UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K/A
Amendment
No. 2
(MARK
ONE)
x ANNUAL REPORT PURSUANT TO SECTION 13, 15(d), OR 37 OF
THE
SECURITIES
EXCHANGE ACT OF 1934
For
the fiscal year ended September 30, 2007
OR
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF
THE
SECURITIES EXCHANGE ACT OF 1934
For the
transition period from _____ to _____
Commission
file number 000-52313
TENNESSEE
VALLEY AUTHORITY
(Exact
name of registrant as specified in its charter)
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A
corporate agency of the United States created by an act of
Congress
(State
or other jurisdiction of incorporation or organization)
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62-0474417
(IRS
Employer Identification No.)
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400
W. Summit Hill Drive
Knoxville,
Tennessee
(Address
of principal executive offices)
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37902
(Zip
Code)
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(865)
632-2101
Registrant’s
telephone number, including area code
Securities
registered pursuant to Section 12(b) of the
Act: None
Securities
registered pursuant to Section 12(g) of the Act: None
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act.
Yes o No x
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13, Section 15(d), or Section 37 of the Securities Exchange
Act. Yes o No x
Indicate
by check mark whether the registrant (1) has filed all reports required to
be filed by Section 13, 15(d), or 37 of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
Yes x No o
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein and will not be contained, to the
best of registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. x
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer,”
“accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the
Securities Exchange Act. (Check one):
Large
accelerated filer o Accelerated
filer o
Non-accelerated
filer x Smaller
reporting company o
(Do
not check if a smaller reporting company)
Indicate
by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Securities Exchange Act). Yes o No x
Page
1
Explanatory
Note
In this Amendment No. 2 to the Annual
Report on Form 10-K/A for the fiscal year ended September 30, 2007 (“Form 10-K/A
No. 2”), the Tennessee Valley Authority (“TVA”) is restating the financial
statements for the years ended September 30, 2007 and 2006, primarily to restate
revenue associated with an accounting error in the financial statements included
in the original Annual Report on Form 10-K (the “Original 10-K”). The error was
discovered during TVA’s review of its unbilled revenue estimation
process.
TVA is primarily a wholesale provider
of power to distributor customers (“distributors”) that resell the power to end
users at retail rates. Under TVA’s end-use billing arrangements with
distributors, TVA relies on distributors to report their end-use
sales. Because of the delay between the wholesale delivery of power
to the distributor and the report of end-use sales to TVA, TVA must estimate the
unbilled revenue at the end of each financial reporting period. In
September 2006, TVA implemented a change in methodology for estimating unbilled
revenue for electricity sales which resulted in an increase of $232 million in
unbilled revenue (2.6 percent of operating revenue) for 2006.
The estimation process implemented in
September 2006 utilized the distributors’ average rates and an estimate of the
number of days of revenue outstanding to reflect the delay in reporting the
end-use sales to TVA (“days outstanding”). The number of days
outstanding was derived using a procedure similar to a cross-correlation
calculation that compared the monthly retail load to the monthly wholesale
load. The intent was to reflect in the unbilled estimate the end-use
sales that would be reported that month by distributors plus any remaining sales
that would not be reported until the following month due to the delay between
wholesale delivery and end-use reporting.
TVA has determined that the process
implemented in September 2006 overestimated the days outstanding and that this
overestimation resulted in an error in recording unbilled revenue and unbilled
receivables. The previous unbilled process also failed to consider
the annual true-up of each distributor’s reported distribution losses. The
annual true-up reconciles total end-use kilowatt-hour (“kWh”) sales and revenue
reported by each distributor with the kWh sales recorded for each distributor at
wholesale.
TVA has used a new process for
estimating unbilled revenue for 2006 and 2007 in this Form 10-K/A No.
2. This process carries over only the portion of sales from the
distributor’s meter read date to the month-end. Those sales, along
with the current month sales, are then priced at rates based on each
distributor’s customer and product mix. Additionally, the true-up
component has been added to the unbilled calculation to reflect any timing
differences that occur between the retail and wholesale billing
cycles. Due to the new process, an adjustment was made to increase
revenue in 2007 by $73 million (less than one percent of operating revenues) and
to decrease revenue by $200 million (approximately 2.2 percent of operating
revenues) in 2006.
The restatement of unbilled revenue
also affected TVA’s fuel cost adjustment (“FCA”) calculation. The FCA
is a mechanism by which TVA collects the direct cost of fuel used in its
generating facilities and also the energy costs of purchased power used to serve
power demand. Implementation of the FCA occurred in October 2006 as a
joint effort between TVA and its customers. The goal of the FCA is
timely recovery of fuel-related expenses to reduce the volatility driven by fuel
and purchased power markets. Under TVA’s FCA methodology, adjustments
to rates are based primarily on the difference between forecasted and actual
expenses for the upcoming quarter as well as the difference between forecasted
and actual revenues for the upcoming quarter. Because the FCA
adjustments are forward-looking, there is typically a difference between what is
collected in rates and what actual expense is realized over the course of the
quarter. This difference is added to or subtracted from a deferred
account on TVA’s balance sheet.
The restatement of unbilled revenue
changed TVA’s forecasted revenues, and since forecasted revenues are a major
component of the FCA calculation, the change in forecasted revenues required a
restatement of the amounts in TVA’s deferred FCA account. In the
Original 10-K, TVA reported a FCA deferred balance of $197 million at September
30, 2007, which was restated to a deferred balance of $150
million. Of the $150 million, $18 million is a deferred asset and
$132 million is a current receivable.
The unbilled revenue error also
affected the application of distributor prepayments. The balance in
the distributors’ unbilled accounts receivable is offset by a reduction in the
advance collections of those distributors who make prepayments for their
power. As a result of the change in unbilled revenue, the balances in
the unbilled receivable and advance collections accounts were also adjusted. The
adjustment related to distributor prepayments had no effect on the account
balances as of September 30, 2007 and increased the balance in the receivable
and advance collections accounts by $1 million as of September 30,
2006.
In light of the need for this
restatement, TVA has identified a material weakness in its internal control over
financial reporting related to its unbilled revenue calculation, and has
concluded that its disclosure controls and procedures were not effective as of
September 30, 2007, solely because of this material weakness. To
rectify the material weakness, the new method of calculating the unbilled
revenue estimate described above was used for periods presented in this Form
10-K/A No. 2. See Item 9A, Controls and Procedures, for additional information
regarding controls and procedures related to this material
weakness.
TVA has also included in the
appropriate periods in its restated consolidated financial statements other
miscellaneous adjustments that were deemed to be not material by management,
either individually or in the aggregate, and therefore were corrected in the
period in which they were identified. These adjustments primarily
include accounting for closed capital projects and related depreciation,
reserves for legal proceedings, and timing of payable recognition and are
described in more detail in Note 2.
The effects of these restatements and
miscellaneous adjustments on TVA's consolidated financial statements as of and
for the years ended September 30, 2007, and 2006, including quarterly data, are
described in Note 2 and Note 17. The restatements had no impact on
TVA’s cash or cash equivalents.
For the convenience of the reader, TVA
is refiling its entire Annual Report on Form 10-K/A for the fiscal year ended
September 30, 2007, by means of this Form 10-K/A No. 2. However,
except for the information affected by the restatement, TVA has not materially
updated the information contained herein for events or transactions occurring
subsequent to the dates the Original 10-K and Amendment No. 1 to the Original
10-K (“10-K/A No. 1”) were filed with the SEC. TVA recommends that
this Form 10- K/A No. 2 be read in conjunction with the reports and any
amendments thereto TVA has filed with the SEC subsequent to the filing date of
the Original 10-K and 10-K/A No. 1.
The following items have been amended
principally as a result of, and to reflect, the restatement, and no other
information in the Original 10-K and 10-K/A No. 1 is amended hereby as a result
of the restatement:
Part I –
Item 1 – Business
Part I –
Item IA – Risk Factors
Part I –
Item 3 – Legal Proceedings
Part II –
Item 6 – Selected Financial Data
Part II –
Item 7 – Management's Discussion and Analysis of Financial Condition and Results
of Operations
Part II –
Item 8 – Financial Statements and Supplementary Data
Part II –
Item 9A – Controls and Procedures
Part III
– Item 11 – Executive Compensation
Part IV –
Item 15 – Exhibits and Financial Statements
TVA is also filing updated
certifications by the Chief Executive Officer and Chief Financial Officer as
exhibits to this Form 10-K/A No. 2.
This Form 10-K/A No. 2 is not
superseding or restating financial statements contained in TVA’s quarterly
reports on Form 10-Q for the quarters ended March 31, 2008, or December 31,
2007, or any current report on Form 8-K filed subsequent to September 30, 2007.
However, the financial statements for the quarters ended March 31, 2008
and December 31, 2007, which are contained in the quarterly reports on Form 10-Q
for the quarters then ended, have also been restated in amended quarterly
reports on Form 10-Q/A, which
TVA plans to file as soon as practicable after the filing of this Form
10-K/A No. 2. See Note 17. Accordingly, the information in
the quarterly reports on Form 10-Q for the quarters ended March 31, 2008, and
December 31, 2007, should be considered in light of the information in this Form
10-K/A No. 2.
The financial statements for the
quarters ended March 31, 2008, and December 31, 2007, which are contained in the
quarterly reports on Form 10-Q for the quarters then ended,
are being restated in amended quarterly reports on Form
10-Q/A, which TVA plans to file as soon as practicable after the
filing of this Form 10-K/A No. 2.
TVA has not separately amended its
Annual Report on Form 10-K for the fiscal year ended September 30, 2006, or its
Quarterly Reports on Form 10-Q for the quarterly periods for the fiscal years
ended September 30, 2007 and 2006. Consequently, the financial and
other information contained in such reports should be read in conjunction with
the restated financial data for these fiscal periods, which is set forth in this
Form 10-K/A No.2. See Note 17.
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This Form 10-K/A No. 2 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 asset retirement
obligations;
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Estimates
regarding power and energy
forecasts;
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Expectations
about the adequacy of TVA’s pension plans, nuclear decommissioning trust,
and asset retirement trust;
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Estimates
regarding the reduction of bonds, notes, and other evidences of
indebtedness, lease/leaseback commitments, and power prepayment
obligations;
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Estimates
of amounts to be reclassified from other comprehensive income to earnings
over the next year;
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TVA’s
plans to continue using short-term debt to meet current obligations;
and
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The
anticipated cost and timetable for placing Watts Bar Unit 2 in
service.
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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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TVA’s
protected service area,
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The
sole authority of the TVA Board to set power
rates,
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Various
environmental and nuclear matters,
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TVA’s
management of the Tennessee River
system,
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TVA’s
credit rating, and
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TVA’s
debt ceiling;
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Loss
of customers;
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Performance
of TVA’s generation and transmission
assets;
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Availability
of fuel supplies;
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Purchased
power price volatility;
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Events
at facilities not owned by TVA that affect the supply of water to TVA’s
generation facilities;
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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 including drought;
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Failure
of transmission facilities;
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Events
at any nuclear facility, even one that is not owned by or licensed to
TVA;
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Catastrophic
events such as fires, earthquakes, floods, tornadoes, pandemics, wars,
terrorist activities, and other similar events, especially if these events
occur in or near TVA’s service
area;
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Reliability
of purchased power providers, fuel suppliers, and other
counterparties;
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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, its counterparties, or its
customers;
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Rising
pension costs and health care
expenses;
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Increases
in TVA’s financial liability for decommissioning its nuclear facilities
and retiring other assets;
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Limitations
on TVA’s ability to borrow money;
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Changes
in the economy;
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Ineffectiveness
of TVA’s disclosure controls and procedures, and its internal control over
financial reporting;
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Changes
in accounting standards;
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The
loss of TVA’s ability to use regulatory
accounting;
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Problems
attracting and retaining skilled
workers;
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Changes
in technology;
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Changes
in the market for TVA securities;
and
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Unforeseeable
events.
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Additionally, other risks that may
cause actual results to differ from the predicted results are set forth in Item
1A, Risk Factors. New factors emerge from time to time, and it is not
possible for management to predict all such factors or to assess the extent to
which any factor or combination of factors may impact TVA’s business or cause
results to differ materially from those contained in any forward-looking
statement.
TVA undertakes no obligation to update
any forward-looking statement to reflect developments that occur after the
statement is made.
Fiscal Year
Unless otherwise indicated, years
(2007, 2006, etc.) in this Annual Report refer to TVA’s fiscal years ended
September 30. References to years in the biographical information
about directors and executive officers in Item 10, Directors, Executive Officers
and Corporate Governance are to calendar years.
Notes
References to “Notes” are to the Notes
to Financial Statements contained in Item 8, Financial Statements and
Supplementary Data.
Available Information
TVA's Annual Report on Form 10-K,
Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments
to those reports are made available on TVA's website, free of charge, as soon as
reasonably practicable after such material is electronically filed with or
furnished to the Securities and Exchange Commission ("SEC"). TVA's
website is www.tva.gov. Information contained on TVA’s website shall
not be deemed incorporated into, or to be a part of, this Annual
Report. In addition, the public may read and copy any reports or
other information that TVA files with the SEC at the SEC’s Public Reference Room
at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain
information on the operation of the Public Reference Room by calling the SEC at
1-800-SEC-0330. TVA's SEC reports are also available to the public
without charge from the website maintained by the SEC at
www.sec.gov.
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 (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, and industry. TVA’s
power system operations, however, constitute the majority of its activities and
provide virtually all of its revenues.
Although TVA is similar to other 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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Each
member of TVA’s board of directors (the “TVA Board”) is appointed by the
President of the United States with the advice and consent of the U.S.
Senate.
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TVA
does not own real property; it holds real property as an agent for the
United States. (Any reference in this Annual Report on Form
10-K (“Annual Report”) to TVA facilities or the ownership by TVA of
facilities or real property refers to property held by TVA but owned by
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 facilities (the “Power Facilities 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
securities.
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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. These rates are not subject to
judicial review or review by any regulatory
body.
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TVA
is exempt from paying federal income taxes and state and local taxes, but
it must pay certain states and counties an amount in lieu of taxes equal
to five percent of TVA’s gross revenues from the sale of power during the
preceding year, excluding sales or deliveries to other federal agencies
and off-system sales with other utilities, with a provision for minimum
payments under certain
circumstances.
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TVA
performs stewardship activities in connection with the Tennessee River and
its tributaries and is required by federal law to fund these activities
primarily with revenues from the power system and to a lesser extent with
revenues from other sources.
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For a discussion of the more
significant of these features, see Item 7, Management’s Discussion and Analysis
of Financial Condition and Results of Operations — Business
Overview.
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
States with the advice and consent of the U.S. Senate. After an
initial phase-in period, TVA Board members serve five-year terms, and at least
one member’s term ends each year. The TVA Board, among other things,
establishes broad goals, objectives, and policies for TVA; establishes
long-range plans to carry out these goals, objectives, and policies; approves
annual budgets; and establishes a compensation plan for
employees. Information about members of the TVA Board and TVA’s
executive officers is discussed in Item 10, Directors, Executive Officers and
Corporate Governance.
Strategy
On May 31, 2007, the TVA Board approved
the 2007 Strategic Plan (“Strategic Plan”). The Strategic Plan
focuses on TVA’s performance in the following five broad areas and establishes
general guidelines for each area:
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CUSTOMERS: Maintain
power reliability, provide competitive rates, and build trust with TVA’s
customers;
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PEOPLE: Build
pride in TVA’s performance and
reputation;
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FINANCIAL: Adhere
to a set of sound financial guiding principles to improve TVA’s fiscal
performance;
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ASSETS: Use TVA’s assets
to meet market demand and deliver public value;
and
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OPERATIONS: Improve
performance to be recognized as an industry
leader.
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Performance Indicators
On September 27, 2007, the TVA Board
adopted performance indicators for 2008 that are aligned with TVA’s Strategic
Plan. These performance indicators are as follows:
2008
TVA Scorecard
TVA operates the nation’s largest
public power system. TVA supplies power in most of Tennessee,
northern Alabama, northeastern Mississippi, and southwestern Kentucky and in
portions of northern Georgia, western North Carolina, and southwestern Virginia
to a population of approximately 8.7 million people.
Subject to certain minor exceptions,
TVA may not, without specific authorization from the U.S. Congress, enter into
contracts which would have the effect of making it, or the distributor customers
of its power, a source of power supply outside the area for which TVA or its
distributor customers were the primary source of power supply on July 1,
1957. This statutory provision is referred to as the “fence” because
it bounds TVA’s sales activities, essentially limiting TVA to power sales within
a defined service area.
Correspondingly, the Federal Power Act
(“FPA”), primarily through its anti-cherrypicking provision, prevents the
Federal Energy Regulatory Commission (“FERC”) from ordering TVA to provide
access to its transmission lines to others for the purpose of delivering power
to customers within substantially all of its defined service
area. The anti-cherrypicking provision reduces TVA’s exposure to loss
of revenue.
Sales of electricity accounted for
substantially all of TVA’s operating revenues in 2007, 2006, and 2005, amounting
to $9.2 billion (restated), $8.8 billion (restated), and $7.7 billion,
respectively. TVA’s revenues by state for the last three years are
detailed in the table below.
Electricity
Sales Revenues by State
For the
years ended September 30
(in
millions)
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2007
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2006*
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2005*
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As
Restated
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As
Restated
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Alabama
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$ | 1,264 | $ | 1,239 | $ | 1,051 | ||||
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Georgia
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206 | 226 | 186 | |||||||
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Kentucky
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1,084 | 902 | 830 | |||||||
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Mississippi
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804 | 798 | 671 | |||||||
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North
Carolina
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58 | 36 | 38 | |||||||
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Tennessee
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5,740 | 5,621 | 4,806 | |||||||
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Virginia
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7 | 5 | 4 | |||||||
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Subtotal
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9,163 | 8,827 | 7,586 | |||||||
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Sale
for resale
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17 | 13 | 95 | |||||||
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Subtotal
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9,180 | 8,840 | 7,681 | |||||||
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Other
revenues
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146 | 143 | 111 | |||||||
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Operating
revenues
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$ | 9,326 | $ | 8,983 | $ | 7,792 | ||||
* See
Note 1 — Reclassifications.
TVA SERVICE AREA
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 to (1) directly
served customers, consisting primarily of federal agencies and customers with
large or unusual loads, and (2) exchange power customers (electric systems that
border TVA’s service area) with which TVA has entered into exchange power
arrangements.
Operating revenues by customer type for
each of the last three years are set forth in the table below. In
this table, sales to industries directly served are included in Industries
directly served, and sales to federal agencies directly served and to exchange
power customers are included in Federal agencies and other.
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Operating
Revenues by Customer Type
For
the years ended September 30
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(in
millions)
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2007
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2006*
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2005*
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As
Restated
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As
Restated
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Municipalities
and cooperatives
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$ | 7,847 | $ | 7,659 | $ | 6,539 | ||||
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Industries
directly served
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1,221 | 1,065 | 961 | |||||||
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Federal
agencies and other
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Federal
agencies directly served
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95 | 103 | 86 | |||||||
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Off-system
sales
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17 | 13 | 95 | |||||||
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Subtotal
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9,180 | 8,840 | 7,681 | |||||||
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Other
revenues
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146 | 143 | 111 | |||||||
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Operating
revenues
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$ | 9,326 | $ | 8,983 | $ | 7,792 | ||||
* See
Note 1 — Reclassifications.
Municipalities and
Cooperatives
Revenues from distributor customers
accounted for 84.1 percent of TVA’s total operating revenues in
2007. At September 30, 2007, TVA had wholesale power contracts with
158 municipalities and cooperatives. All of these contracts require
distributor customers to purchase all of their electric power and energy
requirements from TVA.
All distributor customers purchase
power under one of three basic termination notice arrangements:
|
•
|
Contracts
that require five years’ notice to
terminate;
|
|
•
|
Contracts
that require 10 years’ notice to terminate;
and
|
|
•
|
Contracts
that require 15 years’ notice to
terminate.
|
The number of distributor customers
with the contract arrangements described above, the revenues derived from such
arrangements in 2007, and the percentage of TVA’s 2007 total operating revenues
represented by these revenues are summarized in the table below.
|
TVA
Distributor Customer Contracts
As
of September 30, 2007
|
||||||||||||
|
Contract
Arrangement
|
Number
of Distributor Customers
|
Sales
to Distributor Customers in 2007
|
Percentage
of Total Operating Revenues in 2007
|
|||||||||
|
(in
millions)
|
||||||||||||
|
As
Restated
|
As
Restated
|
|||||||||||
|
15-Year
termination notice
|
5 | $ | 87 | 0.9 | % | |||||||
|
10-Year
termination notice
|
48 | 2,597 | 27.8 | % | ||||||||
|
5-Year
termination notice *
|
102 | 5,112 | 54.8 | % | ||||||||
|
Notice
given - less than 5 years remaining *
|
3 | 51 | 0.6 | % | ||||||||
|
Total
|
158 | $ | 7,847 | 84.1 | % | |||||||
|
|
*
|
Ordinarily
the distributor customer and TVA have the same termination notice period;
however, in contracts with six of the distributor customers with five-year
termination notices, TVA has a 10-year termination notice (which becomes a
five-year termination notice if TVA loses its discretionary wholesale
rate-setting authority).
|
TVA’s two largest distributor customers
— Memphis Light, Gas and Water Division (“MLGW”) and Nashville Electric Service
(“NES”) — have contracts with five-year and 10-year termination notice periods,
respectively. Although no single customer accounted for 10 percent or
more of TVA’s total operating revenues in 2007, sales to MLGW and NES accounted
for 8.6 percent and 7.9 percent, respectively. In 2004, TVA and MLGW
entered into a prepayment agreement under which MLGW prepaid TVA $1.5 billion
for the future costs for a portion of the electricity to be delivered by TVA to
MLGW over a period of 180 months. See Note 1 — Energy Prepayment Obligations
for more information about this prepayment arrangement.
On September 26, 2006, the city of
Bristol, Virginia, announced that it had selected TVA as the new power provider
for its municipal electric system, Bristol Virginia Utilities (“BVU”), beginning
in January 2008. TVA had provided wholesale power to BVU from 1945 to
1997. The contract has a minimum 15-year term, and a five-year
termination notice may not be given until January 2018. The rates
under this contract are intended to recover the cost of reintegrating BVU into
TVA’s power-supply plan and serving its customer load.
All of the power contracts between TVA
and the distributor customers provide for purchase of power by the distributor
customers at the rates established by the TVA Board, which, beginning with 2007,
are adjusted quarterly to reflect changing fuel and purchased power
costs. See Item 1, Business — Rate Actions. 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 subclassifications
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 conform to the TVA Act’s objective of providing an
adequate supply of power at the lowest feasible rates.
Termination Notices
At September 30, 2006, six of TVA’s
distributor customers had notices in effect terminating their power contracts
with TVA. In November 2006, TVA made an offer, which ended January
10, 2007, to allow these six power distributors a grace period to return to
TVA without being subject to reintegration fees. Any distributor
choosing to rescind its contract termination notice after January 10,
2007, would be required to pay the additional costs to resume planning for
its future power supply needs.
Subsequently,
Warren Rural Electric Cooperative Corporation (“Warren”), Duck River Electric
Membership Corporation, and Glasgow Electric Plant Board rescinded their
termination notices in response to this offer. Monticello Electric
Plant Board, Princeton Electric Plant Board, and Paducah Power System did not
accept the offer to rescind. The contracts of the remaining three
distributors will all terminate by January 2010. Sales in 2007 to the
three remaining distributor customers amounted to $51 million, or 0.6 percent of
TVA’s operating revenues in 2007.
The table
below lists the names and locations of the three distributor customers whose
termination notices were still in effect as of September 30, 2007, their
contract termination dates, the amount of revenues that TVA generated by selling
power to these distributor customers in 2007, and the percentage of TVA’s total
2007 operating revenues represented by these revenues.
Distributor
Customers with Termination Notices in Effect
As of
September 30, 2007
(in
millions)
|
Distributor
Customer
|
Location
|
Date
of Termination of Power Contract
|
TVA
Sales to Distributor Customer
in
2007
|
Percentage
of
TVA Operating Revenues in 2007
|
||||||
|
As
Restated
|
As
Restated
|
|||||||||
|
Monticello
Electric Plant Board
|
Kentucky
|
November
2008
|
$ | 6 | 0.1 | % | ||||
|
Paducah
Power System
|
Kentucky
|
December
2009
|
39 | 0.4 | % | |||||
|
Princeton
Electric Plant Board
|
Kentucky
|
January
2010
|
6 | 0.1 | % | |||||
|
Total
|
$ | 51 | 0.6 | % | ||||||
Other
Customers
Revenues from industrial customers
directly served accounted for 13.1 percent of TVA’s total operating revenues in
2007. In 2007, contracts for customers directly served were generally
for terms from five to 10 years. These contracts are subject to
termination by TVA or the customer upon a minimum notice period that varies
according to the customer’s contract demand and the period of time service has
been provided.
The United States Enrichment
Corporation (“USEC”) is TVA’s largest industrial customer directly
served. Sales to USEC for its Paducah, Kentucky, facility represented
5.5 percent of TVA’s total operating revenues in 2007. TVA’s current
contract with USEC expires on May 31, 2012. USEC is currently rated
'CCC' by Standard & Poor's and 'Caa2' by Moody's Investors
Service. As a result of USEC’s credit ratings, it has provided credit
assurance to TVA, per the terms of its power contract. In January
2004, USEC announced its decision to construct a new commercial centrifuge
facility in Piketon, Ohio, which is outside TVA’s service area. Once
this new facility is opened, it is unclear how much electricity USEC will
acquire from TVA for its Paducah, Kentucky, facility. However, the
electric power requirements of USEC, or of its successor at that site, are
expected to be substantially less than their current level.
TVA is
self-regulated with respect to rates and the TVA Act gives the TVA Board sole
responsibility for establishing the rates TVA charges for
power. These rates are not subject to judicial review or to review or
approval by any state or federal regulatory body.
According to the TVA Act, TVA is
required to charge rates for power which will produce gross revenues sufficient
to provide funds for:
|
•
|
Operation,
maintenance, and administration of its power
system;
|
|
•
|
Payments
to states and counties in lieu of
taxes;
|
|
•
|
Debt
service on outstanding
indebtedness;
|
|
•
|
Payments
to the U.S. Treasury in repayment of and as a return on the Power
Facilities Appropriation Investment;
and
|
|
•
|
Such
additional margin as the TVA Board may consider desirable for investment
in power system assets, retirement of outstanding bonds, notes, or other
evidences of indebtedness (“Bonds”) in advance of maturity, additional
reduction of the Power Facilities Appropriation Investment, and other
purposes connected with TVA’s power
business.
|
In setting TVA’s rates, the TVA Board
is charged by the TVA Act to have due regard for the primary objectives of the
TVA Act, including the objective that power shall be sold at rates as low as are
feasible. See Note 1 — General.
Revenue
Requirements
In setting rates to cover the costs set
out in the TVA Act, TVA uses a debt-service coverage (“DSC”) methodology to
derive annual revenue requirements in a manner similar to that used by other
public power entities that also use the DSC rate methodology. The DSC
method is essentially a measure of an organization’s ability to cover its
operating costs and to satisfy its obligations to pay principal and interest on
debt. TVA believes this method is appropriate because of TVA’s
debt-intensive capital structure. This ratemaking approach is
particularly suitable for use by highly leveraged enterprises (i.e., financed
primarily, if not entirely, by debt capital).
The revenue requirements (or projected
costs) are calculated under the DSC method as the sum of the following
components:
|
•
|
Fuel
and purchased power costs;
|
|
•
|
Operating
and maintenance costs;
|
|
•
|
Tax
equivalents; and
|
|
•
|
Debt
service coverage.
|
Once the
revenue requirements (or projected costs) are determined, this amount is
compared to the projected revenues for the year in question, at existing rates,
to arrive at the shortfall or surplus of revenues as compared to the projected
costs. Subject to TVA Board approval, power rates would be adjusted
to a level sufficient to produce revenues approximately equal to projected
costs. This methodology reflects the cause-and-effect relationship between a
regulated entity’s costs and the corresponding rates the entity charges for its
regulated products and services.
Fuel Cost Adjustment
On July 28, 2006, the TVA Board
implemented a fuel cost adjustment (“FCA”) to be used quarterly to adjust TVA’s
rates to reflect changing fuel and purchased power costs beginning in
2007. The FCA was initially set to zero and had its first impact on
rates effective January 1, 2007. The FCA rate adjustment on January
1, 2007, was 0.01 cents per kilowatt-hour, the rate adjustment on April 1, 2007,
was 0.084 cents per kilowatt-hour, and the rate adjustment on July 1, 2007, was
0.087 cents per kilowatt-hour. These 2007 rate adjustments produced
an estimated $82 million in revenue. As of September 30, 2007, TVA
had recognized a regulatory asset of $150 million representing deferred power
costs to be recovered through the FCA adjustments in future
periods. The FCA rate adjustment on October 1, 2007, was 0.432 cents
per kilowatt-hour. Based upon the FCA calculation methodology in use as of
October 1, 2007, the FCA was expected to produce an estimated $159 million in
revenue during the first quarter of 2008.
Under
TVA’s FCA methodology, adjustments to rates are based on the difference between
forecasted and baseline (budgeted) costs for the upcoming quarter. Because
the FCA adjustments are forward-looking, there is typically a difference between
what is collected in rates and what actual expense is realized over the course
of the quarter. This difference is added to or deducted from a
deferred account on TVA’s balance sheet. Each quarterly adjustment
includes a core FCA adjustment plus one half of the deferred balance. The
higher or lower costs added to or taken away from the deferred balance sheet
account are then amortized to expense in the periods in which they are to be
collected in revenues. This allows better matching of the
revenues with associated expenses.
TVA’s cash flow can be negatively
impacted by the FCA process, however. Under the methodology, some of
the FCA portion of higher fuel and purchased power expense realized during the
quarter is placed in the deferred account to be collected in rates in later
periods. The timing of the collection of revenues related to the FCA
does not coincide with the cash expended for fuel and purchased power
consumed. See Item 7, Management’s Discussion and Analysis of
Financial Condition and Results of Operations — Executive Summary — Challenges
During 2007.
Reserve for Future
Generation
Also included in the 2007 rate base was
a reserve for future generation to fund additional generating
capacity. The reserve for generation was calculated as 1.05 percent
of TVA’s billed firm power sales since it was based on firm demand and
energy. Firm sales are those that TVA has no contractual right to
interrupt. TVA collected $76 million during 2007 which it applied to
the purchase of two combustion turbine facilities. See Note 1 — Reserve for Future
Generation. The reserve for generation was not extended beyond
2007.
Environmental Rate
Adjustment
In 2003, the TVA
Board approved a wholesale rate increase of 6.1 percent designed to
cover TVA investment in equipment associated with its clean air
program. This rate adjustment is scheduled to terminate in
2013.
TVA produces forecasts of future load
and energy requirements using multiple models driven by historical TVA loads and
regional economic forecasts of employment, population, and electricity and gas
prices. The best models are then chosen with the result being a range of
load forecasts. Numerous factors, such as weather conditions and the
health of the regional economy, could cause actual results to differ materially
from TVA’s forecasts. See Forward-Looking
Information. As outlined in the Strategic Plan, TVA believes
that new generation sources will be needed to meet load growth under most likely
scenarios. See Item 1, Business — Governance —
Strategy.
General
TVA’s power generating facilities in
operation at September 30, 2007, included 29 conventional hydroelectric sites,
one pumped storage hydroelectric site, 11 coal-fired sites, three nuclear sites,
eight combustion turbine sites, two diesel generator sites, one wind energy
site, one digester gas site, and 16 solar energy sites. In addition,
TVA acquires power under power purchase agreements of varying duration as well
as short-term contracts of less than 24-hour duration (spot
market).
TVA-Owned Generation
Facilities
The following table summarizes TVA’s
net generation in millions of kilowatt-hours by generating source and the
percentage of all electric power generated by TVA for the years
indicated:
Power
Supply from TVA-Owned Generation Facilities
For the
years ended September 30
(millions
of kWh)
|
2007
|
2006
|
2005
|
2004
|
2003
|
|||||||||||||||||||||||||||||||
|
Coal-fired
|
100,169 | 64 | % | 99,598 | 64 | % | 98,361 | 62 | % | 94,618 | 61 | % | 90,958 | 60 | % | ||||||||||||||||||||
|
Nuclear
|
46,441 | 30 | % | 45,313 | 29 | % | 45,156 | 28 | % | 46,003 | 30 | % | 43,167 | 29 | % | ||||||||||||||||||||
|
Hydroelectric
|
9,047 | 6 | % | 9,961 | 6 | % | 15,723 | 10 | % | 13,916 | 9 | % | 16,103 | 11 | % | ||||||||||||||||||||
|
CCombustion
turbine and diesel generators
|
705 |
<1
|
% | 613 |
<1
|
% | 595 |
<1
|
% | 278 |
<1
|
% | 817 |
<1
|
% | ||||||||||||||||||||
|
Renewable
resources *
|
27 |
<1
|
% | 36 |
<1
|
% | 47 |
<1
|
% | 35 |
<1
|
% | 21 |
<1
|
% | ||||||||||||||||||||
|
Total
|
156,389 | 100 | % | 155,521 | 100 | % | 159,882 | 100 | % | 154,850 | 100 | % | 151,066 | 100 | % | ||||||||||||||||||||
Note:
|
|
*
|
Renewable
resources for years 2003 through 2006 have been adjusted to remove
renewable resources amounts that were acquired under purchased power
agreements and included in this table in TVA’s 2006 Annual Reports on
Forms 10-K and 10-K/A. These adjustments resulted in reductions
in the amount of renewable resources by 11 million kWh for 2003, 13
million kWh for 2004, 14 million kWh for 2005, and 15 million kWh for
2006. Also, for years 2003 through 2006 the following amounts
related to TVA’s digester gas cofiring site have been reclassified from
Coal-fired to Renewable resources: 17 million kWh for 2003, 30 million kWh
for 2004, 43 million kWh for 2005, and 32 million kWh for
2006. Renewable resource facilities include a digester gas
cofiring site, a wind energy site, and solar energy
sites.
|
The following table indicates TVA’s
average fuel expense by generation-type for the years indicated:
Fuel
Expense Per kWh
For the
years ended September 30
(cents/kWh)
|
2007
|
2006
|
2005
|
2004
|
2003
|
||||||||||||||||
|
Coal
|
2.13 | 2.02 | 1.65 | 1.48 | 1.43 | |||||||||||||||
|
Natural
gas and fuel oil
|
7.00 | 10.65 | 11.44 | 9.01 | 7.61 | |||||||||||||||
|
Nuclear
|
0.41 | 0.38 | 0.39 | 0.39 | 0.39 | |||||||||||||||
|
Average
fuel cost per kWh net thermal generation
from all sources
|
1.61 | 1.54 | 1.30 | 1.14 | 1.14 | |||||||||||||||
Coal-Fired. TVA
has 11 coal-fired power sites consisting of 59 units. At September
30, 2007, these facilities accounted for 15,052 megawatts of winter net
dependable capacity. Net dependable capacity is defined as the
ability of an electric system, generating unit, or other system component to
carry or generate power for a specified time period excluding any fluctuations
in capacity that may occur due to planned outages, unplanned outages, and
deratings. TVA’s coal-fired units were placed in service between 1951
and 1973. See Item 7, Management’s Discussion and Analysis of
Financial Condition and Results of Operations — Executive Summary — Challenges During
2007.
Nuclear. TVA has three nuclear
sites consisting of six units in operation. At September 30, 2007,
these facilities accounted for 6,898 megawatts of winter net dependable
capacity. For a detailed discussion of TVA’s nuclear power program,
see Item 1, Business — Nuclear. For a
discussion of challenges faced by TVA’s nuclear power program during 2007, see
Item 7, Management’s Discussion and Analysis of Financial Condition and Results
of Operations — Executive
Summary — Challenges During 2007.
Hydroelectric. TVA
has 29 conventional hydroelectric sites consisting of 109 units. In
addition, TVA has one pumped storage facility consisting of four
units. At September 30, 2007, these facilities accounted for 5,186
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 outside TVA’s control, including the amount of
precipitation, runoff, initial water 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. See Item 7, Management’s Discussion and Analysis of Financial
Condition and Results of Operations — Executive Summary — Challenges During 2007 — Weather
Conditions.
Combustion Turbines and Future
Combined Cycle Facility. As of September 30, 2007, TVA had
eight combustion turbine generating facilities consisting of 83 combustion
turbine units providing a maximum of 6,258 megawatts of winter net dependable
capacity. All of the units are quick-start peaking facilities used
during periods of high demand, and all but three of the units are fueled by both
natural gas and fuel oil. As of September 30, 2007, 24 of the
combustion turbine units were leased to private entities and leased back to TVA
under long-term leases. See Note 13 — Other Financing
Obligations.
In 2007, TVA acquired and
re-commissioned combustion turbine facilities in Marshall County, Kentucky, and
Gleason, Tennessee. Together, these facilities include 11 units and
provide 1,296 megawatts of winter net dependable capacity (included in the total
above). In addition, in September 2007, the TVA Board approved the
acquisition and the construction of a combined cycle facility at a former
combustion turbine site of approximately 80 acres located in southwest
Tennessee. Now known as Lagoon Creek 3, the unfinished site contains
turbine foundations and substantial ancillary equipment. With an
anticipated commercial operation date of June 2010, the facility is expected to
have a planned winter net dependable capacity of approximately 600
megawatts. TVA completed acquisition of the site in October
2007.
Diesel
Generators. TVA has two diesel generator plants consisting of
nine units. At September 30, 2007, 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, 2007, the digester gas cofiring site provided
TVA with about three megawatts of renewable capacity. In addition,
the wind energy site and the solar energy 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 and Other
Agreements
TVA acquires power from a variety of
power producers through long-term and short-term power purchase agreements as
well as through spot market purchases. During 2007, TVA acquired 32 percent of
the power that it purchased on the spot market, 41 percent through short-term
power purchase agreements, and 27 percent through long-term power purchase
agreements that expire more than one year after September 30, 2007.
At September 30, 2007, TVA’s long-term
power purchase agreements provided TVA with 3,504 megawatts of winter net
dependable capacity. Counterparties to contracts for 1,308 megawatts
of this capacity were in bankruptcy, but the counterparties have continued to
perform under their power purchase agreements with TVA throughout their
bankruptcy proceedings. See Item 7, Management’s Discussion and
Analysis of Financial Condition and Results of Operations — Risk Management Activities — Credit
Risk.
A portion of TVA’s 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.
|
•
|
Caledonia Combined Cycle
Facility. During the third quarter of 2007, TVA entered
into an operating lease agreement and various related contracts for the
Caledonia combined cycle facility located near Columbus, Mississippi, with
a commencement date of July 1, 2007. The lease agreement has a
15-year term expiring on February 28, 2022. The Caledonia
facility consists of three combined cycle units with a winter net
dependable capacity of 892 megawatts. A conversion services
agreement providing for power purchases from the Caledonia facility was
terminated as of July 1, 2007, the lease commencement date, and dispatch
control was shifted to TVA on July 3, 2007. Under the lease,
TVA will assume plant operations no later than January 1,
2008. The lease agreement further provides for an end-of-term
purchase option.
|
|
•
|
Choctaw Generation,
L.P. TVA has contracted with Choctaw Generation L.P.
(“Choctaw”) for 440 megawatts of winter net dependable capacity from a
lignite-fired generating plant in Chester, Mississippi. TVA’s
contract with Choctaw expires on March 31, 2032. On October 9,
2007, Moody's Investors Service downgraded Choctaw to
'Ba1.' Choctaw has continued to perform under the contract and
has provided credit assurance to TVA, per the terms of the
contract.
|
|
•
|
Alcoa Power Generating,
Inc. Four hydroelectric plants owned by Alcoa Power
Generating, Inc. (“APGI”), formerly known as Tapoco, Inc, are operated in
coordination with the TVA system. Under contractual arrangements with APGI
which terminate on June 20, 2010, TVA dispatches the electric power
generated at these facilities and uses it to partially supply Alcoa’s
energy needs. TVA’s arrangement with APGI provides 348
megawatts of winter net dependable
capacity.
|
|
•
|
Invenergy TN
LLC. TVA has contracted with Invenergy TN LLC for 27
megawatts of wind energy generation from 15 wind turbine generators
located on Buffalo Mountain near Oak Ridge, Tennessee. Because of
the nature of wind conditions in the TVA service area, these generators
provide energy benefits but are not included in TVA’s net dependable
capacity total. TVA's contract with Invenergy TN LLC expires on
December 31, 2024.
|
|
|
•
|
Southeastern Power
Administration. TVA, along with others, contracted with
the Southeastern Power Administration (“SEPA”) to obtain power from eight
U.S. Army Corps of Engineers hydroelectric facilities on the Cumberland
River system. The agreement with SEPA can be terminated upon
three years’ notice, but this notice of termination may not become
effective prior to June 30, 2017. The contract originally
required SEPA to provide TVA an annual minimum of 1,500 hours of power for
each megawatt of TVA’s 405 megawatt allocation, and all surplus power from
the Cumberland River system. Because hydroelectric production
has been reduced at two of the hydroelectric facilities on the Cumberland
River system (Wolf Creek and Center Hill Dams) and because of reductions
in the summer stream flow on the Cumberland River, SEPA declared “force
majeure” on February 25, 2007. SEPA then instituted an
emergency operating plan that:
|
|
|
–
|
Eliminates
its obligation to provide any affected customer (including TVA) with a
minimum amount of power;
|
|
|
–
|
Provides
for all affected customers (except TVA) to receive a pro rata share of a
portion of the gross hourly generation from the eight Cumberland River
hydroelectric facilities;
|
|
|
–
|
Provides
for TVA to receive all of the remaining hourly generation (minus station
service for those facilities);
|
|
|
–
|
Eliminates
the payment of demand charges by customers (including TVA) since there is
significantly reduced dependable capacity on the Cumberland River system;
and
|
|
|
–
|
Increases
the rate charged per kilowatt-hour of energy received by SEPA’s customers
(including TVA), because SEPA is legally required to charge rates that
cover its costs.
|
It is unclear how long the emergency operating plan will remain in
effect.
Under the Public Utility Regulatory
Policies Act of 1978, as amended by the Energy Policy Act of 1992 and the Energy
Policy Act of 2005, TVA is required to purchase energy from qualifying
facilities, cogenerators and small power producers at TVA's avoided cost of
self-generating or purchasing this energy from another source.
During the past five years, TVA
supplemented its power generation through power purchases as
follows:
Purchased Power *
For the
years ended September 30
|
2007
|
2006
|
2005
|
2004
|
2003
|
||||||||||||||||
|
Millions
of kWh
|
22,141 | 19,019 | 14,892 | 14,025 | 15,181 | |||||||||||||||
|
Percent
of TVA’s Total Power Supply
|
12.4 | 10.9 | 8.5 | 8.3 | 9.1 | |||||||||||||||
Note
|
|
*
|
Purchased
power amounts for years 2004, 2005, and 2006 have been adjusted to remove
APGI purchases and include them as a credit to Industries directly
served.
|
For more information regarding TVA’s
power purchase obligations, see Note 15 — Commitments — Power Purchase
Obligations.
Purchasing power from others will
likely remain a part of how TVA meets the power needs of its service
area. The Strategic Plan establishes a goal of balancing production
capabilities with power supply requirements within five
percent. Achieving this goal will require TVA to reduce its reliance
on purchased power. In 2007, TVA took several actions which will help
reduce its dependence on purchased power.
|
|
•
|
TVA
purchased two additional combustion turbine facilities in December 2006
that together provide approximately 1,296 megawatts of winter net
dependable capacity. See Item 1, Business — Power Supply — Combustion Turbines and Future
Combined Cycle Facility.
|
|
|
•
|
Browns
Ferry Nuclear Plant Unit 1 (“Browns Ferry Unit 1”) began commercial
operation on August 1, 2007. Browns Ferry Unit 1 is initially
providing additional generating capacity of approximately 1,150 megawatts
and is expected eventually to provide approximately 1,280 megawatts of
capacity. See Item 1, Business —
Nuclear.
|
|
|
•
|
On
August 1, 2007, the TVA Board approved the completion of Watts Bar Nuclear
Plant Unit 2 (“Watts Bar Unit 2”) upon which construction was halted in
1985. Completing Watts Bar Unit 2 is expected to take 60 months
and cost approximately $2.5 billion, excluding allowance for funds used
during construction and initial nuclear fuel core costs. When completed,
the nuclear unit is expected to provide 1,180 megawatts of
capacity. See Item 1, Business — Nuclear.
|
|
|
•
|
In
September 2007, the TVA Board approved proceeding with the construction of
a combined cycle facility at a former combustion turbine site of
approximately 80 acres located in southwest Tennessee. See Item
1, Business — Power
Supply — Combustion Turbines and Future
Combined Cycle Facility.
|
Net Dependable Capacity
The following table summarizes the
winter and summer net dependable capacity in megawatts TVA had available as of
September 30, 2007:
NET
DEPENDABLE CAPACITY
As of
September 30, 2007
|
Source
of Capacity
|
Location
|
Number
of Units
|
Winter Net Dependable Capacity
1 (MW)
|
Summer Net Dependable Capacity
1
(MW)
|
Date
First Unit Placed in Service
|
Date
Last Unit Placed in Service
|
|||||||||
|
TVA-OWNED GENERATING
FACILITIES
|
|||||||||||||||
|
Coal-Fired
|
|||||||||||||||
|
Allen
|
Tennessee
|
3 | 744 | 735 |
1959
|
1959
|
|||||||||
|
Bull
Run
|
Tennessee
|
1 | 889 | 889 |
1967
|
1967
|
|||||||||
|
Colbert
|
Alabama
|
5 | 1,197 | 1,180 |
1955
|
1965
|
|||||||||
|
Cumberland
|
Tennessee
|
2 | 2,532 | 2,478 |
1973
|
1973
|
|||||||||
|
Gallatin
|
Tennessee
|
4 | 976 | 964 |
1956
|
1959
|
|||||||||
|
John
Sevier
|
Tennessee
|
4 | 712 | 704 |
1955
|
1957
|
|||||||||
|
Johnsonville
|
Tennessee
|
10 | 1,248 | 1,200 |
1951
|
1959
|
|||||||||
|
Kingston
|
Tennessee
|
9 | 1,433 | 1,411 |
1954
|
1955
|
|||||||||
|
Paradise
|
Kentucky
|
3 | 2,324 | 2,201 |
1963
|
1970
|
|||||||||
|
Shawnee
|
Kentucky
|
10 | 1,369 | 1,329 |
1953
|
1956
|
|||||||||
|
Widows
Creek
|
Alabama
|
8 | 1,628 | 1,604 |
1952
|
1965
|
|||||||||
|
Total
Coal-Fired
|
59 | 15,052 | 14,695 | ||||||||||||
|
Nuclear
|
|||||||||||||||
|
Browns
Ferry
|
Alabama
|
3 | 3,383 | 3,280 |
1974
|
1977
|
|||||||||
|
Sequoyah
|
Tennessee
|
2 | 2,333 | 2,282 |
1981
|
1982
|
|||||||||
|
Watts
Bar
|
Tennessee
|
1 | 1,182 | 1,109 |
1996
|
1996
|
|||||||||
|
Total
Nuclear
|
6 | 6,898 | 6,671 |
|
|||||||||||
|
Hydroelectric
|
|||||||||||||||
|
Conventional
Plants
|
Alabama
|
36 | 1,146 | 1,188 |
1925
|
1962
|
|||||||||
|
Georgia
|
2 | 32 | 35 |
1931
|
1956
|
||||||||||
|
Kentucky
|
5 | 165 | 218 |
1944
|
1948
|
||||||||||
|
North
Carolina
|
6 | 455 | 489 |
1940
|
1956
|
||||||||||
|
Tennessee
|
60 | 1,735 | 1,918 |
1912
|
1972
|
||||||||||
|
Pumped
Storage
|
Tennessee
|
4 | 1,653 | 1,653 |
1978
|
1979
|
|||||||||
|
Total
Hydroelectric
|
113 | 5,186 | 5,501 | ||||||||||||
|
Combustion Turbine 2
|
|||||||||||||||
|
Allen
|
Tennessee
|
20 | 597 | 478 |
1971
|
1972
|
|||||||||
|
Colbert
|
Alabama
|
8 | 480 | 384 |
1972
|
1972
|
|||||||||
|
Gallatin
|
Tennessee
|
8 | 790 | 636 |
1975
|
2000
|
|||||||||
|
Gleason
3
|
Tennessee
|
3 | 540 | 519 |
2007
|
2007
|
|||||||||
|
Johnsonville
|
Tennessee
|
20 | 1,509 | 1,218 |
1975
|
2000
|
|||||||||
|
Kemper
|
Mississippi
|
4 | 390 | 329 |
2001
|
2001
|
|||||||||
|
Lagoon
Creek
|
Tennessee
|
12 | 1,196 | 1,009 |
2002
|
2002
|
|||||||||
|
Marshall
County
|
Kentucky
|
8 | 756 | 659 |
2007
|
2007
|
|||||||||
|
Total
Combustion Turbine
|
83 | 6,258 | 5,232 |
|
|||||||||||
|
|
|||||||||||||||
|
Diesel Generator
|
|||||||||||||||
|
Meridian
|
Mississippi
|
5 | 9 | 9 |
1998
|
1998
|
|||||||||
|
Albertville
|
Alabama
|
4 | 4 | 4 |
2000
|
2000
|
|||||||||
|
Total
Diesel Generators
|
9 | 13 | 13 |
|
|||||||||||
|
Renewable
Resources
|
3 | 3 | |||||||||||||
|
Total
TVA-Owned Generation Facilities
|
33,410 | 32,115 | |||||||||||||
|
POWER PURCHASE AND OTHER
AGREEMENTS
|
|||||||||||||||
|
APGI
|
348 | 347 | |||||||||||||
|
Caledonia
|
892 | 768 | |||||||||||||
|
Choctaw
|
440 | 440 | |||||||||||||
|
Other
Power Purchase Agreements
|
1,824 | 1,872 | |||||||||||||
|
Total
Power Purchase Agreements
|
3,504 | 3,427 | |||||||||||||
|
Total
Net Dependable Capacity
|
36,914 | 35,542 | |||||||||||||
|
|
Notes
|
|
|
(1)
|
Net
dependable capacity is defined as the ability of an electric system,
generating unit, or other system component to carry or generate power for
a specified time period excluding any fluctuations in capacity that may
occur due to planned outages, unplanned outages, and
deratings.
|
|
|
(2)
|
As
of September 30, 2007, 24 of TVA’s combustion turbine units were leased to
private entities and leased back to TVA under long-term
leases.
|
|
|
(3)
|
Plant
does not have firm gas transportation or the ability to burn oil as a
back-up fuel; however, TVA forecasts available gas supply for Gleason
throughout the fiscal year.
|
Overview
TVA has six operating nuclear units and
has resumed construction of one nuclear unit that is scheduled to be placed in
service in 2013. Selected statistics of each of these units are
included in the table below.
TVA
Nuclear Power
As of
September 30, 2007
|
Nuclear
Unit
|
Status
|
Installed Capacity (MW)
|
Net
Capacity Factor for 2007
|
Date
of Expiration of Operating License
|
Date
of Expiration of Construction License
|
||||||||||
|
Sequoyah
Unit 1
|
Operating
|
1,221 | 98.5 |
2020
|
–
|
||||||||||
|
Sequoyah
Unit 2
|
Operating
|
1,221 | 89.5 |
2021
|
–
|
||||||||||
|
Browns
Ferry Unit 1
|
Operating
|
1,150 | 85.6 | (1) |
2033
|
–
|
|||||||||
|
Browns
Ferry Unit 2
|
Operating
|
1,190 | 74.0 |
2034
|
–
|
||||||||||
|
Browns
Ferry Unit 3
|
Operating
|
1,190 | 94.1 |
2036
|
–
|
||||||||||
|
Watts
Bar Unit 1
|
Operating
|
1,230 | 82.3 |
2035
|
–
|
||||||||||
|
Watts
Bar Unit 2
(2)
|
Construction
to resume in December 2007
|
– | – |
–
|
2010
|
||||||||||
|
|
Notes
|
(1) Browns
Ferry Unit 1 capacity factor is derived for a period of commercial operation
from August 1, 2007, through September 30, 2007.
(2) Completion
of construction of Watts Bar Unit 2 was approved by the TVA Board on August 1,
2007.
TVA began a significant nuclear plant
construction program in 1966 to meet projected system load growth. At
the height of its construction program, TVA had 17 units either under
construction or in commercial operation at seven plant sites. In
1982, TVA canceled construction of four units because of lower than expected
load growth, and TVA canceled four more units in 1984 for similar
reasons.
By August 1985, TVA had delayed
construction of two units each at Watts Bar and Bellefonte Nuclear Plants and
had shut down its three-unit Browns Ferry Nuclear Plant and two-unit Sequoyah
Nuclear Plant because of an increasing number of technical and operational
problems. The Nuclear Regulatory Commission (“NRC”) required TVA to
address program and management deficiencies and to provide its corrective
actions to the NRC before restarting any of its licensed nuclear units or
requesting a license for Watts Bar Unit 1. After implementing a
comprehensive recovery plan, TVA restarted Sequoyah Unit 2 in May 1988 and
Sequoyah Unit 1 in November 1988. TVA restarted Browns Ferry Unit 2
in May 1991 and Browns Ferry Unit 3 in November 1995. Construction of
Watts Bar Unit 1 was successfully completed, and the unit commenced full power
commercial operation in May 1996.
In May 2002, the TVA Board initiated
activities to return Browns Ferry Unit 1 to service, and on August 1, 2007,
Browns Ferry Unit 1 returned to commercial operation. The total
amount invested in the Unit 1 restart project through the commercial operation
date was $1.84 billion excluding allowance for funds used during construction
(“AFUDC”) of $269 million. TVA completed Browns Ferry Unit 1 during
2007 with a total project cost overrun of $90 million or five percent of the
original projected cost. The cost overruns were due in part
to the scope of work associated with extended power uprate being
greater than planned. Browns Ferry Unit 1 provides additional
generating capacity of approximately 1,150 megawatts and is expected to
eventually provide 1,280 megawatts of capacity.
In November 2005, TVA canceled the
construction of Units 1 and 2 at Bellefonte Nuclear Plant. Two months
prior to the cancellation of these units, the Bellefonte site was selected by
NuStart Development LLC (“NuStart”) as one of two sites for the development of a
combined license application for two new reactors using the Westinghouse
Advanced Passive 1000 (“AP1000”) reactor design. NuStart is an
industry consortium composed of 10 utilities and two reactor vendors whose
purpose is to satisfactorily demonstrate the new NRC licensing process for
advanced design nuclear plants. TVA submitted its combined license
application to the NRC for Bellefonte Units 3 and 4 in October
2007. If approved, the license to build and operate the plant would
be issued to TVA. Obtaining the necessary license will give TVA more
certainty about the cost and schedule of a nuclear option for future
decisions. The TVA Board has not made a decision to construct a new
plant at the Bellefonte site.
On August 1, 2007, the TVA Board
approved completing the construction of Watts Bar Unit 2. Prior to
the approval, TVA conducted a detailed scoping, estimating, and planning study
to estimate the project’s cost, schedule, and risks. Separately, TVA
prepared a report evaluating potential environmental impacts as required by the
National Environmental Policy Act. TVA has an NRC construction permit
for Watts Bar Unit 2 that expires in 2010 and will need to seek an extension of
the permit in order to complete construction activities. TVA will
seek an operating license under NRC regulations, and this process will include
an opportunity for a public hearing. Completing Watts Bar Unit 2 is
expected to take approximately 60 months and cost approximately $2.5 billion,
excluding AFUDC. Preliminary project activities began in October
2007. In accordance with NRC policy, TVA notified the NRC that it may resume
unrestricted construction activities as early as December 3,
2007. Current plans are to begin construction related activities
by the end of December 2007. When completed, Watts Bar Unit 2 is expected
to provide 1,180 megawatts of capacity.
Spent Nuclear Fuel
Under the Nuclear Waste Policy Act of
1982, TVA (and other domestic nuclear utility licensees) entered into a contract
with the U.S. Department of Energy (“DOE”) for the disposal of spent nuclear
fuel. Payments to DOE are based upon TVA’s nuclear generation and
charged to nuclear fuel expense. Although the contracts called for
DOE to begin accepting spent nuclear fuel from the utilities by January 31,
1998, DOE announced that it would 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. TVA would have had sufficient space to continue to
store spent nuclear fuel in those storage pools at its Sequoyah and Browns Ferry
Nuclear Plants indefinitely had DOE begun accepting spent nuclear
fuel. DOE’s failure to do so in a timely manner required TVA to
construct dry cask storage facilities at its Sequoyah and Browns Ferry Nuclear
Plants and to purchase special storage containers for the spent nuclear
fuel. The Sequoyah and Browns Ferry dry cask storage facilities have
been constructed and approved by the NRC and have been in use since 2004 and
2005, respectively, providing storage capacity through 2030 at Sequoyah and 2019
at Browns Ferry. Watts Bar has sufficient storage capacity in its
spent fuel pool to last until approximately 2015.
To recover the cost of providing
long-term, on-site storage for spent nuclear fuel, TVA filed a breach of
contract suit against the United States in the Court of Federal Claims in
2001. In August 2006, the United States paid TVA almost
$35 million in damages awarded by the Court of Federal Claims, which
partially offset the construction costs of the dry cask storage facilities that
TVA incurred through 2004. TVA is pursuing 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. As allowed
by the Low-Level Radioactive Waste Policy Act, on July 1, 2008, the Barnwell,
South Carolina, facility will close to radwaste generators located in states
that are not members of the Atlantic Interstate Low-Level Radioactive Waste
Management Compact ("Atlantic Compact"). Connecticut, New Jersey, and
South Carolina are members of the Atlantic Compact. Accordingly, after
June 2008, TVA will no longer be able to use this disposal facility and
will have to consider other options, which may include storing some radwaste at
its own facilities. TVA is capable of doing so for an extended period
of time, and has done so in the past.
Nuclear
Decommissioning Trust
TVA maintains a nuclear decommissioning
trust to provide funding 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, 2007, totaled $1.1 billion, which is
greater than the present value of TVA’s estimated future nuclear decommissioning
costs as computed under the NRC funding requirements but less than the present
value of these costs as computed under Statement of Financial Accounting
Standards No. 143, “Accounting
for Asset Retirement Obligations.” See Note 15 — 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 for each plant with an operating
license. Funds for the second layer, the Secondary Financial Program,
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
unit. American Nuclear Insurers, under a contract with the NRC,
administers the Secondary Financial Program. With its six licensed
units, TVA could be required to pay a maximum of $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 $4.6 billion
for its licensed nuclear plants, with up to $2.1 billion available for a loss at
any one site, to cover the cost of stabilizing or shutting down a reactor after
an accident. Some of this insurance, which is purchased from Nuclear
Electric Insurance Limited (“NEIL”), may require the payment of retrospective
premiums up to a maximum of approximately $66 million. On October 1,
2007, TVA endorsed the existing property policies for the Watts Bar Nuclear
Plant site to add Builders Risk coverage for the construction of Unit
2. The addition of this coverage places the new maximum retrospective
assessment at $70.5 million.
TVA purchases accidental outage
(business interruption) insurance for TVA’s nuclear sites from
NEIL. In the event that an accident covered by this policy takes a
nuclear unit offline or keeps a nuclear unit offline, NEIL will pay TVA, after a
waiting period, an indemnity (a set dollar amount per week) up to a maximum
indemnity of $490 million per unit. This insurance policy may require
the payment of retrospective premiums up to a maximum of approximately $24
million. See Note 15 — Contingencies — Nuclear
Insurance.
Tritium-Related
Services
TVA and DOE are engaged in a long-term
interagency agreement under which TVA will, at DOE’s request, irradiate tritium
producing burnable absorber rods to assist DOE in producing
tritium. Tritium is used in nuclear weapons. This
agreement, which ends in 2035, requires DOE to reimburse TVA for the costs that
TVA incurs in connection with providing irradiation services and to pay TVA an
irradiation services fee at a specified rate per tritium-producing rod over the
entire operating cycle in which the tritium-producing rods are
irradiated.
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 DOE at these plants. The Watts Bar license amendment
currently permits TVA to install up to 240 tritium-producing rods in 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 and Sequoyah
reactors.
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 its tritium-extraction
facility. TVA loads a fresh set of tritium-producing rods into the
reactor during each refueling outage. Irradiating the
tritium-producing rods does not affect TVA’s ability to operate the reactors to
produce electricity.
TVA began irradiating tritium-producing
rods at Watts Bar Unit 1 in the fall of 2003. TVA removed these rods
from the reactor in the spring of 2005. DOE subsequently successfully
shipped them to its tritium-extraction facility. At this time, no
tritium-related services are being performed at the Sequoyah Nuclear
Plant.
General
TVA’s consumption of various types of
fuel depends largely on the demand for electricity by TVA’s customers, the
availability of various generating units, and the availability and cost of
fuel. The following table indicates TVA’s costs for various fuels for
the years indicated:
Fuel
Purchases for TVA-Owned Facilities
For the
years ended September 30
(in
millions)
|
2007
|
2006
|
2005
|
2004
|
2003
|
||||||||||||||||
|
Coal
|
$ | 1,922 | $ | 1,835 | $ | 1,495 | $ | 1,254 | $ | 1,242 | ||||||||||
|
Natural
gas
|
62 | 60 | 63 | 22 | 42 | |||||||||||||||
|
Fuel
oil
|
22 | 46 | 28 | 17 | 40 | |||||||||||||||
|
Uranium
|
121 | 71 | 44 | 16 | 42 | |||||||||||||||
|
Total
|
$ | 2,127 | $ | 2,012 | $ | 1,630 | $ | 1,309 | $ | 1,366 | ||||||||||
TVA also has tolling agreements under
which it buys power production from outside suppliers. Under these
tolling agreements, TVA supplies the fuel to the outside supplier, and the
outsider supplier converts the fuel into electricity. The following
table indicates the cost of fuel supplied by TVA under these agreements and also
the average fuel expense per kilowatt-hour for the years indicated:
Natural
Gas Purchases and Average Fuel Expense for Tolling Plants
For the
years ended September 30
|
2007
|
2006
|
2005
|
2004
|
2003
|
||||||||||||
| Cost of Fuel (in millions) | $ | 430 | $ | 288 | $ | 159 | $ | 10 | $ | <1 | ||||||
|
Average
Fuel Expense (cents/kWh)
|
5.51 | 6.07 | 6.21 | 4.71 | 0.00 | |||||||||||
Beginning with the implementation of
the FCA mechanism on October 1, 2006, TVA’s rates are adjusted on a quarterly
basis to reflect changing fuel and purchased power costs. See Item 1,
Business — Rate
Actions.
Coal
Coal consumption at TVA’s coal-fired
generating facilities during 2007 was 46.5 million tons. As of September 30,
2007 and 2006, TVA had 23 days and 20 days of system-wide coal supply at full
burn, respectively, with a net book value of coal inventory of $264 million and
$214 million, respectively.
TVA utilizes both short-term and
long-term coal contracts. Long-term coal contracts generally last
longer than one year, while short-term contracts are usually for one year or
less. During 2007, long-term contracts made up 89 percent of coal
purchases and short-term contracts accounted for the remaining 11
percent. TVA plans to continue signing contracts of various lengths,
terms, and coal quality to meet its expected burn and inventory
requirements. During 2007, TVA purchased coal by basin as
follows:
|
•
|
37
percent from the Illinois Basin;
|
|
•
|
24
percent from the Powder River Basin in
Wyoming;
|
|
•
|
23
percent from the Uinta Basin of Utah and Colorado;
and
|
|
•
|
16
percent from the Appalachian Basin of Kentucky, Pennsylvania, Tennessee,
Virginia, and West Virginia.
|
Total system coal inventories were at
or above target levels for all of 2007. During 2007, 42 percent of TVA’s coal
supply was delivered by rail, 19 percent was delivered by barge, and 33 percent
was delivered by a combination of barge and rail. The remainder was delivered by
truck.
Natural
Gas and Fuel Oil
During
2007, 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, 2007,
all but one of TVA’s combustion turbine plants were dual fuel capable, and TVA
has fuel oil stored on each site for its dual-fuel combustion turbines as a
backup to natural gas.
During
2007, TVA purchased substantially all of its fuel oil on the spot
market. At September 30, 2007 and 2006, the net book value of TVA’s
natural gas in inventory was $3 million and $2 million, respectively, and the
net book value of TVA’s fuel oil in inventory was $50 million and $54 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 four-year
(2008 through 2011) uranium mining and milling 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 four-year (2008 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, DOE, and some nuclear fuel
contractors have entered into agreements that provide for the blending down of
surplus DOE highly enriched uranium (uranium that is too highly enriched for use
in a nuclear power plant) with other uranium. Under these agreements,
the enriched uranium that results from this blending process, which is called
blended low enriched uranium (“BLEU”), is fabricated into fuel that can be used
in a nuclear power plant. This blended nuclear fuel was first loaded
in a Browns Ferry reactor in 2005 and is expected to continue to be used to
reload the Browns Ferry reactors through 2013. Plans are underway to
begin using BLEU fuel in Sequoyah Unit 2 beginning in 2008.
Under the terms of an interagency
agreement between DOE and TVA, in exchange for supplying highly enriched uranium
materials for processing into usable BLEU fuel for TVA, DOE will participate to
a degree in the savings generated by TVA’s use of this blended nuclear
fuel. TVA anticipates these future payments could begin in 2009 and
last until 2013. See Note 1 — Blended Low Enriched Uranium Program
for a more detailed discussion of the BLEU project.
TVA owns
all nuclear fuel held for its nuclear plants. As of September 30,
2007 and 2006, the net book value of this nuclear fuel was $602 million and $491
million, respectively.
For a
discussion of TVA’s plans with respect to spent nuclear fuel storage, see Item
1, Business — Nuclear — Spent
Nuclear Fuel.
The TVA transmission system is one of
the largest in North America. The system delivered nearly 175 billion
kilowatt-hours of electricity in 2007, and has operated with 99.999 percent
reliability over the last eight years in delivering electricity to
customers.
To the extent federal law allows access
to the TVA transmission system, the TVA transmission organization offers
transmission services to others to transmit power at wholesale in a manner that
is comparable to TVA's own use of the transmission system. TVA has also adopted
and operates in accordance with a published Standards of Conduct for
Transmission Providers and appropriately separates its transmission functions
from its marketing functions.
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 E.ON U.S. subsidiaries Kentucky Utilities
Company and Louisville Gas and Electric Company.
Consistent with these arrangements, TVA
has been designated by the North American Electric Reliability Corporation
(“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 coordinators in
NERC.
Additionally, TVA, in its capacity as
reliability coordinator, has executed 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 coordinate analysis and
operational processes in support of regional transmission reliability have been
executed with Entergy Services, Inc., Southwest Power Pool, Inc., Southern
Company Services, Inc., and VACAR South RC (a Virginia Carolina reliability
group).
Reliability
Coordinator Map
A new interconnection, the Five Points
- Homewood project, was completed to address several contingency issues in the
southern extreme of TVA's Mississippi service area. This interconnection with
South Mississippi Electric Power Association is the first with a neighboring
utility since 1993. TVA now has interconnections with 13 neighboring
electric systems.
Mandatory compliance with certain
reliability standards began on June 18, 2007. FERC issued its final
rule on the Electric Reliability Organization (“ERO”) Reliability Standards,
approving 83 of 107 proposed standards submitted by the North American Electric
Reliability Corporation. The mandatory reliability standards apply to
all users, owners, and operators of the bulk power system, including TVA, and
both monetary and non-monetary penalties may be imposed for violations of the
standards. The most serious violations can be subject to penalties of up to $1
million per day per violation. The rule directs the ERO to focus on the most
serious violations during an initial period through December 31,
2007. To the best of its knowledge, TVA is operating in conformity
with these reliability standards.
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
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, as well as cooling water for some of
TVA’s coal-fired and nuclear power plants.
TVA reservoirs and public lands provide
outdoor recreation opportunities for millions of visitors each
year. TVA has stewardship responsibility for approximately 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 furnishes over 100 recreation facilities such as
campgrounds, boat ramps, fishing piers, and picnic areas.
Weather affects both the demand for and
the market prices of electricity. TVA’s power system generally peaks
in the summer, with a slightly lower peak in the winter. After
meeting a peak demand of over 32,000 megawatts for the first time in 2006, TVA
met peak demands that exceeded 33,000 megawatts six times in August
2007. TVA met its highest winter peak demand of 30,320 megawatts on
January 31, 2007, and met its highest peak power demand ever, at 33,482
megawatts, late in the afternoon on August 16, 2007, when the average
temperature across the Tennessee Valley was 102 degrees
Fahrenheit. See Item 1A, Risk Factors, for a discussion of the
potential impact of weather on TVA.
TVA uses weather degree days to measure
the impact of weather on TVA’s power operations. Weather degree days
measure the extent to which average temperatures in the five largest cities in
TVA's service area vary from 65 degrees Fahrenheit. TVA
calculates weather degree days for Memphis, Nashville, Knoxville, and
Chattanooga, Tennessee, and Huntsville, Alabama, the five largest cities in
TVA’s service area.
During 2007, TVA had five more heating
degree days and 253 more cooling degree days than in 2006. The graph
below shows the number of heating and cooling degree days for 2007, 2006, and
2005 as compared to the normal number of heating and cooling degree
days. See Item 7, Management’s Discussion and Analysis of Financial
Condition and Results of Operations — Executive Summary — Challenges
During 2007 — Weather Conditions.
2007 was the driest year in the eastern
Tennessee Valley in 118 years of record-keeping with rainfall 66 percent of
normal for the year and runoff 54 percent of normal. Largely as a
result of this low rainfall and runoff, TVA’s hydroelectric production for 2007
was slightly more than nine billion kilowatt-hours, which was nine percent, 42
percent, and 35 percent lower than 2006, 2005, and 2004,
respectively.
The hot weather and low rainfall were
also significant factors in causing TVA to reduce output at several generating
plants during the period of mid-June through mid-September. During
this period, temperatures on the Tennessee and Cumberland Rivers reached levels
at which discharging cooling water from some of TVA’s plants into the rivers
could have caused the permitted thermal limits for the rivers to be
exceeded. While every effort was made to lower electrical output
during low load periods (derates) to reduce financial and operational impacts,
some derates were required during higher load daytime hours to meet the
permitted temperature limits. These conditions caused TVA to rely
heavily on purchased power and more expensive generation sources such as
combustion turbines during 2007. See Item 7, Management’s Discussion
and Analysis of Financial Condition and Results of Operations — Executive Summary —Challenges During
2007 — Weather Conditions.
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 use the TVA
transmission system for the purpose of serving customers within TVA’s service
area. Bristol, Virginia, was exempted from the anti-cherrypicking
provision.
Recently there have been efforts to
erode the protection of the anti-cherrypicking provision. FERC issued
an order that would have required TVA to interconnect its transmission system
with the transmission system of East Kentucky Power Cooperative, Inc. (“East
Kentucky”) in what TVA believed was a violation of the anti-cherrypicking
provision. See Item 3, Legal Proceedings. Additionally,
Senators Jim Bunning and Mitch McConnell introduced the Access to Competitive
Power Act of 2007 in the Senate that would, among other things, provide that the
anti-cherrypicking provision would not apply with respect to any distributor
which provided a termination notice to TVA before December 31, 2006, regardless
of whether the notice was later withdrawn or rescinded. See Item 7,
Management’s Discussion and Analysis of Financial Condition and Results of
Operations — Legislative and
Regulatory Matters. While the FERC action involving East
Kentucky now appears to be moot and the proposed legislation has not made it to
the Senate floor, the events illustrate how the protection to TVA’s service area
provided by the anti-cherrypicking provision could be called into question and
perhaps eliminated at some time in the future.
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, reduce, or eliminate TVA’s activities, significantly change
TVA’s structure, require TVA to sell all or a portion of its assets, or reduce
the U.S. government's ownership interest in TVA. 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, cultural resources, and civil rights
laws.
Securities
and Exchange Commission
Section 37 was added to the Securities
Exchange Act of 1934, as amended (the “Exchange Act”), as part of the
Consolidated Appropriations Act, 2005. Section 37 requires TVA to
file with the Securities and Exchange Commission 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. TVA is also exempted by
section 37 of the Exchange Act from complying with section 10A(m)(3) of the
Exchange Act, which requires each member of a listed issuer’s audit committee to
be an independent member of the board of directors of the
issuer. Since TVA is an agency and instrumentality of the United
States, securities issued or guaranteed by TVA are “exempted securities” under
the Securities Act of 1933, as amended (the “Securities Act”), and may be
offered and sold without registration under the Securities Act. In
addition, securities issued or guaranteed by TVA are “exempted securities” and
“government securities” under the Exchange Act. TVA is also exempt
from sections 14(a)-(d) and 14(f)-(h) of the
Exchange
Act (which address proxy solicitations) insofar as those sections relate to
securities issued by TVA, and transactions in TVA securities are exempt from
rules governing tender offers under Regulation 14E of the Exchange
Act. In addition, since TVA securities are exempted securities under
the Securities Act, TVA is exempt from the Trust Indenture Act of 1939 insofar
as it relates to securities issued by TVA, and no independent trustee is
required for these securities.
Federal
Energy Regulatory Commission
TVA is not a “public utility” as
defined in the Federal Power Act (“FPA”), a term which generally includes
investor-owned utilities. Therefore, TVA is not subject to the full
jurisdiction that FERC exercises over public utilities under the
FPA. TVA is, however, an “electric utility” as defined in the FPA
and, thus, is directly subject to certain aspects of FERC’s
jurisdiction.
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Under
section 210 of the FPA, TVA can be ordered to interconnect its
transmission facilities with the electrical facilities of qualified
generators and other electric utilities that meet certain
requirements. It must be found that the requested
interconnection is in the public interest and would either encourage
conservation of energy or capital, optimize efficiency of facilities or
resources, or improve reliability. The requirements of
section 212 concerning the terms and conditions of interconnection,
including reimbursement of costs, must also be
met.
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Under
section 211 of the FPA, TVA can be ordered to transmit power at
wholesale provided that the order does not impair the reliability of the
TVA or surrounding systems and likewise meets the applicable requirements
of section 212 concerning terms, conditions, and rates for
service. Under section 211A of the FPA, TVA is subject to FERC
review of the transmission rates and the terms and conditions of service
that TVA provides others to ensure comparability of treatment of such
service with TVA’s own use of its transmission system. With the
exception of wheeling power to Bristol, Virginia, the anti-cherrypicking
provision of the FPA precludes TVA from being ordered to wheel another
supplier’s power to a customer if the power would be consumed within TVA’s
defined service territory.
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Sections
221 and 222 of the FPA, applicable to all market participants, including
TVA, prohibit (i) using manipulative or deceptive devices or
contrivances in connection with the purchase or sale of power or
transmission services subject to FERC’s jurisdiction and (ii) reporting
false information on the price of electricity sold at wholesale or the
availability of transmission capacity to a federal agency with intent to
fraudulently affect the data being compiled by the
agency.
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Section
206(e) of the FPA provides FERC with authority to order refunds of
excessive prices on short-term sales (transactions lasting 31 days or
less) by all market participants, including TVA, in market manipulation
and price gouging situations if such sales are under a FERC-approved
tariff.
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Section
220 of the FPA provides FERC with authority to issue regulations requiring
the reporting, on a timely basis, of information about the availability
and prices of wholesale power and transmission service by all market
participants, including TVA.
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Under
sections 306 and 307 of the FPA, FERC may investigate electric
industry practices, including TVA’s operations previously mentioned that
are subject to FERC’s jurisdiction.
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Under
sections 316 and 316A of the FPA, FERC has authority to impose
criminal penalties and civil penalties of up to $1 million a day for
each violation on entities subject to the provisions of Part II of
the FPA, which includes the above provisions applicable to
TVA.
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Finally, while not required to do so,
TVA has elected to implement various FERC orders and regulations pertaining to
public utilities on a voluntary basis to the extent that these are consistent
with TVA’s obligations under the TVA Act.
For a discussion of legislation that
could change FERC’s ability to regulate TVA, see Item 7, Management’s Discussion
and Analysis of Financial Condition and Results of Operations — Legislative and Regulatory
Matters.
Nuclear
Regulatory Commission
TVA, like other utilities, operates its
nuclear facilities in a highly regulated environment and is subject to the
oversight of the NRC, an independent agency which sets the rules that users of
radioactive materials must follow. The NRC has broad authority to
impose requirements relating to the licensing, operation, and decommissioning of
nuclear generating facilities. In addition, if TVA fails to comply with
requirements promulgated by the NRC, the NRC has the authority to impose fines,
shut down units, or modify, suspend, or revoke TVA’s operating
licenses.
Environmental Protection
Agency
TVA is subject to regulation by the
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 U.S.
Constitution prohibits states, without congressional consent, from regulating
the manner in which the federal government conducts its
activities. As a federal agency, TVA is exempt from regulation,
control, and taxation by states except in certain areas such as air and water
quality where Congress has given the states limited powers to regulate federal
activities.
Other
Federal Entities
TVA’s activities and records are also
subject to review by various entities including TVA’s Office of Inspector
General and the following agencies: the Government Accountability
Office, the Congressional Budget Office, and the Office of Management and
Budget.
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 total amount of
these payments is five percent of gross revenues from the sale of power during
the preceding year excluding sales or deliveries to other federal agencies and
off-system sales with other utilities, with a provision for minimum payments
under certain circumstances. Distribution of in lieu of tax payments
within a state is determined by individual state legislation.
TVA’s power generation activities, like
those across the utility industry and in other industrial sectors, are subject
to federal, state, and local environmental statutes and
regulations. Major areas of regulation affecting TVA’s activities
include air quality control, water quality control, and management and disposal
of solid and hazardous wastes.
TVA has incurred, and expects to
continue to incur, substantial capital and operating and maintenance costs to
comply with evolving environmental requirements primarily associated with the
operation of TVA’s 59 coal-fired generating units. While 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 that apply to fossil-fuel units are becoming more
stringent, and additional regulatory programs affecting fossil-fuel units were
promulgated in 2005. These new regulatory programs include the Clean
Air Interstate Rule (“CAIR”) and the Clean Air Mercury Rule
(“CAMR”). CAIR requires significant additional utility reductions of
emissions of sulfur dioxide (“SO2”) and
nitrogen oxides (“NOx”) in the
eastern half of the United States (including all of TVA’s operating area), and
CAMR establishes caps for overall mercury emissions in two phases with the first
phase becoming effective in 2010 and the second in 2018. TVA had
previously estimated its total capital cost for reducing emissions from its
power plants from 1977 through 2010 would reach $5.8 billion, $4.8 billion of
which had already been spent as of September 30, 2007. TVA estimates
that compliance with CAIR and CAMR could lead to additional costs of $3.0
billion to $3.6 billion in the decade beginning in 2011. 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. These costs cannot
reasonably be predicted at this time.
In addition, an existing federal water
regulation covering cooling water intake structures and temperatures may also
become more stringent. In January 2007, the United States Court of
Appeals for the Second Circuit Court (“Second Circuit”) remanded EPA’s rule on
this subject. In response, EPA has suspended the rule, and several
parties are seeking United States Supreme Court review of the Second Circuit
decision. If the Second Circuit’s decision becomes law after all
appeal processes and the issuance of a new rule, compliance is expected to be
more costly for the power industry. TVA is unable at this time to estimate these
costs.
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 as programs evolve 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
2007 and 2006 were approximately $239 million and $182 million,
respectively. These figures include expenditures in 2007 of $7
million to continue to reduce NOx emissions
through the installation of selective catalytic reduction (“SCR”) and selective
non-catalytic reduction (“SNCR”) systems and $207 million for the installation
of flue gas desulfurization systems (“scrubbers”) to continue to reduce SO2 emissions,
each of which is explained in more detail below. The aforementioned
estimate of $5.8 billion does not include additional capital costs of $3.0
billion to $3.6 billion that TVA expects to incur over the decade beginning in
2011 to comply with CAIR and CAMR. Increasingly stringent regulation
of some or all of these substances, as well as mercury and possibly CO2, will
continue to result in significant capital and operating costs for TVA’s
coal-fired generating units.
Sulfur
Dioxide. Coal-fired utilities have historically emitted large
amounts of SO2 compared
to today’s emissions. Utility SO2 emissions
are currently regulated under the Federal Acid Rain Program and state programs
designed to meet the National Ambient Air Quality Standards (“NAAQS”) for
SO2
and fine particulate matter. Looking forward, additional regulation of SO2 emissions
will result from implementation of the Regional Haze Program and
CAIR. In May 2005, EPA finalized CAIR to reduce the interstate
transport of fine particulate matter and ozone by requiring additional large
reductions in utility emissions of NOX and
SO2
from 28 eastern states. All seven states in TVA’s service area are
submitting plans to EPA to implement CAIR through 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 Atmospheric Fluidized Bed Combustion
(“AFBC”) technology, and installing scrubbers on seven of its larger
units. TVA began construction in 2005 on its eighth scrubber at its
Bull Run Fossil Plant and in 2006 began construction 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 at several additional units in the next few
years. 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 any future tightening of applicable
requirements.
Nitrogen Oxides. Utility
NOx
emissions continue to be regulated under state programs to achieve and maintain
EPA’s NAAQS for ozone, the Federal Acid Rain Program, the Regional Haze Program,
and CAIR. 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 59 coal-fired units and installing SCRs
on 21 of the largest units. (The AFBC unit at Shawnee Fossil Plant is inherently
low NOx
emitting.)
In 2005, TVA installed SNCR systems on
two units to demonstrate long-term technology capability, and continued to
operate the SNCR at Johnsonville Unit 1 through the 2007 ozone
season. SNCRs generally have lower NOx removal
capabilities than SCRs. Early in 2006, TVA began testing a High
Energy Reagent Technology (“HERT”) on three units for potential future
application. HERT is similar to SNCR but has higher removal
capabilities than SNCRs. The initial HERT testing program was
successful, and in 2007, TVA installed this technology on two coal-fired units
(Johnsonville Unit 4 and John Sevier Unit 1) to demonstrate the HERT technology
on a potentially permanent basis. Similar equipment is planned for
installation on the other three John Sevier units and Johnsonville Units 2 and 3
by 2009.
TVA’s NOx emission
reduction program is expected to continue to depend primarily on SCRs, but will
also 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 affecting power plant
emissions.
On June 21, 2007, EPA proposed
lowering the eight-hour ozone NAAQS. This proposal began a process that is
expected to lead to a final decision in March 2008 on revising the ozone
standard. Meeting the more stringent EPA standards for ozone contained in the
proposal will challenge states and communities in the Tennessee Valley and
across the country.
The current primary standard, set in
1997, is 0.08 parts per million (“ppm”). EPA is proposing to lower the primary
standard to between 0.075 ppm and 0.070 ppm, and is also proposing to add a new
secondary ozone standard to address impacts on vegetation. If EPA adopts the
proposed standards, many urban areas and surrounding counties in the Tennessee
Valley and throughout the eastern United States are likely to be designated as
“non-attainment” areas (defined as geographic areas where air quality does not
meet standards). Non-attainment designations can have adverse
economic implications for areas that are so designated. Existing emission
sources in non-attainment areas can be required to install additional controls,
and new sources planning to locate in such areas are required to meet more
stringent emission control requirements and obtain offsets for their emissions
from other sources in the non-attainment area. In addition, transportation
projects, such as roadway expansions or repairs, must demonstrate conformity
with state plans to achieve attainment status or risk the loss of federal
highway funds. An increase in the number of counties in the Tennessee Valley
designated as non-attainment areas is also likely to focus additional regulatory
attention on all NOx emission
sources including TVA sources.
Particulates/Opacity. Coarse
particulates (defined as particles of 10 micrometers or larger), which include
fly ash, have long been regulated by states to meet EPA’s NAAQS for particulate
matter. All of TVA’s coal-fired units have been equipped with mechanical
collectors, electrostatic precipitators, scrubbers, or baghouses, which have
reduced particulate emissions from the TVA system by more than 99 percent
compared to uncontrolled units. In 1997, EPA issued separate NAAQS
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 the areas of the country which 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 1997 annual fine particle standard. EPA also
decided to retain the existing 24-hour standard for coarse particles, but
revoked the related annual standard. The last three years of
monitoring data (2004 to 2006) for the Nashville, Chattanooga, Memphis, and
Clarksville/Hopkinsville areas show that these areas will be close to meeting
the more stringent 2006 24-hour and annual fine particle
standards. Attainment designations are scheduled to be made by EPA in
December 2008. 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 to reduce 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 and lawsuits
with special interest groups over the role of continuous opacity monitors in
determining compliance with opacity limitations, and TVA has received an adverse
decision in one such lawsuit. See Item 3, Legal
Proceedings.
Mercury. In March
2005, the EPA issued CAMR, which 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 have adopted CAMR without significant
change. In response to a request for reconsideration, the EPA
confirmed its approach in May 2006. In June 2006, 16 states and
several environmental groups filed lawsuits challenging CAMR. This
lawsuit is currently pending. TVA cannot predict the outcome of the
pending challenge of CAMR, or what effects any decision may have that would
require the EPA to regulate mercury as a hazardous air pollutant. If
the EPA’s decisions are upheld and CAMR is implemented, TVA expects to achieve
the required mercury reductions for at least Phase I of CAMR from 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 the end of
calendar year 2008. The costs associated with the monitoring systems
have been incorporated into TVA's capital budget.
Carbon Dioxide.
Legislation has been introduced in Congress to require reductions of CO2 and, if
enacted, could result in significant additional costs for TVA and other
utilities with coal-fired generation. The current Administration has
implemented a voluntary initiative with the 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 DOE. TVA has taken and is continuing to take
significant voluntary steps to reduce the carbon intensity of its electric
generation, including the recovery of Browns Ferry Unit 1, planned power uprates
of Browns Ferry Units 2 and 3, the planned completion of Watts Bar Unit 2, and
the completion of the hydroelectric modernization program. TVA has
also applied to the NRC for a Combined License for two advanced nuclear reactors
at the Bellefonte Nuclear Plant near Hollywood, Alabama, although no decision
has been made to build the reactors. Looking ahead, TVA intends to
make decisions that give strong consideration to fuel mix and
generating
assets that are low or zero carbon emitting resources. 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 asked utilities to
voluntarily participate in an effort to reduce, sequester, or avoid greenhouse
gases. Under that program, TVA reduced or avoided more than 305
million tons of CO2 from 1994
through 2005, as reported under Section 1605b of the Energy Policy
Act. TVA is incorporating the possibility of mandatory carbon
reductions and a renewable portfolio standard into its long range planning, and
will continue to monitor legislative and regulatory developments related to
CO2
and a renewable portfolio standard to assess any potential financial impacts as
information becomes available.
In addition to legislative activity,
climate change issues are the subject of a number of lawsuits, including
lawsuits against TVA. See Item 3, Legal Proceedings. On
November 29, 2006, the U.S. Supreme Court heard the case of Massachusetts v. EPA,
concerning whether EPA has the authority and duty to regulate CO2 emissions
under the CAA. The District of Columbia Circuit Court of
Appeals earlier affirmed EPA’s decision not to regulate CO2. On
April 2, 2007, the Supreme Court found that greenhouse gases, including CO2, are
pollutants under the CAA and thus EPA does have the authority to regulate
these gases. The Supreme Court also concluded that EPA's refusal to
regulate these pollutants was based on impermissible reasons, and remanded the
case to EPA to "ground its reasons for action or inaction in the
statute." While this case focused on CO2 emissions
from motor vehicles, it sets a precedent for regulation in other industrial
sectors, such as the electric utility industry.
States are also becoming more active in
the regulation of emissions that are believed to be contributing to global
climate change. 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. North
Carolina is studying initiatives aimed at climate change under the provisions of
the state’s Clean Smokestacks Act of 2002. This act required the
State Division of Air Quality to study potential control of CO2 emissions
from coal-fired utility plants and other stationary sources. This
effort has also prompted actions to develop a climate action plan for North
Carolina.
Clean Water Developments
One of the results of the major
reductions in atmospheric emissions resulting from the clean air expenditures
discussed above is that wastewaters at TVA coal-fired facilities and across the
utility industry may be changing because of waste streams from air quality
control technologies. Varying amounts of ammonia or similar compounds used as a
necessary component of SCR and SNCR operations may end up in facility wastewater
ponds that may discharge through outfalls regulated under the Clean Water Act
(“CWA”). Operation of scrubbers for SO2 control
also results in additional amounts of pollutants introduced into facility
wastewater treatment ponds. EPA is currently collecting information to determine
if the Steam Electric Point Source Effluent Guidelines (“Effluent Guidelines”)
under the CWA need to be revised. If the Effluent Guidelines are revised,
potentially more restrictive discharge limitations for existing parameters or
the addition of new parameters could result in additional wastewater treatment
expense to meet requirements of the CWA. These costs cannot be accurately
predicted at this time, but TVA is involved in and closely monitoring EPA’s data
collection activities and the progress of the Effluent Guidelines review
process. On the state level, new numeric nutrient criteria development and
implementation (an EPA requirement) may require additional treatment costs to
reduce nitrogen concentrations being added to the waste treatment ponds as a
result of the operation of air pollution control equipment. TVA is closely
monitoring the development and implementation of numeric nutrient criteria by
the states in TVA’s service area.
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 CWA, the EPA promulgated a final rule for existing power producing
facilities (the “Phase II Rule”) that became effective on September 7,
2004. The Phase II Rule required 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 options included development of a
site-specific compliance option based on application of cost-cost or
cost-benefit tests. The site specific tests were designed to ensure that a
facility’s costs are not significantly greater than cost projections in the rule
or the benefits derived from taking mitigation actions. Actions taken to
compensate for any impacts by restoring habitat, or pursuing other options such
as building hatcheries for fish/shellfish production, would have counted towards
compliance. Some northeastern states and environmental groups
challenged the new regulation, especially the compliance flexibility it offered,
in federal court.
On January 25, 2007, the Second Circuit
issued its decision in the proceeding challenging the EPA's Phase II Rule. The
Second Circuit held that costs cannot be compared to benefits in picking the
best technology available (“BTA”) to minimize the adverse environmental
impacts of intake structures. Instead, the court held that the EPA is
allowed to consider costs in two ways: (1) to determine what technology can
reasonably be borne by industry; and (2) to engage in cost-effectiveness
analysis in determining BTA. Finding the rulemaking record to be unclear on
whether the EPA had relied
on a
cost-benefit analysis or a cost-effectiveness analysis, the Second Circuit
remanded the EPA's BTA determination, giving the EPA the option to provide a
reasonable explanation of its determination or make a new determination based on
the permissible cost considerations set out in the Second Circuit
opinion. The Second Circuit also remanded provisions of the EPA rule that
allowed the use of a site-specific cost-benefit test and restoration measures
(such as building hatcheries) to demonstrate compliance, holding that these rule
provisions were based on an impermissible construction of the statute. Several
other provisions of the Phase II Rule such as the one that sets the performance
standards as a range rather than one national standard were also remanded.
On July 9, 2007, EPA suspended all but
one provision of the Phase II Rule until the agency has resolved the issues
raised by the Second Circuit's remand. The provision that was
retained requires permitting authorities to apply, in the interim, Best
Professional Judgment (“BPJ”) controls for existing facilities. BPJ
controls are those that reflect the best technology available for minimizing the
adverse environmental impacts of intake structures. The use of BPJ
controls reflects a reversion to the regulatory process that was used by
permitting authorities to regulate the impact of intake structures prior to the
promulgation of the Phase II Rule.
All of the intakes at TVA's existing
coal and nuclear generating facilities were subject to the Phase II
Rule. TVA had been in the process of determining what was needed to
comply with the Phase II Rule, and had believed that some expenditures might
have been required. These earlier assessments are now being
re-evaluated in light of the Second Circuit's decision, and EPA's subsequent
decision to suspend the Phase II Rule and revert to BPJ
controls. Given the uncertainty over the ultimate outcome of the
appellate process and what the changes in the final rule as ultimately issued by
EPA will be, TVA cannot assess the potential consequences at this
time.
As a part
of the 2006 triennial review of State Water Quality Standards in Tennessee, the
Tennessee Department of Environment and Conservation (“TDEC”) lowered its
threshold for issuing a Precautionary Fish Consumption Advisory (“Precautionary
Advisory”) due to mercury to 0.3 ppm because of new research and the EPA’s new
water quality criterion for methylmercury. The previous thresholds were 0.5 ppm
for a Precautionary Advisory and 1.0 ppm for a “Do Not Consume Advisory.” In
Tennessee a Precautionary Advisory recommends that sensitive populations such as
children and women of child-bearing age should not consume the fish species
named, and that all other persons should limit consumption of the named species
to one meal per month. A “Do Not Consume Advisory” recommends that certain fish
species should not be consumed by anyone in any amount. As a result of lowering
the threshold, Precautionary Advisories were issued for several additional
stream and reservoir segments within the State of Tennessee, including seven
streams and reservoir segments in the Tennessee River Watershed. TDEC’s
announcement of additional Precautionary Advisories for several Tennessee water
bodies does not mean that mercury levels in fish are increasing. TVA has been
monitoring mercury levels in fish and sediments in TVA reservoirs for the last
35 years, and TVA’s data was provided to TDEC as a part of its review
process. TVA’s data show significant reductions in mercury concentrations in
fish from the reservoirs with known industrial discharges that have now ceased
operation. Other than those areas historically impacted by industrial
discharges, mercury concentrations in fish have tended to fluctuate through time
with no discernible trend in fish from most reservoirs. Despite increased
burning of coal for electricity generation, current and historic data records
indicate that mercury concentrations in reservoir sediments have remained stable
or declined.
As is the case across the utility
industry and in other industrial sectors, TVA is also facing more stringent
requirements related to protection of wetlands, reductions in storm water
impacts from construction activities, water quality degradation, new water
quality criteria, and laboratory analytical methods. TVA is also
following litigation related to the use of herbicides, water transfers, and
releases from dams. TVA is not facing any substantive requirements
related to non-compliance with existing CWA regulations.
Hazardous Substances
Liability for releases and cleanup of
hazardous substances is regulated under the federal Comprehensive Environmental
Response, Compensation, and Liability Act, among other statutes, 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 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
$23,000. 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 David Witherspoon site in Knoxville, Tennessee,
and the Ward Transformer site in Raleigh, North Carolina. As
discussed below, TVA is not able to estimate its liability related to these
sites at this time.
The Witherspoon site is contaminated
with radionuclides, polychlorinated biphenyls (“PCBs”), and
metals. DOE has admitted to being the main contributor of materials
to the Witherspoon site and is currently performing clean-up
activities. DOE claims that TVA sent equipment to be recycled at this
facility, and there is some supporting evidence for the
claim. However, TVA believes it sent only a relatively small amount
of equipment and that none of it was radioactive. DOE has asked TVA
to “cooperate” in completing the cleanup, but it has not provided to TVA any
evidence of TVA’s percentage share of the contamination.
At the Ward Transformer site, EPA and a
working group of potentially responsible parties ("PRPs") have provided
documentation showing that TVA sent electrical equipment containing PCBs to this
site in 1974. The working group is cleaning up on-site contamination
in accordance with an agreement with EPA and plans to sue non-participating PRPs
for contribution. The estimated cost of the cleanup is $20
million. In addition, EPA likely has incurred several million dollars
in response costs, and the working group has reimbursed EPA approximately
$725,000 of those costs. EPA has also proposed a cleanup plan for
off-site contamination. The present worth cost estimate for
performing the proposed plan is about $5 million. In addition, there
may be natural resource damages liability related to this site, but TVA is not
aware of any estimated amount for any such damages.
As of September 30, 2007, TVA’s
estimated liability for environmental cleanup for those sites for which
sufficient information is available to develop a cost estimate (primarily the
TVA sites) is approximately $20 million on a non-discounted basis and is
included in Other liabilities on the Balance Sheet.
Coal-Combustion Wastes
In accordance with a regulatory
determination by EPA in May 2000, coal-combustion and certain related wastes
disposed of in landfills and surface impoundments continue to be regulated as
non-hazardous. In conjunction with this determination, EPA committed
to developing non-hazardous management standards for these
wastes. These standards are likely to include increased groundwater
monitoring, more stringent siting requirements, and closure of existing
waste-management facilities not meeting minimum standards. On August
29, 2007, EPA issued a Notice of Data Availability in which it requested public
comment on whether the additional information mentioned in the notice should
affect the EPA’s decisions as it continues to follow up on its commitment to
develop management standards for coal-combustion wastes. TVA is
currently reviewing this information to evaluate its potential impact on TVA
operations.
On September 30, 2007, TVA had 12,013
employees, of whom 5,167 were trades and labor employees. Under the
TVA Act, TVA is required to pay trades and labor workers hired by TVA or its
contractors the prevailing rate of wages. This rate is the rate of
wages for work of a similar nature prevailing in the vicinity where the work is
being performed. Neither the federal labor relations laws covering
most private sector employers nor those covering most federal agencies apply to
TVA. However, the TVA Board has a long-standing policy of
acknowledging and dealing with recognized representatives of its employees, and
that policy is reflected in long-term agreements to recognize the unions (or
their successors) that represent TVA employees. Federal law prohibits
TVA employees from engaging in strikes against TVA.
The risk factors described below, as
well as the other information included in this Annual Report, should be
carefully considered. Risks and uncertainties described in these risk
factors could cause future results to differ materially from historical results
as well as from the results predicted in forward-looking
statements. Although the risk factors described below are the ones
that TVA management considers significant, additional risk factors that are not
presently known to TVA management or that TVA management presently considers
insignificant may also impair TVA’s business operations. Although TVA
has the authority to set its own rates and thus mitigate some risks by
increasing rates, it is possible that partially or completely eliminating one or
more of these risks through rate increases might adversely affect TVA
commercially or politically. Accordingly, the occurrence of any of
the following could have a material adverse effect on TVA’s cash flows, results
of operations, and financial condition.
For ease of reference, the risk factors
are presented in four categories: strategic risks, operational risks, financial
risks, and risks related to TVA securities.
New
laws, regulations, and administrative orders may negatively affect TVA’s cash
flows, results of operations, and financial condition, as well as the way TVA
conducts its business.
Although
it is difficult to predict exactly how any new laws, regulations, and
administrative orders would impact TVA, some of the possible effects are
described below.
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TVA
could lose its protected service
territory.
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TVA’s 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
TVA’s defined service area. This provision is often called the
“fence” since it limits TVA’s sales activities to a specified service
area.
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The
Federal Power Act prevents FERC from ordering TVA to provide access to
others to its transmission lines for the purpose of delivering power to
customers within TVA’s defined service area, except to those customers
residing in Bristol, Virginia. This provision is often called
the “anti-cherrypicking provision” since it prevents competitors from
“cherrypicking” TVA’s customers.
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If
Congress were to eliminate or reduce the coverage of the anti-cherrypicking
provision, TVA could more easily lose customers, and the loss of these customers
could adversely affect TVA’s cash flows, results of operations, and financial
condition. See Item 7, Management’s Discussion and Analysis of
Financial Condition and Results of Operations — Legislative and Regulatory Matters —
Proposed Legislation.
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The TVA Board could lose its
sole authority to set rates for
electricity.
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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 material adverse effects on TVA including, but not
limited to, the following:
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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 become subject to additional regulatory oversight that could impede
TVA’s ability to manage its
business.
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TVA could become subject to
increased environmental
regulation.
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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. For
example, proposals in Congress that would regulate CO2 and other
greenhouse gases could require TVA and other electric utilities to incur
significantly increased costs. Any such developments could require
TVA to make significant capital expenditures, increase TVA’s operating and
maintenance costs, or even lead to TVA’s closing certain
facilities. See Item 1, Business — Environmental
Matters.
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The
NRC could impose significant restrictions or requirements on
TVA.
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The NRC
has broad authority to impose requirements relating to the licensing, operation,
and decommissioning of nuclear generation facilities. If the NRC
modifies existing requirements or imposes new requirements, TVA could be
required to make substantial capital expenditures at its nuclear plants or make
substantial contributions to its nuclear decommissioning trust. In
addition, if TVA fails to comply with requirements promulgated by the NRC, the
NRC has the authority to impose fines, shut down units, or modify, suspend, or
revoke TVA’s operating licenses. See Item 1, Business — Nuclear.
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TVA could lose responsibility
for managing the Tennessee River
system.
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TVA’s
management of the Tennessee River system is important to effective operation of
the power system. TVA’s ability to integrate management of the
Tennessee River system with power system operations increases power system
reliability and reduces costs. Restrictions on how TVA manages the
Tennessee River system could negatively affect TVA’s operations.
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Congress
could take actions that lead to a downgrade of TVA’s credit
rating.
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TVA’s
rated securities are currently rated “Aaa” by Moody’s Investors Service and
“AAA” by Standard and Poor’s and Fitch Ratings, which are the highest ratings
assigned by these rating agencies. TVA’s credit ratings are not based
solely on its underlying business or financial condition, which by themselves
may not be commensurate with a triple-A rating. TVA’s current ratings
are based to a large extent on the body of legislation that defines TVA’s
business structure. Key characteristics of TVA’s business defined by
legislation include (1) the TVA Board’s ratemaking authority, (2) the current
competitive environment, which is defined by the fence and the
anti-cherrypicking provision, and (3) TVA’s status as a corporate agency and
instrumentality of the United States. Accordingly, if Congress takes
any action that effectively alters any of these characteristics, TVA’s credit
ratings could be downgraded.
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TVA’s debt ceiling could
become more restrictive.
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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. See Item 7,
Management’s Discussion and Analysis of Financial Condition and Results of
Operations — Legislative and
Regulatory Matters — President’s Budget.
TVA
may lose some of its customers.
As of
September 30, 2007, three distributor customers had notices in effect
terminating their power contracts with TVA. Although sales to these
three distributor customers generated only 0.6 percent of TVA’s total operating
revenues in 2007, the loss of additional customers could have a material adverse
effect on TVA’s cash flows, results of operations, and financial
condition. See Item 1, Business —Customers — Termination Notices and Other Customers.
TVA’s
generation and transmission assets may not operate as planned.
Many of
TVA’s generation and transmission assets have been operating since the 1950s or
earlier 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.
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In
addition, the failure of TVA’s assets to perform as planned could cause health,
safety, and environmental problems and even result in such events as the failure
of a dam or a nuclear accident. Any of these potential outcomes could
negatively affect TVA’s cash flows, results of operations, and financial
condition. See Item 7, Management’s Discussion and Analysis of
Financial Condition and Results of Operations — Executive Summary — Challenges
During 2007.
TVA’s
fuel supply might be disrupted.
TVA
purchases coal, uranium, fuel oil, and natural gas from a number of
suppliers. Disruption in the acquisition or delivery of fuel may
result from a variety of factors, including, but not limited to, weather,
production or transportation difficulties, labor challenges, or environmental
regulations affecting TVA’s fuel suppliers. These disruptions could
adversely affect TVA’s ability to operate its facilities and could require TVA
to acquire power at higher prices on the spot market, purchase more expensive
alternative fuels, or operate higher cost plants, thereby adversely affecting
TVA’s cash flows, results of operations, and financial condition.
Compliance
with existing environmental laws and regulations may affect TVA’s operations in
unexpected ways.
TVA is
subject to risks from existing federal, state, and local environmental laws and
regulations including, but not limited to, the following:
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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 TVA’s older facilities, it may be uneconomical for TVA to install
the necessary equipment to comply with future 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.
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See Item
1, Business — Environmental
Matters.
TVA
is the sole power provider for customers within its service area, and if demand
for power in TVA’s service area increases, TVA is contractually obligated to
take steps to meet this increased demand.
If demand
for power in TVA’s service area increases, TVA may need to meet this increased
demand by purchasing power from other sources, building new generation and
transmission facilities, or purchasing existing generation and transmission
facilities. Purchasing power from external sources, as well as
acquiring or building new generation and transmission facilities, could
negatively affect TVA’s cash flows, results of operations, and financial
condition. See Item 7, Management’s Discussion and Analysis of
Financial Condition and Results of Operations — Executive Summary — Challenges
During 2007 — Timing of Cash Flows.
Purchased
power prices may be highly volatile, and providers of purchased power may fail
to perform under their contracts with TVA.
TVA
acquires a portion of its electricity needs through purchased power
arrangements. The price for purchased power has been volatile in
recent years, and the price that TVA pays for purchased power may increase
significantly in the future. In addition, if one of TVA’s purchased
power suppliers fails to perform under the terms of its contract with TVA, TVA
might have to purchase replacement power on the spot market, perhaps at a
significantly higher price than TVA was entitled to pay under the
contract. In some circumstances, TVA may not be able to recover
this difference from the supplier. Moreover, if TVA is unable to
acquire enough purchased power or enough replacement power on the spot market
and does not have enough reserve generation capacity available to offset the
loss of power from the purchased power supplier, TVA might not be able to supply
enough power to meet the demand resulting in power curtailments or even
blackouts. See Item 7, Management’s Discussion and Analysis of
Financial Condition and Results of Operations — Risk Management Activities —
Credit Risk — Credit of Other Counterparties.
TVA’s
ability to supply power and its customers’ demands for power are influenced by
weather conditions.
Extreme
temperatures 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, in periods of low rainfall or drought, TVA’s
low-cost hydroelectric generation may be reduced, requiring TVA to purchase
power or use more costly means of producing power. Furthermore, high
temperatures in the summer may limit TVA’s ability to use water from the
Tennessee or Cumberland River system for cooling at its generating facilities,
thereby limiting TVA’s ability to operate its generating
facilities. See Item 1, Business – Weather and Seasonality
and Item 7, Management’s Discussion and Analysis of Financial Condition
and Results of Operations — Executive Summary — Challenges
During 2007.
TVA
may incur delays and additional costs in power plant construction and may be
unable to obtain necessary regulatory approval.
TVA has
begun the process of completing the construction of Watts Bar Nuclear Unit 2 and
may need to construct more generating facilities in the
future. The completion of such facilities involves substantial risks
of delays and overruns in the cost of labor and materials. In
addition, completion may require regulatory approval, as in the case of Watts
Bar Nuclear Unit 2. If TVA does not obtain the necessary regulatory
approval, is otherwise unable to complete the development or construction
of a facility, decides to cancel construction of a facility, or incurs
delays or cost overruns in connection with constructing a facility, TVA’s cash
flows, financial condition, and results of operations could be
negatively affected. In addition, if construction projects are
not completed according to specifications, TVA may suffer, among other
things, reduced plant efficiency and higher operating
costs. See Item 1, Business — Nuclear.
TVA
may face problems attracting and retaining skilled workers.
As TVA
employees retire and TVA faces competition for skilled workers, TVA may face
problems attracting and retaining skilled workers to, among other things,
operate and maintain TVA’s generation and transmission facilities and complete
large construction projects such as Watts Bar Nuclear Unit 2.
TVA
is involved in various legal and administrative proceedings whose outcomes may
affect TVA’s finances and operations.
TVA is
involved in various legal and administrative proceedings and is likely to become
involved in other legal proceedings in the future in the ordinary course of
business. Although TVA cannot predict the outcome of the individual
matters in which TVA is involved or will become involved, the resolution of
these matters could require TVA to make expenditures in excess of established
reserves and in amounts that could have a material adverse effect on TVA’s cash
flows, results of operations, and financial condition. Similarly,
resolution could require TVA to change its business practices or procedures,
which could also have a material adverse effect on TVA’s cash flows, results of
operations, and financial condition. See Item 3, Legal
Proceedings.
TVA’s
transmission reliability could be affected by problems at other utilities or TVA
facilities.
TVA’s
transmission facilities are directly interconnected with the transmission
facilities of neighboring utilities and are thus part of an interstate power
transmission grid. Accordingly, problems at other utilities, or at
TVA’s own facilities, may cause interruptions in TVA’s transmission
service. If TVA were to suffer a transmission service interruption,
TVA’s cash flows, results of operations, and financial condition could be
negatively affected.
Events
at non-TVA facilities which affect the supply of water to TVA’s generation
facilities may interfere with TVA’s ability to generate power.
TVA’s
coal-fired and nuclear generation facilities depend on water from the river
systems near which they are located for cooling water and for water to convert
into steam to drive turbines. While TVA manages the Tennessee River
and large portions of its tributary system in order to provide much of this
necessary water, the U.S. Army Corps of Engineers operates and manages other
bodies of water upon which some TVA facilities rely. Events at these
non-TVA managed bodies of water or their associated hydroelectric facilities may
interfere with the flow of water and may result in TVA having insufficient water
to meet the needs of its plants. In such scenarios, TVA may be
required to reduce generation at its affected facilities to levels compatible
with the available supply of water. See Item 1, Business — Power Supply and Item 7, Management’s
Discussion and Analysis of Financial Condition and Results of Operations — Executive Summary — Challenges
During 2007.
An
incident at any nuclear facility, even one that is not owned by or licensed to
TVA, could result in increased expenses and oversight.
A nuclear
incident at a TVA facility could have significant consequences including loss of
life, damage to the environment, damage to or loss of the facility, and damage
to non-TVA property. Any nuclear incident, even at a facility that is
not owned by or licensed to TVA, has the potential to impact TVA adversely by
obligating TVA to pay up to $90 million per year and a total of $604 million per
nuclear incident under the Price-Anderson Act. In addition, a nuclear
incident could negatively affect TVA by, among other things, obligating TVA to
pay retrospective premiums, reducing the availability of insurance, increasing
the costs of operating nuclear units, or leading to increased regulation or
restriction on the construction, operation, and decommissioning of nuclear
facilities.
Catastrophic
events could affect TVA’s ability to supply electricity or reduce demand for
electricity.
TVA could
be adversely affected by catastrophic events such as fires, earthquakes, floods,
tornadoes, wars, terrorist activities, pandemics, and other similar
events. These events, the frequency and severity of which are
unpredictable, could negatively affect TVA’s cash flows, results of operations,
and financial condition by, among other things, limiting TVA’s ability to
generate and transmit power, reducing the demand for power, disrupting fuel or
other supplies, leading to an economic downturn, or creating instability in the
financial markets.
Demand
for electricity supplied by TVA could be reduced by changes in
technology.
Research
and development activities are ongoing to improve existing and alternative
technologies to produce electricity, including gas turbines, fuel cells,
microturbines, and solar cells. It is possible that advances in these
or other alternative technologies could reduce the costs of electricity
production from alternative technologies to a level that will enable these
technologies to compete effectively with traditional power plants like
TVA’s. To the extent these technologies become a more cost-effective
option for certain customers, TVA’s sales to these customers could be reduced,
thereby negatively affecting TVA’s cash flows, results of operations, and
financial condition.
TVA
is subject to a variety of market risks that could negatively affect TVA’s cash
flows, results of operations, and financial position.
TVA is
subject to a variety of market risks, including, but not limited to, commodity
price risk, investment price risk, interest rate risk, and credit
risk.
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Commodity Price
Risk. Prices of commodities critical to TVA’s
operations, including coal, uranium, natural gas, fuel oil, emission
allowances, and electricity, have been extremely volatile in recent
years. If TVA fails to effectively manage its commodity price
risk, TVA’s rates could increase and thereby cause customers to look for
alternative power suppliers.
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Investment Price
Risk. TVA is exposed to investment price risk in its
nuclear decommissioning trust, its asset retirement trust, and its pension
fund. If the value of the investments held in the nuclear
decommissioning trust or the pension fund decreases significantly, TVA
could be required to make substantial unplanned contributions to these
funds, which would negatively affect TVA’s cash flows, results of
operations, and financial
condition.
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Interest Rate
Risk. Changes in interest rates could negatively affect
TVA’s cash flows, results of operations, and financial condition by
increasing the amount of interest that TVA pays on new bonds that it
issues, decreasing the return that TVA receives on its short-term
investments, decreasing the value of the investments in TVA’s pension fund
and trusts, and increasing the losses on the mark-to-market valuation of
certain derivative transactions into which TVA has
entered.
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Credit
Risk. TVA is exposed to the risk that its counterparties
will not be able to perform their contractual obligations. If
TVA’s counterparties fail to perform their obligations, TVA’s cash flows,
results of operations, and financial condition could be adversely
affected. In addition, the failure of a counterparty to perform
could make it difficult for TVA to perform its obligations, particularly
if the counterparty is a supplier of electricity or fuel to
TVA.
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See Item
7, Management’s Discussion and Analysis of Financial Condition and Results of
Operations — Risk Management
Activities for more information regarding market risks.
TVA
and owners of TVA securities could be impacted by a downgrade of TVA’s credit
rating.
A
downgrade in TVA’s credit rating could have material adverse effects on TVA’s
cash flows, results of operations, and financial condition as well as on
investors in TVA securities. Among other things, a downgrade could
have the following effects:
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A
downgrade would increase TVA’s interest expense by increasing the interest
rates that TVA pays on new Bonds that it issues. An increase in
TVA’s interest expense 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 power
rates.
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A
significant downgrade could result in TVA’s having to post collateral
under certain physical and financial contracts that contain rating
triggers.
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A
downgrade below a contractual threshold could prevent TVA from borrowing
under two credit facilities totaling $2.5
billion.
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A
downgrade could lower the price of TVA securities in the secondary
market.
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See Item
7, Management’s Discussion and Analysis of Financial Condition and Results of
Operations — Liquidity and
Capital Resources.
TVA
may have to make significant unplanned contributions to fund its pension and
other postretirement benefit plans.
TVA’s
costs of providing pension benefits and other postretirement benefits depend
upon a number of factors, including, but not limited to:
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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.
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Any
number of these factors could increase TVA’s costs of providing pension and
other postretirement benefits and require TVA to make significant unplanned
contributions to the plans. Such contributions would negatively
affect TVA’s cash flows, results of operations, and financial
condition.
TVA
may have to make significant unplanned contributions to its nuclear
decommissioning trust.
TVA
maintains a nuclear decommissioning trust for the purpose of providing funds to
decommission TVA’s nuclear facilities. The decommissioning trust is
invested in securities generally designed to achieve a return in line with
overall equity market performance. TVA might have to make significant
unplanned contributions to the trust if, among other things:
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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 real rate of return on plan assets, which is currently five
percent, is lowered 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.
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If TVA
makes unplanned contributions to the trust, the contributions would negatively
affect TVA’s cash flows, results of operations, and financial
condition.
TVA
may be unable to meet its current cash requirements if its access to the debt
markets is limited.
TVA’s
cash management policy is to use cash provided by operations together with
proceeds from power program borrowings and a $150 million note with the U.S.
Treasury to fund TVA’s current cash requirements. In addition, TVA
has access to $2.5 billion of credit facilities with a national
bank. In light of TVA’s cash management policy, it is critical that
TVA continue to have access to the debt markets in order to meet its cash
requirements. The importance of having access to the debt markets is
underscored by the fact that TVA, unlike many utilities, relies almost entirely
on the debt markets to raise capital since it is not authorized to issue equity
securities. See Item 7, Management’s Discussion and Analysis of
Financial Condition and Results of Operations — Liquidity and Capital
Resources.
Approaching
or reaching its debt ceiling could limit TVA’s ability to carry out its
business.
At
September 30, 2007, TVA had approximately $22.5 billion of Bonds outstanding
(not including noncash items of foreign currency valuation loss of $299 million
and net discount on sale of bonds of $189 million). TVA has a
statutorily imposed ceiling of $30 billion on outstanding Bonds. Approaching or reaching
this debt ceiling could adversely affect TVA’s business by limiting TVA’s
ability to borrow money and increasing the cost of servicing TVA’s
debt. In addition, approaching or reaching this debt ceiling could
lead to increased legislative or regulatory oversight of TVA’s
activities. See Item 7, Management’s Discussion and Analysis of
Financial Condition and Results of Operations — Legislative and Regulatory Matters —
Proposed Legislation.
TVA’s
cash flows, results of operations, and financial condition could be negatively
affected by economic downturns.
Sustained
downturns or weakness in the economy in TVA’s service area or other parts of the
United States could reduce overall demand for power and thus reduce TVA’s power
sales and cash flows, especially as TVA’s industrial customers reduce their
operations and thus their consumption of power.
TVA’s
financial control system cannot guarantee that all control issues and instances
of fraud will be detected.
No
financial control system, no matter how well designed and operated, can provide
absolute assurance that the objectives of the control system are met, and no
evaluation of financial controls can provide absolute assurance that all control
issues and instances of fraud can be detected. The design of any
system of financial controls is based in part upon certain assumptions about the
likelihood of future events, and there can be no assurance that any design will
succeed in achieving its stated goals under all potential future conditions,
regardless of how remote. See Item 9A, Controls and Procedures for
TVA’s assessment of its internal controls as of September 30, 2007.
TVA’s
financial control system cannot guarantee that all control issues and instances
of errors will be detected.
TVA’s
controls and procedures are designed to 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. No evaluation of financial controls can
provide absolute assurance that all control issues and instances of errors can
be detected.
Subsequent
to the periods covered by this report, TVA management identified a material
weakness in internal controls related to TVA's unbilled revenue
calculation. These errors resulted in the restatement of TVA's
statement of net income, balance sheet, cash flow statement, and proprietary
capital statements for the fiscal years ending September 30, 2007 (as described
in Note 2). The new method of calculating unbilled revenue estimate
was used for periods presented in this Form 10-K/A No. 2
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, 2007, TVA had $4.9 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.
Payment
of principal and interest on TVA securities is not guaranteed by the United
States.
Although
TVA is a corporate agency and instrumentality of the United States government,
TVA securities are not backed by the full faith and credit of the United
States. Principal and interest on TVA securities are payable solely
from TVA’s net power proceeds. Net power proceeds are defined as the
remainder of TVA’s gross power revenues after deducting the costs of operating,
maintaining, and administering its power properties and payments to states and
counties in lieu of taxes, but before deducting depreciation accruals or other
charges representing the amortization of capital expenditures, plus the net
proceeds from the sale or other disposition of any power facility or interest
therein.
The
trading market for TVA securities might be limited.
All of
TVA’s Bonds are listed on the New York Stock Exchange except for TVA’s discount
notes, which have maturities of less than one year, and the power bonds issued
under TVA’s electronotes® program,
which is TVA’s medium-term note program. In addition, some of TVA’s
Bonds are listed on foreign stock exchanges. Although many of TVA’s
Bonds are listed on stock exchanges, there can be no assurances that any market
will develop or continue to exist for any Bonds. Additionally, no
assurances can be made as to the ability of the holders of Bonds to sell their
Bonds or the price at which holders will be able to sell their
Bonds. Future trading prices of Bonds will depend on many factors,
including prevailing interest rates, the then-current ratings assigned to the
Bonds, the amount of Bonds outstanding, the time remaining until the maturity of
the Bonds, the redemption features of the Bonds, the market for similar
securities, and the level, direction, and volatility of interest rates
generally.
If a
particular series of Bonds is offered through underwriters, those underwriters
may attempt to make a market in the Bonds. The underwriters would not
be obligated to do so, however, and could terminate any market-making activity
at any time without notice.
In
addition, legal limitations may affect the ability of banks and others to invest
in Bonds. For example, national banks may purchase TVA Bonds for
their own accounts in an amount not to exceed 10 percent of unimpaired
capital and surplus. Also, TVA Bonds are “obligations of a
corporation which is an instrumentality of the United States” within the meaning
of section 7701(a)(19)(C)(ii) of the Internal Revenue Code for purposes of the
60 percent of assets limitation applicable to U.S. building and loan
associations.
Not
applicable.
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.
At September 30, 2007, TVA’s generating
assets consisted of 59 coal-fired units, six nuclear units, 109 conventional
hydroelectric units, four pumped storage units, 83 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. Browns Ferry Unit 1 went online on May 22, 2007, and
began commercial operation on August 1, 2007. Also, on August 1,
2007, the TVA Board approved the completion of Watts Bar Unit 2 construction,
which was halted in 1985. Completing Watts Bar Unit 2 is expected to
take 60 months. In addition, TVA added 11 combustion turbine units in
2007.
Twenty-four of TVA’s combustion
turbines are subject to lease-leaseback arrangements. For more
information regarding these arrangements, see Note 13 — Other Financing
Obligations.
TVA’s transmission system interconnects
with systems of surrounding utilities and consists primarily of the following
assets:
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Approximately
15,800 circuit miles of transmission lines (primarily 500 kilovolt and 161
kilovolt lines);
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495
transmission substations, power switchyards, and switching stations;
and
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68
individual interchange and 985 customer connection
points.
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In 2007, TVA continued to retire and
remove from TVA’s books de-energized transmission lines, while retaining
contiguous rights-of-way for future use. These activities have served
to lower TVA’s operational line miles.
In 2003, TVA entered into a
lease-leaseback of certain qualified technological equipment and other software
related to TVA’s transmission system. For more information regarding
this transaction, see Note 13 — Other Financing
Obligations.
TVA’s hydroelectric assets consist of
49 dams, and TVA manages the following natural 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 facilities.
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TVA has a variety of buildings
throughout its service area in addition to the buildings located at its
generation and transmission facilities, including office buildings, customer
service centers, power service centers, warehouses, visitor centers, and crew
quarters. The most significant of these buildings is the Knoxville
Office Complex. TVA also leases buildings when it deems appropriate,
including its Chattanooga Office Complex. The initial term of TVA's
lease of the Chattanooga Office Complex expires on January 1, 2011, but the
lease contains six automatic renewal terms of five years each that provide TVA
with the right to extend its Chattanooga Office Complex lease for a maximum of
30 years after the end of the initial term. A study of TVA's
long-term options for Chattanooga office space is currently underway, and a
recommendation is expected to be made to the TVA Board in the second quarter of
2008. TVA also owns or leases a significant number of buildings in
Muscle Shoals, Alabama, and is currently evaluating strategies for long-term
solutions to further reduce its Muscle Shoals portfolio.
Under the
TVA Act, TVA has broad authority to dispose of personal property but only
limited authority to dispose of real property. TVA’s primary sources
of authority to dispose of real property are briefly described
below:
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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 providing replacement lands for certain
entities whose lands were flooded or destroyed by dam or reservoir
construction and to grant easements and rights-of-way upon which are
located transmission or distribution
lines.
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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.
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In addition, the Basic Tennessee Valley
Authority Power Bond Resolution adopted by the TVA Board on October 6, 1960, as
amended on September 28, 1976, October 17, 1989, and March 25, 1992, prohibits
TVA from mortgaging any part of its power properties and from disposing of all
or any substantial portion of these properties unless TVA provides for a
continuance of the interest, principal, and sinking fund payments due and to
become due on all outstanding Bonds, or for the retirement of such
Bonds.
TVA
is subject to various legal proceedings and claims that have arisen in the
ordinary course of business. These proceedings and claims include the matters
discussed below. In accordance with SFAS No. 5, “Accounting for
Contingencies,” TVA had accrued approximately $2.5 million with respect
to the proceedings described below as of September 30, 2007, as well as
approximately $4.2 million with respect to other proceedings that have arisen in
the normal course of TVA’s business. No assurance can be given that TVA will not
be subject to significant additional claims and liabilities. If actual
liabilities significantly exceed the estimates made, TVA’s results of
operations, liquidity, and financial condition could be materially adversely
affected.
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
that 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 alleged 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, and the class members
sought over $100 million in damages. The parties engaged in mediation
in December 2006 and reached a settlement agreement under which TVA agreed to
pay approximately $18 million to resolve the case. Because the
settlement was required to be approved by the court to be effective, the
settlement was submitted to the court on May 21, 2007. The court
preliminarily approved it on June 6, 2007. On August 20, 2007, the court
conducted a hearing on the fairness of the settlement, after which it approved
the settlement in the amount of $18 million. In accordance with the
terms of the agreement, TVA paid the settlement amount to an escrow agent on
August 20, 2007. On October 22, 2007, after the period for appealing
the judge's approval of the settlement had expired, TVA authorized the agent to
disburse the funds to the plaintiffs.
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 Corporation, 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 Corporation, Tri-State Electric
Membership Corporation, Upper Cumberland Electric Membership Corporation, and
Volunteer Energy Cooperative. The lawsuit in part challenged TVA’s practice of
setting rates for electric power charged by distributor customers through TVA’s
contracts with distributor customers. The court held that the
federal law claims against TVA failed as a matter of law because Congress had
specifically authorized TVA to set the rates charged by distributor customers
through TVA’s contracts with distributor customers. The court
dismissed the state law claims against the other defendants because the
plaintiffs had not taken the required steps to bring those claims in court. The
plaintiffs appealed to the United States Court of Appeals for the Sixth Circuit
(“Sixth Circuit”), which affirmed the district court’s decision on October 17,
2006, holding, among other things, that TVA’s rates were not subject to judicial
review and that TVA is not subject to antitrust liability when doing so would
interfere with TVA’s purposes. The plaintiffs did not appeal, and the
deadline for doing so has expired.
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 CO2 emissions
from fossil-fuel electric generating facilities should be ordered abated because
they contribute to causing the nuisance. The first case was filed by various
states (California, Connecticut, Iowa, New Jersey, New York, Rhode Island,
Vermont, and Wisconsin) and the City of New York against TVA and other power
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. The plaintiffs do
not seek monetary damages, but instead seek a court order requiring each
defendant to cap its CO2 emissions
and then reduce these emissions by an unspecified percentage each year for at
least a decade. In September 2005, the district court dismissed both lawsuits
because they raised political questions that should not be decided by the
courts. The plaintiffs appealed to the United States Court of Appeals for the
Second Circuit (“Second Circuit”). Oral argument was held before the Second
Circuit on June 7, 2006. On June 21, 2007, the Second Circuit directed the
parties to submit letter briefs by July 6, 2007, addressing the impact of the
Supreme Court’s decision in Massachusetts v. EPA, 127
S.Ct. 1438 (2007), on the issues raised by the parties. On July 6,
2007, the defendants jointly submitted their letter brief.
Case Involving Alleged
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
(“CAA”) and implementing regulations at TVA’s Colbert Fossil Plant (“Colbert”),
a coal-fired electric generating facility located in Tuscumbia, Alabama. The
plaintiffs allege that TVA made major modifications to 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 the 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. In an October 4, 2007 decision, the Eleventh Circuit affirmed
dismissal of the lawsuit.
Case Involving Alleged
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 (“NSR”) requirements of the CAA when TVA
repaired its Bull Run Fossil Plant (“Bull Run”), a coal-fired electric
generating facility located in Anderson County, Tennessee. In March 2005, the
district court granted TVA’s motion to dismiss the lawsuit on statute of
limitation grounds. The plaintiffs’ motion for reconsideration was denied, and
they appealed to the Sixth Circuit. Friend of the court 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 a friend of the
court 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 a panel
of three judges issued a decision reversing the dismissal on March 2, 2007. TVA
requested that the full Sixth Circuit rehear the appeal, but the Sixth Circuit
denied this request. A scheduling order has now been entered by the
district court on remand, setting the case for trial on August 11,
2008. TVA is already installing or has installed the control
equipment that the plaintiffs seek to require TVA to install in this case, and
it is unlikely that an adverse decision will result in substantial additional
costs to TVA. An adverse decision, however, could lead to additional
litigation and could cause TVA to install additional emission control systems
such as scrubbers and selective catalytic reduction systems on units where they
are not currently installed, under construction, or planned to be
installed. It is uncertain whether there would be significant
increased costs to TVA.
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 CAA
opacity limits applicable to Colbert between July 1, 1997, and June 30, 2002.
The plaintiffs seek a court order that could require TVA to incur substantial
additional costs for environmental controls and pay civil penalties of up to
approximately $250 million. After the court dismissed the complaint (finding
that the challenged emissions were within Alabama’s two percent de minimis rule,
which provided a safe harbor if nonexempt opacity monitor readings over 20
percent did not occur more than two percent of the time each quarter), the
plaintiffs appealed the district court’s decision to the Eleventh Circuit. On
November 22, 2005, the Eleventh Circuit affirmed the district court’s dismissal
of the claims for civil penalties but held that the Alabama de minimis rule was
not applicable because Alabama had not yet obtained Environmental Protection
Agency (“EPA”) approval of that rule. The case was remanded to the district
court for further proceedings. On April 5, 2007, the plaintiffs moved for
summary judgment. TVA opposed the motion and moved to stay the
proceedings. On April 12, 2007, EPA proposed to approve Alabama’s de
minimis rule subject to certain changes. This rulemaking proceeding is ongoing.
On July 16, 2007, the district court denied TVA’s motion to stay the proceedings
pending approval of Alabama’s de minimis rule. Oral argument on the motion for
summary judgment was held on August 16, 2007. On August 27, 2007, the
district court granted the plaintiffs’ motion for summary judgment, finding that
TVA had violated the CAA at Colbert. The district court held that,
while TVA had achieved 99 percent compliance on Colbert Units 1-4 and 99.5
percent compliance at Colbert Unit 5, TVA had exceeded the 20 percent opacity
limit (measured in six-minute intervals) more than 3,350 times between January
3, 2000, and September 30, 2002. The district court ordered TVA to
submit a proposed remediation plan, which TVA did on October 26,
2007. The plaintiffs have an opportunity to respond. TVA
is reviewing its options for regulatory and compliance approaches to address
this decision. If EPA approves Alabama’s de minimis rule, then the
lawsuit will become moot.
In addition to Colbert, TVA has another
coal-fired power plant in Alabama, Widows Creek Fossil Plant (“Widows Creek”),
which has a winter net dependable generating capacity of 1,628
megawatts. Since the operation of Widows Creek must meet the same
opacity requirements, this plant may be affected by the decision in this
case. The proposed de minimis rule change would help reduce or
eliminate the chances of an adverse effect on Widows Creek from the district
court decision.
Case Brought by North
Carolina Alleging Public Nuisance. On January 30, 2006, North
Carolina filed suit against TVA in the United States District Court for the
Western District of North Carolina alleging that TVA’s operation of its
coal-fired power plants in Tennessee, Alabama, and Kentucky constitute public
nuisances. North Carolina is asking the court to impose caps on
emissions of certain pollutants from TVA’s coal-fired plants that North Carolina
considers to be equivalent to caps on emissions imposed by North Carolina law on
North Carolina’s two largest electric utilities. The imposition of such
caps could require TVA to install more pollution controls on a faster schedule
than required by federal law. On April 3, 2006, TVA moved to dismiss
the suit on grounds that the case is not suitable for judicial resolution
because of separation of powers principles, including the fact that these
matters are based on policy decisions left to TVA’s discretion in its capacity
as a government agency and thus are not subject to tort liability (the
“discretionary function doctrine”), as well as the Supremacy Clause. In July
2006, the court denied TVA’s motion and set the trial for the term of court
beginning October 2007. On August 4, 2006, TVA filed a motion requesting
permission to file an interlocutory appeal with the United States Court of
Appeals for the Fourth Circuit (the “Fourth Circuit”), which the district court
granted on September 7, 2006. On September 21, 2006, TVA petitioned the Fourth
Circuit to allow the interlocutory appeal. The Fourth Circuit granted the
petition, but the district court did not stay the case during the appeal.
Briefing of the interlocutory appeal to the Fourth Circuit was completed in
January 2007, and oral argument was held on October 31, 2007. On July 2, 2007,
North Carolina filed with the district court a motion for partial summary
judgment addressing certain of TVA’s defenses. On July 31, 2007, and
August 20, 2007, TVA filed two separate motions for summary judgment, seeking
dismissal of the lawsuit. The trial before the district court
previously scheduled for the term of court beginning October 2007 has been
canceled and may be rescheduled for the term of court beginning after January
2008.
Case Involving North
Carolina’s Petition to the EPA. In 2005, the State of North
Carolina petitioned the EPA under Section 126 of the CAA to impose additional
emission reduction requirements for SO2 and
NOX
emitted by coal-fired power plants in 13 states, including states where TVA’s
coal-fired power plants are located. In March 2006, the EPA denied the North
Carolina petition primarily on the basis that the Clean Air Interstate Rule
remedies the problem. In June 2006, North Carolina filed a petition for review
of EPA’s decision with the United States Court of Appeals for the District of
Columbia Circuit. Briefing on the appeal is underway, and on October 1, 2007,
TVA filed a friend of the court brief in support of EPA’s decision to deny North
Carolina’s Section 126 petition.
Case Arising out of
Hurricane Katrina. In April 2006, TVA was added as a defendant
to a class action lawsuit brought in the United States District Court for the
Southern District of Mississippi by 14 residents of Mississippi allegedly
injured by Hurricane Katrina. The plaintiffs sued seven large oil companies and
an oil company trade association, three large chemical companies and a chemical
trade association, and 31 large companies involved in the mining and/or burning
of coal, including TVA and other utilities. The plaintiffs allege that the
defendants’ greenhouse gas emissions contributed to global warming and were a
proximate and direct cause of Hurricane Katrina’s increased destructive force.
The plaintiffs are seeking monetary damages among other relief. TVA has moved to
dismiss the complaint on grounds that TVA’s operation of its coal-fired plants
is not subject to tort liability due to the discretionary function doctrine. On
August 30, 2007, the district court heard oral arguments on whether the issue of
greenhouse gas emissions is a political matter which should not be decided by
the court. The district court then dismissed the case on the grounds
that the plaintiffs lacked standing. The dismissal has been appealed
to the United States Court of Appeals for the Fifth Circuit.
East Kentucky Power
Cooperative Transmission Case. In April 2003, Warren notified
TVA that it was terminating its TVA power contract. Warren then entered into an
arrangement with East Kentucky under which Warren would become a member of East
Kentucky, and East Kentucky would supply power to Warren after its power
contract with TVA expires in 2009. East Kentucky then 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 provide the requested transmission service. 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 and East Kentucky asked
the FERC to order TVA to provide the interconnections. In January 2006, FERC
issued a final order directing TVA to interconnect its transmission facilities
with East Kentucky’s system at three locations on the TVA transmission system.
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 on the grounds that
this order violated the anti-cherrypicking provision. On January 10, 2007, TVA
and Warren executed an agreement under which Warren rescinded its notice of
termination. On May 3, 2007, East Kentucky filed a motion with FERC to terminate
the FERC proceeding on grounds of mootness. TVA has also filed a motion with
FERC to vacate all orders issued in the proceeding. Whether or not FERC grants
TVA’s motion to vacate, it is likely that the FERC proceeding and the resulting
litigation will eventually be dismissed and not proceed to a
conclusion.
Case Involving Areva Fuel
Fabrication. On November 9, 2005, TVA received two invoices
totaling $76 million from Framatome ANP Inc., which subsequently changed its
name to AREVA NP Inc. (“AREVA”). AREVA asserted that it was the successor to the
contract between TVA and Babcock and Wilcox Company (“B&W”) under which
B&W would provide fuel fabrication services for TVA’s Bellefonte Nuclear
Plant. AREVA’s invoices were based upon the premise that the contract required
TVA to buy more fuel fabrication services from B&W than TVA actually
purchased. In September 2006, TVA received a formal claim from AREVA which
requested a Contracting Officer’s decision pursuant to the Contract Disputes Act
of 1978 and reduced the amount sought to approximately $25.8 million. On April
13, 2007, the Contracting Officer issued a final decision denying the claim. On
April 19, 2007, AREVA filed suit in the United States District Court for the
Eastern District of Tennessee, reasserting the $25.8 million claim and alleging
that the contract required TVA to purchase certain amounts of fuel and/or to pay
a cancellation fee. TVA filed its answer to the complaint on June 15,
2007. AREVA subsequently raised its claim to $47.9
million. Trial is scheduled to begin September 29, 2008.
Notification of Potential
Liability for Ward Transformer Site. EPA and a working group
of potentially responsible parties (“PRPs”) have provided documentation showing
that TVA sent electrical equipment containing polychlorinated biphenyls (“PCBs”)
to the Ward Transformer site in Raleigh, North Carolina. 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. The working group is cleaning up on-site contamination in
accordance with an agreement with EPA and plans to sue non-participating PRPs
for contribution. The estimated cost of the cleanup is $20
million. In addition, EPA likely has incurred several million dollars
in response costs, and the working group has reimbursed EPA approximately
$725,000 of those costs. EPA has also proposed a cleanup plan for
off-site contamination. The present worth cost estimate for
performing the proposed plan is about $5 million. In addition, there
may be natural resource damages liability related to this site, but TVA is not
aware of any estimated amount for any such damages. See Item 1,
Business — Environmental
Matters — Hazardous Substances.
Employment
Proceedings. TVA is engaged in various administrative and
legal proceedings arising from employment disputes. These matters are governed
by federal law and involve issues typical of those encountered in the ordinary
course of business of a utility. They may include allegations of discrimination
or retaliation (including retaliation for raising nuclear safety or
environmental concerns), wrongful termination, and failure to pay overtime under
the Fair Labor Standards Act. Adverse outcomes in these proceedings would not
normally be material to TVA’s results of operations, liquidity, and financial
condition, although it is possible that some outcomes could require TVA to
change how it handles certain personnel matters or operates its
plants.
Notice of Violation at
Widows Creek Unit 7. On July 16, 2007, TVA received a Notice
of Violation (“NOV”) from EPA as a result of TVA’s failure to properly maintain
ductwork at Widows Creek Unit 7. From 2002 to 2005, the unit’s ducts allowed
SO2 to
escape into the air. TVA repaired the ductwork in 2005, and the problem has been
resolved. TVA is reviewing the NOV. While the NOV does not set out an
administrative penalty, it is likely that TVA will face a monetary sanction
through giving up emission allowances, paying an administrative penalty, or
both. Based on the current discussions with EPA, TVA's estimate of
potential monetary sanctions is de minimis at this time.
Significant Litigation to
Which TVA Is Not a Party. On April 2, 2007, the Supreme Court
issued an opinion in the case of United States v. Duke Energy,
vacating the ruling of the Fourth Circuit in favor of Duke Energy and against
EPA in EPA’s NSR enforcement case against Duke Energy. The NSR regulations apply
primarily to the construction of new plants but can apply to existing plants if
a maintenance project (1) is “non-routine” and (2) increases emissions. The
Supreme Court held that under EPA’s PSD regulations, increases in annual
emissions should be used for the test, not hourly emissions as utilities,
including TVA, have argued should be the standard. Annual emissions can increase
when a project improves the reliability of plant operations and, depending on
the time period over which emission changes are calculated, it is possible to
argue that almost all reliability projects increase annual emissions. Neither
the Supreme Court nor the Fourth Circuit addressed what the “routine” project
test should be. The United States District Court for the Middle District of
North Carolina had ruled for Duke on this issue, holding that “routine” must
take into account what is routine in the industry and not just what is routine
at a particular plant or unit as EPA has argued. EPA did not appeal this
ruling. On October 5, 2007, EPA filed a motion with the United States
District Court for the Middle District of North Carolina asking that court to
vacate its entire prior ruling, including the portion relating to the test for
“routine” projects.
TVA is currently involved in two NSR
cases (one involving Bull Run, the dismissal of which was recently reversed on
appeal) and another at Colbert (the dismissal of which was recently affirmed on
appeal). These cases are discussed in more detail above. The Supreme Court’s
rejection of the hourly standard for emissions testing could undermine one of
TVA’s defenses in these cases, although TVA has other available defenses.
Environmental groups and North Carolina have given TVA notice in the past that
they may sue TVA for alleged NSR violations at a number of TVA units. The
Supreme Court’s decision could encourage such suits, which are likely to involve
units where emission control systems such as scrubbers and selective catalytic
reduction systems are not installed, under construction, or planned to be
installed in the relatively near term.
Not
applicable.
Not
applicable.
The following selected financial data
for the years 2003 through 2007 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 (electricity used by TVA-owned facilities such as power service buildings,
shops, bridge lights, and dams), displacement sales (transactions that have
been offset by electricity purchased by TVA due to a change in system needs
resulting from a change in operating or economic conditions), and limestone used
for the production of electricity. Certain reclassifications have
been made to the 2003, 2004, 2005, and 2006 financial statement presentation to
conform to the 2007 presentation.
As
previously disclosed in this Form 10-K/A No. 2, the information with respect to
fiscal years 2007 and 2006 has been restated primarily to correct errors in the
method TVA used to estimate unbilled revenue to distributor customers. See
Explanatory Note and Note 2 for additional information.
For the
years ended September 30
(in
millions)
|
2007
|
2006
|
2005
|
2004
|
2003
|
||||||||||||||||
|
As
restated
|
As
restated
|
|||||||||||||||||||
|
Operating
revenues1,
8
|
$ | 9,326 | $ | 8,983 | $ | 7,792 | $ | 7,525 | $ | 6,954 | ||||||||||
|
Revenue
capitalized during
pre-commercial
plant operations
|
(57 | ) | – | – | – | – | ||||||||||||||
|
Operating
expenses 7,
9
|
(7,726 | ) 2 | (7,560 | ) 2 | (6,455 | ) 2 | (5,833 | ) 3 | (5,379 | ) | ||||||||||
|
Operating
income
|
1,543 | 1,423 | 1,337 | 1,692 | 1,575 | |||||||||||||||
|
Other
income, net 1, 4,
7,
8
|
71 | 78 | 57 | 64 | 46 | |||||||||||||||
|
Unrealized
gain (loss) on
derivative
contracts, net
|
41 | (15 | ) | 3 | (7 | ) | (7 | ) | ||||||||||||
|
Net
interest expense 4,
9
|
(1,232 | ) | (1,264 | ) | (1,312 | ) | (1,363 | ) | (1,387 | ) | ||||||||||
|
Cumulative
effect of accounting changes
|
– | (109 | ) 5 | – | – | 217 | 6 | |||||||||||||
|
Net
income
|
$ | 423 | $ | 113 | $ | 85 | $ | 386 | $ | 444 | ||||||||||
|
|
Notes
|
|
|
(1)
|
Prior
to 2007, TVA reported certain revenue not directly associated with revenue
derived from electric operations as Other revenue. This income
of $10 million, $12 million, $8 million, and $7 million for 2006, 2005,
2004, and 2003, respectively, has been reclassified from Other revenue to
Other income. Additionally, certain items not directly
associated with the sale of electricity were previously reported as Sales
of electricity. This revenue of $22 million, $23 million, $22
million, and $22 million for 2006, 2005, 2004, and 2003, respectively, has
been reclassified from Sales of electricity to Other
revenue. See Note 1 —Reclassifications.
|
|
|
(2)
|
During
2007, 2006 and 2005, TVA recognized a total of $21 million, $14 million,
and $24 million, respectively, in impairment losses related to its
Property, plant, and equipment. The 2007 Loss on asset
impairment included a $17 million write-down of a scrubber project at
TVA’s Colbert Fossil Plant (“Colbert”) and write-downs of $4 million
related to other Construction in progress assets. The 2006 Loss
on asset impairment included write-downs of $12 million on 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 and a $2 million write-down on
one of two buildings in TVA’s Knoxville Office Complex based on TVA’s
plans to sell or lease the East Tower of the Knoxville Office
Complex. The 2005 Loss on asset impairment included a $16
million write-down on 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
and an $8 million write-down on one of two buildings in TVA’s Knoxville
Office Complex based on TVA’s plans to sell or lease the East Tower of the
Knoxville Office Complex.
|
|
|
(3)
|
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.
|
|
|
(4)
|
Prior
to 2006, TVA reported short-term investment interest income with interest
expense. Interest income of $19 million, $6 million, and $3
million for 2005, 2004, and 2003, respectively, has been reclassified from
Interest expense, net to Other income,
net.
|
|
|
(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 5.
|
|
|
(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.
|
|
|
(7)
|
TVA
has certain service organizations which provide maintenance and testing
services to customers both inside and outside of TVA. For 2005,
the excess of cost recovery over actual cost and services provided to TVA
organizations of $12 million has been reclassified from Other income to
Operating expense. See Note 1 — Reclassifications.
|
|
|
(8)
|
Certain
items previously reported as revenue under Other revenue were
reclassified as Other income. These items were not directly
associated with revenue derived from electric operations but are
associated with the operation of service organizations which provide
environmental and maintenance and testing services. Previously
reported revenue from these items of approximately $5 million, $13
million, and $7 million for 2005, 2004, and 2003, respectively, are now
included in Other income. Additionally, certain Other
revenue related to income derived from electric operations was
recorded net of related expenses. Expenses of $15 million, $13
million and $15 million for 2005, 2004, and 2003, respectively, have been
reclassified from Other
revenue to operating expenses. See Note 1 — Reclassifications.
|
|
|
(9)
|
Subsequent
to 2005, certain financing charges related to leaseback obligations were
recorded as Operating
and maintenance expense. Beginning with 2006,
these financing charges are classified as interest
expense. Previously reported financing charges of approximately
$51 million, $53 million, and $34 million for 2005, 2004, and 2003,
respectively, are now included in Interest on debt and leaseback
obligations. See Note 1 — Reclassifications.
|
At
September 30
(in
millions)
|
2007
|
2006
|
2005
|
2004
|
2003
1
|
||||||||||||||||
|
As
restated
|
As
restated
|
|||||||||||||||||||
|
Assets
|
||||||||||||||||||||
|
Current
assets 2
|
$ | 2,436 | $ | 2,513 | $ | 2,176 | $ | 2,295 | $ | 2,238 | ||||||||||
|
Property,
plant, and equipment, net
|
24,832 | 24,421 | 23,888 | 23,699 | 23,125 | |||||||||||||||
|
Investment
funds
|
1,169 | 972 | 858 | 744 | 638 | |||||||||||||||
|
Regulatory
and other long-term assets
|
5,295 | 6,402 | 7,551 | 7,451 | 7,027 | |||||||||||||||
|
Total
assets
|
$ | 33,732 | $ | 34,308 | $ | 34,473 | $ | 34,189 | $ | 33,028 | ||||||||||
|
Liabilities
and proprietary capital
|
||||||||||||||||||||
|
Current
liabilities 2
|
$ | 3,429 | $ | 5,229 | $ | 6,724 | $ | 5,420 | $ | 5,819 | 3 | |||||||||
|
Regulatory
and other liabilities
|
6,400 | 7,052 | 7,606 | 7,168 | 5,114 | |||||||||||||||
|
Long-term
debt, net
|
21,099 | 19,544 | 17,751 | 19,337 | 20,201 | |||||||||||||||
|
Total
liabilities
|
30,928 | 31,825 | 32,081 | 31,925 | 31,134 | |||||||||||||||
|
Retained
earnings
|
1,763 | 1,349 | 1,244 | 1,162 | 783 | |||||||||||||||
|
Other
proprietary capital
|
1,041 | 1,134 | 1,148 | 1,102 | 1,111 | |||||||||||||||
|
Total
proprietary capital
|
2,804 | 2,483 | 2,392 | 2,264 | 1,894 | |||||||||||||||
|
Total
liabilities and proprietary capital
|
$ | 33,732 | $ | 34,308 | $ | 34,473 | $ | 34,189 | $ | 33,028 | ||||||||||
Notes
|
|
(1)
|
Prior
to 2004, TVA presented two balance sheets – one for its power program and
one for all programs. The 2003 Balance Sheet presented above is
for all programs which is consistent with the presentation for 2004, 2005,
2006, and 2007.
|
|
|
(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, and $83 million in
2003 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.
|
As of
September 30
(in
millions)
|
2007
|
2006
|
2005
|
2004
|
2003
|
||||||||||||||||
|
Net
long-term debt, excluding current maturities
|
$ | 21,099 | $ | 19,544 | $ | 17,751 | $ | 19,337 | $ | 20,201 | ||||||||||
|
Other
long-term obligations
|
||||||||||||||||||||
|
Capital
leases *
|
104 | 128 | 150 | 138 | 151 | |||||||||||||||
|
Leaseback
commitments
|
1,072 | 1,108 | 1,143 | 1,178 | 1,238 | |||||||||||||||
|
Energy
prepayment obligations
|
1,138 | 1,244 | 1,350 | 1,455 | 47 | |||||||||||||||
|
Total
other long-term obligations
|
2,314 | 2,480 | 2,643 | 2,771 | 1,436 | |||||||||||||||
|
Total
long-term obligations
|
23,413 | 22,024 | 20,394 | 22,108 | 21,637 | |||||||||||||||
|
Discount
notes
|
1,422 | 2,376 | 2,469 | 1,924 | 2,080 | |||||||||||||||
|
Current
maturities of long-term debt, net
|
90 | 985 | 2,693 | 2,000 | 2,336 | |||||||||||||||
|
Total
short-term obligations
|
1,512 | 3,361 | 5,162 | 3,924 | 4,416 | |||||||||||||||
|
Total
financial obligations
|
$ | 24,925 | $ | 25,385 | $ | 25,556 | $ | 26,032 | $ | 26,053 | ||||||||||
Note
* Included
in Accrued liabilities and Other liabilities on the Balance Sheets.
(Dollars
in millions except where noted)
In this
Form 10-K/A No. 2, TVA is restating the financial statements for the years ended
September 30, 2007, and 2006, primarily to restate revenue associated with an
accounting error determined as a result of TVA’s review of its unbilled revenue
estimation process. The information below reflects these
restatements. Overall, this Form 10-K/A No. 2 has not modified
or updated other disclosures presented in the Original Form 10-K, except as
required to reflect the items amended in the Form 10-K/A No. 2 as described
more fully in Note 2. This Form 10-K/A No. 2 is not superseding or
restating financial statements contained in TVA’s quarterly reports on Form 10-Q
for the quarters ended March 31, 2008, or December 31, 2007, or any current
report on Form 8-K filed subsequent to September 30, 2007. However,
the financial statements for the quarters ended March 31, 2008, and December 31,
2007, which are contained in the quarterly reports on Form 10-Q for the quarters
then ended, have also been restated in amended quarterly reports on Form
10-Q/A, which
TVA plans to file as soon as practicable after the filing of this Form
10-K/A No. 2 (see Note 17). Accordingly, the information in the Form
10-Q for the quarters ended March 31, 2008, and December 31, 2007, should be
considered in light of the information in this Form 10-K/A No.
2.
Distinguishing Features of TVA’s
Business
TVA operates the nation’s largest
public power system. In 2007, 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 2007
revenues from the sale of electricity totaled $9.2 billion. As a
wholly-owned agency and instrumentality of the United States, however, TVA is
different from other electric utilities in a number of ways. A few of
the more distinguishing features 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 confines TVA’s sales activities, essentially limiting TVA to power
sales within a defined service area. Correspondingly, however, the
possibility of sales by others into TVA’s service area is significantly
limited. The Federal Power Act, primarily through its
anti-cherrypicking provision, prevents FERC from ordering TVA to provide access
to its transmission lines to others for the purpose of delivering power to
customers within its service area except for customers in Bristol,
Virginia.
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 with respect to
rates. The TVA Act gives the TVA Board sole responsibility for
establishing the rates TVA charges for power. These rates are not
subject to judicial review or review or approval by any state or federal
regulatory body. In setting TVA’s rates, however, the TVA Board is
charged by the TVA Act to have due regard for the objective that power be sold
at rates as low as are feasible.
Funding. TVA’s
operations were originally funded primarily with appropriations from
Congress. In 1959, however, Congress passed legislation that required
TVA’s power program to be self-financing from power revenues and proceeds from
power program financings. Until 1999, TVA continued to receive some
appropriations for certain multipurpose activities and for its stewardship
activities. Since 1999, however, TVA has not received any
appropriations from Congress for any activities and has funded essential
stewardship activities primarily with power revenues in accordance with a
statutory directive from Congress.
TVA, unlike investor-owned power
companies, is not authorized to raise capital by issuing equity
securities. TVA relies primarily on cash from operations and proceeds
from power program borrowings to fund its operations. 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. From time to time, draft legislation is introduced in Congress
that would expand the types of financial obligations that count towards TVA’s
$30 billion debt ceiling. Under this draft legislation,
long-term obligations that finance capital assets would also 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, 2007, TVA had approximately $22.5
billion of Bonds outstanding (not including noncash items of foreign currency
valuation loss of $299 million and net discount on sale of bonds of $189
million).
For
additional information regarding TVA’s sources of funding, see Item 7, Management’s Discussion
and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources —
Sources of Liquidity.
Stewardship Activities. TVA’s
mission includes managing the United States’ fifth largest river system — the
Tennessee River and its tributaries — to provide, among other things, year-round
navigation, flood damage reduction, affordable and reliable electricity, and,
consistent with these primary purposes, recreational opportunities, adequate
water supply, improved water quality, and economic development. There
are 49 dams that comprise TVA’s integrated reservoir system. The
reservoir system provides 800 miles of commercially navigable waterway and also
provides significant flood reduction benefits both within the Tennessee River
system and downstream on the lower Ohio and Mississippi Rivers. The reservoir
system also provides a water supply for residential and industrial customers,
including cooling water for some of TVA’s coal-fired and nuclear power
plants. TVA also manages 293,000 acres of reservoir lands for natural
resource protection, recreation, and other purposes.
Challenges During 2007
TVA faced several challenges during
2007 that impacted its cash flows, results of operations, and financial
condition. The most significant of these challenges were adverse
weather conditions, performance challenges at one of TVA’s generating plants,
project overruns at Browns Ferry Nuclear Plant Unit 1, the impact on TVA’s
system from issues at two dams operated by the U.S. Army Corps of Engineers, and
the timing of cash flows related to the fuel cost adjustment
mechanism.
Weather
Conditions. 2007 was the driest year in the eastern Tennessee
Valley in 118 years of record-keeping. Rainfall in the eastern
Tennessee Valley was 66 percent of normal for the year, and runoff was 54
percent of normal. Largely as a result of this low rainfall and
runoff, TVA’s hydroelectric production for 2007 was slightly more than nine
billion kilowatt-hours, which was nine percent, 42 percent, and 35 percent lower
than in 2006, 2005, and 2004, respectively. Because of the lower
hydroelectric production, TVA had to rely heavily on purchased power and more
expensive generation sources such as combustion turbines during
2007.
2007 was also distinguished by warmer
temperatures across the eastern Tennessee Valley. August was the
hottest month on record in TVA’s service area. Between August 2 and
28, TVA met 13 all-time system peak demands for electricity, including an
all-time record peak of 33,482 megawatts set on August 16. To meet
these peaks, TVA had to purchase a significant amount of
power. During the hour of TVA’s peak supply, purchased power
constituted 21 percent of TVA’s load.
The hot weather and low rainfall were
also significant factors in causing TVA to reduce power output at several
generating plants during the period of mid-June through
mid-September. During this period, temperatures on the Tennessee and
Cumberland Rivers reached levels at which discharging cooling water from some of
TVA’s plants into the rivers could have caused the permitted thermal limits for
the rivers to be exceeded. Accordingly, TVA temporarily took one unit
at Browns Ferry Nuclear Plant offline and reduced the output of the other two
units at Browns Ferry to 75 percent of capacity.
TVA also temporarily reduced the power
output at two coal-fired plants on the Cumberland River. During the period of
early July through early September, output from the Gallatin Fossil Plant was
reduced by five percent and output from the Cumberland Fossil Plant was reduced
by 16 percent to avoid exceeding thermal limits. TVA was able to meet
its customers’ power needs but estimates that the net cost of replacement power
resulting from the curtailment of nuclear and coal-fired generation was
approximately $25 million. While every effort was made to take
derates (lower electrical output) during low load periods to reduce financial
and operational impacts, some derates were required during higher load daytime
hours to meet the permitted temperature limits.
Performance of TVA
Assets. Although TVA’s generation and transmission assets
performed extremely well in meeting the peak demands during the summer, TVA was
adversely affected in 2007 when the planned outage at Unit 3 of Paradise Fossil
Plant to correct an issue with a turbine rotor took longer than
expected. The unit was scheduled to be back on line on April 29,
2007, but did not return to service until June 7, 2007, due to more extensive
repairs identified during the outage. During this outage, the site’s generation
was reduced by 1,026 megawatts. Because of the additional repairs and
extended outage, TVA incurred approximately $7 million in unplanned repair costs
and an additional $25 million in net replacement power purchase
costs.
Project
Overruns. TVA completed Browns Ferry Unit 1 during 2007 with a
total project cost overrun of $90 million or five percent of the
original projected cost. The cost overruns were due in part
to the scope of work associated with extended power uprate being
greater than planned.
Issues at Two U.S. Army Corps of
Engineers Dams. Because of issues at the U.S. Army Corps of
Engineers’ Wolf Creek Dam and Center Hill Dam, the hydroelectric production and
summer stream flow on the Cumberland River were reduced. Because of
these issues, on February 25, 2007, the Southeastern Power Administration
(“SEPA”) asserted “force majeure” on its contract with TVA. SEPA then
instituted an emergency operating plan that:
|
|
•
|
Eliminates
its obligation to provide any affected customer (including TVA) with a
minimum amount of power;
|
|
|
•
|
Provides
for all affected customers (except TVA) to receive a pro rata share of a
portion of the gross hourly generation from the eight Cumberland River
hydroelectric facilities;
|
|
|
•
|
Provides
for TVA to receive all of the remaining hourly generation (minus station
service for those facilities);
|
|
|
•
|
Eliminates
the payment of demand charges by customers (including TVA) since there is
significantly reduced dependable capacity on the Cumberland River system;
and
|
|
|
•
|
Increases
the rate charged per kilowatt-hour of energy received by SEPA’s customers
(including TVA), because SEPA is legally required to charge rates that
cover its costs.
|
It is
unclear how long the emergency operating plan will remain in
effect.
In addition to reducing the amount of
hydroelectric power that TVA is entitled to receive from SEPA, the issues at the
U.S. Army Corps of Engineers’ dams reduced the summer stream flow on the
Cumberland River. This reduction in stream flow, together with the
hot temperatures and low rainfall discussed previously, was a significant factor
in causing TVA to curtail generation at two coal-fired plants during the summer
of 2007 and replace curtailed generation with higher-priced purchased
power. The issues at these dams could affect reservoir and
hydroelectric operations in the Cumberland River system for five to seven
years. Accordingly, even if the drought that the eastern Tennessee
Valley experienced in 2007 does not continue, TVA may have to curtail generation
at its two coal-fired plants located on the Cumberland River from time to time
over the next five to seven years.
Timing of Cash
Flows. On July 28, 2006, the TVA Board implemented a fuel cost
adjustment (“FCA”) to be applied quarterly as a mechanism to adjust TVA’s rates
to reflect changing fuel and purchased power costs beginning in
2007. The FCA was initially set to zero and had its first impact on
rates effective January 1, 2007. The FCA rate adjustment on January
1, 2007, was 0.01 cents per kilowatt-hour, the rate adjustment on April 1, 2007,
was 0.084 cents per kilowatt-hour, and the rate adjustment on July 1, 2007, was
0.087 cents per kilowatt-hour. These 2007 rate adjustments produced
an estimated $82 million in revenue. As of September 30, 2007, TVA
had recognized a regulatory asset of $150 million representing deferred power
costs to be recovered through the FCA adjustments in future
periods. The timing of the collection of the FCA adjustments has
contributed to a decrease in cash of $371 million from September 30, 2006, to
September 30, 2007. The FCA rate adjustment on October 1, 2007, was
0.432 cents per kilowatt-hour. Based upon the FCA calculation methodology in use
as of October 1, 2007, the FCA was expected to produce an estimated $159 million
in revenue during the first quarter of 2008.
Under
TVA’s FCA methodology, adjustments to rates are based on the difference between
forecasted and baseline (budgeted) costs for the upcoming quarter. Because
the FCA adjustments are forward-looking, there is typically a difference between
what is collected in rates and what actual expense is realized over the course
of the quarter. This difference is added to or deducted from a
deferred account on TVA’s balance sheet. Each quarterly adjustment
includes a core FCA adjustment plus one half of the deferred balance. The
higher or lower costs added to or taken away from the deferred balance sheet
account are then amortized to expense in the periods in which they are to be
collected in revenues. This allows better matching of the
revenues with associated expenses.
Although TVA’s cost increases for fuel
and purchased power are mitigated by the FCA, TVA’s cash flow can be negatively
impacted by the FCA cash collection process. Under the methodology,
some of the FCA portion of higher fuel and purchased power expense realized
during the quarter is placed in the deferred account to be collected in rates in
later periods. The timing of the collection of revenues related to
the FCA does not coincide with the cash expended for fuel and purchased power
consumed.
Future Challenges
TVA faces several challenges that may
impact its cash flows, results of operations, and financial
condition. The most significant of these challenges are discussed
below.
Meeting the Power Needs in TVA’s
Service Area. Demand for power in TVA’s service area has been growing at
an average of two percent per year and TVA anticipates the demand will continue
to grow. TVA plans to meet the need for additional power through a
variety of means:
|
|
•
|
New
Generation. TVA intends to add new generation
assets. This intention was reflected in TVA’s decision to
complete the construction of Watts Bar Nuclear Unit 2. The
completion of Watts Bar Nuclear Unit 2 is expected to occur in 2013 and
cost approximately $2.5 billion. TVA plans to consider other
opportunities to add new generation from time to time. Market
conditions, like the volatility of the price of construction materials and
the potential shortage of skilled craft labor, may add uncertainties to
the cost and schedule of new
construction.
|
|
|
•
|
Purchased
Power. Purchasing power from others will likely remain a
part of how TVA meets the power needs of its service area. The
Strategic Plan establishes a goal of balancing production capabilities
with power supply requirements within five percent. Achieving
this goal will require TVA to reduce its reliance on purchased power,
which constituted 12.4 percent of the power that TVA sold in
2007.
|
|
|
•
|
Distributor-Owned
Generation. TVA is also discussing with the distributors
of TVA power ways in which distributors can own generating facilities
while TVA remains the supplier of all of their power
requirements. These discussions, while still in the early
stages, may provide the framework for the distributors of TVA power to
provide some of the future generating
facilities.
|
Non-Fuel Operating and Maintenance
Costs. TVA
has established two significant goals relating to non-fuel operating and
maintenance costs.
|
•
|
TVA
intends to reduce these costs over the next three
years.
|
|
•
|
After
that time, TVA intends to keep the rate of increase in these costs lower
than the rate of growth of TVA’s electricity
sales.
|
Meeting these goals will significantly
affect TVA’s ability to achieve certain objectives identified in the Strategic
Plan, including the objective of adding new generation assets.
Performance of Generation Assets.
Although TVA’s generation and transmission assets performed extremely
well overall in meeting the peak demands during the summer of 2007, TVA was
adversely affected by the failure of some assets to operate as planned during
times of high summer demand. As a result, TVA had to purchase more
power than expected when purchased power prices were high. (See Item
1, Business — Power Supply.)
TVA is likely to face similar problems in the future since many of TVA’s
generation assets have been operating since the 1950s or earlier and have been
in near constant service since they were completed.
Bonds and Other Financial
Obligations. As of September 30, 2007, TVA had $22.5 billion of Bonds
outstanding (not including noncash items of foreign currency valuation loss of
$299 million and net discount on sale of bonds of $189 million). The
amount of TVA’s Bonds outstanding has been reduced by more than $5 billion since
September 30, 1996, when the end of year balance of outstanding Bonds
peaked. Since that time, however, TVA has entered into energy
prepayment transactions that resulted in $1.6 billion in prepayment obligations
and certain lease/leaseback transactions that resulted in $1.3 billion in
obligations. The amount of prepayment and lease/leaseback obligations
outstanding at September 30, 2007, was $2.2 billion. Payments on
these Bonds and obligations do not change with the amount of power sold, and if
competition increases, TVA’s obligations to make these payments could limit its
ability to adjust to market pressures. While prudent management of
Bonds and other financial obligations will remain an important strategic
consideration in the future, increased capital commitments may make it difficult
for TVA to continue its trend of reducing these obligations.
2008 Budget. The
2008 budget approved by the TVA Board on September 27, 2007, is based on TVA’s
obtaining $300 million more in operating cash flows than is currently
anticipated. When the TVA Board approved the budget, it recognized
that TVA would need a rate increase to balance the budget. The amount
of the rate increase needed to balance the budget is expected to be less than 10
percent. TVA and its customers are working to determine the amount of
the rate increase to be effective during the second half of 2008.
Environmental
Regulation. TVA expects to see increased environmental
regulation in the future, including but not limited to, the regulation of
mercury and the emission of greenhouse gases such as CO2. TVA
has considered, and intends to continue considering, fuel mix in making
decisions about additional generation. The restart of Browns Ferry
Unit 1, the decision to complete the construction of Watts Bar Unit 2, and TVA’s
filing of a combined operating license application for two new units at the
Bellefonte Nuclear Plant (although no decision to construct these units has been
made) are examples of TVA’s decisions to pursue or consider generation sources
that do not emit greenhouse gases. The nature or level of future
regulation of greenhouse gases is unclear at this time. Accordingly,
the costs associated with such regulation are currently unknown but could be
substantial. TVA would have to recover such costs in rates or pursue
some other action such as removing some coal-fired units from
service.
Renewable Portfolio.
Renewable power generation resources include solar, wind, incremental
hydroelectric, biomass, and landfill gas. Generating power with
renewable sources instead of coal-fired plants could help reduce the carbon
intensity of TVA’s generation. Generating power with renewable
resources, however, may not be economical using current
technology. If TVA is required to increase its use of renewable
resources and the cost of doing so is greater than the costs of other sources of
generation, TVA’s costs may increase, and, as a result, TVA may be forced to
raise rates.
TVA’s Power Service Area.
TVA’s service area is set by two pieces of legislation: the fence and the
anti-cherrypicking provision. See Item 1, Business — Service
Area. Recently there have been efforts to erode the protection
of the anti-cherrypicking provision. FERC issued an order that would
have required TVA to interconnect its transmission system with the transmission
system of East Kentucky Power Cooperative, Inc. (“East Kentucky”) in what TVA
believed was a violation of the anti-cherrypicking provision. See
Item 3, Legal Proceedings. Additionally, Senators Jim Bunning and
Mitch McConnell introduced the Access to Competitive Power Act of 2007 in the
Senate that would, among other things, provide that the anti-cherrypicking
provision would not apply with respect to any distributor which provided a
termination notice to TVA before December 31, 2006, regardless of whether the
notice was later withdrawn or rescinded. See Item 7, Management’s
Discussion and Analysis of Financial Condition and Result of Operations — Legislative and Regulatory
Matters. While the FERC action involving East Kentucky now
appears to be moot and the proposed legislation has not made it to the Senate
floor, the events illustrate how the protection to TVA’s service area provided
by the anti-cherrypicking provision could be called into question and perhaps
eliminated at some time in the future.
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 would
have a profound, detrimental impact on TVA’s activities could become law with
little or no advance notice. For a discussion of the potential impact
of legislation on TVA, see Item 1A, Risk Factors.
Sources of Liquidity
To meet short-term cash needs and
contingencies, TVA depends on various sources of liquidity. TVA’s
primary sources of liquidity are cash on hand and cash from operations, proceeds
from the issuance of short-term and long-term debt, and proceeds from borrowings
under TVA’s $150 million note with the U.S. Treasury. TVA’s current
liabilities exceed current assets because of the continued use of short-term
debt as a funding source to meet cash needs as well as to meet scheduled
maturities of long-term debt.
The majority of TVA’s balance of cash on hand is typically invested in
short-term investments. During 2007, TVA’s average daily balance of
cash and cash equivalents on hand was $389 million. The daily balance
of cash and cash equivalents maintained is based on near-term expectations for
cash expenditures and funding needs.
Other
sources of liquidity include two $1.25 billion credit facilities with a national
bank as well as occasional proceeds from other financing arrangements including
call monetization transactions and sales of receivables and
loans. Each of these sources of liquidity is discussed
below.
Summary Cash
Flows. A major source of TVA’s liquidity is operating cash
flows resulting from the generation and sales of
electricity. A summary of cash flow components for the years ended
September 30 follows:
|
Summary
Cash Flows
For
the years ended September 30
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
Cash
provided by (used in):
|
As
Restated
|
As
Restated
|
||||||||||
|
Operating
activities
|
$ | 1,788 | $ | 1,985 | $ | 1,462 | ||||||
|
Investing
activities
|
(1,686 | ) | (1,698 | ) | (1,188 | ) | ||||||
|
Financing
activities
|
(473 | ) | (289 | ) | (255 | ) | ||||||
|
Net
(decrease) increase in cash and cash equivalents
|
$ | (371 | ) | $ | (2 | ) | $ | 19 | ||||
Issuance of
Debt. The TVA Act authorizes TVA to issue Bonds in an amount
not to exceed $30 billion outstanding at any time. At September 30,
2007, TVA had only two types of Bonds outstanding: power bonds and
discount notes. Power bonds have maturities of between one and 50
years, and discount notes have maturities of less than one
year. Power bonds and discount notes rank on parity and have first
priority of payment out of net power proceeds. Net power proceeds are
defined as the remainder of TVA’s gross power revenues after deducting the costs
of operating, maintaining, and administering its power properties and payments
to states and counties in lieu of taxes, but before deducting depreciation
accruals or other charges representing the amortization of capital expenditures,
plus the net proceeds from the sale or other disposition of any power facility
or interest therein. See Note 11 — General.
Power bonds and discount notes are both
issued pursuant to section 15d of the TVA Act and pursuant to the Basic
Tennessee Valley Authority Power Bond Resolution adopted by the TVA Board on
October 6, 1960, as amended on September 28, 1976, October 17, 1989, and March
25, 1992 (the “Basic Resolution”). The TVA Act and the Basic
Resolution each contain two bond tests: the rate test and the bondholder
protection test.
Under the
rate test, TVA must charge rates for power which will produce gross revenues
sufficient to provide funds for:
|
•
|
Operation,
maintenance, and administration of its power
system;
|
|
•
|
Payments
to states and counties in lieu of
taxes;
|
|
•
|
Debt
service on outstanding Bonds;
|
|
•
|
Payments
to the U.S. Treasury as a repayment of and a return on the Power
Facilities Appropriation Investment;
and
|
|
•
|
Such
additional margin as the TVA Board may consider desirable for investment
in power system assets, retirement of outstanding Bonds in advance of
maturity, additional reduction of the Power Facilities Appropriation
Investment, and other purposes connected with TVA’s power business, having
due regard for the primary objectives of the TVA Act, including the
objective that power shall be sold at rates as low as are
feasible.
|
Under the
bondholder protection test, TVA must, in successive five-year periods, use an
amount of net power proceeds at least equal to the sum of:
|
•
|
The
depreciation accruals and other charges representing the amortization of
capital expenditures, and
|
|
•
|
The
net proceeds from any disposition of power
facilities,
|
for
either
|
•
|
The
reduction of its capital obligations (including Bonds and the Power
Facilities Appropriation Investment),
or
|
|
•
|
Investment
in power assets.
|
TVA must
next meet the bondholder protection test for the five-year period ending
September 30, 2010.
As discussed above, TVA uses proceeds
from the issuance of discount notes, in addition to other sources of liquidity,
to fund working capital requirements. During 2007, 2006, and 2005,
the average outstanding balance of discount notes was $2.3 billion, $2.0
billion, and $2.1 billion, respectively, and the weighted average interest rate
on discount notes was 5.17 percent, 4.47 percent, and 2.70 percent,
respectively. At September 30, 2007, $1.4 billion of discount notes
were outstanding with a weighted average interest rate of 4.74
percent. The discount notes are not listed on any stock
exchange.
TVA issues power bonds primarily to
refinance previously-issued power bonds as they mature. During 2007
and 2006, TVA issued $1.0 and $1.1 billion of power bonds, respectively, and
redeemed $470 million, and $1.2 billion of power bonds,
respectively. At September 30, 2007, outstanding power bonds
(including current maturities of long-term debt) consisted of the
following:
Outstanding
Power Bonds
As of
September 30, 2007
|
CUSIP
or Other Identifier
|
Maturity
|
Coupon
Rate
|
Principal
Amount
1
|
Stock
Exchange Listings
|
||||||||
|
electronotes®
|
01/15/2008
- 10/15/2026
|
2.450%
- 6.125%
2
|
$ | 1,117 |
None
|
|||||||
|
880591DB5
|
11/13/2008
|
5.375%
|
2,000 |
New
York, Hong Kong, Luxembourg, Singapore
|
||||||||
|
880591DN9
|
01/18/2011
|
5.625%
|
1,000 |
New
York, Luxembourg
|
||||||||
|
880591DL3
|
05/23/2012
|
7.140%
|
29 |
New
York
|
||||||||
|
880591DT6
|
05/23/2012
|
6.790%
|
1,486 |
New
York
|
||||||||
|
880591CW0
|
03/15/2013
|
6.000%
|
1,359 |
New
York, Hong Kong, Luxembourg, Singapore
|
||||||||
|
880591DW9
|
08/01/2013
|
4.750%
|
990 |
New
York, Luxembourg
|
||||||||
|
880591DY5
|
06/15/2015
|
4.375%
|
1,000 |
New
York, Luxembourg
|
||||||||
|
880591DS8
|
12/15/2016
|
4.875%
|
|
524 |
New
York
|
|||||||
|
880591EA6
|
07/18/2017
|
5.500%
|
1,000 |
New
York, Luxembourg
|
||||||||
|
880591CU4
|
12/15/2017
|
6.250%
|
|
750 |
New
York
|
|||||||
|
880591DC3
|
06/07/2021
|
5.805%3
|
409 |
New
York, Luxembourg
|
||||||||
|
880591CJ9
|
11/01/2025
|
6.750%
|
1,350 |
New
York, Hong Kong, Luxembourg, Singapore
|
||||||||
| 880591300 |
06/01/2028
|
5.490%
|
466 |
New
York
|
||||||||
| 880591409 |
05/01/2029
|
5.618%
|
410 |
New
York
|
||||||||
|
880591DM1
|
05/01/2030
|
7.125%
|
1,000 |
New
York, Luxembourg
|
||||||||
|
880591DP4
|
06/07/2032
|
6.587%
|
512 |
New
York, Luxembourg
|
||||||||
|
880591DV1
|
07/15/2033
|
4.700%
|
472 |
New
York, Luxembourg
|
||||||||
|
880591DX7
|
06/15/2035
|
4.650%
|
436 |
New
York
|
||||||||
|
880591CK6
|
04/01/2036
|
5.980%
|
121 |
New
York
|
||||||||
|
880591CS9
|
04/01/2036
|
5.880%
|
1,500 |
New
York
|
||||||||
|
880591CP5
|
01/15/2038
|
6.150%
|
1,000 |
New
York
|
||||||||
|
880591BL5
|
04/15/2042
|
8.250%
|
1,000 |
New
York
|
||||||||
|
880591DU3
|
06/07/2043
|
4.962% 3
|
307 |
New
York, Luxembourg
|
||||||||
|
880591CF7
|
07/15/2045
|
6.235%
|
140 |
New
York
|
||||||||
|
880591DZ2
|
04/01/2056
|
5.375%
|
1,000 |
New
York
|
||||||||
|
Subtotal
|
21,378 | |||||||||||
|
Unamortized
discounts, premiums, and other
|
(189 | ) | ||||||||||
|
Total
outstanding power bonds, net
|
$ | 21,189 | ||||||||||
Notes
(1) The
above table includes net exchange losses from currency transactions of $299
million at September 30, 2007.
(2) The weighted average interest rate
of TVA’s outstanding electronotes® was 4.76
percent at September 30, 2007.
(3) The coupon rate represents TVA’s
effective interest rate.
As of September 30, 2007, all of TVA’s
Bonds were rated by at least one rating agency except for two issues of power
bonds and TVA’s discount notes. TVA’s rated Bonds are currently rated
“Aaa” by Moody’s Investors Service and/or “AAA” by Standard & Poor’s and/or
Fitch Ratings, which are the highest ratings assigned by these agencies. The
ratings are not recommendations to buy, sell, or hold any TVA securities and may
be subject to revision or withdrawal at any time by the rating agencies. Ratings
are assigned independently, and each should be evaluated as such.
For additional information about TVA
debt issuance activity and debt instruments issued and outstanding as of
September 30, 2007 and 2006, including identifiers, rates, maturities,
outstanding principal amounts, and redemption features, see Note
11.
$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 maturity of one year or less in an amount not to exceed $150
million. TVA may draw any portion of the authorized $150 million.
Interest accrues daily and is 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 2007, 2006, and 2005, the daily average amounts
outstanding were approximately $132 million, $131 million, and $103 million,
respectively. The outstanding balances were repaid
quarterly. See Note 9 and Note 11 — Short-Term Debt.
Credit Facilities.
In the event of shortfalls in cash resources, TVA has
short-term funding available in the form of two $1.25 billion short-term
revolving credit facilities, one of which matures on May 14, 2008, and the other
of which matures on November 10, 2008. See Note 18 — Revolving Credit Facility
Agreement. The interest rate on any borrowing under either of these
facilities is variable and based on market factors and the rating of TVA’s
senior unsecured long-term non-credit enhanced debt. 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 on the non-enhanced credit
ratings on TVA’s senior unsecured long-term debt. There were no outstanding
borrowings under the facilities at September 30, 2007. 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, 2007, TVA has entered into four swaption transactions that
generated proceeds of $261 million.
|
•
|
In
2003, TVA monetized the call provisions on a $1 billion Bond issue and a
$476 million Bond issue by entering into swaption agreements with a third
party in exchange for $175 million and $81 million,
respectively.
|
|
•
|
In
2005, TVA monetized the call provisions on two Bond issues ($42 million
total par value) by entering into swaption agreements with a third party
in exchange for $5 million.
|
For more information regarding TVA’s
call monetization transactions, see Note 10 — Swaptions and Related Interest Rate
Swap.
Sales of
Receivables/Loans. From time to time TVA obtains proceeds from
selling receivables and loans. During 2007, TVA sold $2 million of receivables
at par such that TVA did not recognize a gain or loss on the sale. These were
receivables from a power customer related to the construction of a
substation. The proceeds from the sale of these receivables are
included within the Cash Flow Statement under the caption Cash flows from
investing activities.
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 represented receivables from power customers related
to the construction of a substation and other energy conservation projects, and
the proceeds from the sale of these receivables are included within the Cash
Flow Statement under the caption Cash flows from investing
activities.
During 2005, TVA sold $60 million of
receivables at par such that TVA did not recognize a gain or loss on the sale.
Of this amount, $1 million represented receivables from power customers related
to the construction of a substation and other energy conservation projects, and
the proceeds from the sale of these receivables are included within the Cash
Flow Statement under the caption Cash flows from investing activities.
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.
TVA did not retain any claim on these
loans and receivables sold, and they are no longer reported on TVA’s Balance
Sheets. For more information regarding TVA’s sales of receivables and loans, see
Note 1 — Sales of
Receivables/Loans.
2007
Compared to 2006
Net cash provided by operating
activities decreased from $1,985 million in 2006 to $1,788 million in
2007. This $197 million decrease primarily resulted
from:
|
|
•
|
An
increase in cash paid for fuel and purchased power of $249 million due to
higher volume of fuel and purchased power needed to replace hydroelectric
generation as well as increased market prices for
fuel;
|
|
|
•
|
An
increase in cash outlays for routine and recurring operating costs of $108
million;
|
|
|
•
|
An
increase in tax equivalent payments of $76 million;
and
|
|
|
•
|
An
increase in expenditures for nuclear refueling outages of $24 million due
to three planned outages in 2007 compared to two planned outages in the
prior year.
|
|
|
These
items were partially offset by:
|
|
|
•
|
A
decrease of $154 million in cash used by changes in working capital
resulting primarily from a smaller increase in the accounts receivable
balance of $142 million and a larger increase in accounts payable and
accrued liabilities of $9 million;
|
|
|
•
|
Cash
provided by deferred items of $61 million in 2007 compared to a $35
million net use of cash in 2006. This change is primarily due
to funds collected in rates during 2007 that were used to fund future
generation. See Note 1— Reserve for Future
Generation; and
|
|
|
•
|
A
decrease in cash paid for interest of $33 million in
2007.
|
Cash used in investing activities
decreased from $1,698 million in 2006 to $1,686 million in 2007. This
$12 million decrease resulted primarily from:
|
|
•
|
A
source of cash from collateral deposits in 2007 of $48 million as compared
to a net use of cash of $91 million in 2006. See Note 1 — Restricted Cash and
Investments; and
|
|
•
|
A
decrease in expenditures for the enrichment and fabrication of nuclear
fuel of $74 million related to the restart of Browns Ferry Unit 1 in
2007.
|
These
items were partially offset by:
|
|
•
|
An
increase in expenditures of $111 million to acquire the Gleason and
Marshall County combustion turbine facilities in
2007;
|
|
|
•
|
A
$40 million contribution to the Asset Retirement Trust. See
Note 1 — Investment
Funds;
|
|
|
•
|
A
damage award of $35 million that TVA received in 2006 in its breach of
contract suit against the DOE not present in 2007;
and
|
|
|
•
|
An
increase in expenditures for capital projects of $9
million.
|
Net cash used in financing activities
increased from $289 million in 2006 to $473 million in 2007. This
$184 million increase resulted primarily from:
|
|
•
|
A
decrease of $92 million in long-term debt issues;
and
|
|
|
•
|
An
increase in net redemptions of short-term debt of $862
million.
|
These items were partially offset by a
decrease in redemptions of long-term debt of $771 million in 2007 compared to
2006.
2006
Compared to 2005
Net cash provided by operating
activities increased $523 million from 2005 to 2006. This increase
resulted from:
|
•
|
An
increase in cash provided by operating revenues of $1.4 billion primarily
from higher average rates from rate actions effective in October 2005 and
April 2006 and, to a lesser extent, from 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;
|
|
•
|
An
increase in other deferred items of $33 million primarily due to $15
million related to customer advances for construction;
and
|
|
•
|
An
increase in contributions to the TVA Retirement System of $22
million.
|
Net cash used by changes in components
of working capital decreased $146 million from 2005 to 2006 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
$96 million increase in accounts payable and accrued liabilities in 2006
compared to a $16 million decrease in 2005 primarily due to changes of $88
million in the amount of collateral held by TVA under terms of a swap
agreement and higher costs for fuel and purchased power;
and
|
|
|
•
|
A
$23 million increase in accrued interest in 2006 compared to a $22 million
decrease in 2005 due to timing of interest payments on Bonds issued
relative to Bonds retired during
2006.
|
Cash used in investing activities
increased $510 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 $31 million 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 hydroelectric expenditures of $26 million; and
|
|
•
|
A
decrease in proceeds received from the sale of certain receivables/loans
of $45 million compared to the same period of
2005.
|
These items were partially offset
by:
|
•
|
A
damage award in 2006 of $35 million in TVA’s breach of contract suit
against the DOE; and
|
|
•
|
A
smaller increase in collateral deposits in 2006 of $16 million as compared
to 2005. See Note 1 — 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.
|
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 is important in assessing the effectiveness of management’s
decisions related to capital expenditures, pricing, and accessing capital
markets.
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
|
|||||||||||||||||||||||
|
2007
|
2008
|
2009
|
2010
|
2011
|
2012
|
|||||||||||||||||||
|
Watts
Bar Unit 2
|
$ | – | $ | 317 | $ | 670 | $ | 684 | $ | 547 | $ | 276 | ||||||||||||
|
Other
Capacity Expansion Expenditures
|
520 | 691 | 789 | 1,026 | 961 | 512 | ||||||||||||||||||
|
Clean
Air Expenditures
|
240 | 386 | 313 | 276 | 260 | 433 | ||||||||||||||||||
|
Transmission
Expenditures 2
|
44 | 73 | 74 | 56 | 63 | 60 | ||||||||||||||||||
|
Other
Capital Expenditures 3
|
448 | 506 | 550 | 430 | 500 | 513 | ||||||||||||||||||
|
Total
Capital Projects Requirements
|
$ | 1,252 | 4 | $ | 1,973 | $ | 2,396 | $ | 2,472 | $ | 2,331 | $ | 1,794 | |||||||||||
Notes
|
|
(1)
|
TVA
plans to fund these expenditures with power revenues and proceeds from
power program financings. This table shows only expenditures
that are currently planned. Additional expenditures may be
required for TVA to meet the growing demand for power in its service
area.
|
|
|
(2)
|
Transmission
Expenditures include reimbursable
projects.
|
|
|
(3)
|
Other
Capital Expenditures are primarily associated with short lead time
construction projects aimed at the continued safe and reliable operation
of generating assets.
|
|
|
(4)
|
The
numbers above exclude allowance for funds used during construction of $165
million in 2007.
|
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. See Forward-Looking
Information.
TVA does not anticipate receiving a
financial return on its clean air expenditures because these expenditures
neither generate revenues nor reduce costs. In fact, clean air
equipment will reduce the operating efficiency and increase the operating costs
of TVA’s coal-fired units. In the near term, TVA may be negatively
impacted by investments in new generation (i.e., Watts Bar Unit 2) that are not
expected to provide a cash return until put into service.
TVA also has certain obligations and
commitments to make future payments under contracts. The following table sets
forth TVA’s estimates of future payments as of September 30,
2007. See Notes 9, 11, and 15 for a further description of these
obligations and commitments.
|
Commitments
and Contingencies
Payments
due in the year ending September 30
|
|
Total
|
2008
|
2009
|
2010
|
2011
|
2012
|
Thereafter
|
||||||||||||||||||||||
|
Debt
|
$ | 22,501 | 1 | $ | 1,512 | $ | 2,030 | $ | 62 | $ | 1,015 | $ | 1,525 | $ | 16,357 | |||||||||||||
|
Interest
payments relating to debt
|
21,061 | 1,235 | 1,173 | 1,118 | 1,088 | 1,059 | 15,388 | |||||||||||||||||||||
|
Lease
obligations
|
||||||||||||||||||||||||||||
|
Capital
|
209 | 59 | 58 | 57 | 29 | 3 | 3 | |||||||||||||||||||||
|
Non-cancelable
operating
|
421 | 63 | 47 | 37 | 28 | 27 | 219 | |||||||||||||||||||||
|
Purchase
obligations
|
||||||||||||||||||||||||||||
|
Power
|
4,760 | 186 | 183 | 194 | 195 | 196 | 3,806 | |||||||||||||||||||||
|
Fuel
|
3,149 | 1,220 | 527 | 504 | 232 | 223 | 443 | |||||||||||||||||||||
|
Other
|
561 | 310 | 157 | 24 | 16 | 15 | 39 | |||||||||||||||||||||
|
Payments
on other financings
|
1,473 | 89 | 85 | 89 | 95 | 97 | 1,018 | |||||||||||||||||||||
|
Payment
to U.S. Treasury 2
|
||||||||||||||||||||||||||||
|
Return
of Power Facilities
Appropriation
Investment
|
130 | 20 | 20 | 20 | 20 | 20 | 30 | |||||||||||||||||||||
|
Return
on Power Facilities
Appropriation
Investment
|
258 | 19 | 22 | 21 | 20 | 18 | 158 | |||||||||||||||||||||
|
Retirement
plans
|
81 | 81 | – | – | – | – | – | |||||||||||||||||||||
|
Total
|
$ | 54,604 | $ | 4,794 | $ | 4,302 | $ | 2,126 | $ | 2,738 | $ | 3,183 | $ | 37,461 | ||||||||||||||
Notes
|
|
(1)
|
Does
not include noncash items of foreign currency valuation loss of $299
million and net discount on sale of Bonds of $189
million.
|
|
|
(2)
|
TVA has access to
financing arrangements with the U.S. Treasury whereby the U.S. Treasury is
authorized to accept from TVA a short-term note with the maturity of one
year or less in an amount not to exceed $150 million. TVA may
draw any portion of the authorized $150 million during the
year. TVA’s practice is to repay on a quarterly basis the
outstanding balance of the note and related interest. Because
of this practice, there was no outstanding balance on the note as of
September 30, 2007. Accordingly, the Commitments and
Contingencies table does not include any outstanding payment obligations
to the U.S. Treasury for this note at September 30,
2007. See Note 11 — Short-Term
Debt.
|
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
|
Total
|
2008
|
2009
|
2010
|
2011
|
2012
|
Thereafter
|
||||||||||||||||||||||
|
Energy
Prepayment Obligations
|
$ | 1,138 | $ | 106 | $ | 105 | $ | 105 | $ | 105 | $ | 105 | $ | 612 | ||||||||||||||
Financial
Results
The following table compares operating
results and selected statistics for 2007, 2006, and 2005:
Summary
Statements of Income
For the
years ended September 30
|
2007
|
2006
|
2005
|
||||||||||
|
As
Restated
|
As
Restated
|
|||||||||||
|
Operating
revenues
|
$ | 9,326 | $ | 8,983 | $ | 7,792 | ||||||
|
Revenue
capitalized during pre-commercial plant operations
|
(57 | ) | – | – | ||||||||
|
Operating
expenses
|
(7,726 | ) | (7,560 | ) | (6,455 | ) | ||||||
|
Operating
income
|
1,543 | 1,423 | 1,337 | |||||||||
|
Other
income
|
73 | 80 | 61 | |||||||||
|
Other
expense
|
(2 | ) | (2 | ) | (4 | ) | ||||||
|
Unrealized
gain/(loss) on derivative contracts, net
|
41 | (15 | ) | 3 | ||||||||
|
Interest
expense, net
|
(1,232 | ) | (1,264 | ) | (1,312 | ) | ||||||
|
Income
before cumulative effects of accounting changes
|
423 | 222 | 85 | |||||||||
|
Cumulative
effect of change in accounting for conditional asset retirement
obligations
|
– | (109 | ) | – | ||||||||
|
Net
income
|
$ | 423 | $ | 113 | $ | 85 | ||||||
|
Sales
(millions of kWh)
|
175,529 | 171,651 | 171,498 | |||||||||
2007 Compared to 2006
Net income for 2007 was $423 million
compared with net income of $113 million for 2006. The $310 million
increase in net income was mainly attributable to:
|
•
|
A
$109 million cumulative expense charge in 2006 for adoption of a new
accounting standard related to conditional asset retirement obligations
that did not occur in 2007;
|
|
•
|
A
$343 million increase in operating
revenues;
|
|
•
|
A
change of $56 million in net unrealized gain/(loss) on derivative
contracts; and
|
|
•
|
Lower
net interest expense of $32
million.
|
These items were partially offset
by:
|
•
|
A
$166 million increase in operating
expenses;
|
|
•
|
Revenue
of $57 million capitalized during pre-commercial plant operations;
and
|
|
•
|
A
$7 million decrease in other
income.
|
Operating
Revenues. Operating revenues and electricity sales during 2007
and 2006 consisted of the following:
|
Operating
Revenues and Electricity Sales
For
the years ended September 30
|
||||||||||||||||||||||||
|
Operating
Revenues
|
Sales
of Electricity
|
|||||||||||||||||||||||
|
(millions
of dollars)
|
(millions
of kWh)
|
|||||||||||||||||||||||
|
2007
|
2006
|
Percent
Change
|
2007
|
2006
|
Percent
Change
|
|||||||||||||||||||
|
As
Restated
|
As
Restated
|
As
Restated
|
As
Restated
|
|||||||||||||||||||||
|
Operating
revenues and sales of electricity
|
||||||||||||||||||||||||
|
Municipalities
and cooperatives
|
$ | 7,847 | $ | 7,659 | 2.5 | % | 142,461 | 138,624 | 2.8 | % | ||||||||||||||
|
Industries
directly served
|
1,221 | 1,065 | 14.6 | % | 30,993 | 30,987 | 0.0 | % | ||||||||||||||||
|
Federal
agencies and other
|
112 | 116 | (3.4 | %) | 2,075 | 2,040 | 1.7 | % | ||||||||||||||||
|
Other
revenue
|
146 | 143 | 2.1 | % | – | – | – | |||||||||||||||||
|
Total
operating revenues and sales of electricity
|
$ | 9,326 | $ | 8,983 | 3.8 | % | 175,529 | 171,651 | 2.3 | % | ||||||||||||||
Significant items contributing to the
$343 million increase in operating revenues included:
|
•
|
A
$188 million increase in revenue from municipalities and
cooperatives primarily due to increased sales of 2.8 percent and
increased FCA revenue of $76 million, partially offset by a decrease
in average rates of 1.3 percent;
|
|
•
|
A
$156 million increase in revenue from industries directly served
attributable to an increase in average rates of 15.1 percent and a slight
increase in sales; and
|
|
•
|
A
$3 million increase in other revenue primarily due to increased revenue
from salvage sales partially offset by decreased transmission revenues
from wheeling activity.
|
These items were partially offset
by:
|
|
•
|
A
$4 million decrease in revenue from Federal agencies and
other.
|
|
|
o
|
This
decrease was the result of an $8 million decrease in revenues from federal
agencies directly served due to decreased sales of 3.0 percent, and a
decrease in average rates of 4.4
percent.
|
|
|
o
|
This
item was partially offset by a $4 million increase in off-system sales
reflecting increased sales of 40.7 percent partially offset by a decrease
in average rates of 6.5 percent.
|
During 2007 there was also a $57
million revenue offset related to the Browns Ferry Unit 1 pre-commercial plant
operations. See Note 1 — Capitalized Revenue During
Pre-Commercial Plant Operations.
Significant items contributing to the
3.9 billion kilowatt-hour increase in electricity sales included a 3.8 billion
kilowatt-hour increase in sales to municipalities and cooperatives resulting
from increased sales to residential, commercial, and industrial
customers. The increase in residential power demand (which is more
weather sensitive) is primarily a result of an increase in combined degree days
of 258 days, or 4.9 percent, during 2007.
Other items contributing to the
increase include:
|
•
|
A
35 million kilowatt-hour increase in sales to Federal agencies and
other.
|
|
|
o
|
This
increase was attributable to an 89 million kilowatt-hour increase in
off-system sales mainly reflecting increased generation available for
sale.
|
|
|
o
|
This
item was partially offset by a 54 million kilowatt-hour decrease in sales
to federal agencies directly served primarily due to a decrease in demand
by one of TVA’s largest federal agencies directly served as a result of a
change in the nature and scope of its
load.
|
|
•
|
A 6
million kilowatt-hour increase in sales to industries directly served
largely attributable to customer
growth.
|
|
|
Operating Expenses. A table
of operating expenses for 2007 and 2006 follows:
|
TVA
Operating Expenses
For
the years ended September 30
|
||||||||||||
|
2007
|
2006
|
Percent
Change
|
||||||||||
|
As
Restated
|
As
Restated
|
|||||||||||
|
Operating
expenses
|
||||||||||||
|
Fuel
and purchased power
|
$ | 3,449 | $ | 3,342 | 3.2 | % | ||||||
|
Operating
and maintenance
|
2,332 | 2,328 | 0.2 | % | ||||||||
|
Depreciation,
amortization, and accretion
|
1,473 | 1,500 | (1.8 | %) | ||||||||
|
Tax
equivalents
|
451 | 376 | 19.9 | % | ||||||||
|
Loss
on asset impairment
|
21 | 14 | 50.0 | % | ||||||||
|
Total
operating expenses
|
$ | 7,726 | $ | 7,560 | 2.2 | % | ||||||
Significant drivers contributing to the
$166 million increase in total operating expenses included:
|
|
•
|
A
$75 million increase in Tax equivalent payments reflecting increased gross
revenues from the sale of power (excluding sales or deliveries to other
federal agencies and off-system sales with other utilities) during 2006 as
compared to 2005.
|
|
|
•
|
A
$107 million increase in Fuel and purchased power
expense.
|
|
|
o
|
This
increase was mainly due a $114 million increase in purchased power
expense.
|
|
–
|
The
increase in purchased power expense was primarily a result of a 16.4
percent increase in the volume of purchased power to accommodate decreased
hydroelectric generation of 9.2 percent and the extended outage of Unit 3
at TVA’s Paradise Fossil Plant during the third quarter of
2007.
|
|
–
|
The
increase in volume was partially offset by the
following:
|
|
▪
|
A
decrease in the average purchase price of 0.8 percent;
and
|
|
▪
|
An
FCA net deferral and amortization for purchased power expense of $54
million. In accordance with the FCA methodology, TVA has
deferred the amount of purchased power costs that were higher than the
amount included in power rates during 2007. This $54 million
deferred amount will be charged to customers in future FCA
adjustments.
|
|
|
o
|
The
increase in purchased power expense was partially offset by a $7 million
decrease in fuel expense.
|
|
–
|
The
decrease in fuel expense resulted primarily from an FCA net deferral and
amortization for fuel expense of $95 million. In accordance
with the FCA methodology, TVA has deferred the amount of fuel costs that
were higher than the amount included in power rates during
2007. This $95 million deferred amount will be charged to the
customers in future FCA
adjustments.
|
|
–
|
The
decrease was partially offset by the
following:
|
|
▪
|
Higher
aggregate fuel cost per kilowatt-hour net thermal generation of 2.7
percent; and
|
|
▪
|
Increased
generation of 0.6 percent, 14.9 percent, and 2.5 percent at the
coal-fired, combustion turbine, and nuclear plants, respectively, in part
because of the lower hydroelectric
generation.
|
|
|
•
|
A
$7 million increase in Loss on asset impairment from $14 million in 2006
to $21 million in 2007.
|
|
o
|
The
$21 million Loss on asset impairment in 2007 resulted
from:
|
|
–
|
A
$17 million write-down of a scrubber project at Colbert during 2007;
and
|
|
–
|
Write-downs
of $4 million related to other Construction in progress assets during
2007.
|
|
o
|
The
$14 million Loss on asset impairment in 2006 resulted
from:
|
|
–
|
Write-downs
of $12 million on 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; and
|
|
–
|
A
$2 million write-down on one of two buildings in TVA’s Knoxville Office
Complex based on TVA’s plans to sell or lease the East Tower of the
Knoxville Office Complex during
2006.
|
|
|
•
|
A
$4 million increase in Operating and maintenance
expense.
|
|
|
o
|
This
increase was mainly a result of:
|
|
–
|
Increased
outage and routine operating and maintenance costs at coal-fired plants of
$55 million due to:
|
|
•
|
An
increase in outage days of 78 days as a result of four more planned
outages during 2007,
|
|
•
|
Significant
repair work on Unit 3 at Paradise Fossil Plant,
and
|
|
•
|
Acquisition
of new combustion turbine units during
2007;
|
|
–
|
A
$17 million increase in expense primarily related to Watts Bar Unit 2
studies during 2007;
|
|
–
|
A
$10 million increase in severance expense during
2007;
|
|
–
|
A
$5 million increase in workers’ compensation expense primarily as a result
of a 0.05 percent lower discount rate utilized during 2007 and increased
costs to administer the program;
and
|
|
–
|
An
increase in operating and maintenance expenses at nuclear plants of $13
million primarily as a result of the restart of Browns Ferry Unit 1, which
returned to commercial operation on August 1,
2007.
|
|
|
o
|
These
items were partially offset by decreased pension financing costs of $91
million as a result of a 0.52 percent higher discount rate and a 0.50
percent higher than expected long-term rate of return on pension plan
assets.
|
The increases in Tax equivalent
payments, Fuel and purchased power expense, Loss on asset impairment, and
Operating and maintenance expense were partially offset by:
|
•
|
A
$27 million decrease in Depreciation, amortization, and accretion
expense.
|
|
|
o
|
This
decrease was mainly a result of a $41 million decrease in depreciation
expense primarily attributable to the depreciation rate reduction for
Browns Ferry Nuclear Plant reflecting the 20-year license extension
approved by the Nuclear Regulatory Commission (“NRC”) on May 4,
2006.
|
|
|
o
|
This
item was partially offset by a $14 million increase in accretion expense
reflecting the adoption of FIN No. 47, the updated incremental accretion
for SFAS No. 143, and an increase in ARO liability during
2007.
|
Other Income. The
$7 million decrease in other income was largely attributable to decreased
interest income from short-term investments and increased interest earnings on
the collateral deposit funds held by TVA.
Unrealized Gain/(Loss) on Derivative
Contracts, Net. Significant items contributing to the $56
million change in net unrealized gain/(loss) on derivative contracts
included:
|
•
|
A
$58 million smaller loss related to the mark-to-market valuation
adjustment of an embedded call option, from a $61 million loss during 2006
to a $3 million loss during 2007;
and
|
|
•
|
A
$9 million larger gain related to the mark-to-market valuation of swaption
contracts, from a $19 million gain during 2006 to a $28 million gain
during 2007.
|
These items were partially offset by an
$11 million smaller gain related to the mark-to-market valuation adjustment of
an interest rate swap contract, from a $27 million gain during 2006 to a $16
million gain during 2007.
Interest
Expense. Interest expense, outstanding debt, and interest
rates during 2007 and 2006 were as follows:
|
Interest
Expense
For
the years ended September 30
|
||||||||||||
|
2007
|
2006
|
Percent
Change
|
||||||||||
|
Interest
expense
|
||||||||||||
|
Interest
on debt and leaseback obligations
|
$ | 1,390 | $ | 1,406 | (1.1 | %) | ||||||
|
Amortization
of debt discount, issue, and reacquisition costs, net
|
19 | 21 | (9.5 | %) | ||||||||
|
Allowance
for funds used during construction and nuclear fuel
expenditures
|
(177 | ) | (163 | ) | 8.6 | % | ||||||
|
Net
interest expense
|
$ | 1,232 | $ | 1,264 | (2.5 | %) | ||||||
|
(percent)
|
||||||||||||
|
2007
|
2006
|
Percent
Change
|
||||||||||
|
Interest
rates (average)
|
||||||||||||
|
Long-term
|
6.02 | 6.17 | (2.4 | %) | ||||||||
|
Discount
notes
|
5.21 | 4.47 | 16.6 | % | ||||||||
|
Blended
|
5.94 | 6.02 | (1.3 | %) | ||||||||
Significant items contributing to the
$32 million decrease in net interest expense included:
|
•
|
A
decrease in the average long-term interest rate from 6.17 percent in 2006
to 6.02 percent in 2007;
|
|
•
|
A
decrease of $283 million in the average balance of long-term outstanding
debt in 2007; and
|
|
•
|
A
$14 million increase in AFUDC due to a 4.0 percent increase in the
construction work in progress base in
2007.
|
These items were partially offset
by:
|
•
|
An
increase in the average discount notes interest rate from 4.47 percent in
2006 to 5.21 percent in 2007; and
|
|
•
|
An
increase of $260 million in the average balance of discount notes
outstanding in 2007.
|
2006 Compared to 2005
Net income for 2006 was $113 million
compared with net income of $85 million for 2005. The $28 million
increase in net income was mainly attributable to:
|
•
|
A
$1,191 million increase in operating
revenues;
|
|
•
|
Lower
net interest expense of $48
million;
|
|
•
|
A
$19 million increase in other income;
and
|
|
•
|
Lower
other expense of $2 million.
|
These items were partially offset
by:
|
•
|
A
$1,105 million increase in operating
expenses;
|
|
•
|
A
$109 million cumulative expense charge in 2006 for adoption of a new
accounting standard related to conditional asset retirement obligations;
and
|
|
•
|
A
change of $18 million in net unrealized gain/(loss) on derivative
contracts.
|
Operating
Revenues. Operating revenues and electricity sales during 2006
and 2005 consisted of the following:
|
Operating
Revenues and Electricity Sales
For
the years ended September 30
|
||||||||||||||||||||||||
|
Operating
Revenues
|
Sales
of Electricity
|
|||||||||||||||||||||||
|
(millions
of dollars)
|
(millions
of kWh)
|
|||||||||||||||||||||||
|
2006
|
2005
|
Percent
Change
|
2006
|
2005
|
Percent
Change
|
|||||||||||||||||||
|
As
Restated
|
As
Restated
|
|||||||||||||||||||||||
|
Operating
revenues and sales of electricity
|
||||||||||||||||||||||||
|
Municipalities
and cooperatives
|
$ | 7,659 | $ | 6,539 | 17.1 | % | 138,624 | 136,640 | 1.5 | % | ||||||||||||||
|
Industries
directly served
|
1,065 | 961 | 10.8 | % | 30,987 | 30,872 | 0.4 | % | ||||||||||||||||
|
Federal
agencies and other
|
116 | 181 | (35.9 | %) | 2,040 | 3,986 | (48.8 | %) | ||||||||||||||||
|
Other
revenue
|
143 | 111 | 28.8 | % | – | – | – | |||||||||||||||||
|
Total
operating revenues and sales of electricity
|
$ | 8,983 | $ | 7,792 | 15.3 | % | 171,651 | 171,498 | 0.1 | % | ||||||||||||||
Significant items contributing to the
$1,191 million increase in operating revenues included:
|
•
|
A
$1,120 million increase in revenue from municipalities and cooperatives
reflecting increased sales of 1.5 percent and an increase in average rates
of 15.4 percent. Of this $1,120 million increase, $918 million
relates to the rate adjustments effective October 1, 2005, and April 1,
2006.
|
|
•
|
A
$104 million increase in revenue from industries directly served
attributable to an increase in sales of 0.4 percent and an increase in
average rates of 10.3 percent. Of this $104 million increase,
$41 million relates to the rate adjustments effective October 1, 2005, and
April 1, 2006.
|
|
•
|
A
$32 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 was
due to higher average rates related to a shift in product and customer mix and
higher rates for variable priced products.
These items were partially offset
by:
|
•
|
A
$65 million decrease in revenues from Federal agencies and
other.
|
|
|
o
|
This
decrease was due to an $82 million decrease in off-system 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.
|
|
|
o
|
This
item was partially offset by a $17 million increase in revenues from
federal agencies directly served due to increased sales of 4.9 percent and
an increase in average rates of 14.3 percent. Of this $17
million increase, $10 million relates to the rate adjustments effective
October 1, 2005, and April 1, 2006.
|
Significant items contributing to the
153 million kilowatt-hour increase in electricity sales included:
|
•
|
A
1,984 million kilowatt-hour increase in sales to municipalities and
cooperatives.
|
|
•
|
A
115 million kilowatt-hour increase in sales to industries directly served
as a result of increased demand by one of TVA’s largest directly served
industrial customers to accommodate higher production levels at its
facility, partially offset by decreased sales to other large directly
served industrial customers reflecting reduced demand due to more
unplanned outages and lower production levels at those facilities compared
to the prior year.
|
|
|
These items were partially offset
by:
|
•
|
A
1,946 million kilowatt-hour decrease in sales to Federal agencies and
other.
|
|
|
o
|
This
decrease was due to a 2,031 million kilowatt-hour decrease in off-system
sales mainly reflecting decreased generation available for
sale.
|
|
|
o
|
This
item was partially offset by an 85 million kilowatt-hour increase in sales
to federal agencies directly served primarily due to increased demand of
34.5 percent for other miscellaneous
products.
|
Operating Expenses. A table
of operating expenses for 2006 and 2005 follows:
|
TVA
Operating Expenses
For
the years ended September 30
|
||||||||||||
|
2006
|
2005
|
Percent
Change
|
||||||||||
|
Operating
expenses
|
As
Restated
|
|||||||||||
|
Fuel
and purchased power
|
$ | 3,342 | $ | 2,609 | 28.1 | % | ||||||
|
Operating
and maintenance
|
2,328 | 2,303 | 1.1 | % | ||||||||
|
Depreciation,
amortization, and accretion
|
1,500 | 1,154 | 30.0 | % | ||||||||
|
Tax
equivalents
|
376 | 365 | 3.0 | % | ||||||||
|
Loss
on asset impairment
|
14 | 24 | (41.7 | %) | ||||||||
|
Total
operating expenses
|
$ | 7,560 | $ | 6,455 | 17.1 | % | ||||||
Significant drivers contributing to the
$1,105 million increase in total operating expenses included:
|
|
•
|
A
$733 million increase in Fuel and purchased power
expense.
|
|
|
o
|
This
increase was a result of a $378 million increase in fuel expense and a
$355 million increase in purchased power
expense.
|
|
|
–
|
The
increased fuel costs were largely 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.
|
– The
increased purchased power expense was mainly a result of:
|
▪
|
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 in
2005.
|
|
•
|
A
$346 million increase in Depreciation, amortization, and accretion
expense.
|
|
|
o
|
This
increase was primarily a result of:
|
|
–
|
Increased
amortization expense of $388 million largely as a result of the
amortization of the deferred cost of nuclear generating units at
Bellefonte Nuclear Plant; and
|
|
–
|
A
$1 million increase in accretion expense mainly reflecting an increase in
ARO liability during 2006.
|
|
|
o
|
These
items were partially offset by a $43 million decrease in depreciation
expense primarily attributable to the depreciation rate reduction for
Browns Ferry Nuclear Plant reflecting the 20-year license extensions
approved by the NRC on May 4, 2006.
|
|
|
•
|
A
$25 million increase in Operating and maintenance
expense.
|
|
|
o
|
This
increase was primarily due to:
|
|
–
|
Increased
routine operating and maintenance costs at nuclear plants of $21 million
as a result of increased labor costs, more forced outages, and the timing
of contracts and billings during 2006;
and
|
|
–
|
Increased
benefits expense of $19 million attributable to increased pension related
retirement costs and increased health care and dental costs during
2006.
|
|
|
o
|
These
items were partially offset by decreased workers’ compensation expense of
$29 million largely due to a 0.30 percent higher discount rate utilized in
2006.
|
|
•
|
An
$11 million increase in Tax equivalent payments due to increased gross
revenues from the sale of power of 3.1 percent during 2005 as compared to
2004.
|
The increases in Fuel and purchased
power expense, Depreciation, amortization, and accretion expense, Operating and
maintenance expense, and Tax equivalent payments were partially offset
by:
|
•
|
A
$10 million decrease in Loss on asset impairment from $24 million in 2005
to $14 million in 2006.
|
|
|
o
|
The
$14 million Loss on asset impairment during 2006 resulted
from:
|
|
–
|
Write-downs
of $12 million on 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; and
|
|
–
|
A
$2 million write-down on one of two buildings in TVA’s Knoxville Office
Complex based on TVA’s plans to sell or lease the East Tower of the
Complex.
|
|
o
|
The $24 million Loss on asset
impairment during 2005 resulted
from:
|
|
–
|
Write-downs
of $16 million on 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; and
|
|
–
|
An
$8 million write-down on one of two buildings in TVA’s Knoxville Office
Complex based on TVA’s plans to sell or lease the East Tower of the
Complex.
|
Other Income. The
$19 million increase in other income was largely attributable to increased
interest earnings on the collateral deposit funds held by TVA, increased
interest income from short-term investments, and an increase in external
business activities not directly related to TVA’s power program.
Other Expense. The
$2 million decrease in other expense was due to the loss of $2 million on the
sale of distributor customer loan program receivables in 2005 not present in
2006.
Unrealized Gain/(Loss) on Derivative
Contracts, Net. The significant item contributing to the $18
million change in net unrealized gain/(loss) on derivative contracts was a $177
million net change related to the mark-to-market valuation adjustment of an
embedded call option, from a $116 million gain during 2005 to a $61 million loss
during 2006.
This item was partially offset
by:
|
•
|
A
$108 million net change related to the mark-to-market valuation adjustment
of swaption contracts, from an $89 million loss during 2005 to a $19
million gain during 2006;
|
|
•
|
A
$45 million net change related to the mark-to-market valuation adjustment
of an interest rate swap contract, from an $18 million loss during 2005 to
a $27 million gain during 2006; 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:
|
Interest
Expense
For
the years ended September 30
|
||||||||||||
|
2006
|
2005
|
Percent
Change
|
||||||||||
|
Interest
expense
|
||||||||||||
|
Interest
on debt and leaseback obligations
|
$ | 1,406 | $ | 1,407 | (0.1 | %) | ||||||
|
Amortization
of debt discount, issue, and reacquisition costs, net
|
21 | 21 | 0.0 | % | ||||||||
|
Allowance
for funds used during construction and nuclear fuel
expenditures
|
(163 | ) | (116 | ) | 40.5 | % | ||||||
|
Net
interest expense
|
$ | 1,264 | $ | 1,312 | (3.7 | %) | ||||||
|
(percent)
|
||||||||||||
|
2006
|
2005
|
Percent
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
$48 million decrease in net interest expense included:
|
•
|
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 31.4 percent increase in the
construction work in progress base 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.
TVA has entered into one transaction
that could 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 Financial Accounting Standards Board (“FASB”)
Interpretation No. 46, “Consolidation of Variable Interest
Entities,” as amended by FASB Interpretation No. 46R (as amended, “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
Partnership’s balance sheet, results of operations, and cash flows for the year
ended September 30, 2007. Power purchases for 2007 under the
agreement amounted to $122 million, and the remaining financial commitment under
this agreement is $4.4 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 Note 8.
In September 2007, the TVA Board
approved the establishment of an asset retirement trust (“ART”) to more
effectively segregate, manage, and invest funds to help meet future asset
retirement obligations. The purpose of the trust is to hold funds for
the contemplated future retirement of TVA’s long-lived assets and to comply with
any order relating to the retirement of long-lived assets. TVA made a
$40 million initial contribution to the trust on September 28,
2007. While similar in concept, the ART is separate from TVA’s
nuclear decommissioning trust fund. TVA is not legally obligated to
establish or maintain a trust for non-nuclear related obligations nor obligated
to make any future contributions, regardless of funded status. Future
contributions may be made at the discretion of the TVA Board.
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 regard to the level of
judgment involved and its potential impact on TVA’s financial
results. Estimates are deemed critical either when a different
estimate could have reasonably been used, or where changes in the estimate are
reasonably likely to occur from period to period, and such use or change would
materially impact TVA’s financial condition, changes in financial position, or
results of operations. TVA’s critical accounting policies are also
discussed in Note 1.
Regulatory Accounting
TVA’s power rates are not subject to
regulation through a public service commission or other similar
entity. TVA’s Board is authorized by the TVA Act to set rates for
power sold to its customers. This rate-setting authority meets the
“self-regulated” provisions of SFAS No. 71, “Accounting for the Effects of
Certain Types of Regulation,” and TVA meets the remaining criteria of
SFAS No. 71 because (1) TVA’s regulated rates are designed to recover its costs
of providing electricity and (2) in view of demand for electricity and the level
of competition it is reasonable to assume that the rates, set at levels that
will recover TVA’s costs, can be charged and collected. Accordingly,
TVA records certain assets and liabilities that result from the regulated
ratemaking process that would not be recorded under GAAP for non-regulated
entities. Regulatory assets generally represent incurred costs that
have been deferred because such costs are probable of future recovery in
customer rates. Regulatory liabilities generally represent
obligations to make refunds to customers for previous collections for costs that
are not likely to be incurred. Management assesses whether the
regulatory assets are probable of future recovery by considering factors such as
applicable regulatory changes, potential legislation, and changes in
technology. Based on these assessments, 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 would be required to write-off these costs
under the provisions of SFAS No. 101, “Regulated Enterprises–Accounting for
the Discontinuation of Application of FASB Statement No.
71.” Any asset write-offs would be required to be recognized
in earnings in the period in which future recoveries cease to be
probable. See Note 6.
Long-Lived Assets
TVA capitalizes long-lived assets such
as property, plant, and equipment at historical cost, which includes direct and
indirect costs and AFUDC. TVA recovers the costs of these long-lived
assets through depreciation of the physical assets as they are consumed in the
process of providing products or services. Depreciation is generally
computed on a straight-line basis over the estimated productive lives of the
various classes of assets. When TVA retires its regulated long-lived
assets, it charges the original asset cost plus removal costs, less salvage
value, to accumulated depreciation in accordance with utility industry
practice.
Long-Lived Asset
Impairments
TVA evaluates the carrying value of
long-lived assets when circumstances indicate the carrying value of those assets
may not be recoverable. Under the provisions of SFAS No. 144, “Accounting for the Impairment or
Disposal of Long-Lived Assets,” an asset impairment exists for a
long-lived asset to be held and used when the carrying value exceeds the sum of
estimates of the undiscounted cash flows expected to result from the use and
eventual disposition of the asset. If the asset is impaired, the
asset’s carrying value is adjusted downward to its estimated fair value with a
corresponding impairment loss recognized in earnings.
Revenue Recognition
Revenues from power sales are recorded
as power is delivered to customers. TVA accrues estimated unbilled
revenues for power sales provided to customers for the period of time from the
end of the billing cycle to the end of the month. The methodology for
estimating unbilled revenue from electricity sales uses meter readings for each
customer for the current billing period. See Note 1 — Revenues.
Asset Retirement
Obligations
In accordance with the provisions of
SFAS No. 143, “Accounting for
Asset Retirement Obligations,” and FIN No. 47, “Accounting for Conditional Asset
Retirement Obligations — an Interpretation of FASB Statement No. 143,”
TVA recognizes legal obligations associated with the future retirement of
certain tangible long-lived assets. These obligations relate to
fossil-fired generating plants, nuclear generating plants, hydroelectric
generating plants/dams, transmission structures, and other property-related
assets. These other property-related assets include, but are not
limited to, easements, leases, and coal rights. Activities involved
with retiring these assets could include decontamination and demolition of
structures, removal and disposal of wastes, and site
reclamation. Revisions to the amount and timing of certain cash flow
estimates of asset retirement obligations may be made based on engineering
studies. For nuclear assets, the studies are performed annually in
accordance with NRC requirements. For non-nuclear assets, revisions
are made annually in accordance with guidance provided by SFAS No. 143 and FIN
No. 47. See Note 5.
Nuclear Decommissioning
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. The difference in the discount rates used to calculate the
present value of decommissioning costs under SFAS No. 143 versus the NRC has the
greatest impact. Accordingly, the two sets of procedures produce
different estimates for the costs of decommissioning. At September
30, 2007, the present value of the estimated future nuclear decommissioning cost
under SFAS No. 143 was $1.6 billion and was included in Asset retirement
obligations, and the unamortized regulatory asset of $419 million was included
in Other regulatory assets. Under the NRC’s regulations, the present
value of the estimated future nuclear decommissioning cost was $699 million at
September 30, 2007. This decommissioning cost estimate is based on
NRC’s requirements for removing a plant from service, releasing the property for
unrestricted use, and terminating the operating license. The actual
decommissioning costs may vary from the derived estimates because of changes in
current assumptions, such as the assumed dates of decommissioning, changes in
regulatory requirements, changes in technology, and changes in the cost of
labor, materials, and equipment.
TVA maintains a nuclear decommissioning
trust to provide funding for the ultimate decommissioning of its nuclear power
plants. The trust’s funds are invested in securities generally
designed to achieve a return in line with overall equity market
performance. The assets of the 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,
2007, is greater than the present value of the estimated future nuclear
decommissioning costs under the NRC methodology but is less than the present
value of the estimated future nuclear decommissioning costs under SFAS No.
143.
The
following key assumptions can have a significant effect on estimates related to
the nuclear decommissioning costs:
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•
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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 plant’s retirement must be estimated. At a multiple unit
site, the expiration of the unit with the latest to expire operating
license is typically used for this purpose, or an assumption could be made
that the plant will be relicensed and operate for some time beyond the
original license term. Second, an assumption must be made
whether decommissioning will begin immediately upon plant retirement, or
whether the plant will be held in SAFSTOR status — a status authorized by
applicable regulations which allows for a nuclear facility to be
maintained and monitored in a condition that allows the radioactivity to
decay, after which the facility is decommissioned and
dismantled. While the impact of these assumptions cannot be
determined with precision, assuming either license extension or use of
SAFSTOR status can significantly decrease the present value of these
obligations.
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•
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Technology
and Regulation – There is limited experience with actual decommissioning
of large nuclear facilities. Changes in technology and
experience as well as changes in regulations regarding nuclear
decommissioning could cause cost estimates to change
significantly. The impact of these potential changes is not
presently determinable. TVA’s cost studies assume current
technology and regulations.
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•
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Discount
Rate – TVA uses a blended rate of 5.32 percent to calculate the present
value of the weighted estimated cash flows required to satisfy TVA’s
decommissioning obligation.
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•
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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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•
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Cost
Escalation Factors – TVA’s decommissioning estimates include an assumption
that decommissioning costs will escalate over present cost levels by four
percent annually.
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Pension and Other Postretirement
Benefits
TVA sponsors a defined benefit pension
plan with two structures which cover substantially all employees. The
TVA Retirement System (“TVARS”), a separate legal entity governed by its own
board of directors, administers TVA-sponsored retirement
plans. Additionally, TVA provides postretirement health care benefits
for substantially all employees who reach retirement age while still working for
TVA. TVA’s costs of providing these benefits are impacted by numerous
factors including the provisions of the plans, changing employee demographics,
and various actuarial calculations, assumptions, and accounting
mechanisms. The most significant of these factors are discussed
below.
Expected Return on Plan
Assets. The expected return on pension plan assets used to
develop net pension cost was 8.75 percent, 8.25 percent, and 8.25 percent during
2007, 2006, and 2005, respectively, and is determined at the beginning of the
period. Changes in the rate were generally due to higher expected
future returns based on studies performed by TVA’s external investment
advisors. A higher expected rate of return decreases net periodic
pension cost which in turn increases profitability. TVA plans to
continue to utilize an expected rate of return of 8.75 percent for
2008. The 2008 expected rate of return reflects a change in the
allocation policy of TVARS assets. The change in the allocation
policy of TVARS assets was based on a recommendation by TVARS’ investment
consultant. The changes in the expected return on plan assets
discussed above do not affect TVA’s postretirement benefits plan because TVA
does not separately set aside assets to fund such benefits. TVA funds
its postretirement plan benefits on an as-paid basis.
Discount Rate. In the case of
selecting an assumed discount rate, TVA reviews market yields on high-quality
corporate debt and long-term obligations of the U.S. Treasury and endeavors to
match, through the use of a proprietary bond portfolio, instrument maturities
with the maturities of its pension obligations in accordance with the prevailing
accounting standards. The discount rate used to determine pension
expense was 5.90 percent, 5.38 percent, and 5.81 percent during 2007, 2006, and
2005, respectively. The discount rate is determined at the beginning
of the period. TVA plans to use a discount rate of 6.25 percent in
the determination of 2008 net periodic pension cost as well as to value plan
obligations at the end of 2007. Changes in the discount rate were due
to increased long-term interest rates. The discount rate is somewhat
volatile because it is determined based upon the prevailing rate as of the
measurement date. Similar adjustments were made to the discount rate
used to determine postretirement benefit cost. The discount rate used
to determine the postretirement benefits cost is the same rate used to determine
pension benefits cost due to a similar expected duration of the postretirement
and pension benefit obligations. A higher discount rate decreases the
plan obligations and correspondingly decreases the net periodic pension and
postretirement benefits costs for those plans where actuarial losses are being
amortized. On the other hand, a lower discount rate increases net
periodic pension and postretirement benefits costs and thus reduces
profitability.
The expected rate of return on pension
plan assets and the discount rate as well as the amortization of actuarial gains
and losses were determined in accordance with consistent methodologies, as
described in Note 14.
Mortality. Mortality
assumptions are based on the results obtained from an actual company experience
study performed during the most recent six years for retirees as well as other
plan participants. The study supports the use of mortality rates as
depicted within the 1983 Group Annuity Mortality tables. For the
pension plan, the actuarial loss due to mortality experience in 2007, 2006, and
2005 was $20 million, $10 million, and $30 million,
respectively. Such losses represent less than one half of one percent
of the plan’s projected benefit obligation at the respective measurement
dates.
Sensitivity of Costs to Changes in
Assumptions. The following chart reflects the sensitivity of
pension costs to changes in certain actuarial assumptions:
Sensitivity
of Pension Costs to Changes in Assumptions
|
Actuarial
Assumption
|
Change
in Assumption
|
Impact
on 2008 Pension Cost
|
Impact
on 2007 Projected Benefit Obligation
|
|||||||||
|
(Increase
in millions)
|
||||||||||||
|
Discount
rate
|
(0.25%)
|
$ | 17 | $ | 236 | |||||||
|
Rate
of return on plan assets
|
(0.25%)
|
$ | 17 |
NA
|
||||||||
|
Rate
of compensation
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0.25%
|
$ | 4 | $ | 22 | |||||||
Each fluctuation above assumes that the
other components of the calculation are held constant and excludes any impact
for unamortized actuarial gains or losses.
Health Care Cost Trends. 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
2007 and 2006 accumulated postretirement benefit obligations. The
assumed health care trend rate used for 2007 was 8.0 percent which represents a
one-half percent reduction from the 8.5 percent trend rate used during 2006.
Prior to 2006, TVA used a health care cost trend rate of 9.0 percent during each
of the four preceding years. The 2007 health care cost trend rate of 8.0 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.
The following chart reflects the
sensitivity of postretirement benefit costs to changes in certain actuarial
assumptions:
Sensitivity
of Postretirement Benefit Costs to Changes in Assumptions
|
Actuarial
Assumption
|
Change
in Assumption
|
Impact
on 2008 Postretirement Benefit Cost
|
Impact
on 2007 Projected Postretirement Benefit Obligation
|
|||||||||
|
(Increase
in millions)
|
||||||||||||
|
Health
care cost trend
|
0.25 | % | $ | 1 | $ | 15 | ||||||
|
Discount
rate
|
(0.25 | %) | $ | 1 | $ | 14 | ||||||
Each fluctuation above assumes that the
other components of the calculation are held constant and excludes any impact
for unamortized actuarial gains or losses.
Accounting
Mechanisms. In accordance with current accounting
methodologies, TVA utilizes a number of accounting mechanisms that reduce the
volatility of reported pension costs. Differences between actuarial
assumptions and actual plan results are deferred and are amortized into cost
only when the accumulated differences exceed 10 percent of the greater of the
projected benefit obligation or the market-related value of plan
assets. In this case, 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 10 percent corridor in accordance with current
accounting methodologies.
Due to negative pension plan asset
returns in 2002 and 2001, in conjunction with other related market conditions,
TVA’s accumulated benefit obligation at September 30, 2007 and 2006 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 additional minimum liability and the subsequent changes thereto
were recorded in 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 because 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. Prior to adopting
SFAS No. 158, the additional minimum liability was reduced $653 million through
direct corresponding entries to the established regulatory
asset. Subsequent to TVA’s adoption of SFAS No. 158, the regulatory
asset and pension benefit obligation was increased $323 million to recognize the
total unfunded pension obligation of $621 million, and $239 million of
unamortized prior service cost carried as an intangible asset was reclassified
to Accumulated other comprehensive income as required by the accounting
standard.
Medicare
Provisions. There have been several recent developments
related to retiree health care benefits, including cost sharing and legislation,
such as Medicare Part D of the Medicare Prescription Drug, Improvement and
Modernization Act of 2003. Under the Medicare Prescription Drug,
Improvement and Modernization Act of 2003, employers may receive retiree drug
subsidies for Medicare-eligible retirees who enroll in the employer’s retiree
prescription drug plan, provided that the plan is determined to be “actuarially
equivalent” to standard coverage provided under Medicare Part D. TVA
determined that its retiree prescription drug coverage did not qualify for
retiree drug subsidies. As a result, through its prescription benefit
manager, TVA maintained for 2007 an employer-sponsored prescription drug plan
(“PDP”). By providing an employer-sponsored PDP, TVA’s prescription
benefit manager receives subsidies from Medicare which are passed through to
Medicare-eligible retirees in the form of lower premiums. See Note 14
for further description.
At its September 27, 2007, meeting, the
TVA Board approved the following changes in ratemaking, which result in changes
in accounting for these types of transactions.
Allowance for Funds Used During
Construction. Capitalization of interest and other financing
costs has been a generally accepted practice in the utility industry. The
concept of permitting the capitalization of interest on major plant construction
projects results from a regulatory philosophy that today’s customers should not
pay for the costs of financing construction that will benefit only future
customers. As a result, major plant construction costs are not included in rates
until the plant is placed in service. To provide a return on investment during a
period of construction, utilities typically recover the cost of construction
funds from future users by capitalizing a portion of current interest costs
associated with funds invested in the construction projects. This
capitalized interest is referred to as AFUDC.
In accordance with the accounting
policy that was in effect on September 30, 2007, TVA capitalized a portion of
current interest costs associated with funds invested in most construction
projects and most nuclear fuel inventories. Beginning in 2008, TVA
will continue to capitalize a portion of current interest costs associated with
funds invested in most nuclear fuel inventories, but interest on funds invested
in construction projects will be capitalized only if (1) the expected total
cost of a project is $1 billion or more and (2) the estimated construction
period is at least three years. Capitalized interest will continue to
be a component of the asset cost and will be recovered in future periods through
depreciation expense. In addition, AFUDC will continue to be a
reduction to interest expense as costs are incurred. The interest
costs associated with funds invested in construction projects that do not
satisfy the $1 billion and three-year criteria will not be capitalized as AFUDC,
will remain in the Statement of Income, and will be recovered in current year
rates as a component of interest expense. TVA recorded a total of
$177 million in AFUDC in 2007, of which $165 million was related to construction
work in progress. TVA anticipates that it will record lower AFUDC
related to construction projects in future years, particularly in 2008, as a
result of the new policy.
Call
Monetizations. 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 an option 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. Selling
such an option creates a liability for TVA until such time as TVA buys back the
option or until the option matures.
These call monetization transactions
result in long-term liabilities which are marked to market each
quarter. In accordance with the accounting policy that was in effect
on September 30, 2007, the changes in the value of these liabilities were
reported as unrealized gains or losses through TVA’s income statement in
accordance with SFAS No. 133. The volatility of the valuations resulted in the
recognition of sizable amounts of non-cash expense or income, which affects net
income.
Beginning in 2008, the TVA Board
approved the utilization of regulatory accounting treatment for swaps and
swaptions related to call monetization transactions in order to better match the
income statement recognition of gain and loss with the economic reality of when
these transactions actually settle. This treatment removes the
non-cash impacts to TVA’s earnings that result from marking the value of these
instruments to market each quarter. The value of the swaps and swaptions will
still be recorded on TVA’s balance sheet, and any interest expense impacts will
continue to be reflected in TVA’s income statement. If this new
accounting treatment were effective during 2007, TVA’s net income for 2007 would
have been reduced by less than $50 million.
Accounting Changes and Error
Corrections. In May 2005, 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 SFAS 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. This statement became effective for TVA beginning in
2007 and did not have an impact on TVA’s financial statements for
2007.
Accounting for Planned Major
Maintenance Activities. On September 8, 2006, FASB released
FASB Staff Position (“FSP”) AUG AIR-1, “Accounting for Planned Major
Maintenance Activities.” The FSP addresses the accounting for
planned major maintenance activities and amends certain provisions in the
American Institute of Certified Public Accountants Industry Audit Guide, “Audits of Airline” and
Accounting Principles Board Opinion No. 28, “Interim Financial Reporting.” The
guidance in this FSP states that entities should adopt an accounting method that
recognizes overhaul expenses in the appropriate period. The following accounting
methods are most often employed/permitted: direct expensing method; built-in
overhaul method; or deferral method. The guidance in this FSP is applicable to
entities in all industries and must be applied to the first fiscal year
beginning after December 15, 2006. TVA will adopt this guidance for
2008. Because TVA’s policy is to expense maintenance costs as
incurred (direct expensing method), the adoption of this FSP is not expected to
have a material impact on TVA’s results of operations or financial
position.
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 that currently require fair value measurement. 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. SFAS No. 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 is evaluating the
requirements of this statement and has not yet determined the impact of its
implementation, which may or may not be material to TVA’s results of operations
or financial position.
Fair Value
Option. In February 2007, FASB issued SFAS No. 159, “The Fair Value Option for Financial
Assets and Financial Liabilities — Including an amendment of FASB Statement No.
115.” This standard permits an entity to choose to measure many financial
instruments and certain other items at fair value. The fair value
option established by SFAS No.159 permits all entities to choose to measure
eligible items at fair value at specified election dates. A business
entity will report unrealized gains and losses on items for which the fair value
option has been elected in earnings at each subsequent reporting
date. Most of the provisions in this statement are
elective. The provisions of SFAS No. 159 are effective as of the
beginning of an entity’s first fiscal year that begins after November 15,
2007. Early adoption is permitted as of the beginning of the previous
fiscal year provided that the entity makes that choice in the first 120 days of
that fiscal year and also elects to apply the provisions of SFAS No. 157, “Fair Value Measurements.” At
this time, TVA is evaluating the requirements of this statement and has not yet
determined the potential impact of its implementation, which may or may not be
material to TVA’s results of operations or financial position.
Offsetting
Amounts. On April 30, 2007, FASB issued FASB Staff Position
(“FSP”) FIN No. 39-1,
“Amendment of FASB Interpretation No. 39,” which addresses certain
modifications to FASB Interpretation No. 39, “Offsetting of Amounts Related to
Certain Contracts.” This FSP replaces the terms conditional contracts and
exchange contracts with the term derivative instruments as defined in SFAS No.
133, “Accounting for
Derivative Instruments and Hedging Activities.” The FSP also permits a
reporting entity to offset fair value amounts recognized for the right to
reclaim cash collateral (a receivable) or the obligation to return cash
collateral (a payable) against fair value amounts recognized for derivative
instruments executed with the same counterparty under the same master netting
arrangement. The guidance in the FSP is effective for fiscal years
beginning after November 15, 2007, with early application
permitted. At this time, TVA is evaluating the requirements of this
guidance and has not yet determined the potential impact of its implementation,
which may or may not be material to TVA’s financial position.
Employers’ Accounting for
Defined Accounting for Defined Benefit Pension and Other Postretirement
Plans. On September 30, 2007, TVA adopted 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 requires 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 requires an employer
to: recognize in its statement of financial position an asset for a
plan’s overfunded status or a liability for a plan’s underfunded status; measure
a plan’s assets and its obligations that determine its funded status as of the
end of the employer’s fiscal year (with limited exceptions); and recognize
changes in the funded status of a defined benefit postretirement plan in the
year in which the changes occur.
Upon adoption of SFAS No. 158, TVA
recorded a net benefit liability equal to the underfunded status of certain
pension and other postretirement benefit plans at September 30, 2007 in the
amounts of $664 million and $464 million, respectively. On September
30, 2007, the unrecognized prior service costs and unrecognized gains and
losses were recognized as components of accumulated other comprehensive
income which were then reclassified to and recorded as components
of a regulatory asset related to TVA's unfunded benefit
plans. TVA did not have any unrecognized transition obligation
losses. At September 30, 2007, TVA's unfunded benefit plans'
regulatory asset included unamortized prior service costs
and unamortized net actuarial losses of approximately $830 million and
$143 million, respectively, related to pensions and other postretirement
benefits.
Rate-regulated entities may recognize
regulatory assets or liabilities as a result of timing differences between the
recognition of costs, as recorded with SFAS No. 87 and SFAS No.106, and
costs recovered through the ratemaking process. As a result of the
adoption of SFAS No. 158, TVA increased the existing unfunded benefit
plans' regulatory asset by approximately $721 million related to the
defined benefit pension and postretirement plans for amounts that
would otherwise be charged to accumulated other comprehensive income under SFAS
No. 158. See Note 14.
President’s
Budget
On February 5, 2007, the Office of
Management and Budget (“OMB”) transmitted the President’s proposed 2008 federal
budget to Congress. In the portions specifically relating to TVA, the proposed
budget recommends:
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•
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Expanding
the types of financial arrangements that count toward TVA’s
$30 billion debt ceiling;
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•
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Requiring
TVA to register its debt securities with the Securities and Exchange
Commission; and
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•
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Allowing
Congress to establish the amount of TVA’s Office of Inspector General’s
budget and directing TVA to fund the amount with power revenues beginning
in 2008. Funding for TVA’s Office of the Inspector General is currently
established by TVA.
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The first recommendation has been
included in a draft bill prepared by OMB, but it has not been introduced in
Congress. The other recommendations have not been introduced in any
legislation.
Proposed
Legislation
On March 13, 2007, Senators Jim Bunning
and Mitch McConnell, from Kentucky, introduced the Access to Competitive Power
Act of 2007 in the Senate. Under this bill, TVA and federal power
marketing agencies would be subject to greater FERC jurisdiction with respect to
transmission, including rates, terms, and conditions of service. With
regard to TVA, the bill would generally provide, among other things,
that:
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(1)
|
The
anti-cherrypicking provision would not apply with respect to any
distributor which provided a termination notice to TVA before December 31,
2006, regardless of whether the notice was later withdrawn or
rescinded;
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(2)
|
Distributors
that have given termination notices to TVA on or before December 31, 2006,
would have express authority under federal law to receive partial
requirements from TVA and elect, not later than 180 days after enactment,
to rescind the termination notice “without the imposition of a
reintegration fee or any similar
fee;
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(3)
|
Distributors
that have not given termination notices to TVA on or before December 31,
2006, would have express authority under federal law to receive partial
requirements from TVA within a ratable limit, which cumulatively stays
within a three percent compounded annual growth rate on the TVA system;
and
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(4)
|
Any
distributor that terminates its power supply contract with TVA in whole or
in part would have the federal statutory right to directly receive its
share of SEPA power that is otherwise being delivered to TVA for the
benefit of all distributors.
|
On August
4, 2007, the House of Representatives passed H.R. 3221, which, among other
things, calls for annual reductions in greenhouse gas emissions produced by the
federal government or resulting from federal activities, with a goal of having
zero emissions by fiscal year 2050. Each agency (including TVA) would
be required to report greenhouse gas emissions resulting from commercial air
travel of federal employees or contractors, or electricity used by the agency or
its contractors. Because the bill does not exclude power plants, TVA
would most likely have to report any greenhouse gas emissions in the generation
of electricity resulting from TVA’s power production activities, as well as any
greenhouse gas emissions produced by non-federal entities from which TVA buys
power.
No later
than 18 months after enactment, the EPA would be required
to promulgate annual reduction targets for the quantity of greenhouse
gas emissions, expressed as CO2
equivalents, of agencies, taken collectively, for each of fiscal years 2010
through 2050. The President may exempt an agency from complying with the
emissions target (if based on a Presidential determination that the exemption is
in the paramount interest of the United States), but only for one year at a
time.
The Senate passed a different energy
bill that did not include a greenhouse gas reduction provision applicable to
federal agencies. For an energy bill to become law, the U.S. House of
Representatives and U.S. Senate will have to reach mutual agreement on a
bill. A conference committee would decide on the provisions of a
joint energy bill. It is unclear at this time whether a provision
addressing the greenhouse gas emissions of federal agencies would be included in
any energy bill, whether the two current versions are conferenced, or in any
subsequent energy legislation which might be introduced and
considered.
If
enacted in its current form, the House bill would adversely affect TVA by
forcing it to change or curtail some power generation operations, and/or by
requiring the installation of mechanisms for
compliance. Additionally, because the bill applies to TVA but not to
power generators outside the federal government, TVA would be subject to
emission reduction requirements and expenses which other utilities would not
have to bear. The bill also provides a right for any “aggrieved
person” to bring suit against TVA or any agency that has not met its emission
reduction requirement for any particular year.
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 significant impact on TVA’s
activities could become law with little or no advance notice. As a
federal entity, the very nature of TVA can be changed by
legislation. For a discussion of the potential impact of legislation
and regulation on TVA, see Item 1A, Risk Factors.
TVA’s power generation activities, like
those across the utility industry and in other industrial sectors, are subject
to federal, state, and local environmental statutes and
regulations. Major areas of regulation affecting TVA’s activities
include air quality control, water quality control, and management and disposal
of solid and hazardous wastes.
TVA has incurred, and expects to
continue to incur, substantial capital and operating and maintenance costs to
comply with evolving environmental requirements primarily associated with the
operation of TVA’s 59 coal-fired generating units. While 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 that apply to fossil-fuel units are becoming more
stringent, and additional regulatory programs affecting fossil-fuel units were
promulgated in 2005. These new regulatory programs include the Clean
Air Interstate Rule (“CAIR”) and the Clean Air Mercury Rule
(“CAMR”). CAIR requires significant additional utility reductions of
emissions of sulfur dioxide (“SO2”) and
nitrogen oxides (“NOx”) in the
eastern half of the United States (including all of TVA’s operating area), and
CAMR establishes caps for overall mercury emissions in two phases with the first
phase becoming effective in 2010 and the second in 2018. TVA had
previously estimated its total capital cost for reducing emissions from its
power plants from 1977 through 2010 would reach $5.8 billion, $4.8 billion of
which had already been spent as of September 30, 2007. TVA estimates
that compliance with CAIR and CAMR could lead to additional costs of $3.0
billion to $3.6 billion in the decade beginning in 2011. 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. These costs cannot
reasonably be predicted at this time.
In addition, an existing federal water
regulation covering cooling water intake structures and temperatures may also
become more stringent. In January 2007, the United States Court of
Appeals for the Second Circuit Court (“Second Circuit”) remanded EPA’s rule on
this subject. In response, EPA has suspended the rule, and several
parties are seeking United States Supreme Court review of the Second Circuit
decision. If the Second Circuit’s decision becomes law after all
appeal processes and the issuance of a new rule, compliance is expected to be
more costly for the power industry. TVA is unable at this time to estimate these
costs.
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 as programs evolve 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
2007 and 2006 were approximately $239 million and $182 million,
respectively. These figures include expenditures in 2007 of $7
million to continue to reduce NOx emissions
through the installation of selective catalytic reduction (“SCR”) and selective
non-catalytic reduction (“SNCR”) systems and $207 million for the installation
of flue gas desulfurization systems (“scrubbers”) to continue to reduce SO2 emissions,
each of which is explained in more detail below. The aforementioned
estimate of $5.8 billion does not include additional capital costs of $3.0
billion to $3.6 billion that TVA expects to incur over the decade beginning in
2011 to comply with CAIR and CAMR. Increasingly stringent regulation
of some or all of these substances, as well as mercury and possibly CO2, will
continue to result in significant capital and operating costs for TVA’s
coal-fired generating units.
Sulfur
Dioxide. Coal-fired utilities have historically emitted large
amounts of SO2 compared
to today’s emissions. Utility SO2 emissions
are currently regulated under the Federal Acid Rain Program and state programs
designed to meet the National Ambient Air Quality Standards (“NAAQS”) for
SO2
and fine particulate matter. Looking forward, additional regulation of SO2 emissions
will result from implementation of the Regional Haze Program and
CAIR. In May 2005, EPA finalized CAIR to reduce the interstate
transport of fine particulate matter and ozone by requiring additional large
reductions in utility emissions of NOX and
SO2
from 28 eastern states. All seven states in TVA’s service area are
submitting plans to EPA to implement CAIR through 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 Atmospheric Fluidized Bed Combustion
(“AFBC”) technology, and installing scrubbers on seven of its larger
units. TVA began construction in 2005 on its eighth scrubber at its
Bull Run Fossil Plant and in 2006 began construction 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 at several additional units in the next few
years. 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 any future tightening of applicable
requirements.
Nitrogen Oxides. Utility
NOx
emissions continue to be regulated under state programs to achieve and maintain
EPA’s NAAQS for ozone, the Federal Acid Rain Program, the Regional Haze Program,
and CAIR. 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 59 coal-fired units and installing SCRs
on 21 of the largest units. (The AFBC unit at Shawnee Fossil Plant is inherently
low NOx
emitting.)
In 2005, TVA installed SNCR systems on
two units to demonstrate long-term technology capability, and continued to
operate the SNCR at Johnsonville Unit 1 through the 2007 ozone
season. SNCRs generally have lower NOx removal
capabilities than SCRs. Early in 2006, TVA began testing a High
Energy Reagent Technology (“HERT”) on three units for potential future
application. HERT is similar to SNCR but has higher removal
capabilities than SNCRs. The initial HERT testing program was
successful, and in 2007, TVA installed this technology on two coal-fired units
(Johnsonville Unit 4 and John Sevier Unit 1) to demonstrate the HERT technology
on a potentially permanent basis. Similar equipment is planned for
installation on the other three John Sevier units and Johnsonville Units 2 and 3
by 2009.
TVA’s NOx emission
reduction program is expected to continue to depend primarily on SCRs, but will
also 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 affecting power plant
emissions.
On June 21, 2007, EPA proposed
lowering the eight-hour ozone NAAQS. This proposal began a process that is
expected to lead to a final decision in March 2008 on revising the ozone
standard. Meeting the more stringent EPA standards for ozone contained in the
proposal will challenge states and communities in the Tennessee Valley and
across the country.
The current primary standard, set in
1997, is 0.08 parts per million (“ppm”). EPA is proposing to lower the primary
standard to between 0.075 ppm and 0.070 ppm, and is also proposing to add a new
secondary ozone standard to address impacts on vegetation. If EPA adopts the
proposed standards, many urban areas and surrounding counties in the Tennessee
Valley and throughout the eastern United States are likely to be designated as
“non-attainment” areas (defined as geographic areas where air quality does not
meet standards). Non-attainment designations can have adverse
economic implications for areas that are so designated. Existing emission
sources in non-attainment areas can be required to install additional controls,
and new sources planning to locate in such areas are required to meet more
stringent emission control requirements and obtain offsets for their emissions
from other sources in the non-attainment area. In addition, transportation
projects, such as roadway expansions or repairs, must demonstrate conformity
with state plans to achieve attainment status or risk the loss of federal
highway funds. An increase in the number of counties in the Tennessee Valley
designated as non-attainment areas is also likely to focus additional regulatory
attention on all NOx emission
sources including TVA sources.
Particulates/Opacity. Coarse
particulates (defined as particles of 10 micrometers or larger), which include
fly ash, have long been regulated by states to meet EPA’s NAAQS for particulate
matter. All of TVA’s coal-fired units have been equipped with mechanical
collectors, electrostatic precipitators, scrubbers, or baghouses, which have
reduced particulate emissions from the TVA system by more than 99 percent
compared to uncontrolled units. In 1997, EPA issued separate NAAQS
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 the areas of the country which 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 1997 annual fine particle standard. EPA also
decided to retain the existing 24-hour standard for coarse particles, but
revoked the related annual standard. The last three years of
monitoring data (2004 to 2006) for the Nashville, Chattanooga, Memphis, and
Clarksville/Hopkinsville areas show that these areas will be close to meeting
the more stringent 2006 24-hour and annual fine particle
standards. Attainment designations are scheduled to be made by EPA in
December 2008. 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 to reduce 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 and lawsuits
with special interest groups over the role of continuous opacity monitors in
determining compliance with opacity limitations, and TVA has received an adverse
decision in one such lawsuit. See Item 3, Legal
Proceedings.
Mercury. In March
2005, the EPA issued CAMR, which 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 have adopted CAMR without significant
change. In response to a request for reconsideration, the EPA
confirmed its approach in May 2006. In June 2006, 16 states and
several environmental groups filed lawsuits challenging CAMR. This
lawsuit is currently pending. TVA cannot predict the outcome of the
pending challenge of CAMR, or what effects any decision may have that would
require the EPA to regulate mercury as a hazardous air pollutant. If
the EPA’s decisions are upheld and CAMR is implemented, TVA expects to achieve
the required mercury reductions for at least Phase I of CAMR from 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 the end of
calendar year 2008. The costs associated with the monitoring systems
have been incorporated into TVA's capital budget.
Carbon
Dioxide. 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 implemented a
voluntary initiative with the 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 DOE. TVA has taken and is continuing to take significant
voluntary steps to reduce the carbon intensity of its electric generation,
including the recovery of Browns Ferry Unit 1, planned power uprates of Browns
Ferry Units 2 and 3, the planned completion of Watts Bar Unit 2, and the
completion of the hydroelectric modernization program. TVA has also
applied to the NRC for a Combined License for two advanced nuclear reactors at
the Bellefonte Nuclear Plant near Hollywood, Alabama, although no decision has
been made to build the reactors. Looking ahead, TVA intends to make
decisions that give strong consideration to fuel mix and generating assets that
are low or zero carbon emitting resources. 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 asked utilities to
voluntarily participate in an effort to reduce, sequester, or avoid greenhouse
gases. Under that program, TVA reduced or avoided more than 305
million tons of CO2 from 1994
through 2005, as reported under Section 1605b of the Energy Policy
Act. TVA is incorporating the possibility of mandatory carbon
reductions and a renewable portfolio standard into its long range planning, and
will continue to monitor legislative and regulatory developments related to
CO2
and a renewable portfolio standard to assess any potential financial impacts as
information becomes available.
In addition to legislative activity,
climate change issues are the subject to a number of lawsuits, including
lawsuits against TVA. See Item 3, Legal Proceedings. On
November 29, 2006, the U.S. Supreme Court heard the case of Massachusetts v. EPA,
concerning whether EPA has the authority and duty to regulate CO2 emissions
under the CAA. The District of Columbia Circuit Court of
Appeals earlier affirmed EPA’s decision not to regulate CO2. On
April 2, 2007, the Supreme Court found that greenhouse gases, including CO2, are
pollutants under the CAA and thus EPA does have the authority to regulate
these gases. The Supreme Court also concluded that EPA's refusal to
regulate these pollutants was based on impermissible reasons, and remanded the
case to EPA to "ground its reasons for action or inaction in the
statute." While this case focused on CO2 emissions
from motor vehicles, it sets a precedent for regulation in other industrial
sectors, such as the electric utility industry.
States are also becoming more active in
the regulation of emissions that are believed to be contributing to global
climate change. 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. North
Carolina is studying initiatives aimed at climate change under the provisions of
the state’s Clean Smokestacks Act of 2002. This act required the
State Division of Air Quality to study potential control of CO2 emissions
from coal-fired utility plants and other stationary sources. This
effort has also prompted actions to develop a climate action plan for North
Carolina.
Clean Water Developments
One of the results of the major
reductions in atmospheric emissions resulting from the clean air expenditures
discussed above is that wastewaters at TVA coal-fired facilities and across the
utility industry may be changing because of waste streams from air quality
control technologies. Varying amounts of ammonia or similar compounds used as a
necessary component of SCR and SNCR operations may end up in facility wastewater
ponds that may discharge through outfalls regulated under the Clean Water Act
(“CWA”). Operation of scrubbers for SO2 control
also results in additional amounts of pollutants introduced into facility
wastewater treatment ponds. EPA is currently collecting information to determine
if the Steam Electric Point Source Effluent Guidelines (“Effluent Guidelines”)
under the CWA need to be revised. If the Effluent Guidelines are revised,
potentially more restrictive discharge limitations for existing parameters or
the addition of new parameters could result in additional wastewater treatment
expense to meet requirements of the CWA. These costs cannot be accurately
predicted at this time, but TVA is involved in and closely monitoring EPA’s data
collection activities and the progress of the Effluent Guidelines review
process. On the state level, new numeric nutrient criteria development and
implementation (an EPA requirement) may require additional treatment costs to
reduce nitrogen concentrations being added to the waste treatment ponds as a
result of the operation of air pollution control equipment. TVA is closely
monitoring the development and implementation of numeric nutrient criteria by
the states in TVA’s service area.
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 CWA, the EPA promulgated a final rule for existing power producing
facilities (the “Phase II Rule”) that became effective on September 7,
2004. The Phase II Rule required 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 options included development of a
site-specific compliance option based on application of cost-cost or
cost-benefit tests. The site specific tests were designed to ensure that a
facility’s costs are not significantly greater than cost projections in the rule
or the benefits derived from taking mitigation actions. Actions taken to
compensate for any impacts by restoring habitat, or pursuing other options such
as building hatcheries for fish/shellfish production, would have counted towards
compliance. Some northeastern states and environmental groups
challenged the new regulation, especially the compliance flexibility it offered,
in federal court.
On January 25, 2007, the Second Circuit
issued its decision in the proceeding challenging the EPA's Phase II Rule. The
Second Circuit held that costs cannot be compared to benefits in picking the
best technology available (“BTA”) to minimize the adverse environmental
impacts of intake structures. Instead, the court held that the EPA is
allowed to consider costs in two ways: (1) to determine what technology can
reasonably be borne by industry; and (2) to engage in cost-effectiveness
analysis in determining BTA. Finding the rulemaking record to be unclear on
whether the EPA had relied on a cost-benefit analysis or a cost-effectiveness
analysis, the Second Circuit remanded the EPA's BTA determination, giving the
EPA the option to provide a reasonable explanation of its determination or make
a new determination based on the permissible cost considerations set out in the
Second Circuit opinion. The Second Circuit also remanded provisions of the
EPA rule that allowed the use of a site-specific cost-benefit test and
restoration measures (such as building hatcheries) to demonstrate compliance,
holding that these rule provisions were based on an impermissible construction
of the statute. Several other provisions of the Phase II Rule such as the one
that sets the performance standards as a range rather than one national standard
were also remanded.
On July 9, 2007, EPA suspended all but
one provision of the Phase II Rule until the agency has resolved the issues
raised by the Second Circuit's remand. The provision that was
retained requires permitting authorities to apply, in the interim, Best
Professional Judgment (“BPJ”) controls for existing facilities. BPJ
controls are those that reflect the best technology available for minimizing the
adverse environmental impacts of intake structures. The use of BPJ
controls reflects a reversion to the regulatory process that was used by
permitting authorities to regulate the impact of intake structures prior to the
promulgation of the Phase II Rule.
All of the intakes at TVA's existing
coal and nuclear generating facilities were subject to the Phase II
Rule. TVA had been in the process of determining what was needed to
comply with the Phase II Rule, and had believed that some expenditures might
have been required. These earlier assessments are now being
re-evaluated in light of the Second Circuit's decision, and EPA's subsequent
decision to suspend the Phase II Rule and revert to BPJ
controls. Given the uncertainty over the ultimate outcome of the
appellate process and what the changes in the final rule as ultimately issued by
EPA will be, TVA cannot assess the potential consequences at this
time.
As a part
of the 2006 triennial review of State Water Quality Standards in Tennessee, the
Tennessee Department of Environment and Conservation (“TDEC”) lowered its
threshold for issuing a Precautionary Fish Consumption Advisory (“Precautionary
Advisory”) due to mercury to 0.3 ppm because of new research and the EPA’s new
water quality criterion for methylmercury. The previous thresholds were 0.5 ppm
for a Precautionary Advisory and 1.0 ppm for a “Do Not Consume Advisory.” In
Tennessee a Precautionary Advisory recommends that sensitive populations such as
children and women of child-bearing age should not consume the fish species
named, and that all other persons should limit consumption of the named species
to one meal per month. A “Do Not Consume Advisory” recommends that certain fish
species should not be consumed by anyone in any amount. As a result of lowering
the threshold, Precautionary Advisories were issued for several additional
stream and reservoir segments within the State of Tennessee, including seven
streams and reservoir segments in the Tennessee River Watershed. TDEC’s
announcement of additional Precautionary Advisories for several Tennessee water
bodies does not mean that mercury levels in fish are increasing. TVA has been
monitoring mercury levels in fish and sediments in TVA reservoirs for the last
35 years, and TVA’s data was provided to TDEC as a part of its review
process. TVA’s data show significant reductions in mercury concentrations in
fish from the reservoirs with known industrial discharges that have now ceased
operation. Other than those areas historically impacted by industrial
discharges, mercury concentrations in fish have tended to fluctuate through time
with no discernible trend in fish from most reservoirs. Despite increased
burning of coal for electricity generation, current and historic data records
indicate that mercury concentrations in reservoir sediments have remained stable
or declined.
As is the case across the utility
industry and in other industrial sectors, TVA is also facing more stringent
requirements related to protection of wetlands, reductions in storm water
impacts from construction activities, water quality degradation, new water
quality criteria, and laboratory analytical methods. TVA is also
following litigation related to the use of herbicides, water transfers, and
releases from dams. TVA is not facing any substantive requirements
related to non-compliance with existing CWA regulations.
Hazardous
Substances
Liability for releases and cleanup of
hazardous substances is regulated under the federal Comprehensive Environmental
Response, Compensation, and Liability Act, among other statutes, 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 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
$23,000. 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 David Witherspoon site in Knoxville, Tennessee,
and the Ward Transformer site in Raleigh, North Carolina. As
discussed below, TVA is not able to estimate its liability related to these
sites at this time.
The Witherspoon site is contaminated
with radionuclides, polychlorinated biphenyls (“PCBs”), and
metals. DOE has admitted to being the main contributor of materials
to the Witherspoon site and is currently performing clean-up
activities. DOE claims that TVA sent equipment to be recycled at this
facility, and there is some supporting evidence for the
claim. However, TVA believes it sent only a relatively small amount
of equipment and that none of it was radioactive. DOE has asked TVA
to “cooperate” in completing the cleanup, but it has not provided to TVA any
evidence of TVA’s percentage share of the contamination.
At the Ward Transformer site, EPA and a
working group of potentially responsible parties ("PRPs") have provided
documentation showing that TVA sent electrical equipment containing PCBs to this
site in 1974. The working group is cleaning up on-site contamination
in accordance with an agreement with EPA and plans to sue non-participating PRPs
for contribution. The estimated cost of the cleanup is $20
million. In addition, EPA likely has incurred several million dollars
in response costs, and the working group has reimbursed EPA approximately
$725,000 of those costs. EPA has also proposed a cleanup plan for
off-site contamination. The present worth cost estimate for
performing the proposed plan is about $5 million. In addition, there
may be natural resource damages liability related to this site, but TVA is not
aware of any estimated amount for any such damages.
As of September 30, 2007, TVA’s
estimated liability for environmental cleanup for those sites for which
sufficient information is available to develop a cost estimate (primarily the
TVA sites) is approximately $20 million on a non-discounted basis and is
included in Other liabilities on the Balance Sheet.
Coal-Combustion Wastes
In accordance with a regulatory
determination by EPA in May 2000, coal-combustion and certain related wastes
disposed of in landfills and surface impoundments continue to be regulated as
non-hazardous. In conjunction with this determination, EPA committed
to developing non-hazardous management standards for these
wastes. These standards are likely to include increased groundwater
monitoring, more stringent siting requirements, and closure of existing
waste-management facilities not meeting minimum standards. On August
29, 2007, EPA issued a Notice of Data Availability in which it requested public
comment on whether the additional information mentioned in the notice should
affect the EPA’s decisions as it continues to follow up on its commitment to
develop management standards for coal-combustion wastes. TVA is
currently reviewing this information to evaluate its potential impact on TVA
operations.
For a discussion of TVA’s current legal
proceedings and anticipated outcomes, see Item 3, Legal
Proceedings.
Risk
Governance
The Enterprise Risk Council (“ERC”) was
created in August 2005 to strengthen and formalize TVA’s enterprise-wide risk
management efforts. The ERC is responsible for the highest level of
risk oversight at TVA and is also responsible for communicating enterprise-wide
risks with policy implications to the TVA Board or a designated TVA Board
committee. The ERC’s current members are the President and Chief
Executive Officer (chair), the Chief Financial Officer, the 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 three 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 have
cataloged the major enterprise level risks for TVA into three main categories:
strategic risks, operational risks and financial risks. A discussion
of significant risk factors under each of these categories, as well as risk
factors related to TVA securities, is presented in Item 1A, Risk
Factors. In addition, a discussion of derivative instruments that TVA
uses to hedge certain of these risks is contained in Note 10.
Commodity Price
Risk
TVA measures price risk associated with
the commodities that are critical to its operations using either a Value at Risk
(“VaR”) methodology or sensitivity analysis. Following is an
explanation of these methods along with their calculated measures of TVA’s
commodity price risk.
Value at Risk
TVA uses a VaR methodology common to
many energy companies 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 use of a number of assumptions
including a confidence level for losses, market liquidity, and a specified
holding period. This methodology uses standard statistical techniques
to predict market movements in light of current prices, historical volatilities,
and current specific commodity 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 10-day period within a
specified confidence level. TVA’s VaR calculations are based on a 95 percent
confidence level (two-tailed test), which means that there is a 2.5 percent
probability that TVA’s portfolios will incur a loss in value in 10 days at least
as large as the reported VaR. For example, if the VaR is calculated at $5
million, there is a 97.5 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.
The following table illustrates the
potential unfavorable price impact on TVA’s electricity, natural gas, SO2 emission
allowance, and NOx emission
allowance portfolios as measured by the VaR model based on a 10-day holding
period and a 95 percent confidence level. The high and low valuations
represent the highest and lowest VaR values during 2007, and the average
calculation represents the average of the VaR values during 2007.
Value
at Risk
|
September
30, 2007
|
Average
|
High
|
Low
|
|||||||||||||
|
Electricity
1
|
$ | 69 | $ | 48 | $ | 86 | $ | 18 | ||||||||
|
Natural
Gas 2
|
5 | 15 | 35 | 1 | ||||||||||||
|
SO2
Emission Allowances 3
|
20 | 21 | 34 | 16 | ||||||||||||
|
NOx
Emission Allowances 4
|
1 | 1 | 3 | 0 | ||||||||||||
Notes
|
|
(1)
|
TVA’s
VaR calculations for electricity are based on its on-peak electricity
portfolio, which includes electricity forwards and option
contracts.
|
|
|
(2)
|
TVA’s
VaR calculations for natural gas are based on TVA’s natural gas portfolio,
which includes natural gas forwards, futures, and options on futures
contracts.
|
|
|
(3)
|
TVA’s
VaR calculations for SO2
emission allowances are based on TVA’s portfolio of SO2
emission allowances.
|
|
|
(4)
|
TVA’s
VaR calculations for NOx emission allowances are based on TVA’s portfolio
of NOx emission 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
2007, TVA supplied approximately 6.7 percent of system energy requirements with
power purchased under electricity forward contracts.
TVA’s average electricity market risk
exposure has increased annually since 2003. The increases have
resulted primarily from TVA’s increased purchases of power to meet growing
demand and, to a lesser extent, from increased volatility in the electricity
markets.
As shown in the Value at Risk table
above, at a 95 percent confidence level, the average VaR for TVA’s electricity
portfolio for 2007 for a 10-day holding period was $48 million.
Natural Gas. TVA
uses 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, options on futures contracts, swaps, and options on
swaps under a financial hedging program. At September 30, 2007, TVA
had derivative positions outstanding under the program equivalent to about 2,971
contracts, made up of 1,623 futures contracts, 560 options contracts, and 788
swap futures contracts, with an approximate net market value of $136
million.
As shown on the Value at Risk table
above, at a 95 percent confidence level, the average VaR for TVA’s natural gas
portfolio for 2007 for a 10-day holding period was $15 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 TVA’s emissions
requirements, TVA also manages the emission positions utilizing the market 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 2007
for a 10-day holding period for TVA’s SO2 emission
allowance portfolio and NOx emission
allowance portfolio was $21 million and $1 million, respectively.
Fuel Oil. TVA
purchases fuel oil as a substitute fuel source for TVA’s combustion
turbines. Thus, TVA’s hedge against market risk for fuel oil is the
use of natural gas and is captured in the natural gas VaR.
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 2007,
TVA purchased 89 percent of its coal requirements under long-term coal contracts
and 11 percent of its coal requirements under short-term
contracts. If the rates that TVA paid for coal under short-term
contracts during 2007 were 10 percent higher than the rates TVA actually paid,
TVA’s coal expense would have increased by $20 million in 2007.
Uranium. During
2007, TVA did not have to purchase any uranium on the spot market, and as of
September 30, 2007, 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 2008 would have no material effect on
TVA’s financial position, results of operations, or cash flows. See
Item 1, Business — Fuel Supply
— Nuclear Fuel.
Cash Flow at
Risk
Cash Flow at Risk (“CFaR”) is a modeled
portfolio risk metric that measures the amount of potential variability around
forecasted cash flows that could be caused by changes in market conditions,
hydroelectric generation and availability, and load. Although the FCA
serves to limit the amount of cash flow variability to which TVA is exposed, TVA
continues 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, 2007, TVA estimated its 2008 CFaR at $293
million based on a 90 percent confidence level.
Investment Price
Risk
TVA’s investment price risk relates
primarily to investments in TVA’s nuclear decommissioning trust, asset
retirement trust, and pension plan.
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, 2007, the value of the investments in
the trust was $1.1 billion, and an immediate 10 percent decrease in the price of
the investments in the trust would have reduced the value of the trust by $109
million. See Item 7, Management’s Discussion and Analysis of
Financial Condition and Results of Operations — Critical Accounting Policies and
Estimates — Nuclear Decommissioning for more information regarding TVA’s
nuclear decommissioning trust.
Asset Retirement Trust
The asset retirement trust is presently
invested to achieve a return in line with fixed income market performance. The
assets of the trust are invested in fixed income commingled funds. As
of September 30, 2007, the value of the investments in the trust was $40
million, and an immediate 10 percent decrease in the price of the investments in
the trust would reduce the value of the trust by $4 million.
Pension Fund
The assets in TVA’s pension plan are
primarily stocks and bonds. The Tennessee Valley Authority Retirement
System (“TVARS”) targets an asset allocation policy for its pension plan assets
which, in prior years, approximated 60 percent equity securities and 40 percent
fixed income securities. TVARS is transitioning to a new asset allocation policy
adopted March 1, 2007, which targets an asset allocation policy of 65 percent
equity securities and 35 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, 2007, the value of the investments in the pension fund was $8
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 approximately $800
million. See Item 7, Management’s Discussion and Analysis of
Financial Condition and Results of Operations — Critical Accounting Policies and
Estimates — Pension and
Other Postretirement Benefits and Note 14 for additional information
regarding TVA’s pension fund.
Interest Rate
Risk
TVA’s interest rate risk is related
primarily to its short-term investments, its Bonds, TVA’s swaption transactions,
and an interest rate swap related to one of TVA’s swaption
transactions.
Short-Term
Investments
At September 30, 2007, TVA had $165
million of cash and cash equivalents, and the average balance of cash and cash
equivalents for 2007 was $389 million. If the rates of interest that
TVA received on its short-term investments during 2007 were one percentage point
lower than the rates of interest that TVA actually received on these
investments, TVA would have received approximately $4 million less in interest
from its short-term investments during 2007. In addition, changes in
interest rates could affect the value of TVA’s investments in its pension fund,
asset retirement trust, and nuclear decommissioning fund. See Item 7,
Management’s Discussion and Analysis of Financial Condition and Results of
Operations — Risk Management
Activities — Investment Price Risk.
Debt Portfolio
Short-Term
Debt. At September 30, 2007, TVA’s short-term borrowings were
$1.4 billion, and the current maturities of long-term debt were $90
million. Based on TVA’s interest rate exposure at September 30, 2007,
an immediate one percentage point increase in interest rates would have resulted
in an increase of $16 million in TVA’s short-term interest expense during
2008. This calculation assumes that the balance of short-term debt
during 2008 equals the short-term debt balance at September 30, 2007, plus an
amount representing the refinancing of current maturities of long-term
debt.
Long-Term Debt. At
September 30, 2007, the interest rates on all of TVA’s outstanding long-term
debt were fixed. Accordingly, an immediate one percentage point
increase in interest rates would not have affected TVA’s interest expense
associated with its long-term debt. When TVA’s long-term debt matures
or is redeemed, however, TVA typically refinances this debt by issuing
additional long-term debt. Accordingly, if interest rates are high
when TVA issues this additional long-term debt, TVA’s cash flows, results of
operations, and financial condition may be adversely affected. This
risk is somewhat mitigated by the fact that TVA’s debt portfolio is diversified
in terms of maturities and has a long average life. As of September
30, 2007, the average life of TVA’s debt portfolio was 16 years. A
schedule of TVA’s debt maturities is contained in Note 11.
Swaption Agreements and Related
Interest Rate Swap
Changes
in interest rates also affect the amount of gains and losses on the
mark-to-market valuation of TVA’s three swaption agreements and the related
interest rate swap. Gains and losses on these transactions are
recorded in earnings as Unrealized gain/(loss) on derivative contracts, net and
are non-cash in nature. Based on TVA’s interest rate exposure at
September 30, 2007, an immediate one percentage point decrease in interest rates
would have created a non-cash charge to earnings of $283 million and a
corresponding increase in Other liabilities. Due to changes in the
ratemaking process, starting October 1, 2007, any charges will be recorded to a
regulatory asset account until settled.
Currency Exchange Rate
Risk
As of September 30, 2007, 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, 2007, a 10 percent
change in the British pound sterling-U.S. dollar exchange rate would not have
had a material impact on TVA’s cash flows, results of operations, or financial
position.
Credit
Risk
Credit risk is the exposure to
economic loss that would occur as a result of a counterparty’s nonperformance of
its contractual obligations. Where exposed to credit risk, TVA
analyzes the counterparty’s financial condition prior to entering into an
agreement, establishes credit limits, monitors the appropriateness of those
limits, as well as any changes in the creditworthiness of the counterparty on an
ongoing basis, and employs credit mitigation measures, such as collateral or
prepayment arrangements and master purchase and sale agreements, to mitigate
credit risk.
Credit
of Customers
The majority of TVA’s credit risk is
limited to trade accounts receivable from delivered power sales to municipal and
cooperative distributor customers, all located in the Tennessee Valley
region. To a lesser extent, TVA is exposed to credit risk from
industries and federal agencies directly served and from exchange power
arrangements with a small number of investor-owned regional utilities related to
either delivered power or the replacement of open positions of longer-term
purchased power or fuel agreements.
TVA had concentrations of accounts
receivable from seven customers that represented 40 percent of total accounts
receivable as of September 30, 2007.
The table below summarizes TVA’s
customer credit risk from trade accounts receivable as of September 30,
2007:
|
Customer
Credit Risk
As
of September 30
|
||||
|
Trade
Accounts Receivable 1
|
As
Restated
|
|||
|
Municipalities
and Cooperative Distributor Customers
|
||||
|
Investment
Grade
|
$ | 900 | ||
|
Internally
Rated — Investment Grade
|
462 | |||
|
Industries
and Federal Agencies Directly Served
|
||||
|
Investment
Grade
|
37 | |||
|
Non-investment
Grade
|
17 | |||
|
Internally
Rated — Investment Grade
|
4 | |||
|
Internally
Rated — Non-investment Grade
|
4 | |||
|
Exchange
Power Arrangements
|
||||
|
Investment
Grade
|
6 | |||
|
Non-investment
Grade
|
– | |||
|
Internally
Rated — Investment Grade
|
3 | |||
|
Internally
Rated — Non-investment Grade
|
1 | |||
|
Subtotal
|
1,434 | |||
|
Other
Accounts Receivable
|
||||
|
Miscellaneous
Accounts
|
26 | |||
|
Provision
for Uncollectible Accounts
|
(2 | ) | ||
|
Subtotal
|
24 | |||
|
Total
|
$ | 1,458 | ||
Note
(1) Includes
unbilled power receivables of $986 million and unbilled FCA of $132
million.
Credit
of Other Counterparties
In addition to being exposed to
economic loss due to the nonperformance of TVA’s customers, TVA is exposed to
economic loss because of the nonperformance of its other counterparties,
including suppliers and counterparties to its derivative contracts.
Credit of
Suppliers. If one of TVA’s fuel or purchased power suppliers
fails to perform under the terms of its contract with TVA, TVA might lose the
money that it paid to the supplier under the contract and have to purchase
replacement fuel or power on the spot market, perhaps at a significantly higher
price than TVA was entitled to pay under the contract. In addition, TVA might
not be able to acquire replacement fuel or power in a timely manner and thus
might be unable to satisfy its own obligations to deliver power. As
of September 30, 2007, counterparties with which TVA had power purchase
agreements for 1,308 megawatts of capacity were in bankruptcy. Each
of these parties has continued to perform under its power purchase agreement
with TVA throughout the bankruptcy proceedings, and all of these agreements are
secured with either cash or letters of credit. Accordingly, TVA has
not experienced any economic or cash losses as a result of the counterparties’
bankruptcy proceedings.
Credit of Derivative
Counterparties. TVA has entered into derivative contracts for
hedging purposes, and TVA’s nuclear decommissioning trust and pension fund have
entered into derivative contracts for investment purposes. If a
counterparty to one of TVA’s hedging transactions defaults, TVA might incur
substantial costs in connection with entering into a replacement hedging
transaction. If a counterparty to the derivative contracts into which
the nuclear decommissioning trust and the pension fund have entered for
investment purposes defaults, the value of the investment could decline
significantly, or perhaps become worthless.
Credit
of TVA
A downgrade in TVA’s credit rating
could have material adverse effects on TVA’s cash flows, results of operations,
and financial condition and would harm investors in TVA
securities. Among other things, a downgrade could have the
following effects:
|
•
|
A
downgrade would increase TVA’s interest expense by increasing the interest
rates that TVA pays on debt securities that it issues. An
increase in TVA’s interest expense would reduce the amount of cash
available for other purposes, which could result in the need to increase
borrowings, to reduce other expenses or capital investments, or to
increase electricity rates.
|
|
•
|
A
significant downgrade could result in TVA having to post collateral under
certain physical and financial contracts that contain rating
triggers.
|
|
•
|
A
downgrade below a contractual threshold could prevent TVA from borrowing
under two credit facilities totaling $2.5
billion.
|
|
•
|
A
downgrade could lower the price of TVA securities in the secondary market,
thereby hurting investors who sell TVA securities after the downgrade and
diminishing the attractiveness and marketability of TVA
Bonds.
|
For a discussion of factors that could
lead to a downgrade in TVA’s credit rating, see Item 1A, Risk
Factors.
See Note
18.
Quantitative and qualitative
disclosures about market risk are reported in Item 7, Management’s Discussion
and Analysis of Financial Condition and Results of Operations — Risk Management
Activities.
TENNESSEE
VALLEY AUTHORITY
For the
years ended September 30
(in
millions)
|
2007
|
2006
|
2005
|
||||||||||
|
Restated
|
Restated
|
|||||||||||
|
Operating
revenues
|
||||||||||||
|
Sales
of electricity
|
||||||||||||
|
Municipalities
and cooperatives
|
$ | 7,847 | $ | 7,659 | $ | 6,539 | ||||||
|
Industries
directly served
|
1,221 | 1,065 | 961 | |||||||||
|
Federal
agencies and other
|
112 | 116 | 181 | |||||||||
|
Other
revenue
|
146 | 143 | 111 | |||||||||
|
Operating
revenues
|
9,326 | 8,983 | 7,792 | |||||||||
|
Revenue
capitalized during pre-commercial plant operations
|
(57 | ) | – | – | ||||||||
|
Net
operating revenues
|
9,269 | 8,983 | 7,792 | |||||||||
|
Operating
expenses
|
||||||||||||
|
Fuel
and purchased power
|
3,449 | 3,342 | 2,609 | |||||||||
|
Operating
and maintenance
|
2,332 | 2,328 | 2,303 | |||||||||
|
Depreciation,
amortization, and accretion
|
1,473 | 1,500 | 1,154 | |||||||||
|
Tax
equivalents
|
451 | 376 | 365 | |||||||||
|
Loss
on asset impairment
|
21 | 14 | 24 | |||||||||
|
Total
operating expenses
|
7,726 | 7,560 | 6,455 | |||||||||
|
Operating
income
|
1,543 | 1,423 | 1,337 | |||||||||
|
Other
income
|
73 | 80 | 61 | |||||||||
|
Other
expense
|
(2 | ) | (2 | ) | (4 | ) | ||||||
|
Unrealized
gain (loss) on derivative contracts, net
|
41 | (15 | ) | 3 | ||||||||
|
Interest
expense
|
||||||||||||
|
Interest
on debt and leaseback obligations
|
1,390 | 1,406 | 1,407 | |||||||||
|
Amortization
of debt discount, issue, and reacquisition costs, net
|
19 | 21 | 21 | |||||||||
|
Allowance
for funds used during construction and nuclear fuel
expenditures
|
(177 | ) | (163 | ) | (116 | ) | ||||||
|
Net
interest expense
|
1,232 | 1,264 | 1,312 | |||||||||
|
Income
before cumulative effects of accounting changes
|
423 | 222 | 85 | |||||||||
|
Cumulative
effect of change in accounting for conditional
asset
retirement obligations
|
– | (109 | ) | – | ||||||||
|
Net
income
|
$ | 423 | $ | 113 | $ | 85 | ||||||
The
accompanying notes are an integral part of these financial
statements.
TENNESSEE
VALLEY AUTHORITY
At
September 30
(in
millions)
|
ASSETS
|
||||||||
|
2007
|
2006
|
|||||||
|
Restated
|
Restated
|
|||||||
|
Current
assets
|
||||||||
|
Cash
and cash equivalents
|
$ | 165 | $ | 536 | ||||
|
Restricted
cash and investments
|
150 | 198 | ||||||
|
Accounts
receivable, net
|
1,458 | 1,181 | ||||||
|
Inventories
and other
|
663 | 598 | ||||||
|
Total
current assets
|
2,436 | 2,513 | ||||||
|
Property, plant, and equipment
(Note 4)
|
||||||||
|
Completed
plant
|
38,811 | 35,652 | ||||||
|
Less
accumulated depreciation
|
(15,937 | ) | (15,339 | ) | ||||
|
Net
completed plant
|
22,874 | 20,313 | ||||||
|
Construction
in progress
|
1,286 | 3,534 | ||||||
|
Nuclear
fuel and capital leases
|
672 | 574 | ||||||
|
Total
property, plant, and equipment, net
|
24,832 | 24,421 | ||||||
|
Investment
funds
|
1,169 | 972 | ||||||
|
Regulatory
and other long-term assets
|
||||||||
|
Deferred
nuclear generating units
|
3,130 | 3,521 | ||||||
|
Other
regulatory assets (Note 6)
|
1,790 | 1,787 | ||||||
|
Subtotal
|
4,920 | 5,308 | ||||||
|
Other
long-term assets
|
375 | 1,094 | ||||||
|
Total
regulatory and other long-term assets
|
5,295 | 6,402 | ||||||
|
Total
assets
|
$ | 33,732 | $ | 34,308 | ||||
|
LIABILITIES
AND PROPRIETARY CAPITAL
|
||||||||
|
Current
liabilities
|
||||||||
|
Accounts
payable
|
$ | 1,000 | $ | 890 | ||||
|
Accrued
liabilities
|
205 | 237 | ||||||
|
Collateral
funds held
|
157 | 195 | ||||||
|
Accrued
interest
|
406 | 403 | ||||||
|
Current
portion of leaseback obligations
|
43 | 37 | ||||||
|
Current
portion of energy prepayment obligations
|
106 | 106 | ||||||
|
Short-term
debt, net
|
1,422 | 2,376 | ||||||
|
Current
maturities of long-term debt (Note 11)
|
90 | 985 | ||||||
|
Total
current liabilities
|
3,429 | 5,229 | ||||||
|
Other
liabilities
|
||||||||
|
Other
liabilities
|
2,067 | 2,283 | ||||||
|
Regulatory
liabilities (Note 6)
|
83 | 575 | ||||||
|
Asset
retirement obligations
|
2,189 | 1,985 | ||||||
|
Leaseback
obligations
|
1,029 | 1,071 | ||||||
|
Energy
prepayment obligations
|
1,032 | 1,138 | ||||||
|
Total
other liabilities
|
6,400 | 7,052 | ||||||
|
Long-term debt, net
(Note 11)
|
21,099 | 19,544 | ||||||
|
Total
liabilities
|
30,928 | 31,825 | ||||||
|
Commitments and
contingencies (Note 15)
|
||||||||
|
Proprietary
capital
|
||||||||
|
Appropriation
investment
|
4,743 | 4,763 | ||||||
|
Retained
earnings
|
1,763 | 1,349 | ||||||
|
Accumulated
other comprehensive (loss) income
|
(19 | ) | 43 | |||||
|
Accumulated
net expense of stewardship programs
|
(3,683 | ) | (3,672 | ) | ||||
|
Total
proprietary capital
|
2,804 | 2,483 | ||||||
|
Total
liabilities and proprietary capital
|
$ | 33,732 | $ | 34,308 | ||||
The
accompanying notes are an integral part of these financial
statements.
TENNESSEE
VALLEY AUTHORITY
For the
years ended September 30
(in
millions)
|
2007
|
2006
|
2005
|
||||||||||
|
Cash
flows from operating activities
|
Restated
|
Restated
|
||||||||||
|
Net
income
|
$ | 423 | $ | 113 | $ | 85 | ||||||
|
Adjustments
to reconcile net income to net cash provided by operating
activities
|
||||||||||||
|
Depreciation,
amortization, and accretion
|
1,492 | 1,521 | 1,175 | |||||||||
|
Nuclear
refueling outage amortization
|
86 | 89 | 105 | |||||||||
|
Loss
on asset impairment
|
21 | 14 | 24 | |||||||||
|
Cumulative
effect of change in accounting principle
|
– | 109 | - | |||||||||
|
Amortization
of nuclear fuel
|
137 | 128 | 131 | |||||||||
|
Non-cash
retirement benefit expense
|
201 | 302 | 289 | |||||||||
|
Net
unrealized gain on derivative contracts
|
(41 | ) | 15 | (3 | ) | |||||||
|
Prepayment
credits applied to revenue
|
(105 | ) | (105 | ) | (105 | ) | ||||||
|
Fuel
cost adjustment deferral
|
(150 | ) | – | – | ||||||||
|
Other,
net
|
(31 | ) | (3 | ) | 7 | |||||||
|
Changes
in current assets and liabilities
|
||||||||||||
|
Accounts
receivable, net
|
(144 | ) | (15 | ) | (19 | ) | ||||||
|
Inventories
and other
|
(98 | ) | (120 | ) | (12 | ) | ||||||
|
Accounts
payable and accrued liabilities
|
103 | 96 | (16 | ) | ||||||||
|
Accrued
interest
|
4 | 23 | (22 | ) | ||||||||
|
Pension
contributions
|
(75 | ) | (75 | ) | (53 | ) | ||||||
|
Refueling
outage costs
|
(96 | ) | (72 | ) | (122 | ) | ||||||
|
Other,
net
|
61 | (35 | ) | (2 | ) | |||||||
|
Net
cash provided by operating activities
|
1,788 | 1,985 | 1,462 | |||||||||
|
Cash
flows from investing activities
|
||||||||||||
|
Construction
expenditures
|
(1,379 | ) | (1,370 | ) | (1,339 | ) | ||||||
|
Combustion
turbine asset acquisitions
|
(111 | ) | – | – | ||||||||
|
Nuclear
fuel expenditures
|
(203 | ) | (277 | ) | (141 | ) | ||||||
|
Change
in restricted cash and investments
|
48 | (91 | ) | (107 | ) | |||||||
|
(Purchases)
proceeds of investments
|
(44 | ) | – | 335 | ||||||||
|
Loans
and other receivables
|
||||||||||||
|
Advances
|
(16 | ) | (17 | ) | (12 | ) | ||||||
|
Repayments
|
16 | 13 | 18 | |||||||||
|
Proceeds
from sale of receivables/loans (Note 1)
|
2 | 11 | 56 | |||||||||
|
Proceeds
from settlement of litigation
|
– | 35 | – | |||||||||
|
Other,
net
|
1 | (2 | ) | 2 | ||||||||
|
Net
cash used in investing activities
|
(1,686 | ) | (1,698 | ) | (1,188 | ) | ||||||
|
Cash
flows from financing activities
|
||||||||||||
|
Long-term
debt
|
||||||||||||
|
Issues
|
1,040 | 1,132 | 1,650 | |||||||||
|
Redemptions
and repurchases (Note 11)
|
(470 | ) | (1,241 | ) | (2,368 | ) | ||||||
|
Short-term
(redemptions)/borrowings, net
|
(955 | ) | (93 | ) | 546 | |||||||
|
Proceeds
from call monetizations
|
– | – | 5 | |||||||||
|
Payments
on leaseback financing
|
(30 | ) | (28 | ) | (29 | ) | ||||||
|
Payments
on equipment financing
|
(7 | ) | (6 | ) | (6 | ) | ||||||
|
Financing
costs, net
|
(11 | ) | (14 | ) | (17 | ) | ||||||
|
Payments
to U.S. Treasury
|
(40 | ) | (38 | ) | (36 | ) | ||||||
|
Other
|
– | (1 | ) | – | ||||||||
|
Net
cash used in financing activities
|
(473 | ) | (289 | ) | (255 | ) | ||||||
|
Net
change in cash and cash equivalents
|
(371 | ) | (2 | ) | 19 | |||||||
|
Cash
and cash equivalents at beginning of period
|
536 | 538 | 519 | |||||||||
|
Cash
and cash equivalents at end of period
|
$ | 165 | $ | 536 | $ | 538 | ||||||
See Note
12 for supplemental cash flow information.
The
accompanying notes are an integral part of these financial
statements.
TENNESSEE
VALLEY AUTHORITY
For the
years ended September 30
(in
millions)
|
Appropriation
Investment
|
Retained
Earnings
|
Accumulated
Other Comprehensive (Loss) Income
|
Accumulated
Net Expense of Stewardship Programs
|
Total
|
Comprehensive
Income
|
|||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Balance
at September 30, 2004
|
$ | 4,803 | $ | 1,162 | $ | (52 | ) | $ | (3,649 | ) | $ | 2,264 | ||||||||||||
|
Net
income (loss)
|
– | 98 | – | (13 | ) | 85 | $ | 85 | ||||||||||||||||
|
Return
on Power Facility Appropriation Investment
|
– | (16 | ) | – | – | (16 | ) | – | ||||||||||||||||
|
Accumulated
other comprehensive income (Note 9)
|
– | – | 79 | – | 79 | 79 | ||||||||||||||||||
|
Return
of Power Facility Appropriation Investment
|
(20 | ) | – | – | – | (20 | ) | – | ||||||||||||||||
|
Balance
at September 30, 2005
|
4,783 | 1,244 | 27 | (3,662 | ) | 2,392 | $ | 164 | ||||||||||||||||
|
Net
income (loss) (as restated)
|
– | 123 | – | (10 | ) | 113 | $ | 113 | ||||||||||||||||
|
Return
on Power Facility Appropriation Investment
|
– | (18 | ) | – | – | (18 | ) | – | ||||||||||||||||
|
Accumulated
other comprehensive income (Note 9)
|
– | – | 16 | – | 16 | 16 | ||||||||||||||||||
|
Return
of Power Facility Appropriation Investment
|
(20 | ) | – | – | – | (20 | ) | – | ||||||||||||||||
|
Balance
at September 30, 2006 (as restated)
|
4,763 | 1,349 | 43 | (3,672 | ) | 2,483 | $ | 129 | ||||||||||||||||
|
Net
income (loss) (as restated)
|
– | 434 | – | (11 | ) | 423 | $ | 423 | ||||||||||||||||
|
Return
on Power Facility Appropriation Investment
|
– | (20 | ) | – | – | (20 | ) | – | ||||||||||||||||
|
Accumulated
other comprehensive (loss) (Notes 9 and 14)
|
– | – | (62 | ) | – | (62 | ) | (62 | ) | |||||||||||||||
|
Return
of Power Facility Appropriation Investment
|
(20 | ) | – | – | – | (20 | ) | – | ||||||||||||||||
|
Balance
at September 30, 2007 (as restated)
|
$ | 4,743 | $ | 1,763 | $ | (19 | ) | $ | (3,683 | ) | $ | 2,804 | $ | 361 | ||||||||||
The
accompanying notes are an integral part of these 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 (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, and
industry.
Substantially all TVA revenues and
assets are attributable to the power program. TVA provides power in
most of Tennessee, northern Alabama, northeastern Mississippi, and southwestern
Kentucky, and in portions of northern Georgia, western North Carolina, and
southwestern Virginia to a population of approximately 8.7 million
people. The power program has historically been separate and distinct
from the stewardship programs. It is required to be self-supporting
from power revenues and proceeds from power financings, such as proceeds from
the issuance of bonds, notes, and other evidences of indebtedness
(“Bonds”). Although TVA does not currently receive congressional
appropriations, it is required to make annual payments to the U.S. Treasury in
repayment of, and as a return on, the government’s appropriation investment in
TVA power facilities (the “Power Facility Appropriation
Investment”). Until 2000, most of the funding for TVA’s stewardship
programs was provided by congressional appropriations. These programs
are now funded with power revenues, except for certain stewardship activities
that generate various revenues and user fees. These activities
related to stewardship properties do not meet the criteria of an operating
segment pursuant to Statement of Financial Accounting Standard (“SFAS”) No. 131,
“Disclosures About Segments of
an Enterprise and Related Information.” Accordingly, these
assets and properties are included as part of the power program, TVA’s only
operating segment.
Power rates are established by the TVA board of directors (“TVA Board”) as
authorized by the TVA Act. The TVA Act requires TVA to charge rates
for power that will produce gross revenues sufficient to provide funds for
operation, maintenance, and administration of its power system; payments to
states and counties in lieu of taxes; debt service on outstanding indebtedness;
payments to the U.S. Treasury in repayment of and as a return on the Power
Facility Appropriation Investment; and such additional margin as the TVA Board
may consider desirable for investment in power system assets, retirement of
outstanding Bonds in advance of maturity, additional reduction of the Power
Facility Appropriation Investment, and other purposes connected with TVA’s power
business. In setting TVA’s rates, the TVA Board is charged by the TVA
Act to have due regard for the primary objectives of the TVA Act, including the
objective that power shall be sold at rates as low as are
feasible. Rates set by the TVA Board are not subject to review or
approval by any state or federal regulatory body.
Fiscal Year
Unless otherwise indicated, years
(2007, 2006, etc.) refer to TVA’s fiscal years ended September 30.
Cost-Based Regulation
The rate-setting authority vested in the TVA Board by the TVA Act meets the
“self-regulated” provisions of SFAS No. 71, “Accounting for the Effects of
Certain Types of Regulation.” In addition, TVA meets the
remaining criteria for the application of SFAS No. 71 because (1) TVA’s
regulated rates are designed to recover its costs of providing electricity and
(2) in view of the demand for electricity and the level of competition it is
reasonable to assume that the rates, set at levels that will recover TVA’s
costs, can be charged and collected. Accordingly, TVA records certain
assets and liabilities that result from the regulated ratemaking process that
would not be recorded under generally accepted accounting principles (“GAAP”)
for non-regulated entities. Regulatory assets generally represent
incurred costs that have been deferred because such costs are probable of future
recovery in customer rates. Regulatory liabilities generally
represent obligations to make refunds to customers for previous collections for
costs that are not likely to be incurred or deferral of gains that will be
credited to customers in future periods. Management assesses whether
the regulatory assets are probable of future recovery by considering factors
such as applicable regulatory changes, potential legislation, and changes in
technology. Based on these assessments, 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 would be required to write-off
these costs. Any asset 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 GAAP in the United States 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 financial statements to conform to the 2007 and 2006
presentation.
Beginning with October 2006, certain
items previously considered revenue from Sales of electricity were reclassified
as Other revenue. These items are not directly associated with the sale of
electricity and include delivery point charges, administrative charges, and
customer charges. Previously reported sales of electricity of
approximately $22 million and $23 million for 2006 and 2005, respectively, are
now included in Other revenue. Additionally, certain items previously
considered revenue from Other revenue were reclassified as Other
income. These items are not directly associated with revenue derived
from electric operations but are associated with the operation of service
organizations which provide environmental and maintenance and testing
services. Previously reported revenue from these items of
approximately $10 million and $12 million for 2006 and 2005, respectively, is
now included in Other income. Additionally, certain Other
revenue related to income derived from electric operations was recorded
net of related expenses. Expenses of $15 million for 2005 have been
reclassified from Other revenue to Operating expenses.
TVA has
certain service organizations which provide maintenance and testing services to
customers both inside and outside of TVA. For 2005, the excess of
cost recovery over actual cost and services provided to TVA organizations of $12
million has been reclassified from Other income to Operating
expense.
Subsequent
to 2005, certain financing charges related to leaseback obligations were
recorded as Operating
and maintenance expense. Beginning with 2006, these
financing charges are classified as interest expense. Previously
reported financing charges of approximately $51 million for 2005 are now
included in Interest on debt and leaseback obligations.
Cash and Cash Equivalents
Cash and cash equivalents include the
cash available in TVA’s commercial bank accounts and U.S. Treasury accounts, as
well as short-term securities held for the primary purpose of general
liquidity. Such securities mature within three months from the
original date of issuance.
Restricted Cash and
Investments
As of September 30, 2007 and 2006, TVA
had $150 million and $198 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 resulted 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 (see Note 2):
|
Accounts
Receivable
As
of September 30
|
||||||||
|
2007
|
2006
|
|||||||
|
As
Restated
|
As
Restated
|
|||||||
|
Power
receivables billed
|
$ | 316 | $ | 303 | ||||
|
Power
receivables unbilled
|
986 | 832 | ||||||
|
Fuel
cost adjustments unbilled
|
132 | - | ||||||
|
Total
power receivables
|
1,434 | 1,135 | ||||||
|
Other
receivables
|
26 | 56 | ||||||
|
Allowance
for uncollectible accounts
|
(2 | ) | (10 | ) | ||||
|
Net
accounts receivable
|
$ | 1,458 | $ | 1,181 | ||||
Allowance for Uncollectible
Accounts
The allowance for uncollectible
accounts reflects TVA’s estimate of probable losses inherent in the accounts
receivable, unbilled revenue, and loans receivable balances. TVA
determines the allowance based on known accounts, historical experience, and
other currently available information including events such as customer
bankruptcy and/or a customer failing to fulfill payment arrangements after 90
days. TVA’s corporate credit department is consulted to assess the
financial condition of customers and the credit quality of the
accounts. The allowance for uncollectible accounts was $2 million and
$10 million at September 30, 2007 and 2006, respectively, for accounts
receivable and $15 million at both September 30, 2007 and 2006, for loans
receivable.
Revenues
Revenues from power sales are recorded
as power is delivered to customers. In addition to power sales invoiced and
recorded during the month, TVA accrues estimated unbilled revenues for power
sales provided to customers for the period of time from the end of the
customer's billing cycle to the end of TVA's accounting period. Components of
the unbilled revenue include estimated wholesale meter readings at the
applicable rates and sales of excess generation at market rates. These
components can fluctuate as a result of a number of factors including weather,
generation patterns, and other operational constraints. These factors can be
unpredictable and can vary from historical trends. 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.)
Reserve for Future
Generation
During the first quarter of 2007, TVA
began collecting in rates amounts intended to fund future generation based on
the need for additional generating capacity that would be required to meet
future power demand in its service area. Because these amounts were intended to
fund future costs, they were originally deferred as a regulatory
liability. The funds were based on a predetermined rate applied to
electricity sales approved as part of TVA’s 2007 budget. Collections for 2007
amounted to $76 million. Following the purchase of two combustion
turbine facilities, these funds were applied as credits to Completed plant and
are reflected on the September 30, 2007, Balance Sheet. These funds collected
for future generation were amortized to revenue in order to match revenue with
the corresponding depreciation expense of the purchased assets on the Statement
of Income. This revenue recognition process began when the assets were placed
into service. The reserve for future generation was not extended
beyond 2007.
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, 2007 and 2006, TVA had $316 million and $270
million, respectively, in fuel inventories and $317 million and $288 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 obsolescence. The allowance for
surplus and obsolete inventory was $43 million and $38 million at September 30,
2007 and 2006, respectively.
Emission
Allowances. TVA has emission allowances for sulfur dioxide
(“SO2”) and
nitrogen oxides (“NOx”) which
are accounted for as inventory. The average cost of allowances used
each month is charged to operating expense based on tons of SO2 and
NOx
emitted. NOx emission
allowances are used only 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
(“AFUDC”). Beginning in 2008, TVA will continue to capitalize a
portion of current interest costs associated with funds invested in most nuclear
fuel inventories, but interest on funds invested in construction projects will
be capitalized only if (1) the expected total cost of a project is
$1 billion or more and (2) the estimated construction period is at least
three years. 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 2.90 percent
for 2007, 3.17 percent for 2006, and 3.33 percent for
2005. Depreciation rates by asset class are as follows:
|
TVA
Property, Plant, and Equipment Depreciation Rates
As
of September 30
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
As
Restated
|
As
Restated
|
|||||||||||
|
Asset
Class:
|
(percent)
|
|||||||||||
|
Nuclear
|
2.29 | 3.00 | 3.40 | |||||||||
|
Coal-Fired
|
3.59 | 3.53 | 3.53 | |||||||||
|
Hydroelectric
|
1.82 | 1.79 | 1.78 | |||||||||
|
Combustion
turbine/diesel generators
|
4.70 | 4.54 | 4.55 | |||||||||
|
Transmission
|
2.53 | 2.57 | 2.52 | |||||||||
|
Other
|
7.05 | 6.26 | 5.60 | |||||||||
Depreciation expense for the years
ended September 30, 2007, 2006, and 2005, was $1,048 million, $1,090 million,
and $1,132 million, respectively. The single major reason for the
reduction in depreciation expense for 2007 and 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. The change in the depreciation rate for the Other asset
class category was due to the addition of communication-type equipment in 2007
having a depreciable life of five years.
Property,
plant, and equipment also includes assets recorded under capital lease
agreements which primarily consist of office facilities of $30 million and $39
million as of September 30, 2007 and 2006, respectively, and fuel fabrication
and blending facilities of $39 million and $45 million as of September 30, 2007
and 2006, respectively.
Blended Low Enriched Uranium
Program
Under the blended low enriched uranium
(“BLEU”) program, TVA, the Department of Energy (“DOE”), and nuclear fuel
contractors have entered into agreements providing for surplus highly enriched
uranium to be blended with other uranium down to a level that allows the blended
uranium to be fabricated into fuel that can be used in nuclear power
plants. This blended nuclear fuel was first loaded in a Browns Ferry
reactor in 2005, which initiated the amortization of the costs of the BLEU fuel
assemblies to nuclear fuel expense.
Under the terms of an interagency agreement between TVA and DOE, DOE supplies
off-specification, highly enriched uranium materials to the appropriate third
party fuel processors for processing into usable fuel for TVA. In
exchange, DOE will participate to a degree in the savings generated by TVA’s use
of this blended nuclear fuel. Over the life of the program, TVA
projects that DOE’s share of savings generated by TVA’s use of this blended
nuclear fuel could result in future payments to DOE of as much as $257
million. TVA anticipates these future payments could begin in 2009
and last until 2013. 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. At
September 30, 2007, this obligation was $6 million.
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. In accordance with the requirements of EITF No. 01-08,
“Determining Whether an
Arrangement Contains a Lease,” and SFAS No. 13, “Accounting for Leases,”
however, 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 $7 million and $13
million at September 30, 2007 and 2006, respectively. Additionally,
TVA has recognized asset amortization expense of $6 million and $6 million and
interest expense of $0.4 million and $1 million related to the capital lease
obligation through September 30, 2007 and 2006, respectively.
Investment Funds
Investment funds consist primarily of trust funds designated to fund
nuclear decommissioning requirements (see Note 15 — Contingencies — Decommissioning
Costs), asset retirement obligations (see Note 5 — Asset Retirement Trust), and
the supplemental executive retirement plan (“SERP”). See Note 14 — Supplemental Executive Retirement
Plan. Decommissioning funds and SERP funds, which are
classified as trading, are invested in portfolios of securities generally
designed to earn returns in line with overall equity market
performance. Asset retirement funds, which are classified as trading,
are invested in commingled funds designed to earn returns in line with fixed
income market performance.
Other
Long-Term Assets
The year-end balances of TVA’s Other
long-term assets are as follows:
Other
Long-Term Assets
As of
September 30
|
2007
|
2006
|
|||||||
|
Loans
and long-term receivables, net
|
$ | 79 | $ | 80 | ||||
|
Intangible
asset related to pension prior service cost
|
– | 280 | ||||||
|
Valuation
of currency swaps
|
280 | 246 | ||||||
|
Valuation
of commodity contracts
|
16 | 487 | ||||||
| $ | 375 | $ | 1,093 | |||||
For additional information on the
components of Other long-term assets, see Note 1 — Allowance for Uncollectible
Accounts, Note 10 — Overview of Accounting Treatment,
Commodity Contracts, and Swaps, Note 13 — Loans and Other Long-term
Receivables, and Note 14 — Defined Benefit Pension Plan —
Components of Plan, Other Postretirement Benefits — Components of Other
Postretirement Benefits, and Supplemental Executive Retirement
Plan.
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 entitles the
purchaser to a $0.025/kilowatt-hour discount on a specified quantity of firm
power over a period of years (five, 10, 15, or 20) for each kilowatt-hour in the
prepaid block. The remainder of the price of the kilowatt-hours
delivered to the customer is due upon billing.
TVA did not offer the DEU program in
2007, 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, 2007 and 2006, 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, 2007, $25.9 million has been applied
against power billings on a cumulative basis during the life of the program, of
which over $5.6 million was recognized as noncash revenue during 2007, 2006, and
2005.
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, 2007 and 2006, 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, 2007, $390.4 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 2007,
2006, and 2005.
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 15 — 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 insurance for certain conventional (non-nuclear) assets as
well as outage insurance (business interruption) for selected conventional
generating assets. TVA also purchases liability insurance which
provides coverage for its directors and officers subject to the terms and
conditions of the policy.
Sale of Receivables/Loans
During 2007, TVA sold $2 million of
receivables at par such that TVA did not recognize a gain or loss on the sale.
These receivables were from a power customer and were related to the
construction of a substation. The proceeds from the sale of these
receivables are included in the Cash Flow Statement under the caption Cash flows
from investing activities.
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 represented receivables from power customers related
to the construction of a substation and other energy conservation
projects. The proceeds from the sale of these receivables are
included in the Cash Flow Statement under the caption Cash flows from investing
activities.
TVA did not retain any claim on these
receivables sold, and they are no longer reported on TVA’s Balance
Sheets.
Asset Retirement
Obligations
In accordance with the provisions of
SFAS No. 143, “Accounting for
Asset Retirement Obligations," TVA recognizes legal obligations
associated with the future retirement of certain tangible long-lived
assets. TVA records estimates of such disposal costs only at the time
the legal obligation arises. See Note 5.
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 investments, amortization of
the decommissioning regulatory asset, and interest expense on the
decommissioning liability are deferred as a regulatory asset. See
Note 15 — Contingencies —
Decommissioning Costs. Beginning in 2003, TVA evaluated the
nature and scope of its decommissioning policy as it relates to all electric
plants. 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 5. On September 30, 2006, TVA
began applying the guidance of Financial Accounting Standards Board (“FASB”)
Interpretation (“FIN”) No. 47, “Accounting for Conditional Asset
Retirement Obligations—an Interpretation of FASB Statement No.
143.” See Note 5 for the effects of applying this
interpretation.
Capitalized Revenue During
Pre-Commercial Plant Operations
As part of the process of restarting
Browns Ferry Unit 1, TVA commenced pre-commercial plant operations on June 2,
2007. The pre-commercial plant operations period ended July 31, 2007,
and commercial operations began on August 1, 2007. The electricity
produced during the pre-commercial plant operations period was used to serve the
demands of the system; therefore, TVA calculated estimates of revenue realized
from such pre-commercial generation based on the guidance provided by FERC
regulations. The calculated revenue of $57 million was capitalized to
offset project costs and is reported as a contra-revenue account on the income
statement. During this same period, TVA capitalized operating costs,
including fuel, of over $9 million.
Discounts
on Sales
TVA’s DEU program (see Note 1 — Energy Prepayment
Obligations) allows customers to use cash on hand to prepay TVA for some
of their power needs, providing funding to TVA and a savings to customers in the
form of a discount on future purchases. The distributor customer receives a
discount on a specified volume of firm energy purchased. The
supplement to the power contract specifies the discount rate (2.5 cents per
kilowatt-hour), the monthly block of kilowatt-hours to which the discount
applies, the number of years (term), and contingencies upon contract
termination.
TVA’s largest customer, MLGW, also has
a power prepayment agreement (see Note 1 — Energy Prepayment
Obligations) under which it has prepaid $1.5 billion for a fixed amount
of power. TVA repays MLGW in the form of a monthly credit sufficient
for MLGW to pay debt service on its prepayment bonds plus a return on
investment.
Discounts for these programs amounted
to $47 million for each of the years ended September 30, 2007, 2006, and
2005.
Allowance for Funds Used During
Construction
TVA capitalizes AFUDC based on the average interest rate of TVA’s
outstanding debt. The allowance is applicable to construction in
progress and nuclear fuel fabrication. Beginning in 2008, TVA will
continue to capitalize a portion of current interest costs associated with funds
invested in most nuclear fuel inventories, but interest on funds invested in
construction projects will be capitalized only if (1) the expected total
cost of a project is $1 billion or more and (2) the estimated construction
period is at least three years.
Software Costs
TVA capitalizes certain costs incurred
in connection with developing or obtaining internal-use
software. Capitalized software costs are included in Property, plant,
and equipment on the Balance Sheet and are primarily amortized over five
years. TVA capitalized costs of $22 million in 2007 and $2 million in
2006 related to an enterprise management project. Software costs that
do not meet capitalization criteria are expensed as incurred.
Research and Development
Costs
Research and development costs are
expensed when incurred. TVA’s research programs include those related to
transmission technologies, emerging technologies (clean coal, renewables,
distributed resources, and energy efficiency), technologies related to
generation (fossil, nuclear, and hydro), and environmental technologies. During
2007, 2006, and 2005 research and development costs of $20 million, $20 million,
and $21 million, respectively, 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 off-system sales with other utilities,
with a provision for minimum payments under certain circumstances.
Impairment of Assets
TVA evaluates long-lived assets for
impairment in accordance with the provisions of SFAS No. 144, “Accounting for the Impairment or
Disposal of Long-Lived Assets,” when events or changes in circumstances
indicate that the carrying value of such assets may not be
recoverable. For long-lived assets, TVA bases its evaluation on
impairment indicators such as the nature of the assets, the future economic
benefit of the assets, any historical or future profitability measurements, and
other external market conditions or factors that may be present. If
such impairment indicators are present or other factors exist that indicate that
the carrying amount of an asset may not be recoverable, TVA determines whether
an impairment has occurred based on an estimate of undiscounted cash flows
attributable to the asset as compared with the carrying value of the
asset. If an impairment has occurred, the amount of the impairment
recognized is measured as the excess of the asset’s carrying value over its fair
value. See Note 7.
Impact of New Accounting Standards and
Interpretations
Accounting Changes and Error
Corrections. In May 2005, 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 SFAS 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. This statement became effective for TVA beginning in
2007 and did not have an impact on TVA’s financial statements for
2007.
Accounting for Planned Major
Maintenance Activities. On September 8, 2006, FASB released
FASB Staff Position (“FSP”) AUG AIR-1, “Accounting for Planned Major
Maintenance Activities.” The FSP addresses the accounting for
planned major maintenance activities and amends certain provisions in the
American Institute of Certified Public Accountants Industry Audit Guide, “Audits of Airline” and
Accounting Principles Board Opinion No. 28, “Interim Financial Reporting.” The
guidance in this FSP states that entities should adopt an accounting method that
recognizes overhaul expenses in the appropriate period. The following accounting
methods are most often employed/permitted: direct expensing method; built-in
overhaul method; or deferral method. The guidance in this FSP is applicable to
entities in all industries and must be applied to the first fiscal year
beginning after December 15, 2006. TVA will adopt this guidance for
2008. Because TVA’s policy is to expense maintenance costs as
incurred (direct expensing method), the adoption of this FSP is not expected to
have a material impact on TVA’s results of operations or financial
position.
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 that currently require fair value measurement. 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. SFAS No. 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 is evaluating the
requirements of this statement and has not yet determined the impact of its
implementation, which may or may not be material to TVA’s results of operations
or financial position.
Fair Value
Option. In February 2007, FASB issued SFAS No. 159, “The Fair Value Option for Financial
Assets and Financial Liabilities — Including an amendment of FASB Statement No.
115.” This standard permits an entity to choose to measure many financial
instruments and certain other items at fair value. The fair value
option established by SFAS No.159 permits all entities to choose to measure
eligible items at fair value at specified election dates. A business
entity will report unrealized gains and losses on items for which the fair value
option has been elected in earnings at each subsequent reporting
date. Most of the provisions in this statement are
elective. The provisions of SFAS No. 159 are effective as of the
beginning of an entity’s first fiscal year that begins after November 15,
2007. Early adoption is permitted as of the beginning of the previous
fiscal year provided that the entity makes that choice in the first 120 days of
that fiscal year and also elects to apply the provisions of SFAS No. 157, “Fair Value Measurements.” At
this time, TVA is evaluating the requirements of this statement and has not yet
determined the potential impact of its implementation, which may or may not be
material to TVA’s results of operations or financial position.
Offsetting
Amounts. On April 30, 2007, FASB issued FASB Staff Position
(“FSP”) FIN No. 39-1,
“Amendment of FASB Interpretation No. 39,” which addresses certain
modifications to FASB Interpretation No. 39, “Offsetting of Amounts Related to
Certain Contracts.” This FSP replaces the terms “conditional contracts”
and “exchange contracts” with the term “derivative instruments” as defined in
SFAS No. 133, “Accounting for
Derivative Instruments and Hedging Activities.” The FSP also permits a
reporting entity to offset fair value amounts recognized for the right to
reclaim cash collateral (a receivable) or the obligation to return cash
collateral (a payable) against fair value amounts recognized for derivative
instruments executed with the same counterparty under the same master netting
arrangement. The guidance in the FSP is effective for fiscal years
beginning after November 15, 2007, with early application
permitted. At this time, TVA is evaluating the requirements of this
guidance and has not yet determined the potential impact of its implementation,
which may or may not be material to TVA’s financial position.
Employers’ Accounting for
Defined Accounting for Defined Benefit Pension and Other Postretirement
Plans. On September 30, 2007, TVA adopted 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 requires 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 requires an employer
to: recognize in its statement of financial position an asset for a
plan’s overfunded status or a liability for a plan’s underfunded status; measure
a plan’s assets and its obligations that determine its funded status as of the
end of the employer’s fiscal year (with limited exceptions); and recognize
changes in the funded status of a defined benefit postretirement plan in the
year in which the changes occur.
Upon adoption of SFAS No. 158, TVA
recorded a net benefit liability equal to the underfunded status of certain
pension and other postretirement benefit plans at September 30, 2007 in the
amounts of $664 million and $464 million, respectively. On September
30, 2007, the unrecognized prior service costs and unrecognized gains and
losses were recognized as components of accumulated other comprehensive
income which were then reclassified to and recorded as components
of a regulatory asset related to TVA's unfunded benefit
plans. TVA did not have any unrecognized transition obligation
losses. At September 30, 2007, TVA's unfunded benefit plans'
regulatory asset included unamortized prior service costs
and unamortized net actuarial losses of approximately $830 million and
$143 million, respectively, related to pensions and other postretirement
benefits.
Rate-regulated entities may recognize
regulatory assets or liabilities as a result of timing differences between the
recognition of costs, as recorded with SFAS No. 87 and SFAS No.106, and
costs recovered through the ratemaking process. As a result of the
adoption of SFAS No. 158, TVA increased the existing unfunded benefit
plans' regulatory asset by approximately $721 million related to the
defined benefit pension and postretirement plans for amounts that
would otherwise be charged to accumulated other comprehensive income under SFAS
No. 158. See Note 14.
2.
Restatement
The accompanying financial statements
as of September 30, 2007 and 2006, and for each of the two years then ended have
been restated. TVA determined that the method implemented to estimate unbilled
revenues in September 2006 had resulted in errors in unbilled revenue presented
in TVA’s financial statements for the fiscal years ended September 30, 2006, and
2007, and the quarterly periods ended December 31, 2006, March 31, 2007, June
30, 2007, December 31, 2007, and March 31, 2008. There was no effect
on periods prior to the three months ended September 30, 2006.
Under TVA’s end-use billing
arrangements with its distributor customers (“distributors”), TVA relies on the
distributors to report their end-use sales. Because of the delay between the
wholesale delivery of power to the distributor and the report of end-use sales
to TVA, TVA must estimate the unbilled revenue at the end of each financial
reporting period. In September 2006, TVA implemented a change in methodology for
estimating unbilled revenue for electricity sales which resulted in an increase
of $232 million in unbilled revenue (2.6 percent of operating revenue) for
2006.
The estimation process implemented in
September 2006 utilized the distributors’ average rates and an estimate of the
number of days of revenue outstanding to reflect the delay in reporting the
end-use sales to TVA (“days outstanding”). The number of days
outstanding was derived using a procedure similar to a cross-correlation
calculation that compared the monthly retail load to the monthly wholesale
load. The intent was to reflect in the unbilled estimate the end-use
sales that would be reported that month by distributors plus any remaining sales
that would not be reported until the following month due to the delay between
wholesale delivery and end-use reporting.
TVA has determined that the
process implemented in September 2006 overestimated the days outstanding and
that this overestimation resulted in an error in recording unbilled revenue and
unbilled receivable. The
previous unbilled process also failed to consider the annual true-up of each
distributor’s reported distribution losses. The annual true-up
reconciles total end-use kilowatt-hour (“kWh”) sales and revenue reported by
each distributor with the kWh sales recorded for each distributor at
wholesale.
TVA has
used a new process for estimating unbilled revenue for 2006 and
2007. This process carries over only the portion of sales from the
distributor’s meter read date to the month-end. Those sales along with the
current month sales are then priced at rates based on each distributor’s
customer and product mix. Additionally, the true-up component has
been added to the unbilled calculation to reflect any timing differences that
occur between the retail and wholesale billing cycles. Due to the new
process, an adjustment was made to increase revenue in 2007 by $73 million and
to decrease revenue by $200 million in 2006.
The restatement of unbilled revenue
also affected TVA’s fuel cost adjustment (“FCA”) calculation. The FCA is a
mechanism by which TVA collects the direct cost of fuel used in its generating
facilities and also the energy costs of purchased power used to serve customer
power demand. Implementation of the FCA occurred in October 2006 as a
joint effort between TVA and its customers. The goal of the FCA is
timely recovery of fuel-related expenses to reduce the volatility driven by fuel
and purchased power markets. Under TVA’s FCA methodology, adjustments
to rates are based primarily on the difference between forecasted and actual
expenses for the upcoming quarter as well as the difference between forecasted
and actual revenues for the upcoming quarter. Because the FCA
adjustments are forward-looking, there is typically a difference between what is
collected in rates and what actual expense is realized over the course of the
quarter. This difference is added to or subtracted from a deferred
account on TVA’s balance sheet.
The restatement of unbilled revenue
changed TVA’s forecasted revenues, and since forecasted revenues are a major
component of the FCA calculation, the change in forecasted revenues required a
restatement of the amounts in TVA’s deferred FCA account. In the
Original 10-K, TVA reported a FCA deferred balance of $197 million at September
30, 2007, which was restated to a deferred balance of $150 million. Of the $150
million, $18 million is a deferred asset and $132 million is a current
receivable.
The unbilled revenue error also
affected the application of distributor prepayments. The balance in the
distributors’ unbilled accounts receivable is offset by a reduction in the
advance collections of those distributors who make prepayments for their power.
As a result of the change in unbilled revenue, the balances in the unbilled
receivable and advance collections accounts were also adjusted. The adjustment
related to distributor prepayments had no effect on the account balances as
of September 30, 2007, and increased the balance in the receivable and
advance collections accounts by $1 million as of September 30,
2006.
TVA has
evaluated these errors and determined that the impact was an overstatement of
net income for the fiscal year ended September 30, 2006, and an understatement
of net income for the fiscal year ended September 30, 2007. The changes to the
financial statements as of or for the respective years primarily involves
accounts receivable and retained earnings on the balance sheets, and operating
revenues and net income on the statements of income. The errors and restatements
have no impact on cash and cash equivalents.
In addition to the unbilled revenue and
FCA adjustments, there were certain miscellaneous items that were previously
deemed to be immaterial by management which have been corrected in the period in
which they were identified. Summary restatements tables are presented
below. References in the “Note” column correspond to lines on the Statements of
Income and Balance Sheets following these tables. Accordingly,
previously reported amounts are being restated to properly reflect the
accounting for these items as follows:
Statements
of Income
Summary
of Restatements
|
Description
of Adjustment
|
2007
|
Note
|
2006
|
Note
|
||||||||
|
Operating
revenues
|
Unbilled
revenue adjustments
|
$ | 73 | $ | (200 | ) | ||||||
|
Reclassification
of expenses previously netted with revenue
|
9 | 8 | ||||||||||
| 82 | I07-1 | (192 | ) | I06-1 | ||||||||
|
Operating
expenses
|
Fuel
cost adjustment
|
46 | – | |||||||||
|
Write
off of construction projects
|
(5 | ) | 5 | |||||||||
|
Capitalization
of construction projects
|
(8 | ) | 8 | |||||||||
|
Financing
cost interest reclassification
|
(48 | ) | (49 | ) | ||||||||
|
Reclassification
of expenses previously netted with revenue
|
15 | 26 | ||||||||||
|
Additional
legal expense
|
3 | – | ||||||||||
|
Intracompany
charges reclassification
|
– | (12 | ) | |||||||||
| 3 | I07-2 | (22 | ) | I06-2 | ||||||||
|
Operating
income
|
79 | (170 | ) | |||||||||
|
Other
income
|
Additional
legal reserve
|
3 | (3 | ) | ||||||||
|
Reclassification
of other income previously reported as revenue
|
6 | 18 | ||||||||||
|
Intrarcompany
charges reclassification
|
– | (12 | ) | |||||||||
| 9 | I07-3 | 3 | I06-3 | |||||||||
|
Interest
expense
|
Financing
cost interest reclassification
|
48 | I07-4 | 49 | I06-4 | |||||||
|
Net
income
|
$ | 40 | $ | (216 | ) | |||||||
Balance
Sheets
Summary
of Restatements
|
Description
of Adjustment
|
2007
|
Note
|
2006
|
Note
|
|||||||||
|
Current
assets
|
|||||||||||||
|
Accounts
receivable
|
Unbilled
revenue adjustments
|
$ | (127 | ) | $ | (199 | ) | ||||||
|
Accounts
receivable
|
Swap
asset reclassification
|
– | 21 | ||||||||||
|
Accounts
receivable
|
Fuel
cost adjustments
|
132 | – | ||||||||||
|
Inventories
and other
|
Derivative
reclassification
|
– | 22 | ||||||||||
| 5 | B07-1 | (156 | ) | B06-1 | |||||||||
|
Property,
plant, and equipment
|
|||||||||||||
|
Accumulated
depreciation
|
Capitalization
of construction projects
|
– | (8 | ) | |||||||||
|
Construction
in progress
|
Write
off of construction projects
|
– | (5 | ) | |||||||||
|
Construction
in progress
|
Unrecorded
software liability
|
4 | – | ||||||||||
| 4 | B07-2 | (13 | ) | B06-2 | |||||||||
|
Regulatory
and other long-term assets
|
|||||||||||||
|
Regulatory
assets
|
Fuel
cost adjustments
|
(179 | ) | – | |||||||||
|
Regulatory
assets
|
Derivative
reclassification
|
– | (22 | ) | |||||||||
|
Other
long-term assets
|
Swap
asset reclassification
|
– | (21 | ) | |||||||||
| (179 | ) | B07-3 | (43 | ) | B06-3 | ||||||||
|
Total
restatement of assets
|
$ | (170 | ) | $ | (212 | ) | |||||||
|
Current
liabilities
|
|||||||||||||
|
Accrued
liabilities
|
Derivative
reclassification
|
$ | – | $ | 22 | ||||||||
|
Accrued
liabilities
|
Legal
reserve adjustment
|
– | 3 | ||||||||||
|
Accrued
liabilities
|
Unbilled
revenue adjustments
|
– | 1 | ||||||||||
|
Accrued
liabilities
|
Fuel
cost adjustments
|
(1 | ) | – | |||||||||
|
Accrued
liabilities
|
Unrecorded
software liability
|
4 | – | ||||||||||
|
Accrued
liabilities
|
Legal
expense adjustment
|
3 | – | ||||||||||
| 6 | B07-4 | 26 | B06-4 | ||||||||||
|
Other
liabiliites
|
|||||||||||||
|
Other
liabilities
|
Derivative
reclassification
|
– | (22 | ) | B06-5 | ||||||||
|
Total
restatement of liabilities
|
6 | 4 | |||||||||||
|
Proprietary
capital
|
|||||||||||||
|
Retained
earnings
|
Write
off of construction projects
|
4 | (4 | ) | |||||||||
|
Retained
earnings
|
Legal
reserve adjustment
|
4 | (4 | ) | |||||||||
|
Retained
earnings
|
Derivative
reclassification
|
8 | (8 | ) | |||||||||
|
Retained
earnings
|
Unbilled
revenue adjustments
|
73 | (200 | ) | |||||||||
|
Retained
earnings
|
Fuel
cost adjustments
|
(46 | ) | – | |||||||||
|
Retained
earnings
|
Legal
expense adjustment
|
(3 | ) | – | |||||||||
|
Retained
earnings
|
Beginning
retained earnings adjustment
|
(216 | ) | – | |||||||||
| (176 | ) | B07-5 | (216 | ) | B06-6 | ||||||||
|
Total
restatement of liabilities and proprietary capital
|
$ | (170 | ) | $ | (212 | ) | |||||||
Accordingly,
previously reported amounts are being restated to properly reflect the
accounting for these items as follows:
Statements of
Income
The
following table summarizes the statements of income for the periods indicated,
giving effect to the restatement adjustments described above and showing
previously reported amounts and restated amounts for the years ended
September 30, 2007, and 2006.
|
Statement
of Income
|
|
2007
|
2006
|
|||||||||||||||||||||||||
|
As
Previously Reported
|
Increase
(Decrease)
|
Note
|
As
Restated
|
As
Previously Reported
|
Increase
(Decrease)
|
Note
|
As
Restated
|
|||||||||||||||||||
|
Operating
revenues
|
||||||||||||||||||||||||||
|
Sales
of electricity
|
||||||||||||||||||||||||||
|
Municipalities
and cooperatives
|
$ | 7,774 | 73 | $ | 7,847 | $ | 7,859 | (200 | ) | $ | 7,659 | |||||||||||||||
|
Industries
directly served
|
1,221 | – | 1,221 | 1,065 | – | 1,065 | ||||||||||||||||||||
|
Federal
agencies and other
|
112 | – | 112 | 116 | – | 116 | ||||||||||||||||||||
|
Other
revenue
|
137 | 9 | 146 | 135 | 8 | 143 | ||||||||||||||||||||
|
Operating
revenues
|
9,244 | 82 | 9,326 | 9,175 | (192 | ) | 8,983 | |||||||||||||||||||
|
Revenue
capitalized during pre-commercial plant operations
|
(57 | ) | – | (57 | ) | – | – | – | ||||||||||||||||||
|
Net
operating revenues
|
9,187 | 82 | 107-1 | 9,269 | 9,175 | (192 | ) | 106-1 | 8,983 | |||||||||||||||||
|
Operating
expenses
|
||||||||||||||||||||||||||
|
Fuel
and purchased power
|
3,382 | 67 | 3,449 | 3,333 | 9 | 3,342 | ||||||||||||||||||||
|
Operating
and maintenance
|
2,382 | (50 | ) | 2,332 | 2,372 | (44 | ) | 2,328 | ||||||||||||||||||
|
Depreciation,
amortization, and accretion
|
1,481 | (8 | ) | 1,473 | 1,492 | 8 | 1,500 | |||||||||||||||||||
|
Tax
equivalents
|
452 | (1 | ) | 451 | 376 | – | 376 | |||||||||||||||||||
|
Loss
on asset impairment
|
26 | (5 | ) | 21 | 9 | 5 | 14 | |||||||||||||||||||
|
Total
operating expenses
|
7,723 | 3 | 107-2 | 7,726 | 7,582 | (22 | ) | 106-2 | 7,560 | |||||||||||||||||
|
Operating
income
|
1,464 | 79 | 1,543 | 1,593 | (170 | ) | 1,423 | |||||||||||||||||||
|
Other
income
|
64 | 9 | 107-3 | 73 | 77 | 3 | 106-3 | 80 | ||||||||||||||||||
|
Other
expense
|
(2 | ) | – | (2 | ) | (2 | ) | – | (2 | ) | ||||||||||||||||
|
Unrealized
gain/(loss) on derivative contracts, net
|
41 | – | 41 | (15 | ) | – | (15 | ) | ||||||||||||||||||
|
Interest
expense
|
||||||||||||||||||||||||||
|
Interest
on debt and leaseback obligations
|
1,342 | 48 | 1,390 | 1,357 | 49 | 1,406 | ||||||||||||||||||||
|
Amortization
of debt discount, issue, and reacquisition costs, net
|
19 | – | 19 | 21 | – | 21 | ||||||||||||||||||||
|
Allowance
for funds used during construction and nuclear fuel
expenditures
|
(177 | ) | – | (177 | ) | (163 | ) | – | (163 | ) | ||||||||||||||||
|
Net
interest expense
|
1,184 | 48 | 107-4 | 1,232 | 1,215 | 49 | 106-3 | 1,264 | ||||||||||||||||||
|
Income
before cumulative effects of accounting changes
|
383 | 40 | 423 | 438 | (216 | ) | 222 | |||||||||||||||||||
|
Cumulative
effect of change in accounting for conditional
asset
retirement obligations
|
– | – | – | (109 | ) | – | (109 | ) | ||||||||||||||||||
|
Net
income
|
$ | 383 | $ | 40 | $ | 423 | $ | 329 | (216 | ) | $ | 113 | ||||||||||||||
Balance
Sheets
The
following table sets forth the balance sheets giving effect to the restatement
and other adjustments described above and showing previously reported amounts
and restated amounts as of September 30, 2007, and 2006.
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Balance
Sheets
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