
$ |
26,053 |
|
|
$ |
25,573 |
|
Less foreign currency valuations |
|
|
(195 |
) |
|
|
(52 |
) |
|
|
(113 |
) |
|
|
35 |
|
|
|
220 |
|
Plus discount on bonds |
|
|
178 |
|
|
|
227 |
|
|
|
102 |
|
|
|
223 |
|
|
|
185 |
|
Capital leases |
|
|
(128 |
) |
|
|
(150 |
) |
|
|
(138 |
) |
|
|
(151 |
) |
|
|
(162 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
25,240 |
|
|
$ |
25,581 |
|
|
$ |
25,883 |
|
|
$ |
26,160 |
|
|
$ |
25,816 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Page 40 of 141
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 TVAs 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. |
Page 41 of 141
ITEM 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(Dollars in millions except where noted)
Business Overview
Distinguishing Features of TVAs Business
TVA operates the nations 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 TVAs sales
activities, essentially limiting TVA to power sales within a defined service area.
Correspondingly, however, the possibility of sales by others into TVAs 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 TVAs 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. TVAs operations were originally funded primarily with appropriations from Congress.
In 1959, however, Congress passed legislation that required TVAs 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 TVAs $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 TVAs sources of funding, see Item 7, Managements Discussion
and Analysis of Financial Condition and Results of Operations Liquidity and Capital Resources
Sources of Liquidity.
Stewardship Activities. TVAs 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 TVAs fossil fuel and
nuclear power plants.
Page 42 of 141
Strategy and Performance Indicators
Strategy. In the context of these distinguishing features of TVAs business, the recently
restructured TVA Board is now determining TVAs 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 TVAs 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 TVAs transmission system |
|
|
|
|
|
Customer
|
|
Customer Satisfaction Survey
|
|
Measures the satisfaction of TVAs 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 TVAs
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 TVAs generation plants, increased fuel and purchased power costs, and adverse weather
conditions.
Performance of Certain Generation Assets During the Summer. Many of TVAs generation assets
have been operating since the 1950s and have been in near constant service since they were
completed. In 2006, some of TVAs 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. |
Page 43 of 141
Increased Fuel and Purchased Power Costs. During 2006, TVAs fuel and purchased power costs
increased $732 million, or 28.1 percent, over TVAs 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 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 TVAs 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 TVAs hydroelectric
generation, as well as the amount of water available for cooling TVAs nuclear and coal-fired
plants. Hydroelectric generation decreased from 10 percent of TVAs total generation in 2005 to
six percent of TVAs 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 TVAs other
generation units, which are more costly to operate than TVAs 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, total
financing obligations, retention of customers, TVAs service area, and legislation.
New Generation. TVA is considering the proper balance between using purchased power and TVAs
own generation to meet the TVA service areas growing power supply needs. At September 30, 2006,
4,275 megawatts, or 12.2 percent, of TVAs 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 TVAs 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 TVAs 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.
Total Financing Obligations. As of September 30, 2006, TVA had $25.2 billion of Bonds, energy
prepayment obligations, and lease financing obligations outstanding (collectively, Total Financing
Obligations or TFOs). Payment obligations on TFOs are fixed and do not change with the amount
of power sold. If competition increases, large TFO payment obligations could limit TVAs ability
to adjust to market pressure. During 2006 and 2005, TVA reduced TFOs by $341 million and $302
million, respectively, and TVA has reduced TFOs by a total of $2.5 billion since 1996, when TFOs
reached their highest level. While prudent management of TFOs will remain an important strategic
consideration in the future, increased capital commitments may make it difficult for TVA to
continue its trend of reducing TFOs.
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 TVAs distributor customers had notices terminating their power contracts still in
effect, and sales to these six distributor customers generated 2.9 percent of TVAs total operating
revenues in 2006. Five of these distributor customers are located in Kentucky, where power rates
are among the lowest in the nation.
Page 44 of 141
Challenges to TVAs Service Area. There are currently two significant challenges to TVAs
service area involving distributor customers located in Kentucky. The first is the FERC
administrative proceeding, which is now in litigation, involving the request of East Kentucky Power
Cooperative to interconnect its transmission system with TVAs 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 TVAs total operating
revenues in 2006, a negative resolution to either of these challenges could establish a precedent
for reducing TVAs 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 TVAs 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
TVAs 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. TVAs
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 TVAs $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 TVAs 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. During the past three years, TVA issued two types of Bonds: 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.
TVAs rated Bonds are currently rated Aaa by Moodys Investors Service, and AAA by
Standard & Poors and 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 a discussion on the effects of a reduction in TVAs credit
rating, see Item 7, Managements Discussion and Analysis of Financial Condition and Results of
Operations Risk Management Activities Credit Risk.
TVA relies heavily on proceeds from the issuance of discount notes to fund current cash
requirements. During 2006, 2005, and 2004, the average outstanding balance of discount notes was
$2.0 billion, $2.1 billion, and $1.1 billion.
Page 45 of 141
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.
For more information regarding TVAs debt activities, see Note 9.
$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 TVAs 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
TVAs 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 TVAs 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 TVAs Balance Sheets. For more
information regarding TVAs sales of receivables and loans, see Note 1 Sales of
Receivables/Loans.
Page 46 of 141
2006 Compared to 2005
Net cash provided by operating activities increased $552 million from 2005 to 2006. This
increase resulted from:
|
|
|
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
increase 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 TVAs breach of contract suit
against the DOE; and |
Page 47 of 141
|
|
|
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; |
|
|
|
|
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 in 2005 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:
Page 48 of 141
|
|
|
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; |
|
|
|
|
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 managements
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 Requirements 4 |
|
$ |
1,248 |
|
|
$ |
1,052 |
|
|
$ |
1,199 |
|
|
$ |
1,135 |
|
|
$ |
1,162 |
|
|
$ |
1,180 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Page 49 of 141
|
|
|
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
TVAs 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. |
|
(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 TVAs 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 TVAs 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 |
|
|
432 |
|
|
|
40 |
|
|
|
43 |
|
|
|
42 |
|
|
|
41 |
|
|
|
40 |
|
|
|
226 |
|
Retirement plans |
|
|
90 |
|
|
|
90 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
54,625 |
|
|
$ |
6,359 |
|
|
$ |
2,240 |
|
|
$ |
3,985 |
|
|
$ |
1,859 |
|
|
$ |
2,600 |
|
|
$ |
37,582 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note |
|
|
|
* |
|
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 TVAs
use of this blended nuclear fuel product. As of September 30, 2006, TVA projects that DOEs share
of savings generated by TVAs 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 50 of 141
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 51 of 141
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
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. |
Page 52 of 141
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 1Restricted 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:
Page 53 of 141
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;
|
Page 54 of 141
|
|
|
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 TVAs
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.
Page 55 of 141
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
Page 56 of 141
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, Managements 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 TVAs 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 TVAs financial condition, changes in financial position, or results
of operations. TVAs critical accounting policies are also discussed in Note 1 Summary of
Significant Accounting Policies.
Regulatory Accounting
Although TVAs power rates are not subject to regulation through a public service commission
or other similar entity, TVAs 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) TVAs 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 TVAs 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
EnterprisesAccounting 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 assets carrying value is adjusted downward to its estimated fair value with a
corresponding impairment loss recognized in earnings.
Page 57 of 141
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 Obligationsan
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 NRCs regulations, the present value of the estimated future nuclear decommissioning cost
was $670 million. This decommissioning cost estimate is based on NRCs 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 trusts 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 TVAs application for license extension at each of TVAs
three Browns Ferry units. The license extension has the effect of improving the funded status of
TVAs 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:
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Timing In projecting decommissioning costs, two assumptions must be made to
estimate the timing of plant decommissioning. First, the date of the plants
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. |
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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 |
Page 58 of 141
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estimates to change significantly. The impact of these potential changes is not
presently determinable. TVAs cost studies assume current technology and regulations. |
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Discount Rate TVAs decommissioning fund uses a blended rate of 5.65 percent
to calculate the present value of the weighted estimated cash flows required to satisfy
TVAs decommissioning obligation. |
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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. |
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Cost Escalation Factors TVAs 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. TVAs 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:
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Interest and discount rates used in determining the future benefit obligations; |
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Projected health care cost trend rates; |
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Expected long-term rate of return on plan assets; and |
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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 TVAs 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 Moodys 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 Systems policy includes a
permissible three percent deviation from these target allocations. The TVA Retirement System Board
can take action, as appropriate, to rebalance the systems 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
Page 59 of 141
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:
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Impact on 2006 |
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Change in |
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Impact on 2007 |
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Projected Benefit |
Actuarial Assumption |
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Assumption |
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Pension Cost |
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Obligation |
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(Increase in millions) |
Discount rate |
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(0.25 |
%) |
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$ |
18 |
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$ |
248 |
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Rate of return on plan assets |
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(0.25 |
%) |
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$ |
16 |
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NA |
Rate of compensation |
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0.25 |
% |
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$ |
12 |
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$ |
67 |
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The following chart reflects the sensitivity of postretirement benefit cost to changes in
certain actuarial assumptions:
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Impact on 2006 |
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Impact on 2007 |
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Projected |
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Change in |
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Postretirement |
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Postretirement |
Actuarial Assumption |
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Assumption |
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Benefit Cost |
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Benefit Obligation |
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(Increase in millions) |
Discount rate |
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(0.25 |
%) |
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$ |
1 |
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$ |
14 |
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Health care cost trend |
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0.25 |
% |
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$ |
1 |
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$ |
15 |
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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, TVAs 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, TVAs 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.
Page 60 of 141
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 employers 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,
TVAs 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
VIEs 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 TVAs results of operations or financial condition.
Conditional Asset Retirement Obligations
In March 2005, the FASB issued FIN No. 47, Accounting for Conditional Asset Retirement
Obligationsan 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
Page 61 of 141
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 entitys 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 TVAs 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 debtors 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 debtors 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
Page 62 of 141
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 TVAs 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 TVAs 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 TVAs 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 TVAs 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 employers 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 plans overfunded status or a
liability for a plans underfunded status; measure a plans assets and its obligations that
determine its funded status as of the end of the employers 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
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and benefit obligations as of the date of the employers 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 TVAs 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 TVAs $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 TVAs 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 TVAs 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.
Page 64 of 141
Environmental Matters
As is the case across the utility industry and in other industrial sectors, TVAs activities
are subject to certain federal, state, and local environmental statutes and regulations. Major
areas of regulation affecting TVAs 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 TVAs 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 (NOx) in the eastern half of the United States (including in all of TVAs
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.
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, NOx, 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 NOx 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 NOX
and SO2 from 28 eastern states. CAIR is currently in effect in all of these states as a
federal rule. States in TVAs 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
NOx 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
Page 65 of 141
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 NOx emissions are extensively regulated and will be regulated further under
state programs to achieve and maintain EPAs 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 NOx emissions during the summer (when ozone levels increase) by 81 percent by
installing various controls including low-NOx burners and/or combustion controls on 58
of its coal-fired units. (The AFBC unit at Shawnee is inherently low NOx emitting.) TVA
has also installed SCRs 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 NOx 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 NOx 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. TVAs
NOx 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.
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 NOx 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 NOx reduction
requirements of CAIR will continue to help states achieve EPAs ozone and fine particle standards.
CAIR caps and reduces NOx 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 EPAs national ambient air quality standard for particulate
matter. TVAs 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 years
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 NOx 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.
Page 66 of 141
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 EPAs 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
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. TVAs 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 EPAs 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 TVAs 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 states 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 facilitys 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
Page 67 of 141
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 TVAs 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 EPAs 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 TVAs
allocated share of such costs and evaluate the likely effectiveness of TVAs 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, TVAs 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
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.
Legal Proceedings
For a discussion of TVAs 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
TVAs 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 ERCs current members are
the President (chair), the Chief Financial Officer, the
Page 68 of 141
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 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 TVAs 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 TVAs
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 TVAs 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 TVAs 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. TVAs VaR calculations are based on a 95 percent confidence level,
which means that there is a five percent probability that TVAs 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 TVAs electricity,
natural gas, SO2 emission allowance, and NOx 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.
Page 69 of 141
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 |
|
NOx Emission Allowances 4
|
|
|
1 |
|
|
|
5 |
|
|
|
10 |
|
|
|
1 |
|
|
|
|
Notes |
|
|
|
1 |
|
TVAs VaR calculations for electricity are based on
its on-peak electricity portfolio, which includes electricity forwards
and option contracts. |
|
2 |
|
TVAs VaR calculations for natural gas are based on
TVAs natural gas portfolio, which includes natural gas forwards,
futures, and options on futures contracts. |
|
3 |
|
TVAs VaR calculations for SO2 emission
allowances are based on TVAs portfolio of SO2 emission
allowances. |
|
4 |
|
TVAs VaR calculations for NOx
emission allowances are based on TVAs portfolio of NOx
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.
TVAs average electricity market risk exposure has increased annually since 2003. The
increases have resulted primarily from TVAs 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 TVAs 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 TVAs 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 TVAs natural gas portfolio for 2006 for a 10-day holding period was $26 million.
Emission Allowances. TVA acquires both SO2 emission allowances and NOx
emission allowances to help TVA comply with the emission requirements of the CAA and its
implementing regulations. In addition to meeting TVAs 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 TVAs SO2 emission allowance portfolio and NOx emission
allowance portfolio was $20 million and $5 million, respectively.
Fuel Oil. TVA purchases fuel oil as a substitute fuel source for TVAs combustion turbines.
Thus, TVAs hedge against market risk for fuel oil is the use of natural gas and is captured in the
natural gas VaR.
Page 70 of 141
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, TVAs 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 TVAs 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
TVAs investment price risk relates primarily to investments in TVAs 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, Managements Discussion and Analysis of
Financial Condition and Results of Operations Critical Accounting Policies and Estimates
Nuclear Decommissioning for more information regarding TVAs 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, Managements 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 TVAs pension fund.
Interest Rate Risk
TVAs interest rate risk is related primarily to its short-term investments, its Bonds, and
TVAs swaption transactions and an interest rate swap related to one of TVAs swaption
transactions.
Page 71 of 141
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 TVAs investments in its pension fund and nuclear
decommissioning fund. See Item 7, Managements 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, TVAs short-term borrowings were $2.4 billion, and
the current maturities of long-term debt were $1.0 billion. Based on TVAs 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 TVAs 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 TVAs outstanding
long-term debt were fixed. Accordingly, an immediate one percentage point increase in interest
rates would not have affected TVAs interest expense associated with its long-term debt. When
TVAs 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, TVAs cash flows, results of operations, and financial condition may be adversely
affected. This risk is somewhat mitigated by the fact that TVAs debt portfolio is diversified in
terms of maturities and has a long average life. As of September 30, 2006, the average life of
TVAs debt portfolio was 17 years. A schedule of TVAs 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 TVAs 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 TVAs 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 TVAs 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 TVAs 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 counterpartys
nonperformance of its contractual obligations. Where exposed to credit risk, TVA analyzes the
counterpartys 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.
Page 72 of 141
Credit of Customers
The majority of TVAs 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 TVAs 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 TVAs
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 TVAs 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 TVAs nuclear decommissioning trust and pension fund have entered into derivative
contracts for investment purposes. If a counterparty to one of TVAs 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.
Page 73 of 141
Credit of TVA
A downgrade in TVAs credit rating could have material adverse effects on TVAs 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 TVAs interest expense by increasing the interest rates that
TVA pays on debt securities that it issues. An increase in TVAs 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 TVAs 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 TVAs 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,
Managements Discussion and Analysis of Financial Condition and Results of Operations Risk
Management Activities.
Page 74 of 141
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.
Page 75 of 141
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.
Page 76 of 141
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.
Page 77 of 141
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 78 of 141
NOTES TO FINANCIAL STATEMENTS
(Dollars in millions except where noted)
1. Summary of Significant Accounting Policies
General
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.
Substantially all TVA revenues and assets are attributable to the power program. TVAs
service area includes 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. 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
governments Appropriation Investment in TVA power facilities. Until 2000, most of the funding for
TVAs 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, TVAs 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, and
payments to the U.S. Treasury in repayment of and as a return on the Appropriation Investment in
TVAs 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 TVAs power business. In setting
TVAs 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 TVAs 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) TVAs 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 TVAs 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 regulatory assets are probable of recovery. This
determination reflects the current regulatory and political
Page 79 of 141
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 noncash component of investing activities
rather than a noncash component of operating activities. The revised classification is consistent
with guidance for the cash flow presentation for 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 for 2005 and 2004, respectively.
Cash and Cash Equivalents
Cash and Cash Equivalents include the cash available in TVAs 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:
Page 80 of 141
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 TVAs 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. TVAs 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
TVAs 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
Page 81 of 141
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
(NOx) 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 NOx emitted.
NOx 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 TVAs 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.
Page 82 of 141
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 TVAs 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.
Page 83 of 141
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.
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 TVAs 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
Page 84 of 141
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 and Standards Board (FASB) Interpretation (FIN) No. 47, Accounting for
Conditional Asset Retirement Obligationsan Interpretation of FASB Statement No. 143. See Note 4
for the effects of applying this interpretation.
Discounts on Sales
TVAs 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.
TVAs 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 TVAs 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.
Page 85 of 141
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 assets 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 VIEs 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 TVAs results of operations or financial condition.
Conditional Asset Retirement Obligations. In March 2005, the FASB issued FIN No. 47, Accounting
for Conditional Asset Retirement Obligationsan 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)
Page 86 of 141
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 TVAs 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 entitys 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 TVAs 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 debtors 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 debtors
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
Page 87 of 141
second quarter of 2006. The adoption of this guidance did not have a material
impact on TVAs 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
TVAs 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 TVAs 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 TVAs 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 employers 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 plans overfunded status or a liability for a plans
underfunded status; measure a plans assets and its obligations that determine its funded status as
of the end of the employers 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 employers 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.
Page 88 of 141
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, TVAs 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 Bars 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 TVAs 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.
TVAs 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 TVAs 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 TVAs ability to use the site for future projects.
Page 89 of 141
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 TVAs application for license extension at each of its three
reactors at Browns Ferry Nuclear Plant. As a result of the NRCs action, each units 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
Page 90 of 141
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 TVAs 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 TVAs 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 TVAs
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
Page 91 of 141
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 assets
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, TVAs 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, TVAs 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 TVAs 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.
The year-end balances of TVAs regulatory assets and liabilities are as follows:
Page 92 of 141
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 |
|
|
|
|
|
|
|
|
TVAs 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 TVAs rates when incurred.
Nuclear decommissioning costs include certain deferred charges related to the future closure
and decommissioning of TVAs nuclear generating units under NRC requirements and liability
recognition under the accounting rules for asset retirement obligation. 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 FERCs 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 TVAs 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 TVAs financial trading program represent
unrealized gains and losses on futures and options at September 30, 2006. The program is used to
reduce TVAs 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 TVAs ability and intent to recover the cost of these commodity contracts in
future periods through the TVA Board approved fuel cost adjustment.
TVAs 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.
Page 93 of 141
Deferred capital lease costs represent the difference between FERCs 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 TVAs 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 TVAs 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, TVAs $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 TVAs 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
TVAs Knoxville Office Complex based on quoted market price. TVAs 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
TVAs power program and stewardship program were originally funded primarily with
appropriations from Congress. In 1959, however, Congress passed legislation that required TVAs
power program to be self-financing from power revenues and proceeds from power program financings.
While TVAs 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 activities
since 1999, and since that time, TVA has funded stewardship program activities primarily with power
Page 94 of 141
revenues in accordance with a statutory directive from Congress. The table below summarizes TVAs
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. |
Page 95 of 141
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 TVAs 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
Page 96 of 141
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 debts
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
Page 97 of 141
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 TVAs 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.
Page 98 of 141
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 TVAs 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 TVAs bond covenants. Debt service on these
obligations, which is payable solely from TVAs 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 99 of 141
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 TVAs
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 TVAs 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 TVAs
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 survivors 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 survivors 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 TVAs Bond activity for the period from October 1, 2005, to
September 30, 2006.
Page 100 of 141
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Page 101 of 141
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 |
% |
|
$ |
|
|
|
$ |
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 102 of 141
Long-Term Debt, continued
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Call/(Put) |
|
|
Coupon |
|
|
2006 |
|
|
2005 Par |
|
CUSIP or Other Identifier |
|
Maturity |
|
|
Date |
|
|
Rate |
|
|
Par Amount |
|
|
Amount |
|
|
88059TDL2 |
|
|
01/18/2021 |
|
|
|
01/15/2009 |
|
|
|
5.125 |
% |
|
$ |
5 |
|
|
$ |
|
|
880591DC3 |
|
|
06/07/2021 |
|
|
|
|
|
|
|
5.805 |
% |
|
|
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 |
|
|
|
|
|
880591300 2 |
|
|
06/01/2028 |
|
|
|
|
|
|
|
5.490 |
% |
|
|
466 |
|
|
|
466 |
|
880591409 2 |
|
|
05/01/2029 |
|
|
|
|
|
|
|
5.618 |
% |
|
|
410 |
|
|
|
410 |
|
880591DM1 |
|
|
05/01/2030 |
|
|
|
|
|
|
|
7.125 |
% |
|
|
1,000 |
|
|
|
1,000 |
|
880591DP4 |
|
|
07/07/2032 |
|
|
|
|
|
|
|
6.587 |
% |
|
|
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 |
% |
|
|
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) |
|
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 103 of 141
The estimated values of TVAs financial instruments at September 30 are as follows:
Estimated Values of Financial Instruments
As of September 30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
|
Carrying |
|
Fair |
|
Carrying |
|
Fair |
|
|
Amount |
|
Value |
|
Amount |
|
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 TVAs 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.
Page 104 of 141
Due to TVAs 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 TVAs 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.
TVAs 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 TVAs 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 members years of creditable service, the members average base pay for the highest three
consecutive years, and the pension rate for the members 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 members account and the members age. A members
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
Page 105 of 141
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 TVAs 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.
Page 106 of 141
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 |
|
Page 107 of 141
Components of Pension and Other Postretirement Benefits
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits |
|
|
|
Other Postretirement
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.
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 Systems policy includes a
permissible three percent deviation from these target allocations. The TVA Retirement System Board
can take action, as appropriate, to rebalance the systems assets consistent with the asset
allocation policy. For 2006, the asset holdings of the System included equities of about 59
percent (comprised of
U.S. equity holdings of about 41 percent, non-U. S. equity holdings of about
15 percent, and private equity holdings of about three percent), plus fixed income securities
of about 41 percent. For 2005, the asset holdings of the System included equities of about 61 percent
(comprised of
Page 108 of 141
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 Pension.
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 TVAs 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 TVAs 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 employers 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 TVAs Medicare
supplement. By
Page 109 of 141
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 TVAs 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 |
|
|
1083 |
|
|
|
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 TVAs
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
Page 110 of 141
agreements with TVA throughout their bankruptcy proceedings. Costs under TVAs 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.
TVA also has an agreement with the Southeastern Power Administration to receive 405 megawatts
of net dependable capacity from the Cumberland River Basin Projects for use in the TVA system. TVA
receives a yearly energy allocation of 607,500 megawatt hours which is based on the reserved
capacity. Once this allocation is exceeded, TVA is assessed an additional energy charge for the
excess generation received based on rates as specified in the Federal Register.
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 each successive five-year period
beginning October 1, 1960, 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 the 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 the DOE in producing tritium, which is
used in nuclear weapons. This agreement, which ends in 2035, requires the 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.
Page 111 of 141
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 TVAs 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 TVAs 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.
Page 112 of 141
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. TVAs 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 TVAs application for license extension at each of TVAs
three Browns Ferry units. As a result of the NRCs action, each units license has been extended
20 years. The license extension has the effect of improving the funded status of TVAs 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. TVAs activities are subject to certain federal, state, and local
environmental statutes and regulations. Major areas of regulation affecting TVAs 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 TVAs 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.
TVAs 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.
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
Page 113 of 141
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 TVAs allocated share of
such costs and evaluate the likely effectiveness of TVAs 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, TVAs 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.
Legal Proceedings
TVA is involved in various claims amounting to approximately $54 million incidental to the
conduct of its business for which it has assessed the likelihood of gain or loss. The claims,
grouped by likelihood of loss, include (1) claims recorded by TVA in the amount of $28 million
representing probable losses of $27 million and losses deemed reasonably possible of $1 million,
and (2) claims of about $26 million for which a determination of loss cannot be made at this time.
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 TVAs 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 TVAs defenses. TVA filed a motion seeking permission to take an interlocutory appeal of the
courts ruling on summary judgment. On July 31, 2006, the district court reconsidered its decision
on summary judgment with respect to TVAs 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 TVAs 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 TVAs practice of setting rates for electric power charged by
distributor customers through TVAs 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 TVAs 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 courts decision, and held, among
Page 114 of 141
other things, that TVAs rates were not subject to judicial review and that TVA is not subject to
antitrust liability when doing so would interfere with TVAs 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.
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 TVAs 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
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 TVAs 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 Alabamas 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 courts
decision to the Eleventh Circuit. On November 22, 2005, the Eleventh Circuit affirmed the district
courts 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
Page 115 of 141
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 Carolinas Attorney General filed suit against TVA in the United States
District Court for the Western District of North Carolina alleging that TVAs 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 TVAs 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 TVAs 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 Carolinas 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 TVAs 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 EPAs 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 Katrinas increased destructive force. The
plaintiffs are seeking monetary damages among other relief. TVA has moved to dismiss the complaint
on grounds that TVAs 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. Arevas
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
Page 116 of 141
these proceedings would not normally be material to TVAs business, although it is possible that
some outcomes could require TVA to change how it handles certain personnel matters or operates its
plants.
It is not possible to predict with certainty whether TVA will incur any liability or to
estimate the damages, if any, that TVA might incur in connection with the lawsuits and claims
described above except as specifically noted. TVA has recognized charges to earnings and actual
costs, including legal fees and expenses, related to litigation. No assurance can be given that
TVA will not be subject to significant additional claims and material additional liabilities.
If actual liabilities significantly exceed the estimates made, the results of operations,
liquidity, and financial condition could be materially adversely affected. In accordance with SFAS
No. 5, Accounting for Contingencies, TVA has accrued approximately $28 million as of September
30, 2006, related to the cases described above.
14. Related Parties
TVA is a wholly-owned corporate agency of the federal government, and because of this
relationship, TVAs revenues and expenses are included as part of the federal budget. TVAs
purpose and responsibilities as an agency are described under the Other Agencies section of the
federal budget. Although TVAs Bonds are not guaranteed by the federal government, they are
included in the federal budget. TVAs 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
governments Appropriation Investment under the self-financing amendment to the TVA Act, TVA will
continue to repay a portion of the governments 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 |
|
Page 117 of 141
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.
Page 118 of 141
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 Item 15(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 Companys 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 Obligationsan Interpretation of FASB Statement No. 143.
PricewaterhouseCoopers
LLP
Knoxville, Tennessee
December 14, 2006
Page 119 of 141
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
During 2006, there were no changes in or disagreements with TVAs independent auditors on
accounting matters or financial disclosure.
Page 120 of 141
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 and members of the
Disclosure Control Committee (including the Interim Chief Financial Officer and the Vice President
and Controller) of the effectiveness of TVAs disclosure controls and procedures as of September
30, 2006. Based on that evaluation, 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), TVAs 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, TVAs 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 TVAs 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 TVAs 2006 revenue either had qualified opinions and/or internal
control test results that negatively impact their ability to meet TVAs 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 TVAs 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.
Except for the efforts taken and currently underway as described above, there have been no
changes in TVAs internal control over financial reporting during the most recently completed
fiscal quarter that have materially affected, or are reasonably likely to materially affect, TVAs
internal control over financial reporting.
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. TVAs controls and procedures can provide
reasonable, but not absolute, assurance that the objectives will be met. It 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.
Page 121 of 141
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
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.
Page 122 of 141
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. Gores 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
TVAs
executive officers as of December 15, 2006, their titles, their ages, and the date their
employment commenced are as follows:
Page 123 of 141
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 Treasurers 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
Page 124 of 141
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 TVAs 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 TVAs nuclear business office and
has held a variety of financial positions, including Supervisor of Revenue Billing. In January
1995, she joined the Treasurers office and was subsequently named Senior Manager in July 2001. As
Senior Manager, she was responsible for management of TVAs short-term and long-term financing
programs, investments, investor relations, and TVAs 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
Page 125 of 141
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 TVAs 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 TVAs 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 TVAs website at: www.tva.gov. Information contained on TVAs
website shall not be deemed incorporated into, or to be a part of, this Annual Report.
Audit Committee
TVA has an Audit and Ethics Committee established in accordance with the TVA Act. TVAs 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 is an audit committee
financial expert under applicable SEC rules. Each member of the TVA Board is appointed by the
President of the United States with the advice and consent of the U.S. Senate, and 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 issuers 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.
Other Committees
On May 18, 2006, the TVA Board approved the establishment of the following committees in
addition to the Audit and Ethics Committee:
|
|
|
Corporate Governance Committee |
|
|
|
|
Finance, Strategy and Rates Committee |
|
|
|
|
Operations, Environment and Safety Committee |
|
|
|
|
Human Resources Committee |
|
|
|
|
Community Relations Committee. |
ITEM 11. EXECUTIVE COMPENSATION
Director Compensation
At the beginning of 2006, the TVA Board consisted of two members. With the implementation of
the Consolidated Appropriations Act, 2005, the TVA Board now consists of nine members. The
differences in length of service of the two incumbent directors and differences in compensation
under the Consolidated Appropriations Act,
Page 126 of 141
2005, are reflected in this information about director compensation. In accordance with the
Consolidated Appropriations Act, 2005, each director receives a stipend of $45,000 per year, or, in
the case of the chairman of any TVA Board committee, $46,000 per year, or, in the case of the
chairman of the TVA Board, $50,000 per year. Directors are also reimbursed for travel, lodging,
and related expenses they incur in attending meetings, in the same manner as persons employed
intermittently in federal government service under Section 5703 of Title 5 of the United States
Code.
The following table sets out the current annual stipend for each director and the compensation
received by TVAs directors during 2006.
|
|
|
|
|
|
|
|
|
Director Compensation |
|
|
|
|
|
|
Total |
|
|
Annual Stipend |
|
Director Compensation1 |
Name |
|
($) |
|
($) |
|
William W. Baxter |
|
|
45,000 |
|
|
|
61,737 |
2 |
Dennis C. Bottorff |
|
|
46,000 |
|
|
|
21,581 |
|
Donald R. DePriest |
|
|
46,000 |
|
|
|
21,581 |
|
Robert M. Duncan |
|
|
46,000 |
|
|
|
21,581 |
|
Bishop William Graves3 |
|
|
45,000 |
|
|
|
|
|
Skila S. Harris |
|
|
46,000 |
|
|
|
59,500 |
4 |
William B. Sansom |
|
|
50,000 |
|
|
|
23,336 |
|
Howard A. Thrailkill |
|
|
46,000 |
|
|
|
21,277 |
|
Susan Richardson Williams |
|
|
46,000 |
|
|
|
21,606 |
|
|
|
|
Notes |
|
|
|
(1) |
|
Total Director Compensation excludes expense reimbursement. |
|
(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, at 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 Graves was not sworn in as 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, at 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 of $46,000 annually. |
Directors are eligible to participate in TVAs 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 TVAs 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 the following three components: (1) Social
Security benefits, (2) Basic Benefit Plan, and (3) Thrift Savings Plan. Each director pays full
Social Security taxes and 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 high average of three years of salary 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.
Page 127 of 141
The following table presents the estimated retirement benefits each director will be eligible
to receive under FERS if he or she continues to serve until the expiration of their respective
terms.
Retirement Benefits Provided Under FERS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expiration of |
|
|
|
Earliest |
|
|
Estimated |
|
|
|
Current |
|
Period of |
|
Eligibility |
|
|
Monthly Annuity 3 |
|
Name |
|
Appointment |
|
Creditable Service 1 |
|
Date 2 |
|
|
($) |
|
|
William W. Baxter |
|
5/18/2011 |
|
9 yrs., 5 mos. |
|
|
7/31/2015 |
|
|
|
1,099 |
|
Dennis C. Bottorff |
|
5/18/2011 |
|
5 yrs., 1 mo. |
|
|
5/18/2011 |
|
|
|
194 |
|
Donald R. DePriest |
|
5/18/2009 |
|
3 yrs., 1 mo. |
|
|
|
5 |
|
|
|
5 |
Robert M. Duncan |
|
5/18/2011 |
|
5 yrs., 1 mo. |
|
|
4/13/2013 |
|
|
|
194 |
|
Bishop William Graves |
|
5/18/2007 |
|
|
|
|
|
|
|
|
|
|
Skila S. Harris |
|
5/18/2008 |
|
15 yrs., 8 mos. 4 |
|
|
5/18/2008 |
|
|
|
1,401 |
|
William B. Sansom |
|
5/18/2009 |
|
3 yrs., 1 mo. |
|
|
|
5 |
|
|
|
5 |
Howard A. Thrailkill |
|
5/18/2010 |
|
4 yrs., 1 mo. |
|
|
|
5 |
|
|
|
5 |
Susan Richardson Williams |
|
5/18/2007 |
|
1 yr., 1 mo. |
|
|
|
5 |
|
|
|
5 |
|
|
|
Notes |
|
|
|
(1) |
|
Assumes each director will continue to serve through the expiration of his or her
respective current term without reappointment. |
|
(2) |
|
Earliest date each director will become eligible to receive an unreduced
retirement benefit. Directors may be eligible for a reduced benefit at an earlier
date. |
|
(3) |
|
Assumes there will be no change in the amount shown in the Annual Stipend
column in the Director Compensation Table in 2006 and all subsequent years. In the
case of Ms. Harris and Mr. Baxter, the highest average of salary during three
consecutive plan years is based on the salaries received while serving as full-time
directors. |
|
(4) |
|
Includes seven years and two months of prior federal service. |
|
(5) |
|
The director will not meet mandatory vesting requirements prior to the
expiration of his or her term and will not be eligible to receive a retirement
benefit under the FERS Basic Benefit Plan. |
Each director is also eligible to participate in the Thrift Savings Plan (TSP) after a
mandatory waiting period. The TSP is a tax-deferred retirement savings and investment plan that
offers the same type of savings and tax benefits offered under 401(k) plans. Once a director
becomes eligible, TVA contributes an amount equal to one percent of the directors stipend each pay
period (every two weeks) into a TSP account for the director. These contributions are made
automatically regardless of whether the director decides to make 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 directors stipend, 50 percent of
each dollar for the next two percent of the directors stipend, and zero percent for contributions
above five percent of the directors stipend.
Executive Compensation
TVAs executive compensation program is designed to provide a competitive level of
compensation so that TVA is able to attract, retain, and motivate key employees critical to TVAs
success. Its purpose is to reward high performance and to align executive compensation with TVAs
business strategy. TVAs executive compensation program targets base compensation plus an annual
incentive award, which is reviewed annually, at the median of the relevant labor market for most
positions, and ties annual incentive awards to levels of achievement of specific financial,
operating, and other goals. TVAs relevant labor market is comprised of both private and
publicly-owned companies in the energy services industry of similar revenue and scope to TVA.
The primary components of executive compensation at TVA include base compensation, annual
incentives, and long-term incentives. Incentives are at-risk and are based upon attainment of
organization goals.
Consistent with the Consolidated Appropriations Act, 2005, the TVA Board approves all forms of
compensation for the Chief Executive Officer (CEO) and the executives that report directly to the
CEO.
Base Compensation
Base compensation includes salary plus additional annual compensation (if applicable). Base
compensation received by executives is based on their level of responsibility, their individual
merit performance, and the competitive level of compensation for executives in similar positions in
the energy services industry comparison group. Base compensation is reviewed annually by senior
executive officers and any recommended adjustments are submitted to the TVA Board or its delegees
for approval.
Page 128 of 141
Salary. Prior to March 31, 2006, salaries for TVA employees, including executive officers,
could not exceed the TVA Board member salary established by law and by executive order of the
President of the United States which was $143,000 at that date.
Additional Annual Compensation. In 2006, additional annual compensation was used to provide
market-based compensation to participants. Additional annual compensation was paid in quarterly
installments.
Annual Incentive
The Executive Annual Incentive Plan (EAIP) is designed to encourage and reward participants
for their contribution to successfully achieving short-term financial and operational goals. The
EAIP provides a variable performance-based element of total annual compensation for participants.
The CEO and the other executive officers named in the Summary Compensation Table participate in
this EAIP.
Incentive opportunities (represented as a percentage of each participants base compensation)
are established for each position based on opportunities provided for comparable positions in the
energy services industry. Actual incentive awards are tied to the achievement of predefined
corporate and business unit performance goals established each fiscal year as identified in TVAs
Winning Performance Balanced Scorecards. Payments pursuant to the EAIP are made during the first
quarter of the succeeding fiscal year for performance in the year indicated.
All awards are paid in cash with a deferral option. Awards provided to participants under
this plan for the performance period that ended on September 30, 2006, are reported under the
column titled Bonus in the Summary Compensation Table.
Long-Term Incentive
The Executive Long-Term Incentive Plan (ELTIP) is designed to provide participants an
equitable and competitive level of incentive compensation based on successfully achieving
established financial and/or operational goals measured over a multi-year period. Designated
executives are typically those in critical positions who make decisions that impact TVAs
long-term strategic objectives. The CEO and the other executive officers named in the Summary
Compensation Table participate in this ELTIP.
The ELTIP follows three-year performance cycles. Performance measures and goals established
under the ELTIP focus on the achievement of TVAs long-term financial and/or operational goals.
Incentive opportunities (represented as a percentage of each participants base compensation)
are established for each position based on opportunities provided for comparable positions in the
energy services industry. Actual incentive awards are tied to the achievement of predefined
corporate performance goal(s). Payments pursuant to the ELTIP are made during the first quarter of
the fiscal year following the end of the performance cycle.
All awards are paid in cash with a deferral option. Awards provided to participants under
this plan for the performance period that ended on September 30, 2006, are reported under the
column titled LTIP Payouts in the Summary Compensation Table.
Compensation Tables. The following table sets forth information regarding compensation
received by the CEO and the other four most highly compensated executive officers who were employed
by TVA on September 30, 2006.
Page 129 of 141
Summary Compensation Table
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Annual Compensation |
|
|
Long-Term Compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payouts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Annual |
|
|
|
|
|
All Other |
|
|
|
|
|
|
|
Salary |
|
|
Bonus 1 |
|
|
Compensation 2 |
|
|
LTIP Payouts 3 |
|
|
Compensation 4 |
|
Name and Principal Position |
|
Year |
|
|
($) |
|
|
($) |
|
|
($) |
|
|
($) |
|
|
($) |
|
|
Tom D. Kilgore
President and Chief Executive Officer |
|
|
2006 |
|
|
|
140,000 |
|
|
|
334,152 |
5 |
|
|
511,984 |
|
|
|
293,709 |
6 |
|
|
306,300 |
7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Karl W. Singer
Chief Nuclear Officer and
Executive Vice President, TVA Nuclear |
|
|
2006 |
|
|
|
140,000 |
|
|
|
283,382 |
|
|
|
426,723 |
8 |
|
|
216,893 |
|
|
|
206,300 |
9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ashok S. Bhatnagar
Senior Vice President, Nuclear Operations |
|
|
2006 |
|
|
|
140,000 |
|
|
|
210,007 |
|
|
|
321,470 |
10 |
|
|
140,641 |
|
|
|
153,705 |
11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Joseph R. Bynum
Executive Vice President, Fossil Power Group |
|
|
2006 |
|
|
|
140,000 |
|
|
|
154,540 |
|
|
|
275,066 |
|
|
|
124,713 |
|
|
|
150,269 |
12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Michael E. Rescoe 13
Chief Financial Officer and
Executive Vice President, Financial Services |
|
|
2006 |
|
|
|
140,000 |
|
|
|
195,075 |
5 |
|
|
286,109 |
|
|
|
100,021 |
6 |
|
|
6,300 |
14 |
|
|
|
Notes |
|
|
|
(1) |
|
Represents actual amount awarded under the EAIP except as noted otherwise. Under the EAIP,
incentive opportunities (represented as a percentage of each participants base compensation)
are established for each position based on opportunities provided for comparable positions in
the energy services industry. Actual incentive awards are tied to the achievement of
predefined corporate and business unit performance goals established each fiscal year and
identified in TVAs Winning Performance Balanced Scorecards. Payments pursuant to the EAIP
are made during the first quarter of the succeeding fiscal year for performance in the year
indicated. |
|
(2) |
|
Represents additional annual compensation paid in quarterly payments unless otherwise
noted. |
|
(3) |
|
Represents actual amount awarded under the ELTIP except as noted otherwise. Under the
ELTIP, incentive opportunities (represented as a percentage of each participants base
compensation) are established for each position based on opportunities provided for
comparable positions in the energy services industry. Actual incentive awards are tied to
the achievement of predefined corporate performance goal(s). Payments pursuant to the ELTIP
are made during the first quarter of the fiscal year following the end of the performance
cycle. |
|
(4) |
|
Represents annual deferred compensation credits provided under Long-Term Deferred
Compensation Plan (LTDCP) agreements and/or employer matching contributions to the TVA
Retirement Systems 401(k) plan. Agreements administered under the LTDCP are designed to
provide retention incentives to executives to encourage them to remain with TVA and to
provide, in combination with ELTIP incentive awards, a competitive level of total direct
compensation. Under the agreements, credits are made to an account in an executives name
(typically on an annual basis) for a predetermined length of time (typically five years)
after which the executive becomes vested in the balance of the account, including interest
and/or return on investment, and receives a distribution in accordance with an earlier
deferral election. |
|
(5) |
|
Represents the estimated amount to be awarded under the EAIP but not yet paid. |
|
(6) |
|
Represents the estimated amount to be awarded under the ELTIP but not yet paid. |
|
(7) |
|
Includes a $300,000 annual deferred compensation credit provided under a LTDCP agreement
and $6,300 in employer matching contributions to the TVA Retirement Systems 401(k) plan
based on Mr. Kilgores elective contribution. |
|
(8) |
|
Includes $341,323 in additional annual compensation paid in quarterly installments, $5,400
in vehicle allowance payments (paid at the rate of $450 every two weeks beginning April
2006), and an approved $80,000 in deferred compensation awarded for achievement of major milestone
objectives established in conjunction with the Browns Ferry Unit 1
recovery project but not yet paid. |
|
(9) |
|
Includes a $200,000 annual deferred compensation credit provided under a LTDCP agreement
and $6,300 in employer matching contributions to the TVA Retirement Systems 401(k) plan
based on Mr. Singers elective contribution. |
|
(10) |
|
Includes $276,070 in additional annual compensation paid in quarterly installments, $5,400
in vehicle allowance payments (paid at the rate of $450 every two weeks beginning April
2006), and an approved $40,000 in deferred compensation awarded for achievement of major milestone
objectives established in conjunction with the Browns Ferry Unit 1
recovery project but not yet paid. |
|
(11) |
|
Includes a $150,000 annual deferred compensation credit provided under a LTDCP agreement
and $3,705 in employer matching contributions to the TVA Retirement Systems 401(k) plan
based on Mr. Bhatnagars elective contribution. |
|
(12) |
|
Includes a $150,000 annual deferred compensation credit provided under a LTDCP agreement
and $269 in employer matching contributions to the TVA Retirement Systems 401(k) plan based
on Mr. Bynums elective contribution. |
|
(13) |
|
Mr. Rescoe left TVA effective November 13, 2006. |
|
(14) |
|
Represents $6,300 in employer matching contributions to the TVA Retirement Systems 401(k)
plan based on Mr. Rescoes elective contribution. |
Page 130 of 141
The following table presents long-term incentive plan information with respect to the
named executive officers in 2006.
Long Term Incentive Plans
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Future Payouts Under Non Stock |
|
|
|
|
|
|
|
Price Based Plan 2 |
|
|
|
Performance or Other |
|
|
|
|
|
|
|
|
|
|
|
|
Period Until Maturation |
|
|
Threshold |
|
|
Target |
|
|
Maximum |
|
Name |
|
Payout 1 |
|
|
($) |
|
|
($) |
|
|
($) |
|
|
Tom D. Kilgore |
|
3 Years |
|
|
292,500 |
|
|
|
390,000 |
|
|
|
487,500 |
|
Karl W. Singer |
|
3 Years |
|
|
216,000 |
|
|
|
288,000 |
|
|
|
360,000 |
|
Ashok S. Bhatnagar |
|
3 Years |
|
|
140,063 |
|
|
|
186,750 |
|
|
|
233,438 |
|
Joseph R. Bynum |
|
3 Years |
|
|
124,200 |
|
|
|
165,600 |
|
|
|
207,000 |
|
Michael E. Rescoe |
|
3 Years |
|
|
99,610 |
|
|
|
132,813 |
|
|
|
166,016 |
|
|
|
|
Notes |
|
|
|
(1) |
|
While originally designed to cover three-year performance cycles,
the plan has been administered as an annual incentive. |
|
(2) |
|
The awards were or are to be paid in cash in the
first quarter of 2007 and are reported under the column titled LTIP
Payouts in the Summary Compensation Table. |
TVAs ELTIP was intended to follow three-year performance cycles with performance measures
and goals generally established at the beginning of each performance cycle and measured over a
three-year period. The performance measures focus TVAs executives on the achievement of TVAs
long-term financial and/or operational goals.
Target incentive opportunities were established for each executive based on market data and
level of responsibility. At the end of the performance cycle, performance was measured against the
target(s) resulting in a percentage ranging from zero percent to 125 percent. A minimum level of
threshold performance (75 percent of target) must be achieved in order for any payout to occur.
Awards may not exceed 125 percent of an executives target incentive opportunity. Actual awards
were determined by multiplying the executives target incentive opportunity, expressed as a
percentage of the executives base compensation, by the actual level of performance achieved. In
accordance with the performance goals established for the 2004 to 2006 performance cycle, the
threshold, target and maximum awards were equal to 75 percent, 100 percent and 125 percent of the
participants award opportunity target.
In order to focus on the goal of reducing TVAs total financing obligations, the ELTIP has
administratively functioned in a manner similar to an annual incentive plan with awards made and
targets set with respect to a one year period and with payments made in the first quarter of the
following fiscal year. ELTIP awards made in the performance cycle ending in 2006 were based solely
on the reduction of TVAs total financing obligations in 2006. The following goals were
established for this performance measure for 2006: threshold ($340 million), target, ($420
million), and maximum ($500 million). In 2006, TVA realized a reduction in total financing
obligations of $341 million or 75.3 percent of the target established. As a result, each of the
named executive officers received an ELTIP award in 2006 equal to 75.3 percent of his respective
target incentive opportunity.
Retirement Benefits
Qualified Defined Benefit Plan
TVA maintains a qualified defined benefit plan with two structures for all employees including
the CEO and other executive officers named in the Summary Compensation Table. The structures are
the Original Benefit Structure (OBS) and the Cash Balance Benefit Structure (CBBS).
Participation in the OBS is limited to employees who were covered under the plan prior to January
1, 1996. All employees first hired by TVA on or after January 1, 1996, participate in the CBBS.
As with any other qualified retirement plan, there are limits on employee and employer
contributions and compensation that can be counted for benefit calculations set by the TVA
Retirement System rules and IRS regulations.
TVAs Original Benefit Structure. The pension provided under the OBS is based on a final
average pay formula that includes the members 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 executive officers who are members of the
OBS, compensation is defined as annual salary only for benefit
Page 131 of 141
calculation purposes and is shown under the column titled Salary in the Summary Compensation
Table. Creditable service is the length of time spent as a member of the TVA Retirement System and
may also include certain military service, some periods of leave without pay, and forfeited annual
and unused sick leave. The pension factor, which can reach a maximum of 1.3 percent, is determined
by a members age and length of creditable service and whether the member has obtained the Rule of
80. The Rule of 80 is the sum of a members age and years of 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. 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 length of
creditable service equals 80 points or more receive the maximum pension factor of 1.3 percent.
Members who reach age 60 with at least five years of creditable service receive the maximum pension
factor of 1.3 percent even if they do not have 80 points.
Mr. Bynum is the only executive officer named in the Summary Compensation Table who is a
member in the OBS. As of September 30, 2006, Mr. Bynum reached the age of 59 years and nine months
and had 32 years and two months of creditable service, including unused sick and forfeited annual
leave, which would result in 95 points and a maximum pension factor of 1.3 percent. As of that
date, he was eligible to receive an immediate monthly retirement benefit of $5,046 which includes
the supplemental benefit described below. This amount represents the maximum benefit and is not
reduced for any survivor options available under the plan.
TVAs Cash Balance Structure. Under the CBBS, each member has a cash balance account that
receives pay credits equal to six percent of his or her compensation each pay period (every two
weeks). For executive officers and members of the CBBS, compensation is defined as annual base
salary only for benefit calculation purposes and 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 is 10 percent unless the TVA Retirement
System Board, with TVAs 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 members actual age in years and months.
Members with at least five years of CBBS service who are at least actual age 55 are eligible
to receive an immediate benefit. Members who have at least five years of CBBS service and have not
reached actual age 55 may also receive an immediate benefit. CBBS service is the length of time
spent as a member of the TVA Retirement System and does not include credit for unused sick leave,
forfeited annual leave, or pre-TVA employment military service. Mr. Kilgore, Mr. Singer, and Mr.
Bhatnagar are members in the CBBS. Mr. Rescoe was a member in the CBBS.
The estimated monthly benefit that would be payable under the cash balance formula to the CEO
and each of the other executive officers named in the Summary Compensation Table (other than Mr.
Bynum) at age 55 or the earliest eligibility date is presented in the following table.
|
|
|
|
|
|
|
Estimated Monthly Retirement Benefit 1 |
Name |
|
($) |
|
Tom D. Kilgore |
|
|
345 |
2 |
Karl W. Singer |
|
|
1,671 |
3 |
Ashok S. Bhatnagar |
|
|
958 |
3 |
Michael E. Rescoe |
|
|
0 |
4 |
|
|
|
Notes |
|
|
|
(1) |
|
These estimates represent the maximum benefit and are
not reduced for any survivor options available under the
plan. Except for Mr. Rescoe, the estimates are based on
the following assumption: the annual salary amounts
reported in the Summary Compensation Table are used for
fiscal year 2006 and all subsequent years. |
|
(2) |
|
Represents the estimated monthly
retirement benefit payable at the earliest date Mr. Kilgore
will be eligible to receive an immediate benefit (March 3,
2010). This estimated benefit reflects a monthly pension
benefit only. Mr. Kilgore will not be eligible to receive
a supplemental benefit at the earliest date he becomes
eligible to receive an immediate pension benefit since he
will not have the required 10 years of creditable service. |
|
(3) |
|
Represents the estimated monthly
retirement benefit at age 55 for Mr. Singer and Mr.
Bhatnagar, which includes the combined monthly pension
benefit and the monthly supplemental benefit. |
|
(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 the CBBS or to receive a supplemental
benefit. |
Page 132 of 141
Supplemental Retirement Benefit
All members of the TVA Retirement System who meet eligibility criteria, including the CEO and
the other executive officers named in the Summary Compensation Table also receive after retirement
a supplemental benefit regardless of the members benefit structure. The benefit is provided to
eligible retirees and eligible surviving spouses to help with the cost of medical insurance,
although the benefit is not required to be used to pay for medical insurance. The amount of this
benefit is based on the length of time spent as a member of the TVA Retirement System. The monthly
benefit for the year 2006 is $10.45 per month for each full year of actual TVA Retirement System
service plus an additional $85.04 per month. These amounts are subject to change each year due to
an annual cost-of-living adjustment applied each January based on the increase in the Consumer
Price Index. Members must have reached at least actual age 50 at termination with 10 years of
actual service (age 55 with 10 years of actual service after January 1, 2009) to be eligible to
receive the supplemental benefit. Since Mr. Rescoe left TVA before he became eligible to receive
retirement benefits, he will not receive the supplemental benefit.
TVA Sponsored 401(k) Plan
Members of the TVA Retirement System, including the CEO and the other executive officers named
in the Summary Compensation table, may elect to participate in the TVA Retirement Systems 401(k)
plan on a before-tax and on an after-tax basis. For OBS members, TVA provides a matching
contribution of 25 cents on every dollar contributed on a before-tax or an after-tax basis up to
1.5 percent of the participants annual earned compensation. For CBBS members, TVA provides a
matching contribution of 75 cents on every dollar contributed on a before-tax or an after-tax basis
up to 4.5 percent of the participants annual earned compensation. Members are vested in the TVA
matching contributions after three years of actual TVA Retirement System service. For the CEO and
other executive officers named in the Summary Compensation Table, annual earned compensation is
defined as annual salary only and is shown under the column titled Salary in the Summary
Compensation Table.
Supplemental Executive Retirement Plan
The Supplemental Executive Retirement Plan (SERP) is a non-qualified defined benefit
pension plan similar to those typically found in other companies and is provided to a limited
number of TVA executives including the CEO and each of the other executive officers named in the
Summary Compensation Table. TVAs 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 TVAs defined benefit plan and the limits on qualified
retirement plans set forth in Section 415 of the Internal Revenue Code. The plan recognizes
additional annual compensation and annual incentives in the definition of compensation for
supplemental benefits.
SERP benefits are based on a participants highest average compensation during three
consecutive SERP years and a pension multiple of 2.5 percent for each year of creditable 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. SERP requires participants to have 24 years of creditable service in order
to receive full supplemental benefits at age 62. Executives with less creditable 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 SERP. Benefits are offset by Social Security benefits, benefits provided under TVAs defined
benefit plan (Qualified Plan Offset), and prior employer pension benefits (Prior Employer
Offset) when applicable.
Page 133 of 141
The following table shows the estimated annual benefits payable upon retirement for the specified
levels of compensation and years of service.
SERP Benefit Table
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years of Creditable Service |
|
Remuneration 1 |
|
5 |
|
|
10 |
|
|
15 |
|
|
20 |
|
|
24 and > 2 |
|
($) |
|
($) |
|
|
($) |
|
|
($) |
|
|
($) |
|
|
($) |
|
|
150,000 |
|
|
18,750 |
|
|
|
37,500 |
|
|
|
56,250 |
|
|
|
75,000 |
|
|
|
90,000 |
|
200,000 |
|
|
25,000 |
|
|
|
50,000 |
|
|
|
75,000 |
|
|
|
100,000 |
|
|
|
120,000 |
|
300,000 |
|
|
37,500 |
|
|
|
75,000 |
|
|
|
112,500 |
|
|
|
150,000 |
|
|
|
180,000 |
|
400,000 |
|
|
50,000 |
|
|
|
100,000 |
|
|
|
150,000 |
|
|
|
200,000 |
|
|
|
240,000 |
|
500,000 |
|
|
62,500 |
|
|
|
125,000 |
|
|
|
187,500 |
|
|
|
250,000 |
|
|
|
300,000 |
|
600,000 |
|
|
75,000 |
|
|
|
150,000 |
|
|
|
225,000 |
|
|
|
300,000 |
|
|
|
360,000 |
|
700,000 |
|
|
87,500 |
|
|
|
175,000 |
|
|
|
262,500 |
|
|
|
350,000 |
|
|
|
420,000 |
|
800,000 |
|
|
100,000 |
|
|
|
200,000 |
|
|
|
300,000 |
|
|
|
400,000 |
|
|
|
480,000 |
|
900,000 |
|
|
112,500 |
|
|
|
225,000 |
|
|
|
337,500 |
|
|
|
450,000 |
|
|
|
540,000 |
|
1,000,000 |
|
|
125,000 |
|
|
|
250,000 |
|
|
|
375,000 |
|
|
|
500,000 |
|
|
|
600,000 |
|
1,100,000 |
|
|
137,500 |
|
|
|
275,000 |
|
|
|
412,500 |
|
|
|
550,000 |
|
|
|
680,000 |
|
1,200,000 |
|
|
150,000 |
|
|
|
300,000 |
|
|
|
450,000 |
|
|
|
600,000 |
|
|
|
720,000 |
|
|
|
|
Notes |
|
|
|
(1) |
|
Represents the highest average of compensation during any three
consecutive SERP years (for benefit calculation purposes, compensation
includes the combined amounts reported under the columns titled
Salary and Bonus, and additional annual compensation which is
reported under the column titled Other Annual Compensation in the
Summary Compensation Table). |
|
(2) |
|
Maximum benefit received at 24 years no increase in
benefits beyond 24 years of service. |
The estimated benefits presented in the SERP Benefit Table represent a present value of an
annual lifetime annuity prior to any applicable offsets. Actual benefits will be reduced by
applicable offsets as described above and will be converted to an actuarial equivalent value
distributed in either five or 10 annual installments upon retirement as selected by the
participant.
As of September 30, 2006, the applicable remuneration and accredited service for determination
of pension benefits for the CEO and the other named executives were:
|
|
|
|
|
|
|
|
|
|
|
Remuneration |
|
Creditable 1 |
Named Officer |
|
($) |
|
Service |
|
Tom D. Kilgore |
|
|
984,152 |
2 |
|
|
<2 |
|
Karl W. Singer |
|
|
737,806 |
3 |
|
|
14 |
|
Ashok S. Bhatnagar |
|
|
587,350 |
|
|
|
7 |
|
Joseph R. Bynum |
|
|
607,997 |
|
|
|
24 |
|
Michael E. Rescoe4 |
|
NA |
|
NA |
|
|
|
Notes |
|
|
|
(1) |
|
Limited to 24 years when determining supplemental benefits
available under TVAs SERP. |
|
(2) |
|
Mr. Kilgore will be granted three additional
years of creditable 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 Prior Employer
Offset will be waived and the Qualified Plan Offset will be
calculated based on the actual pension benefit he will receive as a
participant in TVAs CBBS. |
|
(3) |
|
TVA has agreed to grant Mr. Singer up to six
additional years of creditable service at the rate of one years
service for each year of TVA service, beginning August 17, 2006
(age 50), and continuing through August 17, 2011 (age 55). |
|
(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 TVAs SERP. |
Page 134 of 141
Long-Term Deferred Compensation Plan Agreements
Agreements administered under TVAs 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 ELTIP incentive awards, a competitive level of total direct
compensation. Under the agreements, credits are made to an account in an executives name
(typically on an annual basis) for a predetermined length of time after which the executive becomes
vested in the balance of the account, including interest and/or return on investment, and receives
a distribution in accordance with an earlier deferral election only if he or she remains employed
at TVA until the end of the vesting period (typically five years).
In March 2005, TVA entered into a defined service-related LTDCP agreement with Mr. Kilgore.
The agreement provides annual deferred compensation credits of $300,000 over a service period of
four years and seven months, beginning on March 1, 2006, and ending on September 30, 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 become fully vested in the remaining 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 has entered into two LTDCP agreements with Mr. Singer. Under the terms of the first
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. Under the first agreement, 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 balance again on September 30, 2008, as long as he remains
employed with TVA on each of those vesting dates. Mr. Singer will receive the remaining balance of
his LTDCP account only if he remains employed with TVA until the expiration of the agreement on
September 30, 2009.
The second LTDCP agreement with Mr. Singer provides annual deferred compensation credits of up
to $100,000 for a period of four years beginning on September 30, 2004, and ending on September 30,
2007. The actual amount credited each year is to be based on the achievement of milestone
performance objectives established for the Browns Ferry Unit 1 recovery project at the beginning of
each year and shall not exceed the maximum of $100,000 each year. Under this agreement, credits
earned will be vested and credited to his deferred compensation account at the end of each fiscal
year. In the event the Browns Ferry Unit 1 recovery project is completed prior to September 30,
2007, all remaining unpaid compensation credits, based on the annual maximum of $100,000, will be
credited to Mr. Singers deferred compensation account and vested immediately.
TVA has entered into two LTDCP agreements with Mr. Bhatnagar. Under the terms of the first
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 become
vested 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.
The second LTDCP agreement with Mr. Bhatnagar provides annual deferred compensation credits of
up to $50,000 for a period of four years beginning on September 30, 2004, and ending on September
30, 2007. The actual amount credited each year is to be based on the achievement of milestone
performance objectives established for the Browns Ferry Unit 1 recovery project at the beginning of
each year and shall not exceed the maximum of $50,000 each year. Under this agreement, credits
earned will be vested and credited to his deferred compensation account at the end of each fiscal
year. In the event the Browns Ferry Unit 1 recovery project is completed prior to September 30,
2007, all remaining unpaid compensation credits, based on the annual maximum of $50,000, will be
credited to Mr. Bhatnagars deferred compensation account and vested immediately to his deferred
compensation account at the end of each fiscal year.
TVA entered into a LTDCP agreement with Mr. Bynum in 2001 that provides 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 in fiscal years 2004 through 2006. Pursuant
to the agreement, Mr. Bynum was to receive the full balance of his account if he remained employed
by TVA until the expiration of his agreement on September 30, 2006. Mr. Bynum was vested in the
balance of his account on September 30, 2006, and the balance of his account was distributed in
accordance with his deferral elections.
Other Agreements
In March 2005, TVA entered into an agreement with Mr. Kilgore that provides a lump sum payment
equal to one years annual compensation if (1) he is not appointed as TVAs Chief Executive
Officer, (2) his duties and/or responsibilities are reduced, (3) his compensation is substantially
reduced, and he terminates his employment with
Page 135 of 141
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 EAIP and ELTIP incentive awards he would have been eligible to
receive based on 100 percent achievement of mid-level performance goals.
In April 2004, TVA entered into an agreement with Mr. Rescoe that provides 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 if he 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 is defined as annual salary plus additional annual compensation plus the
amount of the EAIP and ELTIP incentive awards he would have been eligible to receive based on 100
percent achievement of mid-level 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
10 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 $823,437.50 in November 2006. The second
installment will be paid to Mr. Rescoe in November 2007.
Compensation Committee Interlocks and Insider Participation
Except as described below, in 2006 the CEO and the Chief Administrative Officer (CAO),
acting under a delegation from the TVA Board, reviewed and set the compensation of executive
officers. Compensation for the CEO and the CAO was approved by the TVA Board. Also, in 2006, the
TVA Board approved the compensation of William Stanley Orser, Interim Chief Operating Officer
(COO). Mr. Orsers compensation was recommended by the CEO and reviewed by the Human Resources
Committee of the TVA Board, which unanimously recommended that the TVA Board approve the CEOs
recommendation.
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 is reviewing a compensation plan
covering all TVA employees. Additionally, 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 governments Executive Schedule Level IV (currently,
$143,000), monitor TVA executive compensation programs, and periodically review the compensation
and benefits programs for all TVA employees.
Under the TVA Act, the TVA Board has the authority to approve salaries in excess of the
federal governments Executive Schedule Level IV. While the 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.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
MATTERS
Not applicable.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
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.
Page 136 of 141
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 TVAs annual financial
statements, the review of the interim financial
statements included in TVAs 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 TVAs
initial Form 10-K filing. |
|
3. |
|
All other fees relate to
in-house training of TVA personnel. |
On July 28, 2006, TVAs Audit and Ethics Committee recommended that the TVA Board select
PricewaterhouseCoopers LLP as TVAs 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.
Page 137 of 141
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 138 of 141
(3) Exhibit Index.
|
|
|
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 |
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10.7
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Void Walk Away Agreement Among Memphis Light, Gas and Water Division, the City of Memphis, Tennessee,
and TVA dated as of November 20, 2003 |
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10.8
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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 |
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10.9
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Overview of TVAs September 26, 2003, Lease and Leaseback of Control, Monitoring, and Data Analysis
Network with Respect to TVAs Transmission System in Tennessee, Kentucky, Georgia, and Mississippi |
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10.10*
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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 |
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10.11*
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Network Lease Agreement Dated as of September 26, 2003, Between NVG Network I Statutory Trust, as Owner
Lessor, and TVA, as Lessee |
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10.12*
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Head Lease Agreement Dated as of September 26, 2003, Between TVA, as Head Lessor, and NVG Network I
Statutory Trust, as Head Lessee |
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10.13*
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Leasehold Security Agreement Dated as of September 26, 2003, Made by NVG Network I Statutory Trust to TVA |
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10.14
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Description of Compensation of TVAs Directors and Named Executive Officers |
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10.15
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Tennessee Valley Authority Supplemental Executive Retirement Plan, Effective as of October 1, 1995 |
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10.16
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Tennessee Valley Authority Executive Annual Incentive Plan, Effective in Fiscal Year 1999 |
Page 139 of 141
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10.17
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Tennessee Valley Authority Executive Long-Term Incentive Plan, Effective in Fiscal Year 1999 |
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10.18
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Tennessee Valley Authority Long Term Deferred Compensation Plan |
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10.19
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Employment Contract Between TVA and Tom D. Kilgore Dated as of January 19, 2005 |
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10.20
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Employment Contract Between TVA and Michal E. Rescoe Dated as of April 21, 2004 |
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10.21
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First Deferral Agreement Between TVA and Ashok S. Bhatnagar Dated as of September 28, 2004 |
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10.22
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Second Deferral Agreement Between TVA and Ashok S. Bhatnagar Dated as of September 28, 2004 |
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10.23
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Deferral Agreement Between TVA and Joseph R. Bynum Dated as of March 3, 2004 |
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10.24
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Deferral Agreement Between TVA and Tom D. Kilgore Dated as of March 29, 2005 |
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10.25
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First Deferral Agreement Between TVA and Karl W. Singer Dated as of May 7, 2004 |
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10.26
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Second Deferral Agreement Between TVA and Karl W. Singer Dated as of May 7, 2004 |
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14
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Disclosure and Financial Ethics Code |
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31.1
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Rule 13a-14(a)/15d-14(a) Certification Executed by the Chief Executive Officer |
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31.2
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Rule 13a-14(a)/15d-14(a) Certification Executed by the Chief Financial Officer |
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32.1
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Section 1350 Certification Executed by the Chief Executive Officer |
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32.2
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Section 1350 Certification Executed by the Chief Financial Officer |
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Management contract or compensatory arrangement. |
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* |
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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. |
Page 140 of 141
SIGNATURES
Pursuant to the requirements of Section 13, 15(d), or 37 of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
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Date: December 15, 2006 |
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TENNESSEE VALLEY AUTHORITY
(Registrant) |
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By:
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/s/ Tom D. Kilgore
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Tom D. Kilgore |
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President and Chief Executive Officer |
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(Principal Executive Officer) |
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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed
below by the following persons on behalf of the registrant and in the capacities and on the date
indicated.
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Signature |
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Title |
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Date |
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/s/ Tom D. Kilgore
(Tom D. Kilgore)
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President and Chief Executive Officer
(Principal Executive Officer)
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December 15, 2006 |
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/s/ John M. Hoskins
(John M. Hoskins)
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Interim Chief Financial Officer &
Executive Vice President,
Financial Services
(Principal Financial Officer)
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December 15, 2006 |
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/s/ Randy Trusley
(Randy Trusley)
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Vice President and Controller
(Principal Accounting Officer)
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December 15, 2006 |
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/s/ William B. Sansom
(William B. Sansom)
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Chairman and Director
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December 15, 2006 |
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/s/ Dennis C. Bottorff
(Dennis C. Bottorff)
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Director
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December 15, 2006 |
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/s/ Donald R. DePriest
(Donald R. DePriest)
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Director
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December 15, 2006 |
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/s/ Robert M. Duncan
(Robert M. Duncan)
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Director
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December 15, 2006 |
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/s/ Bishop William Graves
(Bishop William Graves)
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Director
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December 15, 2006 |
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/s/ Skila S. Harris
(Skila S. Harris)
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Director
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December 15, 2006 |
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/s/ Howard A. Thrailkill
(Howard A. Thrailkill)
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Director
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December 15, 2006 |
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/s/ Susan Richardson Williams
(Susan Richardson Williams)
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Director
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December 15, 2006 |
Page 141 of 141