Tennessee Valley Authority - Annual Report: 2007 (Form 10-K)
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
(MARK
ONE)
[
X ]
ANNUAL REPORT PURSUANT TO SECTION 13, 15(d), OR 37 OF THE
SECURITIES
EXCHANGE ACT OF 1934
For
the fiscal year ended September 30, 2007
OR
[ ]
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
(I.R.S.
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
[ ] 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 [ ] 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 [ ]
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, or a non-accelerated filer. See definition of
“accelerated filer and large accelerated filer” in Rule 12b-2 of the
Securities Exchange Act. (Check one): Large accelerated
filer [ ] Accelerated filer
[ ] Non-accelerated filer [ X
]
Indicate
by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Securities Exchange Act). Yes
[ ] No [ X ]
Page
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This
Annual Report on Form 10-K
(“Annual Report”) contains forward-looking statements relating to future events
and future performance. All statements other than those that are
purely historical may be forward-looking statements.
In
certain cases, forward-looking
statements can be identified by the use of words such as “may,” “will,”
“should,” “expect,” “anticipate,” “believe,” “intend,” “project,” “plan,”
“predict,” “assume,” “forecast,” “estimate,” “objective,” “possible,”
“probably,” “likely,” “potential,” or other similar expressions.
Examples
of forward-looking statements
include, but are not limited to:
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Statements
regarding strategic objectives;
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Projections
regarding potential rate actions;
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Estimates
of costs of certain 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:
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 $9.1 billion, $9.0 billion, 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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Alabama
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$1,254
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$1,265
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$1,051
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Georgia
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204
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228
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186
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Kentucky
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1,080
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906
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830
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Mississippi
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799
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823
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671
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North
Carolina
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57
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47
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38
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Tennessee
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5,688
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5,751
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4,806
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Virginia
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8
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7
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4
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Subtotal
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9,090
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9,027
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7,586
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Sale
for resale
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17
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13
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95
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Subtotal
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9,107
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9,040
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7,681
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Other
revenues
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137
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135
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101
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Operating
revenues
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$9,244
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$9,175
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$7,782
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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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Municipalities
and cooperatives
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$7,774
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$7,859
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$6,539
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Industries
directly served
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1,221
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1,065
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961
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Federal
agencies and other
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Federal
agencies directly served
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95
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103
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86
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Off-system
sales
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17
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13
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95
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Subtotal
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9,107
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9,040
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7,681
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Other
revenues
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137
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135
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101
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Operating
revenues
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$9,244
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$9,175
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$7,782
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Municipalities
and
Cooperatives
Revenues
from distributor customers
accounted for 84.1 percent of TVA’s total operating revenues in
2007. At September 30, 2007, TVA had wholesale power contracts with
158 municipalities and cooperatives. All of these contracts require
distributor customers to purchase all of their electric power and energy
requirements from TVA.
All
distributor customers purchase
power under one of three basic termination notice arrangements:
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Contracts
that require five years’ notice to
terminate;
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Contracts
that require 10 years’ notice to terminate;
and
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Contracts
that require 15 years’ notice to
terminate.
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The
number of distributor customers
with the contract arrangements described above, the revenues derived from such
arrangements in 2007, and the percentage of TVA’s 2007 total operating revenues
represented by these revenues are summarized in the table below.
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TVA
Distributor Customer Contracts
As
of September 30, 2007
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Contract
Arrangement
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Number
of Distributor Customers
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Sales
to Distributor Customers in 2007
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Percentage
of Total Operating Revenues in 2007
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(in
millions)
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15-Year
termination notice
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5
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$ |
87
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0.9
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% | |||
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10-Year
termination notice
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48
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2,570
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27.8
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%
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5-Year
termination notice *
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102
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5,066
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54.8
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% | ||||
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Notice
given - less than 5 years remaining *
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3
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51
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0.6
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% | ||||
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Total
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158
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$ |
7,774
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84.1
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% | |||
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*
Ordinarily the distributor customer and TVA have the same termination
notice period; however, in contracts with six of the distributor
customers
with 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).
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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 8.7 percent and 7.8 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 $51 million, or 0.6 percent
of
TVA’s operating revenues in 2007.
The
table
below lists the names and locations of the three distributor customers whose
termination notices were still in effect as of September 30, 2007, their
contract termination dates, the amount of revenues that TVA generated by selling
power to these distributor customers in 2007, and the percentage of TVA’s total
2007 operating revenues represented by these revenues.
Distributor
Customers with Termination Notices in Effect
As
of
September 30, 2007
(in
millions)
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Distributor
Customer
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Location
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Date
of Termination of Power Contract
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TVA
Sales to Distributor Customer
in
2007
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Percentage
of
TVA Operating Revenues in 2007
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Monticello
Electric Plant Board
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Kentucky
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November
2008
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$ 6
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0.1%
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Paducah
Power System
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Kentucky
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December
2009
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39
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0.4%
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Princeton
Electric Plant Board
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Kentucky
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January
2010
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6
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0.1%
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Total
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$ 51
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0.6%
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Other
Customers
Revenues
from industrial customers
directly served accounted for 13.2 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 $65 million in revenue. As of September 30, 2007, TVA
had recognized a regulatory asset of $197 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 and is 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%
|
||||
|
Combustion
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 12 — 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 14 — 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 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 14 — 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 14 — 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 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.
|
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
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 $4.7 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 12 — 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 12 — 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 to provide replacement lands for certain
entities whose lands were flooded or destroyed by dam or reservoir
construction and to grant easements and rights-of-way upon which
are
located transmission or distribution
lines.
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Under
Section 15d(g) of the TVA Act, TVA can dispose of real property in
connection with the construction of generating plants or other facilities
under certain circumstances.
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Under
40 U.S.C. § 1314, TVA has authority to grant easements for rights-of-way
or other purposes.
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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 $1.1 million with respect to other proceedings that have arisen
in
the normal course of TVA’s business. No assurance can be given that TVA will not
be subject to significant additional claims and liabilities. If actual
liabilities significantly exceed the estimates made, TVA’s results of
operations, liquidity, and financial condition could be materially adversely
affected.
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.
PART
II
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.
For
the
years ended September 30
(in
millions)
|
2007
|
2006
|
2005
|
2004
|
2003
|
|||||||||||||||
|
Operating
revenues1
|
|
$9,244
|
|
$9,175
|
|
$7,782
|
|
$7,525
|
|
$6,946
|
|||||||||
|
Revenue
capitalized during
pre-commercial
plant operations
|
(57)
|
–
|
–
|
–
|
–
|
||||||||||||||
|
Operating
expenses
|
(7,723)
|
2 |
(7,582)
|
2 |
(6,503)
|
2 |
(5,873)
|
3 |
|
(5,398)
|
|||||||||
|
Operating
income
|
1,464
|
1,593
|
1,279
|
1,652
|
1,548
|
||||||||||||||
|
Other
income, net 1,
4
|
62
|
75
|
64
|
51
|
39
|
||||||||||||||
|
Unrealized
gain (loss) on
derivative
contracts, net
|
41
|
(15)
|
3
|
(7)
|
(7)
|
||||||||||||||
|
Net
interest expense 4
|
(1,184)
|
(1,215)
|
(1,261)
|
(1,310)
|
(1,353)
|
||||||||||||||
|
Cumulative
effect of accounting changes
|
–
|
(109)
|
5 |
–
|
–
|
217
|
6 | ||||||||||||
|
Net
income
|
|
$383
|
|
$329
|
|
$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 $26 million, $9
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 $9 million
related to other Construction in progress assets. The 2006 Loss
on asset impairment included write-downs of $7 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 4.
(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.
|
|||||||||||||||||||
At
September 30
(in
millions)
|
2007
|
2006
|
2005
|
2004
|
2003
1
|
|||||||||||||||
|
Assets
|
|||||||||||||||||||
|
Current
assets 2
|
$2,431
|
$2,669
|
$2,176
|
$2,295
|
$2,238
|
||||||||||||||
|
Property,
plant, and equipment, net
|
24,828
|
24,434
|
23,888
|
23,699
|
23,125
|
||||||||||||||
|
Investment
funds
|
1,169
|
972
|
858
|
744
|
638
|
||||||||||||||
|
Regulatory
and other long-term assets
|
5,474
|
6,445
|
7,551
|
7,451
|
7,027
|
||||||||||||||
|
Total
assets
|
$33,902
|
$34,520
|
$34,473
|
$34,189
|
$33,028
|
||||||||||||||
|
|
|
|
|||||||||||||||||
|
Liabilities
and proprietary capital
|
|||||||||||||||||||
|
Current
liabilities 2
|
$3,423
|
$5,203
|
$6,724
|
$5,420
|
$5,819
|
3 | |||||||||||||
|
Regulatory
and other liabilities
|
6,400
|
7,074
|
7,606
|
7,168
|
5,114
|
||||||||||||||
|
Long-term
debt, net
|
21,099
|
19,544
|
17,751
|
19,337
|
20,201
|
||||||||||||||
|
Total
liabilities
|
30,922
|
31,821
|
32,081
|
31,925
|
31,134
|
||||||||||||||
|
Retained
earnings
|
1,939
|
1,565
|
1,244
|
1,162
|
783
|
||||||||||||||
|
Other
proprietary capital
|
1,041
|
1,134
|
1,148
|
1,102
|
1,111
|
||||||||||||||
|
Total
proprietary capital
|
2,980
|
2,699
|
2,392
|
2,264
|
1,894
|
||||||||||||||
|
Total
liabilities and proprietary capital
|
$33,902
|
$34,520
|
$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
|
|||||||||||||||
|
Lease/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)
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 $9.1 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 $65 million in revenue. As of September 30, 2007, TVA
had recognized a regulatory asset of $197 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, is
0.432 cents per kilowatt-hour and is 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):
|
||||||||||||
|
Operating
activities
|
$1,763
|
$2,014
|
$1,462
|
|||||||||
|
Investing
activities
|
(1,661)
|
(1,727)
|
(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 10 — 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
|
PrincipalAmount
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%
3
|
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
10.
$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 8 and Note 10 — 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 17 — 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 9 — 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 $2,014 million in 2006 to $1,763 million in
2007. This $251 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
$100 million decrease in cash used by changes in working capital
resulting
primarily from a smaller increase in accounts receivable of $142
million,
partially offset by a smaller increase in accounts payable and accrued
liabilities of $45 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.
|
|
|
•
|
A
decrease in cash paid for interest of $33 million in
2007.
|
Cash
used in investing activities
decreased from $1,727 million in 2006 to $1,661 million in 2007. This
$66 million decrease resulted primarily from:
|
|
•
|
A
decrease in expenditures for capital projects of
$93 million.
|
|
o
|
This
decrease is primarily a result of a decrease in expenditures for
the
Browns Ferry Unit 1 restart project of $262
million.
|
|
o
|
This
item was partially offset by:
|
|
–
|
An
increase in expenditures of $47 million related primarily to the
Watts Bar
Nuclear Plant steam generator replacement
project;
|
|
–
|
Increased
expenditures related to TVA’s coal-fired plants of $106 million primarily
resulting from:
|
|
•
|
Extensive
repairs during an extended outage at Paradise Fossil
Plant;
|
|
•
|
The
rehabilitation of a precipitator at Colbert Fossil Plant;
and
|
|
•
|
Increased
clean air expenditures primarily related to the scrubber projects
at the
Kingston and Bull Run Fossil Plants;
and
|
|
–
|
Increased
administrative capital expenditures related to certain process and
system
improvements.
|
|
|
•
|
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.
|
|
•
|
Expenditures
for the enrichment and fabrication of nuclear fuel of $26 million
related to the restart of Browns Ferry Unit
1.
|
|
|
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.
|
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 $552 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; and
|
|
•
|
An
increase in other deferred items of $55 million primarily due to
$22
million of increased contributions to the TVA Retirement System and
$15
million related to customer advances for
construction.
|
Net
cash used by changes in components
of working capital increased $117 million from 2005 primarily from:
|
•
|
A
larger increase in accounts receivable of $195 million due to increased
sales of the prior year and higher rates in 2006;
and
|
|
•
|
A
larger increase in inventories of $108 million due to higher priced
coal
and natural gas in ending inventory in 2006 and a higher volume of
coal on
hand at the end of 2006.
|
These
items were partially offset
by:
|
•
|
A
$125 million increase in accounts payable and accrued liabilities
in 2006
compared to a $16 million decrease in 2005 primarily due to changes
in the
amount of collateral held by TVA of $88 million under terms of a
swap
agreement and higher costs for fuel and purchased power;
and
|
|
•
|
A
$23 million increase in accrued interest in 2006 compared to a $22
million
decrease in 2005 due to timing of interest payments on Bonds issued
relative to Bonds retired during
2006.
|
Cash
used in investing activities
increased $539 million from 2005 to 2006. The increase is primarily
due to:
|
•
|
Sales
of short-term investments of $335 million in 2005 with no comparable
sales
in 2006;
|
|
•
|
An
increase in expenditures for the enrichment and fabrication of nuclear
fuel of $136 million for the Sequoyah Unit 2 and Watts Bar Unit 1
reloads
scheduled to be completed in the first quarter of 2007, and expenditures
related to uranium conversion and enrichment for Browns Ferry Unit
1;
|
|
•
|
An
increase in expenditures for capital projects of $60 million 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 8, 10, and 14 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 10 — 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
|
|||||||||
|
Operating
revenues
|
$9,244
|
$9,175
|
$7,782
|
||||||||
|
Revenue
capitalized during pre-commercial plant operations
|
(57)
|
–
|
–
|
||||||||
|
Operating
expenses
|
(7,723)
|
(7,582)
|
(6,503)
|
||||||||
|
Operating
income
|
1,464
|
1,593
|
1,279
|
||||||||
|
Other
income
|
64
|
77
|
68
|
||||||||
|
Other
expense
|
(2)
|
(2)
|
(4)
|
||||||||
|
Unrealized
gain/(loss) on derivative contracts, net
|
41
|
(15)
|
3
|
||||||||
|
Interest
expense, net
|
(1,184)
|
(1,215)
|
(1,261)
|
||||||||
|
Income
before cumulative effects of accounting changes
|
383
|
438
|
85
|
||||||||
|
Cumulative
effect of change in accounting for conditional asset retirement
obligations
|
–
|
(109)
|
–
|
|
|||||||
|
Net
income
|
$383
|
$329
|
$85
|
||||||||
|
|
|||||||||||
|
Sales
(millions of kWh)
|
174,810
|
176,370
|
171,498
|
||||||||
2007
Compared to 2006
Net
income for 2007 was $383 million
compared with net income of $329 million for 2006. The $54 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
$69 million increase in operating
revenues;
|
|
•
|
A
change of $56 million in net unrealized gain/(loss) on derivative
contracts; and
|
|
•
|
Lower
net interest expense of $31
million.
|
These
items were partially offset
by:
|
•
|
A
$141 million increase in operating
expenses;
|
|
•
|
A
change of $57 million in revenue capitalized during pre-commercial
plant
operations; and
|
|
•
|
A
$13 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
|
|||||||||||||||||||
|
Operating
revenues and sales of electricity
|
||||||||||||||||||||||||
|
Municipalities
and cooperatives
|
$
7,774
|
$
7,859
|
(1.1
|
%) |
141,742
|
143,343
|
(1.1
|
%) | ||||||||||||||||
|
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
|
137
|
135
|
1.5
|
% |
–
|
–
|
–
|
|||||||||||||||||
|
|
||||||||||||||||||||||||
|
Total
operating revenues and sales of electricity
|
$
9,244
|
$
9,175
|
0.8
|
% |
174,810
|
176,370
|
(0.9
|
%) | ||||||||||||||||
Significant
items contributing to the
$69 million increase in operating revenues included:
|
•
|
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
$2 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:
|
•
|
An
$85 million decrease in revenue from municipalities and cooperatives
reflecting decreased sales of 1.1 percent partially offset by an
increase
in average rates of 0.9 percent that yielded $3 million in increased
revenue; and
|
|
|
•
|
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.
A
significant item contributing to the
1,560 million kilowatt-hour decrease in electricity sales included a 1,601
million kilowatt-hour decrease in sales to municipalities and cooperatives
attributable to a change in TVA's unbilled estimate methodology in
2006. See Note 1 — Accounts Receivable. This item
was partially offset by an increase in residential power demand (which is more
weather sensitive) as a result of an increase in combined degree days of 258
days, or 4.9 percent, during 2007.
This
decrease in sales to
municipalities and cooperatives was partially offset by:
|
•
|
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
|
|||||||||
|
Operating
expenses
|
|||||||||||
|
Fuel
and purchased power
|
$
3,382
|
$
3,333
|
1.5
|
% | |||||||
|
Operating
and maintenance
|
2,382
|
2,372
|
0.4
|
% | |||||||
|
Depreciation,
amortization, and accretion
|
1,481
|
1,492
|
(0.7
|
%) | |||||||
|
Tax
equivalents
|
452
|
376
|
20.2
|
% | |||||||
|
Loss
on asset impairment
|
26
|
9
|
NM
|
||||||||
|
Total
operating expenses
|
$
7,723
|
$
7,582
|
1.9
|
% | |||||||
Significant
drivers contributing to the
$141 million increase in total operating expenses included:
|
|
•
|
A
$76 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
$49 million increase in Fuel and purchased power
expense.
|
|
|
o
|
This
increase was mainly due a $127 million increase in fuel
expense.
|
|
–
|
The
increase in fuel expense resulted primarily
from:
|
|
▪
|
Higher
aggregate fuel cost per kilowatt-hour net thermal generation of 2.7
percent;
|
|
▪
|
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 lower hydroelectric generation;
and
|
|
▪
|
An
FCA net deferral and amortization for fuel expense of $39
million. In accordance with the FCA methodology, TVA has
deferred the amount of fuel costs that were lower than the amount
included
in power rates during 2007. This $39 million deferred amount
will be refunded to customers in future FCA
adjustments.
|
|
|
o
|
The
increase in fuel expense was primarily offset by a $78 million decrease
in
purchased power expense.
|
|
|
–
|
The
decrease in purchased power expense resulted mainly
from:
|
|
▪
|
A
decrease in the average purchase price of 0.8 percent;
and
|
|
▪
|
An
FCA net deferral and amortization for purchased power expense of
$246
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 $246 million
deferred amount will be charged to customers in future FCA
adjustments.
|
|
–
|
These
items were partially offset by a 16.4 percent increase in the volume
of
purchased power to accommodate for 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.
|
|
|
•
|
A
$17 million increase in Loss on asset impairment from $9 million
in 2006
to $26 million in 2007.
|
|
o
|
The
$26 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 $9 million related to other Construction in progress assets during
2007.
|
|
o
|
The
$9 million Loss on asset impairment in 2006 resulted
from:
|
|
–
|
Write-downs
of $7 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
$10 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
FCA net deferral and amortization for operating and maintenance expense
of
$10 million. In accordance with the FCA methodology, TVA has
deferred the amount of operating and maintenance costs that were
lower
than the amount included in power rates during 2007. This $10
million deferred amount will be refunded to customers in future FCA
adjustments.
|
|
|
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:
|
•
|
An
$11 million decrease in Depreciation, amortization, and accretion
expense.
|
|
|
o
|
This
decrease was mainly a result of a $25 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
$13 million decrease in other income was largely attributable to decreased
interest income from short-term investments and decreased 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
|
PercentChange
|
|||||||||
|
Interest
expense
|
|||||||||||
|
Interest
on debt
|
$1,342
|
$1,357
|
(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
|
$1,184
|
$1,215
|
(2.6
|
%) | |||||||
|
(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
$31 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 $329 million
compared with net income of $85 million for 2005. The $244 million
increase in net income was mainly attributable to:
|
•
|
A
$1,393 million increase in operating
revenues;
|
|
•
|
Lower
net interest expense of $46
million;
|
|
•
|
A
$9 million increase in other income;
and
|
|
•
|
Lower
other expense of $2 million.
|
These
items were partially offset
by:
|
•
|
A
$1,079 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
|
|||||||||||||||||||
|
Operating
revenues and sales of electricity
|
||||||||||||||||||||||||
|
Municipalities
and cooperatives
|
$7,859
|
$6,539
|
20.2
|
% |
143,343
|
136,640
|
4.9
|
% | ||||||||||||||||
|
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
|
135
|
101
|
33.7
|
% |
–
|
–
|
–
|
|||||||||||||||||
|
|
||||||||||||||||||||||||
|
Total
operating revenues and sales of electricity
|
$9,175
|
$7,782
|
17.9
|
% |
176,370
|
171,498
|
2.8
|
% | ||||||||||||||||
Significant
items contributing to the
$1,393 million increase in operating revenues included:
|
•
|
A
$1,320 million increase in revenue from municipalities and cooperatives
reflecting increased sales of 4.9 percent and an increase in average
rates
of 14.6 percent. Of this $1,320 million increase, $822 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
$34 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
4,872 million kilowatt-hour increase in electricity sales included:
|
•
|
A
6,703 million kilowatt-hour increase in sales to municipalities and
cooperatives.
|
|
|
o
|
This
increase was primarily due to:
|
|
–
|
A
4,707 million kilowatt-hour increase resulting from a change in the
unbilled estimate methodology used in 2006 as compared to 2005;
and
|
|
–
|
A
1,996 million kilowatt-hour increase in sales demand by municipalities
and
cooperatives during 2006.
|
|
•
|
A
115 million kilowatt-hour increase in sales to 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
|
|||||||||||
|
Fuel
and purchased power
|
$
3,333
|
$
2,601
|
28.1
|
% | |||||||
|
Operating
and maintenance
|
2,372
|
2,359
|
0.6
|
% | |||||||
|
Depreciation,
amortization, and accretion
|
1,492
|
1,154
|
29.3
|
% | |||||||
|
Tax
equivalents
|
376
|
365
|
3.0
|
% | |||||||
|
Loss
on asset impairment
|
9
|
24
|
(62.5
|
%) | |||||||
|
Total
operating expenses
|
$
7,582
|
$
6,503
|
16.6
|
% | |||||||
Significant
drivers contributing to the
$1,079 million increase in total operating expenses included:
|
|
•
|
A
$732 million increase in Fuel and purchased power
expense.
|
|
|
o
|
This
increase was a result of a $377 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
$338 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 $51 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
$13 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
$15 million decrease in Loss on asset impairment from $24 million
in 2005
to $9 million in 2006.
|
|
|
o
|
The
$9 million Loss on asset impairment during 2006 resulted
from:
|
|
–
|
Write-downs
of $7 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
$9 million increase in other income was largely attributable to increased
interest earnings on the collateral deposit funds held by TVA and increased
interest income from short-term investments.
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
|
PercentChange
|
|||||||||
|
Interest
expense
|
|||||||||||
|
Interest
on debt
|
$1,357
|
$1,356
|
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
|
$1,215
|
$1,261
|
(3.6
|
%) | |||||||
|
(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
$46 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 7.
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 5.
Long-Lived
Assets
TVA
capitalizes long-lived assets such
as property, plant, and equipment at historical cost, which includes direct
and
indirect costs and 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 4.
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.
|
|
•
|
Investment
Rate of Return – TVA assumes that its decommissioning fund will achieve a
rate of return that is five percent greater than the rate of
inflation.
|
|
•
|
Cost
Escalation Factors – TVA’s decommissioning estimates include an assumption
that decommissioning costs will escalate over present cost levels
by 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 13.
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
|
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 othercomprehensive
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 13
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
FinancialReporting.” 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 13.
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:
|
•
|
Expanding
the types of financial arrangements that count toward TVA’s
$30 billion debt ceiling;
|
|
•
|
Requiring
TVA to register its debt securities with the Securities and Exchange
Commission; and
|
|
•
|
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.
|
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:
|
(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;
|
|
(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;
|
|
(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
|
|
(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 9.
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
13 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 10.
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 41 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
|
|||
|
Municipalities
and Cooperative Distributor Customers
|
|||
|
Investment
Grade
|
$ 897
|
||
|
Internally
Rated — Investment Grade
|
460
|
||
|
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
|
1,429
|
||
|
Other
Accounts Receivable
|
|||
|
Miscellaneous
Accounts
|
26
|
||
|
Provision
for Uncollectible Accounts
|
(2)
|
||
|
Subtotal
|
24
|
||
|
Total
|
$1,453
|
||
|
Note:
(1) Includes
unbilled power receivables of $1,113 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
17.
ITEM
7A. QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK
Quantitative
and qualitative
disclosures about market risk are reported in Item 7, Management’s Discussion
and Analysis of Financial Condition and Results of Operations — Risk
Management Activities.
TENNESSEE
VALLEY AUTHORITY
For
the
years ended September 30
(in
millions)
|
2007
|
2006
|
2005
|
|||||||||
|
Operating
revenues
|
|||||||||||
|
Sales
of electricity
|
|||||||||||
|
Municipalities
and cooperatives
|
$7,774
|
$7,859
|
$6,539
|
||||||||
|
Industries
directly served
|
1,221
|
1,065
|
961
|
||||||||
|
Federal
agencies and other
|
112
|
116
|
181
|
||||||||
|
Other
revenue
|
137
|
135
|
101
|
||||||||
|
Operating
revenues
|
9,244
|
9,175
|
7,782
|
||||||||
|
Revenue
capitalized during pre-commercial plant operations
|
(57
|
) |
–
|
–
|
|||||||
|
Net
operating revenues
|
9,187
|
9,175
|
7,782
|
||||||||
|
Operating
expenses
|
|||||||||||
|
Fuel
and purchased power
|
3,382
|
3,333
|
2,601
|
||||||||
|
Operating
and maintenance
|
2,382
|
2,372
|
2,359
|
||||||||
|
Depreciation,
amortization, and accretion
|
1,481
|
1,492
|
1,154
|
||||||||
|
Tax
equivalents
|
452
|
376
|
365
|
||||||||
|
Loss
on asset impairment
|
26
|
9
|
24
|
||||||||
|
Total
operating expenses
|
7,723
|
7,582
|
6,503
|
||||||||
|
Operating
income
|
1,464
|
1,593
|
1,279
|
||||||||
|
Other
income
|
64
|
77
|
68
|
||||||||
|
Other
expense
|
(2
|
) |
(2
|
) |
(4
|
) | |||||
|
|
|||||||||||
|
Unrealized
gain/(loss) on derivative contracts, net
|
41
|
(15
|
) |
3
|
|||||||
|
Interest
expense
|
|||||||||||
|
Interest
on debt
|
1,342
|
1,357
|
1,356
|
||||||||
|
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
|
1,184
|
1,215
|
1,261
|
||||||||
|
|
|||||||||||
|
Income
before cumulative effects of accounting changes
|
383
|
438
|
85
|
||||||||
|
Cumulative
effect of change in accounting for conditional
asset
retirement obligations
|
–
|
(109
|
)
|
–
|
|||||||
|
Net
income
|
$383
|
$329
|
$85
|
||||||||
The
accompanying notes are an integral part of these financial
statements.
TENNESSEE
VALLEY AUTHORITY
At
September 30
(in
millions)
|
ASSETS
|
|||||||
|
2007
|
2006
|
||||||
|
Current
assets
|
|||||||
|
Cash
and cash equivalents
|
$ 165
|
$ 536
|
|||||
|
Restricted
cash and investments
|
150
|
198
|
|||||
|
Accounts
receivable, net
|
1,453
|
1,359
|
|||||
|
Inventories
and other
|
663
|
576
|
|||||
|
Total
current assets
|
2,431
|
2,669
|
|||||
|
Property,
plant, and equipment (Note 3)
|
|||||||
|
Completed
plant
|
38,811
|
35,652
|
|||||
|
Less
accumulated depreciation
|
(15,937
|
) |
(15,331
|
) | |||
|
Net
completed plant
|
22,874
|
20,321
|
|||||
|
Construction
in progress
|
1,282
|
3,539
|
|||||
|
Nuclear
fuel and capital leases
|
672
|
574
|
|||||
|
Total
property, plant, and equipment, net
|
24,828
|
24,434
|
|||||
|
Investment
funds
|
1,169
|
972
|
|||||
|
Regulatory
and other long-term assets
|
|||||||
|
Deferred
nuclear generating units
|
3,130
|
3,521
|
|||||
|
Other
regulatory assets (Note 5)
|
1,969
|
1,809
|
|||||
|
Subtotal
|
5,099
|
5,330
|
|||||
|
Other
long-term assets
|
375
|
1,115
|
|||||
|
Total
regulatory and other long-term assets
|
5,474
|
6,445
|
|||||
|
Total
assets
|
$33,902
|
$34,520
|
|||||
|
LIABILITIES
AND PROPRIETARY CAPITAL
|
|||||||
|
Current
liabilities
|
|||||||
|
Accounts
payable
|
$ 1,000
|
$ 890
|
|||||
|
Accrued
liabilities
|
199
|
211
|
|||||
|
Collateral
funds held
|
157
|
195
|
|||||
|
Accrued
interest
|
406
|
403
|
|||||
|
Current
portion of lease/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 10)
|
90
|
985
|
|||||
|
Total
current liabilities
|
3,423
|
5,203
|
|||||
|
Other
liabilities
|
|||||||
|
Other
liabilities
|
2,067
|
2,305
|
|||||
|
Regulatory
liabilities (Note 5)
|
83
|
575
|
|||||
|
Asset
retirement obligations
|
2,189
|
1,985
|
|||||
|
Lease/leaseback
obligations
|
1,029
|
1,071
|
|||||
|
Energy
prepayment obligations
|
1,032
|
1,138
|
|||||
|
Total
other liabilities
|
6,400
|
7,074
|
|||||
|
Long-term
debt, net (Note 10)
|
21,099
|
19,544
|
|||||
|
Total
liabilities
|
30,922
|
31,821
|
|||||
|
Commitments
and contingencies (Note 14)
|
|||||||
|
Proprietary
capital
|
|||||||
|
Appropriation
investment
|
4,743
|
4,763
|
|||||
|
Retained
earnings
|
1,939
|
1,565
|
|||||
|
Accumulated
other comprehensive (loss) income
|
(19
|
) |
43
|
||||
|
Accumulated
net expense of stewardship programs
|
(3,683
|
) |
(3,672
|
) | |||
|
Total
proprietary capital
|
2,980
|
2,699
|
|||||
|
Total
liabilities and proprietary capital
|
$ 33,902
|
$ 34,520
|
|||||
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
|
|||||||||||
|
Net
income
|
$ 383
|
$ 329
|
$ 85
|
||||||||
|
Adjustments
to reconcile net income to net cash provided by operating
activities
|
|
||||||||||
|
Depreciation,
amortization, and accretion
|
1,500
|
1,513
|
1,175
|
||||||||
|
Nuclear
refueling outage amortization
|
86
|
89
|
105
|
||||||||
|
Loss
on asset impairment
|
26
|
9
|
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
|
(197
|
) |
–
|
–
|
|||||||
|
Other,
net
|
(31
|
) |
(7
|
) |
7
|
||||||
|
Changes
in current assets and liabilities
|
|
|
|||||||||
|
Accounts
receivable, net
|
(72
|
) |
(214
|
) |
(19
|
) | |||||
|
Inventories
and other
|
(98
|
) |
(120
|
) |
(12
|
) | |||||
|
Accounts
payable and accrued liabilities
|
80
|
125
|
(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
|
1,763
|
2,014
|
1,462
|
||||||||
|
|
|||||||||||
|
Cash
flows from investing activities
|
|
||||||||||
|
Construction
expenditures
|
(1,306
|
) |
(1,399
|
) |
(1,339
|
) | |||||
|
Combustion
turbine asset acquisitions
|
(111
|
) |
–
|
–
|
|||||||
|
Nuclear
fuel expenditures
|
(251
|
) |
(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
|
(1,661
|
) |
(1,727
|
) |
(1,188
|
) | |||||
|
Cash
flows from financing activities
|
|||||||||||
|
Long-term
debt
|
|||||||||||
|
Issues
|
1,040
|
1,132
|
1,650
|
||||||||
|
Redemptions
and repurchases (Note 10)
|
(470
|
) |
(1,241
|
) |
(2,368
|
) | |||||
|
Short-term
(redemptions)/borrowings, net
|
(955
|
) |
(93
|
) |
546
|
||||||
|
Proceeds
from call monetizations
|
–
|
–
|
5
|
||||||||
|
Payments
on lease/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
11 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 8)
|
–
|
–
|
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)
|
–
|
339
|
–
|
(10
|
) |
329
|
329
|
|||||||||||
|
Return
on Power Facility Appropriation Investment
|
–
|
(18
|
) |
–
|
–
|
(18
|
) |
–
|
||||||||||
|
Accumulated
other comprehensive income (Note 8)
|
–
|
–
|
16
|
–
|
16
|
16
|
||||||||||||
|
Return
of Power Facility Appropriation Investment
|
(20
|
) |
–
|
–
|
–
|
(20
|
) |
–
|
||||||||||
|
Balance
at September 30, 2006
|
4,763
|
1,565
|
43
|
(3,672
|
) |
2,699
|
$ 345
|
|||||||||||
|
Net
income (loss)
|
–
|
394
|
–
|
(11
|
) |
383
|
383
|
|||||||||||
|
Return
on Power Facility Appropriation Investment
|
–
|
(20
|
) |
–
|
–
|
(20
|
) |
–
|
||||||||||
|
Accumulated
other comprehensive (loss) (Notes 8 and 13)
|
–
|
–
|
(62
|
) |
–
|
(62
|
) |
(62
|
) | |||||||||
|
Return
of Power Facility Appropriation Investment
|
(20
|
) |
–
|
–
|
–
|
(20
|
) |
–
|
||||||||||
|
Balance
at September 30, 2007
|
$4,743
|
$1,939
|
$(19
|
) |
$(3,683
|
) |
$2,980
|
$ 321
|
||||||||||
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 2006 and 2005 financial statements to conform to the 2007
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.
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:
|
Accounts
Receivable
As
of September 30
|
|||||||
|
2007
|
2006
|
||||||
|
Power
receivables billed
|
$ 316
|
$ 303
|
|||||
|
Power
receivables unbilled
|
1,113
|
1,031
|
|||||
|
Total
power receivables
|
1,429
|
1,334
|
|||||
|
Other
receivables
|
26
|
35
|
|||||
|
Allowance
for uncollectible accounts
|
(2
|
) |
(10
|
) | |||
|
Net
accounts receivable
|
$
1,453
|
$
1,359
|
|||||
Effective
September 2006, TVA
implemented a change in the methodology for estimating unbilled revenue for
electricity sales. The change in calculating unbilled revenue was
from a method that estimates unbilled revenue on an aggregated distributor
basis
to a method that estimates unbilled revenue for each distributor and sums the
results to arrive at the total estimated unbilled revenue. The change
also involves moving from an aggregate generation-based estimate to an estimate
based on wholesale meter readings for each specific distributor. The
impact of this change resulted in an increase in the September 2006 sales
estimate of 4,497 million kilowatt-hours and an increase in September 2006
accounts receivable and revenue of $232 million.
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. As a result, the overall
estimate of unbilled revenues may be significantly affected, which could have
a
material impact on TVA’s results of operations. Exchange power sales are
presented in the accompanying Statements of Income as a component of Sales
of
electricity-federal agencies and other. Exchange power sales are sales of excess
power after meeting TVA native load and direct served requirements. (Native
load
refers to the customers on whose behalf a company, by statute, franchise,
regulatory requirement, or contract, has undertaken an obligation to
serve.)
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 2.92 percent
for 2007, 3.15 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
|
|||||
|
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
|
7.84
|
5.45
|
5.60
|
||||
Depreciation
expense for the years
ended September 30, 2007, 2006, and 2005, was $1,056 million, $1,082 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
14
— Contingencies — Decommissioning Costs), asset retirement obligations
(see Note 4 — Asset Retirement Trust), and the supplemental executive
retirement plan (“SERP”). See Note 13 — 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
|
$ 102
|
|||||
|
Intangible
asset related to pension prior service cost
|
–
|
280
|
|||||
|
Valuation
of currency swaps
|
280
|
246
|
|||||
|
Valuation
of commodity contracts
|
16
|
487
|
|||||
|
$ 375
|
$1,115
|
||||||
For
additional information on the
components of Other long-term assets, see Note 1 — Allowance for
Uncollectible Accounts, Note 9 — Overview of Accounting Treatment,
Commodity Contracts, and Swaps, Note 12 — Loans and Other
Long-term Receivables, and Note 13 — 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 14— 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
4.
Based
on updating assumptions in the
engineering studies annually in accordance with NRC requirements, revisions
to
the amount and timing of certain cash flow estimates of nuclear asset retirement
obligations may be made. TVA recognizes as incurred all obligations
related to closure and removal of its nuclear units. TVA measures the
liability for closure at the present value of the weighted estimated cash flows
required to satisfy the related obligation, discounted at the credit adjusted
rate of interest in effect at the time the liability was actually incurred
or
originally accrued, and subsequently modified to comply with SFAS No.
143. Earnings from decommissioning fund investments, amortization of
the decommissioning regulatory asset, and interest expense on the
decommissioning liability are deferred as a regulatory asset. See
Note 14 — 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
4. On September 30, 2006, TVA began applying the guidance of
Financial Accounting Standards Board (“FASB”) Interpretation (“FIN”) No. 47,
“Accounting for Conditional Asset Retirement Obligations—an Interpretation
of FASB Statement No. 143.” See Note 4 for the effects of
applying this interpretation.
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 6.
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
FinancialReporting.” 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 13.
2.
Nuclear Power Program
At
September 30, 2007, TVA's nuclear
power program consisted of seven units — six operating (commercially generating
electricity), and one in planning stages which will resume construction in
2008. The units are in three locations with investments in property,
plant, and equipment as follows and in the status indicated:
Nuclear
Production Plants
As
of
September 30, 2007
|
Completed
Plant, Net
|
Construction
in Progress
|
Fuel
Investment
|
|||||||||
|
Browns
Ferry
|
$ 4,001
|
$ 117
|
$ 245
|
||||||||
|
Sequoyah
|
1,559
|
32
|
132
|
||||||||
|
Watts
Bar*
|
5,403
|
9
|
45
|
||||||||
|
Raw
materials
|
–
|
–
|
180
|
||||||||
|
Total
Nuclear Production
|
$ 10,963
|
$ 158
|
$ 602
|
||||||||
|
Note:
*
Watts Bar Unit 2 is in planning stages and construction on it will
resume
in 2008.
|
|||||||||||
Browns
Ferry Unit 1 was taken offline
in 1985 for plant modifications and regulatory improvements. In May
2002, the TVA Board initiated activities for the return of Browns Ferry Unit
1
to service to meet long-term power requirements, and on August 1, 2007, Browns
Ferry Unit 1 returned to commercial operation. The total amount
invested in the restart project through the commercial operation date was $1.84
billion excluding AFUDC of $269 million. The unit is initially
providing generating capacity of approximately 1,150 megawatts and is expected
eventually to provide 1,280 megawatts of capacity.
On
August 1, 2007, the TVA Board
approved the completion of Watts Bar Nuclear Plant Unit 2 (“Watts Bar Unit 2”),
construction of which was halted in 1985. 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.
The
TVA Board determined as of the end
of 2001 that the values of some of its existing assets were impaired and should
be reduced. Certain nuclear assets — portions of Bellefonte Unit 1
and Unit 2 and Watts Bar Unit 2 in its entirety — were identified as assets for
which the estimated cash flows expected to be provided through future rates
were
less than recorded book values. Accordingly, TVA revalued certain
nuclear assets — Watts Bar Unit 2 in its entirety and portions of Bellefonte
Unit 1 and Unit 2 — downward by $2.2 billion and recognized an impairment
loss. During 2004, the TVA Board approved the reclassification of
approximately $203 million of Bellefonte assets from Deferred nuclear generating
units to Completed plant. In July 2005, the TVA Board approved the
amortization of TVA’s remaining investment in the deferred generating units at
Bellefonte over a 10-year period beginning in 2006. See Note 1 —
Cost-Based Regulation. TVA began amortizing and recovering
in rates the investment of the $3.9 billion in deferred nuclear generating
units
at Bellefonte Nuclear Plant on October 1, 2005. TVA’s Board approved
canceling the unfinished Bellefonte construction project in November 2005 and
the NRC approved TVA’s request to terminate the construction permits in
September 2006. See Note 5 — Deferred Nuclear Generating
Units. None of these actions interfere in any way with TVA’s
ability to use the site for future projects.
In
September 2005, NuStart Development
LLC (“NuStart”) selected Bellefonte as one of the two sites in the country
for a new advanced design nuclear plant. NuStart is an industry
consortium comprised of 10 utilities and two reactor vendors whose purpose
is to satisfactorily demonstrate the new NRC licensing process for new nuclear
plants. NuStart intends to seek a combined construction and operating
license for the site for the new Advanced Passive 1000 reactor design by
Westinghouse Electric Co. As the license applicant, TVA submitted its
combined license application to the NRC in October 2007. If approved,
the license to build and operate the plant would be issued to
TVA. The TVA Board has not made a decision to construct a new plant
at the Bellefonte site.
On
May 4, 2006, the NRC approved TVA’s
application for license extension at each of its three reactors at Browns Ferry
Nuclear Plant. As a result of the NRC’s action, each unit’s license
has been extended 20 years. See Note 4. The depreciable
lives of these units were therefore extended in 2006. Current
expiration dates of the operating licenses for the Browns Ferry units are as
follows:
TVA
Nuclear Unit Operating License Expiration Dates
As
of
September 30, 2007
|
Nuclear
Unit
|
Operating
License Expiration Date
|
|
Browns
Ferry Unit 1
|
2033
|
|
Browns
Ferry Unit 2
|
2034
|
|
Browns
Ferry Unit 3
|
2036
|
3.
Completed Plant
Completed
plant consisted of the following at September 30:
TVA
Completed Plant
As
of
September 30
|
2007
|
2006
|
|||||||||||||||||
|
Cost
|
Accumulated
Depreciation
|
Net
|
Cost
|
Accumulated
Depreciation
|
Net
|
|||||||||||||
|
Coal-Fired
|
$11,093
|
$5,606
|
$5,487
|
$10,567
|
$5,249
|
$5,318
|
||||||||||||
|
Combustion
turbine
|
1,212
|
555
|
657
|
1,168
|
500
|
668
|
||||||||||||
|
Nuclear
|
17,514
|
6,551
|
10,963
|
15,437
|
6,520
|
8,917
|
||||||||||||
|
Transmission
|
4,680
|
1,682
|
2,998
|
4,360
|
1,607
|
2,753
|
||||||||||||
|
Hydroelectric
|
1,991
|
718
|
1,273
|
1,879
|
683
|
1,196
|
||||||||||||
|
Other
electrical plant
|
1,315
|
471
|
844
|
1,235
|
428
|
807
|
||||||||||||
|
Subtotal
|
37,805
|
15,583
|
22,222
|
34,646
|
14,987
|
19,659
|
||||||||||||
|
|
||||||||||||||||||
|
Multipurpose
dams
|
962
|
345
|
617
|
962
|
336
|
626
|
||||||||||||
|
Other
stewardship
|
44
|
9
|
35
|
44
|
8
|
36
|
||||||||||||
|
Subtotal
|
1,006
|
354
|
652
|
1,006
|
344
|
662
|
||||||||||||
|
|
|
|
||||||||||||||||
|
Total
|
$38,811
|
$15,937
|
$22,874
|
$35,652
|
$15,331
|
$20,321
|
||||||||||||
4.
Asset Retirement Obligations
Effective
October 1, 2002, TVA adopted
SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No.
143”), which requires the recognition of a liability, and capitalization of the
associated asset retirement cost as part of the carrying amount of the
long-lived asset, for legal obligations associated with the retirement of
long-lived assets that result from the acquisition, construction, development,
and/or normal operation of long-lived assets. TVA identified and
reviewed all relevant information to determine its potential asset retirement
obligations (“AROs”), and three categories of AROs which represent legal
obligations of TVA under the requirements set forth in the standard were
identified. Costs associated with retirement of coal-fired (including
ash/waste ponds) and gas/oil combustion turbine generating plants are being
expensed as period costs while costs associated with retirement of nuclear
generating plants are receiving SFAS No. 71 treatment based on the partially
funded status of the nuclear decommissioning obligation. See Note 1 —
Cost-Based Regulation.
When
TVA adopted SFAS No. 143, the
accounting requirement was to incur only the minimum legally required costs
related to plant shut-down and to consider certain assets as
perpetually-lived. Accordingly, TVA adopted a containment strategy
through plant maintenance related to asbestos and polychlorinated biphenyls
(“PCBs”), and due to uncertainty surrounding the timing of estimated plant
closures, did not record an ARO for the complete removal costs. FIN
No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN
47”), clarifies that even though the timing or method of settlement of an
obligation may be conditional on a future event, the obligation to perform
the
asset retirement activity is unconditional. Accordingly, an entity is
required to recognize a liability for the fair value of a conditional asset
retirement obligation when incurred if the liability’s fair value can be
reasonably estimated.
Asbestos
and
PCBs. On September 30, 2006, TVA began applying FIN 47 which
resulted in the recognition of additional ARO liabilities for asbestos and
PCB
abatement costs. The effect of the adoption of FIN 47 during 2006 included
a
cumulative effect charge to income of $109 million, a recognition of a
corresponding additional long-term liability of $132 million, a recognition
of
an increase in assets of $43 million, and related accumulated depreciation
of
$20 million.
|
Conditional
Asset Retirement Obligations for Asbestos and PCB Abatement
Costs
|
|||||||||||||||||
|
FIN
47 ARO Category
|
Pro-Forma
October
1, 2005 Obligation
|
September
30,
2006
Obligation
|
September
30, 2007 Obligation
|
Estimated
Future Liability (Undiscounted)September
30, 2007
|
|||||||||||||
|
Coal-Fired
Plants
|
$ 111
|
$ 117
|
$ 123
|
$ 449
|
|||||||||||||
|
Office
and Other Facilities
|
2
|
2
|
2
|
42
|
|||||||||||||
|
Hydroelectric
Plants
|
5
|
5
|
5
|
32
|
|||||||||||||
|
Transmission
Facilities
|
9
|
8
|
9
|
21
|
|||||||||||||
|
Total
|
$ 127
|
$ 132
|
$ 139
|
$ 544
|
|||||||||||||
TVA
has
identified but not recognized conditional AROs related to items that contain
PCBs such as electromagnets, voltage regulators, and small
capacitors. These items reside in numerous larger pieces of equipment
throughout TVA’s integrated system and generally require retirement action only
upon failure or malfunction. The conditional AROs related to these
items are not currently estimable because TVA does not have a comprehensive
inventory of such items and does not have the historical data available to
develop a reasonable estimate of when such items will fail or
malfunction. If material, TVA will recognize a conditional ARO
associated with these items at the time the information becomes available to
develop a reasonable estimate.
Coal-Fired
Generating
Plants. The activities associated with coal-fired plant
retirement include plant shutdown, securing the physical property, closure
of
storage and/or waste areas (including ash/waste ponds), maintenance of stack
lights, security patrols, and measures to contain asbestos and other hazardous
materials from release into the environment. The estimated costs of
these activities have been included in the calculation of TVA’s coal-fired plant
AROs. Certain ash ponds and waste areas have estimated useful lives
that are independent of the lives of the coal plants
themselves. Accordingly, these specific ash/waste pond areas were
quantified as separate AROs based on their specific estimated useful
lives.
Gas/Oil
Turbine Generating
Plants. The activities associated with gas and oil turbine plant
retirement include annual operating costs for site security, lighting,
powerhouse and grounds maintenance, containment of asbestos, paint, and other
materials, and groundwater monitoring. The estimated costs of these
activities have been identified and are included in the calculation of TVA’s
combustion turbine plant AROs.
For
each ARO previously
identified, TVA calculated the net present value of the obligation as of the
current period, the original and incremental cost of the long-lived asset at
the
time of initial operation, the cumulative effect of depreciation on the adjusted
asset base, and accretion of the liability from the date of initial operation
to
the current period.
Nuclear Generating Plants. Prior to implementing SFAS
No. 143, TVA had recognized a decommissioning liability related to its nuclear
generating plants in accordance with NRC funding requirements. The
adoption of SFAS No. 143 resulted in a change in the methodology of quantifying
this nuclear decommissioning obligation in accordance with the new accounting
standard. TVA has increased the nuclear decommissioning liability on
the balance sheet to reflect the new methodology but has retained its regulatory
accounting treatment of capturing all changes in the liability, investment
funds, and certain other deferred charges, which includes depreciation of the
ARO asset base, as changes in the regulatory asset instead of recording these
items on the income statement because recovery of these net costs is probable
in
future revenues.
In
March 2007 and 2006, TVA made
revisions to the amount and timing of certain cash flow estimates related to
its
nuclear AROs. The revisions in cost were based on new engineering
analyses of certain components of the cost performed annually in accordance
with
requirements of the NRC. Accordingly, TVA made adjustments in the
recorded amounts to properly reflect such revised balances based on the latest
cost estimates. In 2007, the effect of the changes in estimates
produced an increase in obligations greater than the amounts originally
recorded. The adjustments resulted in an increase in the regulatory
asset of $82 million with a corresponding increase in the ARO
liability. In 2006, the effect of the changes in estimates produced
obligations that were less than the amounts originally recorded on an accreted
basis. The adjustments resulted in an aggregate decrease of $89
million in the ARO, a $29 million reduction in the asset base, a $12 million
reduction in accumulated depreciation, and a decrease of $72 million in the
originally recorded regulatory asset which TVA recorded in accordance with
SFAS
No. 71. Therefore, the result of the change described did not impact
net income.
In
May
2006, the NRC granted a 20-year license extension for the operation of each
of
the three units at TVA’s Browns Ferry Nuclear Plant. The license
extension changes the timing of certain cash flow estimates utilized by TVA
in
the determination of the Browns Ferry ARO. Accordingly, TVA made
adjustments to the Browns Ferry ARO and related accounts to reflect the revised
cost estimates. TVA previously calculated the Browns Ferry ARO
utilizing two equally weighted sets of estimated cash flows: one set based
on a
40-year license life and a second set based on a 60-year license
life. The cash flow estimates represented by the 40-year life are no
longer applicable. The adjustments made are cumulative for the year
and include reductions in the nuclear ARO of $153 million, a reduction in the
incremental asset base of $31 million, a reduction in the asset’s accumulated
depreciation of $44 million, and a reduction in the regulatory asset of $166
million. The result of the changes described does not impact net
income for any of the periods presented.
Reconciliation
of ARO
Liability. In accordance with the provisions of SFAS No. 143 TVA
recognizes the fair value of legal obligations associated with the retirement
of
certain tangible long-lived assets. The fair value of the liability
is added to the book value of the associated asset. The liability
increases due to the passage of time (accretion expense), based on the time
value of money, until the obligations settle. Subsequent to the
initial recognition, the future liability is adjusted for any periodic revisions
to the expected cost of the retirement obligation (changes in estimates to
future cash flows) and for accretion of the liability due to the passage of
time. During 2006, TVA’s total ARO increased $128 million, net of all
cumulative adjustments, due to combined accretion expense of $100 million and
a
recognition of a conditional ARO of $132 million and $138 million due to the
application of FIN 47 and SFAS 143, respectively, partially offset by the $242
million in revisions to the nuclear ARO. The nuclear accretion
expense of $87 million was deferred and charged to a regulatory asset in
accordance with SFAS No. 71. The remaining accretion expense of $13
million, related to coal-fired and gas/oil combustion turbine plants, was
expensed in 2006. During year 2007, TVA’s total ARO liability
increased $204 million. The increase was comprised of $91 million in
new AROs plus $113 million in ARO expense (accretion of the
liability). The increase in the nuclear ARO is comprised of a second
quarter increase of $82 million based on a revision to the 2007 cost study,
which accounted for biennial changes in burial rates, a third quarter increase
of $7 million due to the replacement of steam generators at Watts Bar Nuclear
Plant, and a fourth quarter increase of $1 million due to the replacement of
steam generators at Watts Bar Nuclear Plant. The nuclear accretion
expense of $85 million was deferred and charged to a regulatory asset in
accordance with SFAS No. 71. The remaining accretion expense of $28
million, related to non-nuclear assets, was expensed in 2007.
Reconciliation
of Asset Retirement Obligation Liability
As
of
September 30
|
2007
|
2006
|
||||||
|
Balance
at beginning of period
|
$1,985
|
$1,857
|
|||||
|
Changes
in nuclear estimates to future cash flows
|
90
|
(242
|
) | ||||
|
Non-nuclear
additional obligations
|
1
|
270
|
|||||
|
91
|
28
|
||||||
|
Add: ARO
(accretion) expense
|
|||||||
|
Nuclear
accretion (recorded as a regulatory asset)
|
85
|
87
|
|||||
|
Non-nuclear
accretion (charged to expense)
|
28
|
13
|
|||||
|
113
|
100
|
||||||
|
Balance
at end of period
|
$2,189
|
$1,985
|
|||||
Asset
Retirement
Trust. 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
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.
5. Regulatory
Assets and Liabilities
Regulatory
assets capitalized under the
provisions of SFAS No. 71 are included in Deferred nuclear generating units
and
Other regulatory assets on the September 30, 2007 and 2006, Balance
Sheets. Components of Other regulatory assets include certain charges
related to the closure and removal from service of nuclear generating units,
debt reacquisition costs, deferred outage costs, unrealized losses related
to
power purchase contracts, deferred capital lease asset costs, deferred losses
relating to TVA’s financial trading program, adjustment to accrue the minimum
pension liability, fuel cost adjustments, and unfunded benefit
costs. All regulatory assets are probable of recovery in future
revenues. Components of Regulatory liabilities include unrealized
gains on coal purchase contracts, a reserve for future generation, and capital
lease liabilities. See Note 1 — Cost-Based Regulation and
Note 2.
The
year-end balances of TVA’s
regulatory assets and liabilities are as follows:
|
TVA
Regulatory Assets and Liabilities
As
of September 30
|
|||||||
|
2007
|
2006
|
||||||
|
Regulatory
Assets:
|
|||||||
|
Unfunded
benefit costs
|
$ 973
|
$ –
|
|||||
|
Minimum
pension liability
|
–
|
914
|
|||||
|
Nuclear
decommissioning costs
|
419
|
474
|
|||||
|
Debt
reacquisition costs
|
210
|
232
|
|||||
|
Deferred
losses relating to TVA’s financial trading program
|
8
|
6
|
|||||
|
Deferred
outage costs
|
96
|
85
|
|||||
|
Deferred
capital lease asset costs
|
66
|
76
|
|||||
|
Unrealized
losses on power purchase contracts
|
–
|
22
|
|||||
|
Fuel
cost adjustment
|
197
|
–
|
|||||
|
Subtotal
|
1,969
|
1,809
|
|||||
|
Deferred
nuclear generating units
|
3,130
|
3,521
|
|||||
|
Total
|
$5,099
|
$
5,330
|
|||||
|
Regulatory
Liabilities:
|
|||||||
|
Unrealized
gain on coal purchase contracts
|
$ 16
|
$ 487
|
|||||
|
Capital
lease liability
|
67
|
88
|
|||||
|
Subtotal
|
83
|
575
|
|||||
|
Reserve
for future generation
|
74
|
–
|
|||||
|
Total
|
$ 157
|
$ 575
|
|||||
Unfunded
Benefit
Costs. Unfunded benefit costs are changes in the amount of
either the pension projected benefit obligation or pension plan assets resulting
from experience different from that previously assumed as well as from changes
in assumptions. In accordance with 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),” such amounts are
typically recognized as components of Accumulated other comprehensive income;
however, TVA recognizes all such unfunded benefit costs, to the extent the
projected benefit obligation exceeds plan assets, as regulatory assets in
accordance with the specific requirements of the TVA Board. Before
September 30, 2007, TVA recognized such unfunded actuarial losses as regulatory
assets, only to the extent the accumulated benefit obligation exceeded pension
plan assets less prior service cost, as required by SFAS No. 87 and the
recognition of the additional minimum liability (“AML”) or minimum pension
liability. See Minimum Pension Liability below.
Minimum
Pension
Liability. TVA’s accumulated pension benefit obligation at
September 30, 2007, prior to TVA’s adoption of SFAS No. 158, and at September
30, 2006, exceeded plan assets. As a result, TVA was required to
recognize an additional minimum pension liability as prescribed by SFAS No.
87,
“Employers’ Accounting for Pensions.” TVA records as
regulatory assets the portion of the unfunded benefit obligation represented
by
actuarial losses as determined by the plan’s actuarial valuation process at the
end of the current year. Such recognition of actuarial losses as
regulatory assets is made in accordance with the directives of the TVA
Board. These future pension costs will be funded through a
combination of the pension investment funds already set aside by TVA, future
earnings on those pension investment funds, and, if recommended by the Tennessee
Valley Authority Retirement System (“TVARS”) Board of Directors (“TVARS Board”)
under the rules and regulations of TVARS and approved by TVA, future TVA cash
contributions to the pension plan which will be recovered in TVA’s rates when
incurred.
Nuclear
Decommissioning
Costs. Nuclear decommissioning costs include certain deferred
charges related to the future closure and decommissioning of TVA’s nuclear
generating units under NRC requirements and liability recognition under the
accounting rules for asset retirement obligations. These future costs
will be funded through a combination of investment funds already set aside
by
TVA, future earnings on those investment funds, and if necessary, additional
TVA
cash contributions to the investment funds. See Note 1 —
Investment Funds and Note 4.
Debt
Reacquisition
Costs. Reacquisition expenses, call premiums, and other related
costs, such as unamortized debt issue costs associated with redeemed Bond
issues, are deferred under provisions of the FERC’s Uniform System of Accounts
Prescribed for Public Utilities and Licensees Subject to the Provisions of
the
Federal Power Act (“Uniform System of Accounts”). These costs are
deferred and amortized (accreted) on a straight-line basis over the weighted
average life of TVA’s debt portfolio. (Even though TVA is not a
public utility subject generally to FERC jurisdiction, the TVA Act requires
TVA
to keep accounts in accordance with the requirements established by
FERC.)
Deferred
Losses Relating to TVA’s
Financial Trading Program. Deferred losses relating to TVA’s financial
trading program represent unrealized gains and losses on futures and options
at
September 30, 2007. The program is used to reduce TVA’s economic risk
exposure associated with electricity generation, purchases, and
sales. Due to the implementation of a fuel cost adjustment (“FCA”)
mechanism as of October 1, 2006, TVA changed its accounting for these unrealized
gains and losses as of September 30, 2006, to defer the unrealized gains until
the contracts settle. Prior to this time, gains and losses were
reported on the income statement as an offset to purchased
power. Unrealized losses as of September 30, 2006, were approximately
$6 million. The new accounting treatment reflects TVA’s ability and
intent to recover the cost of these commodity contracts in future periods
through the FCA.
Deferred
Outage
Costs. TVA’s investment in the fuel used in its nuclear units is
being amortized and accounted for as a component of fuel expense. See
Note 2. Nuclear refueling outage and maintenance costs already
incurred are deferred and amortized on a straight-line basis over the estimated
period until the next refueling outage. The amounts of deferred
outage costs for 2007, 2006, and 2005 were $96 million, $85 million, and $103
million, respectively.
Deferred
Capital Lease Asset
Costs. Deferred capital lease asset costs represent the
difference between FERC’s Uniform System of Accounts model balances recovered in
rates and the SFAS No. 13, “Accounting for Leases,” model
balances. Under the Uniform System of Accounts, TVA recognized the
initial capital lease asset and liability at inception of the lease in
accordance with SFAS No. 13; however, the annual expense under the Uniform
System of Accounts is equal to the annual lease payments, which differs from
SFAS No. 13 accounting treatment. This practice results in TVA’s
capital lease asset balances being higher than they otherwise would have been
under the SFAS No. 13 model, with the difference representing a regulatory
asset
related to each capital lease. These costs are being amortized over
the respective lease terms as lease payments are made.
Unrealized
Losses on Power Purchase
Contracts. Unrealized losses on a power purchase contract
represent the estimated unrealized loss related to the mark-to-market valuation
of the contract. Under the accounting rules contained in SFAS No. 133,
“Accounting for Derivative Instruments and Hedging Activities,” as
amended, this contract qualifies as a derivative contract but does not qualify
for cash flow hedge accounting treatment. As a result, TVA recognizes
the changes in the market value of this derivative contract as a regulatory
asset. This treatment reflects TVA’s ability and intent to recover
the cost of this commodity contract on a settlement basis for ratemaking
purposes. TVA has historically recognized the actual cost of
purchased power received under this contract in purchased power expense at
the
time of settlement. The contract expired in 2007. See Note
9.
Fuel
Cost
Adjustment. On July 28, 2006, the TVA Board approved the FCA to
be applied quarterly as a mechanism to adjust TVA's rates to reflect changing
fuel and purchased power costs beginning in 2007. As of September 30,
2007, TVA had recognized a regulatory asset of $197 million representing
deferred power costs to be recovered through the FCA adjustments in future
periods.
Deferred
Nuclear Generating
Units. In July 2005, the TVA Board approved the amortization, and inclusion
into rates, of TVA’s $3.9 billion investment in the deferred nuclear generating
units at Bellefonte Nuclear Plant over a 10-year period beginning in
2006. The TVA Board determined that a 10-year recovery period would
not place an undue burden on ratepayers while still ensuring the probability
of
cost recovery during that 10-year period. See Note 2.
Regulatory
liabilities accounted for
under the provisions of SFAS No. 71 consist of mark-to-market valuation gains
on
coal purchase contracts, capital leases, and reserve for future
generation.
Unrealized
Gains on Coal Purchase
Contracts. Unrealized gains on coal purchase contracts represent the
estimated unrealized gains related to the mark-to-market valuation of coal
purchase contracts. Under the accounting rules contained in SFAS No. 133, as
amended, these contracts qualify as derivative contracts but do not qualify
for
cash flow hedge accounting treatment. As a result, TVA recognizes the
changes in the market value of these derivative contracts as a regulatory
liability. This treatment reflects TVA’s ability and intent to
recover the cost of these commodity contracts on a settlement basis for
ratemaking purposes. TVA has historically recognized the actual cost
of fuel received under these contracts in fuel expense at the time the fuel
is
used to generate electricity. These contracts expire at various times
through 2017. See Note 9.
Capital
Lease
Liability. As a result of a capital lease payment stream
requiring larger cash payments during the latter years of the lease term than
during the early years of the lease term, TVA levelized the annual lease expense
recognition related to this lease in order to promote the fair and equitable
cost recovery from ratepayers. These levelized costs are being
amortized over the lease term.
Reserve
for Future Generation.
During 2007, TVA collected $76 million in rates 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. Once generating capacity is acquired, funds in the
reserve account are to be reclassified from a regulatory liability to completed
plant. In December 2006, TVA purchased two combustion turbine facilities for
a
combined purchase price of $98 million. One facility is a 756-megawatt winter
net dependable capacity, dual-fuel combustion turbine facility and includes
certain related transmission facilities. The second facility is a 540-megawatt
winter net dependable capacity, natural gas-fired combustion turbine facility.
The 540-megawatt winter net dependable capacity facility was available for
commercial operation in January 2007, and the 756-megawatt winter net dependable
capacity facility was available for commercial operation in May 2007. During
2007, depreciation related to the 540-megawatt winter net dependable capacity
facility was $0.7 million and depreciation related to the 756-megawatt winter
net dependable capacity facility was $1.0 million. TVA also recognized revenue
of $1.7 million during 2007 consistent with the manner in which the related
asset is being depreciated. The balance of the reserve for future
generation is $74 million at September 30, 2007. See Note 1 —
Reserve for Future Generation.
6. Asset
Impairment
During
2007 and 2006, TVA recognized a
total of $26 million and $9 million respectively, in impairment losses related
to its Property, plant, and equipment. The $26 million Loss on asset
impairment in 2007 included a $17 million write-off of a scrubber project at
TVA’s Colbert Fossil Plant (“Colbert”) and write-downs of $9 million related to
other Construction in progress assets. The $9 million Loss on asset
impairment in 2006 included write-off of $7 million on certain Construction
in
progress assets related to new pollution-control and other technologies that
had
not been proven effective and a re-valuation of other projects due to funding
limitations. TVA also revalued one of two buildings in its Knoxville
Office Complex because of its plans to sell or lease the East Tower of the
Complex. Based on evaluation of independent appraisals which were
deemed to be market value, a $2 million write-down was recognized on the
building.
7. Variable
Interest Entity
In
February 1997, TVA entered into a power purchase 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 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 totaled $122 million. TVA has no additional financial
commitments beyond the power purchase agreement with respect to the
facility.
8.
Proprietary Capital
Appropriation
Investment
TVA’s
power program and stewardship
program were originally funded primarily by appropriations from
Congress. In 1959, however, Congress passed legislation that
required TVA’s power program to be self-financing from power revenues and
proceeds from power program financings. While TVA’s power program did not
directly receive appropriated funds after it became self-financing, TVA
continued to receive appropriations for certain multipurpose and other
mission-related activities as well as for its stewardship activities. TVA has
not received any appropriations from Congress for any activities since 1999,
and
since that time, TVA has funded stewardship program activities primarily with
power revenues in accordance with a statutory directive from
Congress.
In
1959,
Congress also passed legislation that required TVA, beginning in 1961, to make
annual payments to the U.S. Treasury from net power proceeds as a repayment
of
and as a return on the Power Facility Appropriation Investment until an
additional $1 billion of the Power Facility Appropriation Investment has been
repaid. Of this $1 billion amount, $130 million remained unpaid at
September 30, 2007. Once the additional $1 billion of the Power
Facility Appropriation Investment has been repaid, the TVA Act requires TVA
to
continue making payments to the U.S. Treasury as a return on the remaining
Power
Facility Appropriation Investment. The remaining Power Facility
Appropriation Investment will be $258 million if TVA receives no additional
appropriations from Congress for its power program.
The
table
below summarizes TVA's activities related to appropriated funds.
|
Appropriations
Activity
As
of September 30
|
|||||||||||
|
Power
Facility Appropriation Investment
|
Stewardship
Program
Appropriations
|
Total
Appropriation Investment
|
|||||||||
|
Appropriation
Investment at September 30, 2005
|
$ 428
|
$ 4,355
|
$ 4,783
|
||||||||
|
Less
repayments to the U.S. Treasury
|
(20
|
) |
–
|
(20
|
) | ||||||
|
Appropriation
Investment at September 30, 2006
|
408
|
4,355
|
4,763
|
||||||||
| Less repayments to the U.S. Treasury |
(20
|
) |
–
|
(20
|
) | ||||||
| Appropriation Investment at September 30, 2007 |
$ 388
|
$ 4,355
|
$ 4,743
|
||||||||
Payments
to the U.S. Treasury
TVA
paid $20 million each year for
2007, 2006, and 2005 as a repayment of the Power Facility Appropriation
Investment. In addition, TVA paid the U.S. Treasury $20 million in
2007, $18 million in 2006, and $16 million in 2005 as a return on the Power
Facility Appropriation Investment. The amount of the return on the
Power Facility Appropriation Investment is based on the Power Facility
Appropriation Investment balance as of the beginning of that year and the
computed average interest rate payable by the U.S. Treasury on its total
marketable public obligations as of the same date. The interest rates
payable by TVA on the Power Facility Appropriation Investment were 4.87 percent,
4.24 percent, and 3.71 percent for 2007, 2006, and 2005,
respectively.
Accumulated
Other Comprehensive
Income
SFAS
No. 130, “Reporting
Comprehensive Income,” requires the disclosure of comprehensive income or
loss to reflect changes in capital that result from transactions and economic
events from nonowner sources. The items included in Accumulated other
comprehensive income (loss) consist of market valuation adjustments for certain
derivative instruments (see Note 9). The Accumulated other
comprehensive income (loss) as of September 30, 2007, 2006, and 2005, was $(19)
million, $43 million, and $27 million, respectively.
|
Total
Other Comprehensive Income (Loss) Activity
As
of September 30
|
||||
|
Accumulated
other comprehensive loss, October 1, 2004
|
$ (52
|
) | ||
|
Changes
in fair value:
|
|
|||
|
Inflation
swap
|
4
|
|||
|
Foreign
currency swaps 1
|
75
|
|||
|
Accumulated
other comprehensive income, September 30, 2005
|
27
|
|||
|
Changes
in fair value:
|
||||
|
Inflation
swap
|
(11
|
) | ||
|
Foreign
currency swaps 1
|
27
|
|||
|
Accumulated
other comprehensive income, September 30, 2006
|
43
|
|||
|
Changes
in fair value:
|
||||
|
Inflation
swap
|
9
|
|||
|
Foreign
currency swaps 1
|
(71
|
) | ||
|
Accumulated
other comprehensive loss, September 30, 2007
|
$ (19
|
) | ||
|
Notes:
(1) Foreign
currency swap changes are shown net of reclassifications from Other
comprehensive income to earnings.
(2) See
Note 13.
|
||||
TVA
records exchange rate gains and
losses on debt in earnings and marks its currency swap assets to market through
other comprehensive income. TVA then reclassifies an amount out of
other comprehensive income into earnings offsetting the earnings gain/loss
from
recording the exchange gain/loss on the debt. The amounts
reclassified from other comprehensive income resulted in an increase to earnings
of $104 million in 2007, an increase to earnings of $143 million in 2006, and
a
charge to earnings of $61 million in 2005. These reclassifications,
coupled with the recording of the exchange gain/loss on the debt, resulted
in a
net effect on earnings of zero for 2007, 2006, and 2005. Due to the
number of variables affecting the future gains/losses on these instruments,
TVA
is unable to reasonably estimate the amount to be reclassified from other
comprehensive income to earnings in future years.
9.
Risk Management Activities and Derivative Transactions
TVA
is exposed to various market
risks. These market risks include risks related to commodity prices,
investment prices, interest rates, currency exchange rates, inflation, and
credit risk. To help manage certain of these risks, TVA has entered
into various derivative transactions, principally commodity option contracts,
forward contracts, swaps, swaptions, futures, and options on
futures. Following is a general overview of the accounting treatment
for these derivative transactions as well as a more detailed discussion of
certain of these derivative transactions. It is TVA’s policy to enter
into derivative transactions solely for hedging purposes and not for speculative
purposes.
Overview
of Accounting
Treatment
Prior
to October 1, 2000, TVA accounted
for hedging activities using the deferral method, and gains and losses were
recognized in the financial statements when the related hedged transaction
occurred. During 2001, TVA adopted SFAS No. 133, which was
subsequently amended by SFAS No. 138, “Accounting for Certain Derivative
Instruments and Certain Hedging Activities,” and SFAS No. 149,
“Amendment of Statement 133 on Derivative Instruments and Hedging
Activities.”
The
following tables summarize the accounting treatment that certain of TVA’s
financial derivative transactions receive.
Summary
of Derivative Instruments That Receive Hedge Accounting
Treatment
As
of
September 30, 2007
|
Derivative
Hedging Instrument
|
Hedged
Item
|
Purpose
of Hedge Transaction
|
Type
of Hedge
|
Accounting
for Derivative Hedging Instrument
|
Accounting
for the Hedged Item
|
|
Currency
Swaps
|
Anticipated
payment denominated in a foreign currency
|
To
protect against changes in cash flows caused by changes in
foreign-currency exchange rates
|
Cash
Flow
|
Cumulative
unrealized gains and losses are recorded in Other comprehensive income
and
reclassified to earnings to the extent they are offset by cumulative
gains
and losses on the hedged transaction.
|
No
adjustment is made to the basis of the hedged
item.
|
Summary
of Derivative Instruments That Do Not Receive Hedge Accounting
Treatment
As
of
September 30, 2007
|
Derivative
Type
|
Purpose
of Derivative
|
Accounting
for Derivative Instrument
|
|
Coal
Contracts with Volume Options
|
To
protect against fluctuations in market prices of the item to be
purchased
|
Gains
and losses are recorded as regulatory assets or liabilities until
settlement at which time they are recognized in fuel and purchased
power
expense.
|
|
Interest
Rate Swap
|
To
fix short-term debt variable rate to a fixed rate
|
Gains
and losses are recorded in earnings as unrealized gains/losses on
derivative contracts.
|
|
Swaptions
|
To
protect against decreases in value of the embedded call
|
Gains
and losses are recorded in earnings as unrealized gains/losses on
derivative contracts.
|
|
Futures
and Options on Futures
|
To
protect against fluctuations in the price of the item to be
purchased
|
Realized
gains and losses are recorded in earnings as purchased power expense;
unrealized gains and losses are recorded as a regulatory
asset/liability.
|
TVA
has recorded the following amounts
for its derivative financial instruments:
Mark-to-Market
Values of TVA Derivatives
As
of
September 30
|
2007
Balance
|
2007
Balance
Sheet Presentation
|
2006
Balance
|
2006 Balance Sheet Presentation
|
2007
Notional Amount
|
Year
of Expiration
|
|||
|
Inflation
swap
|
$ –
|
–
|
$22
|
Other
long-term assets
|
–
|
2007
|
||
|
Interest
rate swap
|
(115
|
) |
Other
liabilities
|
(131
|
) |
Other
liabilities
|
$476
million
|
2044
|
|
Currency
swaps:
|
||||||||
|
Sterling
|
63
|
Other
long-term assets
|
47
|
Other
long-term assets
|
£200
million
|
2021
|
||
|
Sterling
|
148
|
Other
long-term assets
|
133
|
Other
long-term assets
|
£250
million
|
2032
|
||
|
Sterling
|
69
|
Other
long-term assets
|
66
|
Other
long-term assets
|
£150
million
|
2043
|
||
|
Swaptions:
|
||||||||
|
$1
billion notional
|
(269
|
) |
Other
liabilities
|
(296
|
) |
Other
liabilities
|
$1
billion
|
2042
|
|
$28
million notional
|
(3
|
) |
Other
liabilities
|
(3
|
) |
Other
liabilities
|
$28
million
|
2022
|
|
$14
million notional
|
(1
|
) |
Other
liabilities
|
(2
|
) |
Other
liabilities
|
$14
million
|
2022
|
|
Coal
contracts with volume options
|
16
|
Other
long-term assets
|
487
|
Other
long-term assets
|
115
million tons
|
2017
|
||
|
Purchase
power option contracts
|
–
|
–
|
(22
|
) |
Other
liabilities
|
–
|
2007
|
|
|
Futures
and options on futures:
|
||||||||
|
Margin
Cash Account*
|
18
|
Inventories
and other
|
6
|
Inventories
and other
|
23,800,000
mmBtu
|
2009
|
||
|
Unrealized
losses
|
8
|
Other
regulatory assets
|
6
|
Other
regulatory assets
|
–
|
–
|
||
Note
|
|
*
|
In
accordance with certain credit terms, TVA used leveraging to trade
financial instruments under the financial trading
program. Therefore, the margin cash account balance does not
represent 100 percent of the net market value of the derivative positions
outstanding as shown in the Financial Trading Program Activity
table.
|
Commodity
Contracts
TVA
enters into forward contracts that
hedge cash flow exposures to market fluctuations in the price and delivery
of
certain commodities including coal, natural gas, and electricity. TVA
expects to take or make delivery, as appropriate, under these forward
contracts. Accordingly, these contracts qualify for normal purchases
and normal sales accounting under SFAS No. 133, as amended.
Swaps
To
hedge certain market risks to which
TVA is subject, TVA has entered into four currency swaps three of which were
still outstanding at September 30, 2007, and one inflation swap which expired
in
2007. Following is a discussion of each of these swaps as well as a
discussion of the hedge accounting treatment that these swaps
receive.
Currency
Swaps. During 1996, TVA entered into a currency swap contract as
a hedge for a foreign currency denominated Bond transaction. TVA
issued DM1.5 billion of Bonds and entered into a currency swap to hedge
fluctuations in the DM-U.S. dollar exchange rate. The overall
effective cost to TVA of these Bonds and the associated swap was 7.13
percent. In 2006, the Bonds matured and the related swap agreement
expired.
In
addition, TVA entered into currency
swap contracts during 2003, 2001, and 1999 as hedges for sterling-denominated
Bond transactions in which TVA issued £150 million, £250 million, and £200
million of Bonds, respectively. The overall effective cost to TVA of
these Bonds and the associated swaps was 4.96 percent, 6.59 percent, and 5.81
percent, respectively. Any gains or losses on the Bonds due to the
foreign currency transactions are offset by losses or gains on the swap
contracts. At September 30, 2007 and 2006, the currency transactions
had resulted in net exchange losses of $299 million and of $195 million,
respectively, which are included in Long-term debt, net. However, the
net exchange losses were offset by corresponding gains on the swap contracts,
which are reported as a deferred asset.
In
accordance with SFAS No. 133, as
amended, the foreign currency swap contracts represent cash flow hedges of
certain Bond transactions and any mark-to-market gains or losses have been
recognized in Accumulated other comprehensive income (loss). If any loss (gain)
were to be incurred as a result of the early termination of the foreign currency
swap contract, any resulting charge (income) would be amortized over the
remaining life of the associated Bond as a component of interest
expense.
Inflation Swap. In 1997, TVA issued $300 million of
inflation-indexed accreting principal Bonds. The 10-year Bonds had a
fixed coupon rate that was paid on the inflation-adjusted principal
amount. TVA hedged its inflation exposure under the securities
through a receive-floating, pay-fixed inflation swap agreement. The
overall effective cost to TVA of these Bonds and the associated swap was 6.64
percent. On September 21, 2004, TVA received a payment of $55 million
from the swap counterparty representing the present value of the accretion
as of
that date. The present value of the accretion is recorded as a
long-term receivable on the September 30, 2006, Balance Sheets. At
the termination of the swap in 2007, TVA received the additional $23 million
in
accretion from the swap counterparty.
In
accordance
with SFAS No. 133, as amended, the inflation swap contract represented a cash
flow hedge of a Bond transaction, with mark-to-market gains or losses recognized
in accumulated other comprehensive income (loss). The inflation swap
contract expired during 2007.
Swaptions
and Related Interest Rate
Swap
TVA
has entered into four swaption
transactions to monetize the value of call provisions on certain of its Bond
issues. A swaption essentially grants a third party the right to
enter into a swap agreement with TVA under which TVA receives a floating rate
of
interest and pays the third party a fixed rate of interest equal to the interest
rate on the bond issue whose call provision TVA monetized.
|
•
|
In
2003, TVA monetized the call provisions on a $1 billion Bond issue
by
entering into a swaption agreement with a third party in exchange
for $175
million (the “2003A Swaption”).
|
|
•
|
In
2003, TVA also monetized the call provisions on a Bond issue of $476
million by entering into a swaption agreement with a third party
in
exchange for $81 million (the “2003B
Swaption”).
|
|
•
|
In
2005, TVA monetized the call provisions on two electronotes®
issues ($42
million total par value) by entering into swaption agreements with
a third
party in exchange for $5 million (the “2005
Swaptions”).
|
In
February 2004, the counterparty to
the 2003B Swaption transaction exercised its option to enter into a swap with
TVA, effective April 10, 2004, requiring TVA to make fixed rate payments to
the
counterparty of 6.875 percent and the counterparty to make floating payments
to
TVA based on London Interbank Offered Rate. These payments are based
on a notional principal amount of $476 million, and the parties began making
these payments on June 15, 2004.
The
2003A Swaption was recorded in
Other liabilities on the September 30, 2007 and 2006, Balance Sheets and is
designated as a hedge of future changes in the fair value of the original call
provision. Under SFAS No. 133, as amended, TVA records the changes in
market value of both the swaption and the embedded call. These values
historically have been highly correlated; however, to the extent that the values
do not perfectly offset, any differences will be recognized currently through
earnings. In the third quarter of 2006, the hedge related to the
2003A Swaption ceased to be effective and continued to be ineffective during
the
fourth quarter of 2007 from an accounting perspective. As a result,
TVA has not received hedge accounting treatment on the 2003A Swaption since
the
second quarter of 2006.
Changes
in the market value of the
2003A Swaption and the embedded call resulted in an unrealized noncash gain
of
$24 million for the fiscal year ended September 30, 2007, in an unrealized
noncash loss of $43 million for the year-ended September 30, 2006, and an
unrealized noncash gain of $27 million for the year-ended September 30,
2005.
The
2005 Swaptions and the swap entered
into pursuant to the 2003B Swaption are also recorded in Other liabilities
on
the September 30, 2007 and 2006, Balance Sheets, and the changes in market
value
are recognized currently in earnings. These changes amounted to a $16
million noncash gain for the year ended September 30, 2007, and a $28 million
noncash gain for the year ended September 30, 2006. TVA did not elect
hedge accounting treatment for the 2005 Swaptions.
Futures
and Options on
Futures
In
2005, the TVA Board approved a
financial trading program under which TVA can purchase swaps, options on swaps,
futures, and options on futures to hedge TVA’s exposure to natural gas and fuel
oil prices. In August 2007, the TVA Board expanded the financial
trading program, among other things, (1) to permit financial trading for
the purpose of hedging or otherwise limiting the economic risks associated
with
the price of electricity, coal, emission allowances, nuclear fuel, and other
commodities such as ammonia and limestone, as well as the price of natural
gas
and fuel oil, (2) to authorize the use of futures, swaps, options, and
combinations of these instruments as long as these instruments are standard
in
the industry, (3) to authorize the use of the Intercontinental Exchange as
well as the New York Mercantile
Exchange
to trade financial instruments, and (4) to increase the aggregate
transaction limit to $130 million (based on one-day Value at Risk). Under
the expanded program, TVA is still prohibited from trading financial instruments
for speculative purposes.
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, 788 swap futures contracts,
and
560 options contracts with an approximate net market value of $136
million. For the year ended September 30, 2007, TVA recognized
realized losses of $45 million, which were recorded as an increase to purchased
power expense. Unrealized losses at the end of the year were $8
million, which TVA deferred as a regulatory asset in accordance with the FCA
rate mechanism. TVA will continue to defer all financial trading
program unrealized gains or losses and record only realized gains or losses
as
purchased power costs at the time the derivative instruments are
settled.
At
September 30, 2006, TVA had
derivative positions outstanding under the program equivalent to about 1,158
contracts, made up of 429 futures contracts and 729 swap futures contracts,
with
an approximate net market value of $40 million. For the year ended
September 30, 2006, TVA recognized realized losses of $23 million, which were
recorded as an increase to purchased power expense. Unrealized losses
at the end of the year were $6 million, which TVA deferred as a regulatory
asset
in accordance with the FCA rate mechanism.
Financial
Trading Program Activity
As
of
September 30
|
2007
|
2006
|
||||||||||||
|
NotionalAmount
|
Contract
Value
|
Notional
Amount
|
Contract
Value
|
||||||||||
|
(in
mmBtu)
|
(in
millions)
|
(in
mmBtu)
|
(in
millions)
|
||||||||||
|
Futures
contracts
|
|||||||||||||
|
Financial
positions, beginning of period, net
|
4,290,000
|
$ 35
|
880,000
|
$ 9
|
|||||||||
|
Purchased
|
52,780,000
|
403
|
18,160,000
|
146
|
|||||||||
|
Settled
|
(40,840,000
|
) |
(273
|
) |
(14,750,000
|
) |
(97
|
) | |||||
|
Realized
(losses)
|
–
|
(34
|
) |
–
|
(23
|
) | |||||||
|
Net
positions-long
|
16,230,000
|
131
|
4,290,000
|
35
|
|||||||||
|
Swap
futures
|
|||||||||||||
|
Financial
positions, beginning of period, net
|
1,822,500
|
11
|
–
|
–
|
|||||||||
|
Fixed
portion
|
17,007,500
|
120
|
1,977,500
|
12
|
|||||||||
|
Floating
portion - realized
|
(16,860,000
|
) |
(108
|
) |
(155,000
|
) |
(1
|
) | |||||
|
Realized
(losses)
|
–
|
(11
|
) |
–
|
–
|
||||||||
|
Net
positions-long
|
1,970,000
|
12
|
1,822,500
|
11
|
|||||||||
|
Option
contracts
|
|||||||||||||
|
Financial
positions, beginning of period, net
|
–
|
–
|
240,000
|
–
|
|||||||||
|
Calls
purchased
|
2,900,000
|
2
|
–
|
–
|
|||||||||
|
Puts
sold
|
2,900,000
|
(1
|
) |
–
|
–
|
||||||||
|
Positions
closed or expired
|
(200,000
|
) |
–
|
(240,000
|
) |
–
|
|||||||
|
Net
positions-long
|
5,600,000
|
1
|
–
|
–
|
|||||||||
|
Holding
(losses)/gains
|
|||||||||||||
|
Unrealized
(loss) gain at beginning of period, net
|
–
|
(6
|
) |
–
|
1
|
||||||||
|
Unrealized
(losses) for the period
|
–
|
(2
|
) |
–
|
(7
|
) | |||||||
|
Unrealized
(losses) at end of period, net
|
–
|
(8
|
) |
–
|
(6
|
) | |||||||
|
|
|||||||||||||
|
Financial
positions at end of period, net
|
23,800,000
|
$136
|
6,112,500
|
$ 40
|
|||||||||
Concentration
of Credit
Risk. Seven customers, which represented an aggregate of 33
percent of TVA’s total power sales in 2007 and 2006, purchased power from TVA
under contracts that require either five or 10 years’ notice to
terminate. Outstanding accounts receivable for these customers at
September 30, 2007, were $593 million, or 41 percent of total outstanding
accounts receivable, and at September 30, 2006, were $561 million, or 42 percent
of total outstanding accounts receivable.
10.
Debt
General
The
TVA Act authorizes TVA to issue
Bonds in an amount not to exceed $30 billion 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 are both issued pursuant to
section 15d of the TVA Act and pursuant to the Basic Tennessee Valley Authority
Power Bond Resolution adopted by the TVA Board on October 6, 1960, as amended
on
September 28, 1976, October 17, 1989, and March 25, 1992 (the “Basic
Resolution”). TVA Bonds are not obligations of the United States, and
the United States does not guarantee the payments of principal or interest
on
Bonds.
Power
bonds and discount notes rank on
parity and have first priority of payment out of net power proceeds, which
are
defined as:
|
•
|
the
remainder of TVA’s gross power
revenues
|
|
o
|
after
deducting
|
|
–
|
the
costs of operating, maintaining, and administering its power properties,
and
|
|
–
|
payments
to states and counties in lieu of taxes,
but
|
|
o
|
before
deducting depreciation accruals or other charges representing the
amortization of capital expenditures,
plus
|
|
•
|
the
net proceeds from the sale or other disposition of any power facility
or
interest therein.
|
Because
TVA’s lease payments under its
lease/leaseback transactions are considered costs of operating, maintaining, and
administering its power properties, those payments have priority over TVA’s
payments on the Bonds. See Note 12 — Other Financing
Obligations. Once Net Power Proceeds have been applied to
payments on power bonds and discount notes as well as any other Bonds that
TVA
may issue in the future that rank on parity with or subordinate to power bonds
and discount notes, Section 2.3 of the Basic Resolution provides that the
remaining net power proceeds shall be used only for minimum payments into the
United States Treasury required by the TVA Act in repayment of and as a return
on the Power Facility Appropriation Investment, investment in power assets,
additional reductions of TVA’s capital obligations, and other lawful purposes
related to TVA’s power program.
The
TVA Act and the Basic Resolution
each contain two bond tests: the rate 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, among other
things, debt service on outstanding Bonds. See Note 1 —
General. Under the bondholder protection test, TVA must, in
successive five-year periods, use an amount of net power proceeds at least
equal
to the sum of:
|
–
|
the
depreciation accruals and other charges representing the amortization
of
capital expenditures and
|
|
–
|
the
net proceeds from any disposition of power
facilities
|
for
either
|
–
|
the
reduction of its capital obligations (including Bonds and the Power
Facility Appropriation Investment)
or
|
|
–
|
investment
in power assets.
|
TVA
must next meet the bondholder
protection test for the five-year period ending September 30,
2010. See Note 8 — Appropriation Investment.
Short-Term
Debt
The
weighted average rates applicable
to short-term debt outstanding in the public market as of September 30, 2007,
2006, and 2005, were 4.74 percent, 5.21 percent, and 3.64 percent,
respectively. During 2007, 2006, and 2005, the maximum outstanding
balances of TVA short-term borrowings held by the public were $2.8 billion,
$2.8
billion, and $3.1 billion, respectively. For these same years, the
average amounts (and weighted average interest rates) of TVA short-term
borrowings were approximately $2.3 billion (5.17 percent), $2.0 billion (4.47
percent), and $2.1 billion (2.70 percent), respectively.
TVA
also has access to a financing arrangement with the U.S. Treasury whereby the
U.S. Treasury is authorized to accept a short-term note with the maturity of
one
year or less in an amount not to exceed $150 million. TVA may draw
any portion of the authorized $150 million during the year. Interest
is accrued daily and paid quarterly at a rate determined by the United States
Secretary of the Treasury each month based on the average rate on outstanding
marketable obligations of the United States with maturities of one year or
less. During 2007, 2006, and 2005, the daily average amounts
outstanding (and average interest rates) were approximately $132 million (5.07
percent), $131 million (4.33 percent), and $103 million (2.46 percent),
respectively.
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 November
10, 2008. See Note 17 — Revolving Credit Facility
Agreement. The interest rate on any borrowing under 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.
Put
and Call Options
Bond issues of $2.3 billion held by the public are redeemable in whole or in
part, at TVA’s option, on call dates ranging from the present to 2020 and at
call prices ranging from 100 percent to 106 percent of the principal
amount. Sixty-nine Bond issues totaling $1.1 billion, with maturity
dates ranging from 2008 to 2027, include a “survivor’s option,” which allows for
right of redemption upon the death of a beneficial owner in certain specified
circumstances. There is no accounting difference between a
“survivor’s option” put and a “regular” put on any TVA put Bond.
Additionally, TVA has two issues of Putable Automatic Rate Reset Securities
(“PARRS”) outstanding. After a fixed-rate period of five years, the
coupon rate on the PARRS may automatically be reset downward under certain
market conditions on an annual basis. The coupon rate reset on the
PARRS is based on a calculation. For both series of PARRS, the coupon rate
will reset downward on the reset date if the rate calculated is below the coupon
rate on the Bond. The calculation dates, potential reset dates,
and terms of the calculation are different for each series. The coupon
rate on the 1998 Series D PARRS may be reset on June 1 (annually) if the sum
of the five-day average of the 30-Year Constant Maturity Treasury (“CMT”)
rate for the week ending the last Friday in April, plus 94 basis points, is
below the then-current coupon rate. The coupon rate on the 1999
Series A PARRS may be reset on May 1 (annually) if the sum of the
five-day average of the 30-Year CMT rate for the week ending the last Friday
in
March, plus 84 basis points, is below the then-current coupon rate. The
coupon rates may only be reset downward, but investors may request to redeem
their bonds at par value in conjunction with a coupon rate reset for a limited
period of time prior to the reset dates and under certain
circumstances. Due to the contingent nature of the put option on the
PARRS, TVA determines whether the PARRS should be classified as long-term debt
or current maturities of long-term debt by calculating the expected reset rate
on the bonds. The expected reset rate is calculated using forward
rates and the fixed spread for each bond issue as noted above. If the
expected reset rate is less than the coupon on the bond, the PARRS are included
in current maturities. Otherwise, the PARRS are included in long-term
debt. At September 30, 2007, the expected reset rate is higher than
the current coupon on each issue of PARRS; therefore, the par amount outstanding
is classified as long-term debt.
The
1998 Series D PARRS issue totals
$466 million, matures in June 2028, and had its first reset date in June
2003. The rate reset to 5.95 percent from 6.75 percent in June 2003,
at which time $23 million of the original $575 million 1998 Series D PARRS
were
redeemed at par. The rate reset again to 5.49 percent from 5.95 percent in
June
2005, at which time $86 million of the 1998 Series D PARRS were redeemed at
par. The 1999 Series A PARRS issue totals $410 million, matures in
May 2029, and had its first rate reset date in May 2004. The rate
reset in May 2004 to 5.62 percent from 6.50 percent, and $115 million of the
original $525 million of 1999 Series A PARRS were redeemed at par.
Debt
Securities
Activity
The
table below summarizes TVA’s Bond
activity for the period from October 1, 2005, to September 30,
2007.
Debt
Securities Activity from October 1, 2005, to September 30,
2007
|
Principal
Amount
|
|||||||
|
Redemptions/Maturities:
|
2007
|
2006
|
|||||
|
electronotes®
|
|||||||
|
First
quarter
|
$ 2
|
$ 152
|
|||||
|
Second
quarter
|
5
|
3
|
|||||
|
Third
quarter
|
5
|
4
|
|||||
|
Fourth
quarter
|
1
|
4
|
|||||
|
2001
Series D
|
75
|
–
|
|||||
|
1997
Series A
|
382
|
–
|
|||||
|
1996
Series C
|
–
|
1,000
|
|||||
|
2003
Series B
|
–
|
28
|
* | ||||
|
2005
Series A
|
–
|
64
|
* | ||||
|
Total
|
$ 470
|
$ 1,255
|
|||||
|
|
|||||||
|
Issues:
|
|||||||
|
electronotes®
|
|||||||
|
First
quarter
|
9
|
$ 49
|
|||||
|
Second
quarter
|
19
|
19
|
|||||
|
Third
quarter
|
8
|
37
|
|||||
|
Fourth
quarter
|
4
|
27
|
|||||
|
2006
Series A
|
–
|
1,000
|
|||||
|
2007
Series A
|
1,000
|
–
|
|||||
|
Total
|
$ 1,040
|
$ 1,132
|
|||||
|
Inflation
indexed bond (decretion) accretion
|
$ (3
|
) |
$ 15
|
||||
Note
* Includes $13 million gain on redemption.
Debt
Outstanding
Debt
outstanding at September 30, 2007,
consisted of the following:
Short-Term
Debt
As
of
September 30
|
CUSIP
or Other Identifier
|
Maturity
|
Call/(Put)
Date
|
Coupon
Rate
|
2007
Par
Amount
|
2006
Par
Amount
|
|||||
|
Discount
Notes (net of discount)
|
$ 1,422
|
$ 2,376
|
||||||||
|
Current
maturities of long-term debt:
|
||||||||||
|
880591CQ3
|
01/15/2007
|
6.643%*
|
–
|
385
|
||||||
|
880591DS8
|
12/15/2016
|
(12/15/2006)
|
4.875%
|
–
|
600
|
|||||
|
88059TBQ3
|
01/15/2008
|
01/15/2004
|
3.05%
|
10
|
–
|
|||||
|
88059TBS9
|
01/15/2008
|
01/15/2004
|
3.30%
|
40
|
–
|
|||||
|
88059TCB5
|
05/15/2008
|
05/15/2004
|
2.45%
|
40
|
–
|
|||||
|
Current
maturities of long-term debt
|
90
|
985
|
||||||||
|
|
||||||||||
|
Total
short-term debt, net
|
$ 1,512
|
$ 3,361
|
||||||||
|
Note:
*
The coupon rate represents TVA’s effective interest
rate.
|
||||||||||
Long-Term
Debt 1
As
of
September 30
|
CUSIP
or Other Identifier
|
Maturity
|
Call/(Put)
Date
|
Coupon
Rate
|
2007
Par
Amount
|
2006
Par Amount
|
|||||
|
88059TBQ3
|
01/15/2008
|
01/15/2004
|
3.050%
|
$–
|
$10
|
|||||
|
88059TBS9
|
01/15/2008
|
01/15/2004
|
3.300%
|
–
|
40
|
|||||
|
88059TCB5
|
05/15/2008
|
05/15/2004
|
2.450%
|
–
|
|
40
|
||||
|
Maturing
in 2008
|
–
|
90
|
||||||||
|
880591DB5
|
11/13/2008
|
5.375%
|
2,000
|
2,000
|
||||||
|
88059TCW9
|
03/15/2009
|
03/15/2005
|
3.200%
|
30
|
30
|
|||||
|
Maturing
in 2009
|
2,030
|
2,030
|
||||||||
|
88059TDP3
|
04/15/2010
|
04/15/2007
|
5.125%
|
21
|
21
|
|||||
|
88059TDD0
|
06/15/2010
|
06/15/2006
|
4.125%
|
41
|
42
|
|||||
|
Maturing
in 2010
|
62
|
63
|
||||||||
|
880591DN9
|
01/18/2011
|
5.625%
|
1,000
|
1,000
|
||||||
|
88059TDQ1
|
05/15/2011
|
05/15/2007
|
5.250%
|
6
|
6
|
|||||
|
88059TDR9
|
06/15/2011
|
06/15/2007
|
5.250%
|
9
|
9
|
|||||
|
Maturing
in 2011
|
1,015
|
1,015
|
||||||||
|
880591DL3
|
05/23/2012
|
7.140%
|
29
|
29
|
||||||
|
880591DT6
|
05/23/2012
|
6.790%
|
1,486
|
1,486
|
||||||
|
88059TBH3
|
09/15/2012
|
09/15/2004
|
4.375%
|
10
|
10
|
|||||
|
Maturing
in 2012
|
1,525
|
1,525
|
||||||||
|
880591CW0
|
03/15/2013
|
6.000%
|
1,359
|
1,359
|
||||||
|
88059TBR1
|
01/15/2013
|
01/15/2005
|
4.375%
|
14
|
14
|
|||||
|
88059TBW0
|
03/15/2013
|
03/15/2005
|
4.000%
|
23
|
23
|
|||||
|
88059TBX8
|
03/15/2013
|
03/15/2004
|
4.250%
|
12
|
13
|
|||||
|
88059TCD1
|
06/15/2013
|
06/15/2004
|
3.500%
|
12
|
12
|
|||||
|
880591DW9
|
08/01/2013
|
4.750%
|
990
|
990
|
||||||
|
88059TCF6
|
07/15/2013
|
07/15/2005
|
4.350%
|
17
|
17
|
|||||
|
88059TDS7
|
07/15/2013
|
07/15/2008
|
5.625%
|
9
|
9
|
|||||
|
Maturing
in 2013
|
2,436
|
2,437
|
||||||||
|
88059TCL3
|
10/15/2013
|
10/15/2005
|
4.500%
|
12
|
12
|
|||||
|
88059TCQ2
|
12/15/2013
|
12/15/2005
|
4.700%
|
8
|
8
|
|||||
|
88059TDX6
|
02/15/2014
|
02/15/2008
|
5.250%
|
7
|
–
|
|||||
|
88059TDZ1
|
04/15/2014
|
04/15/2008
|
5.000%
|
4
|
–
|
|||||
|
Maturing
in 2014
|
31
|
20
|
||||||||
|
88059TBJ9
|
10/15/2014
|
10/15/2004
|
4.600%
|
21
|
22
|
|||||
|
88059TBN0
|
12/15/2014
|
12/15/2004
|
5.000%
|
54
|
54
|
|||||
|
88059TBY6
|
04/15/2015
|
04/15/2005
|
4.600%
|
20
|
20
|
|||||
|
88059TDB4
|
04/15/2015
|
04/15/2007
|
5.000%
|
50
|
50
|
|||||
|
880591DY5
|
06/15/2015
|
4.375%
|
1,000
|
1,000
|
||||||
|
88059TDE8
|
07/15/2015
|
07/15/2007
|
4.500%
|
7
|
7
|
|||||
|
88059TCH2
|
08/15/2015
|
08/15/2005
|
5.125%
|
34
|
34
|
|||||
|
88050TBK6
|
10/15/2015
|
10/15/2005
|
5.050%
|
19
|
19
|
|||||
|
88059TDH1
|
10/15/2015
|
10/15/2007
|
5.000%
|
27
|
28
|
|||||
|
88059TBL4
|
11/15/2015
|
11/15/2005
|
4.800%
|
26
|
27
|
|||||
|
88059TCR0
|
12/15/2015
|
12/15/2005
|
4.875%
|
11
|
11
|
|||||
|
88059TDK4
|
12/15/2015
|
12/15/2006
|
5.375%
|
10
|
10
|
|||||
|
88059TBU4
|
02/15/2016
|
02/15/2006
|
4.550%
|
8
|
9
|
|||||
|
88059TCV1
|
02/15/2016
|
02/15/2006
|
4.500%
|
3
|
3
|
|||||
|
88059TDN8
|
03/15/2016
|
03/15/2008
|
5.375%
|
8
|
8
|
|||||
|
88059TCC3
|
06/15/2016
|
06/15/2006
|
3.875%
|
3
|
4
|
|||||
|
88059TDT5
|
08/15/2016
|
08/15/2007
|
5.625%
|
4
|
4
|
|||||
|
88059TCJ8
|
09/15/2016
|
09/15/2006
|
4.950%
|
11
|
11
|
|||||
|
88059TDU2
|
09/15/2016
|
09/15/2007
|
5.375%
|
14
|
14
|
|||||
|
880591DS8
|
12/15/2016
|
4.875%
|
524
|
–
|
||||||
|
88059TCS8
|
01/15/2017
|
01/15/2007
|
5.000%
|
28
|
29
|
|||||
|
88059TDW8
|
01/15/2017
|
01/15/2008
|
5.250%
|
6
|
–
|
|||||
|
88059TEA5
|
06/15/2017
|
06/15/2008
|
5.500%
|
4
|
–
|
|||||
|
880591EA6
|
07/18/2017
|
5.500%
|
1,000
|
–
|
||||||
|
88059TEB3
|
09/15/2017
|
09/15/2009
|
5.000%
|
4
|
–
|
|||||
|
|
||||||||||
|
CUSIP
or Other Identifier
|
Maturity
|
Call/(Put)
Date
|
Coupon
Rate
|
2007
Par
Amount
|
2006
Par
Amount
|
||||
|
880591CU4
|
12/15/2017
|
6.250%
|
750
|
750
|
|||||
|
88059TCA7
|
05/15/2018
|
05/15/2004
|
4.750%
|
24
|
24
|
|
|||
|
88059TCE9
|
07/15/2018
|
07/15/2004
|
4.700%
|
35
|
35
|
|
|||
|
88059TCN9
|
11/15/2018
|
11/15/2006
|
5.125%
|
18
|
18
|
|
|||
|
88059TCT6
|
01/15/2019
|
01/15/2005
|
5.000%
|
28
|
28
|
||||
|
88059TCX7
|
03/15/2019
|
03/15/2007
|
4.500%
|
12
|
13
|
||||
|
88059TDF5
|
08/15/2020
|
08/15/2008
|
5.000%
|
10
|
10
|
||||
|
88059TDG3
|
09/15/2020
|
09/15/2008
|
4.800%
|
3
|
3
|
||||
|
88059TDJ7
|
11/15/2020
|
11/15/2008
|
5.500%
|
11
|
11
|
||||
|
88059TDL2
|
01/18/2021
|
01/15/2009
|
5.125%
|
5
|
5
|
||||
|
880591DC3
|
06/07/2021
|
5.805%
2
|
409
|
374
|
|||||
|
88859TAN1
|
12/15/2021
|
12/15/2005
|
6.000%
|
25
|
25
|
||||
|
88059TAR2
|
01/15/2022
|
01/15/2006
|
6.125%
|
28
|
28
|
||||
|
88059TDY4
|
03/15/2022
|
03/15/2008
|
5.375%
|
6
|
–
|
||||
|
88059TAX9
|
04/15/2022
|
04/15/2006
|
6.125%
|
13
|
14
|
||||
|
88059TBE0
|
08/15/2022
|
08/15/2006
|
5.500%
|
28
|
28
|
||||
|
88059TBM2
|
11/15/2022
|
11/15/2006
|
5.000%
|
11
|
11
|
||||
|
88059TBP5
|
12/15/2022
|
12/15/2006
|
5.000%
|
19
|
20
|
||||
|
88059TBT7
|
01/15/2023
|
01/15/2007
|
5.000%
|
11
|
11
|
||||
|
88059TBV2
|
02/15/2023
|
02/15/2007
|
5.000%
|
16
|
17
|
||||
|
88059TBZ3
|
05/15/2023
|
05/15/2004
|
5.125%
|
14
|
15
|
||||
|
88059TCK5
|
10/15/2023
|
10/15/2007
|
5.200%
|
14
|
14
|
||||
|
88059TCP4
|
11/15/2023
|
11/15/2004
|
5.250%
|
12
|
12
|
||||
|
88059TCU3
|
02/15/2024
|
02/15/2008
|
5.125%
|
9
|
9
|
||||
|
88059TCY5
|
04/15/2024
|
04/15/2005
|
5.375%
|
14
|
14
|
||||
|
88059TCZ2
|
02/15/2025
|
02/15/2006
|
5.000%
|
18
|
18
|
||||
|
88059TDA6
|
03/15/2025
|
03/15/2009
|
5.000%
|
6
|
6
|
||||
|
88059TDC2
|
05/15/2025
|
05/15/2009
|
5.125%
|
14
|
14
|
||||
|
880591CJ9
|
11/01/2025
|
6.750%
|
1,350
|
1,350
|
|||||
|
88059TDM0
|
02/15/2026
|
02/15/2010
|
5.500%
|
7
|
7
|
||||
|
88059TDV0
|
10/15/2026
|
10/15/2010
|
5.500%
|
9
|
–
|
||||
|
880591300
3
|
06/01/2028
|
5.490%
|
466
|
466
|
|||||
|
880591409
3
|
05/01/2029
|
5.618%
|
410
|
410
|
|||||
|
880591DM1
|
05/01/2030
|
7.125%
|
1,000
|
1,000
|
|||||
|
880591DP4
|
06/07/2032
|
6.587%
2
|
512
|
468
|
|||||
|
880591DV1
|
07/15/2033
|
4.700%
|
472
|
472
|
|||||
|
880591DX7
|
06/15/2035
|
4.650%
|
436
|
436
|
|||||
|
880591CK6
|
04/01/2036
|
5.980%
|
121
|
121
|
|||||
|
880591CS9
|
04/01/2036
|
5.880%
|
1,500
|
1,500
|
|||||
|
880591CP5
|
01/15/2038
|
6.150%
|
1,000
|
1,000
|
|||||
|
880591BL5
|
04/15/2042
|
04/15/2012
|
8.250%
|
1,000
|
1,000
|
||||
|
880591DU3
|
06/07/2043
|
4.962%
2
|
307
|
281
|
|||||
|
880591CF7
|
07/15/2045
|
07/15/2020
|
6.235%
|
140
|
140
|
||||
|
880591DZ2
|
04/01/2056
|
5.375%
|
1,000
|
1,000
|
|||||
|
Maturing
2015-2056
|
14,189
|
12,542
|
|||||||
|
Subtotal
|
21,288
|
19,722
|
|||||||
|
Unamortized
discounts, premiums,
and
other
|
(189)
|
(178)
|
|||||||
|
Total
long-term debt, net
|
$ 21,099
|
$ 19,544
|
|||||||
Notes
|
|
(1)
|
The
above table includes net exchange losses from currency transactions
of
$299 million and $195 million at September 30, 2007 and 2006,
respectively.
|
|
|
(2)
|
The
coupon rate represents TVA’s effective interest
rate.
|
|
|
(3)
|
TVA
PARRS, CUSIP numbers 880591300 and 880591409, may be redeemed under
certain conditions. See Note 10 — Put and Call
Options.
|
11.
Supplemental Cash Flow Information
Interest
paid was $1,248 million in
2007, $1,260 million in 2006, and $1,351 million in 2005. These
amounts differ from interest expense due to the timing of payments and interest
capitalized of $177 million in 2007, $163 million in 2006, and $116 million
in
2005 as a part of major capital expenditures.
TVA
had non-cash activity related to
financing transactions on the 2005 Statements of Cash Flows related to a capital
lease for BLEU fuel of $36.2 million. See Note 1 — Blended Low
Enriched Uranium Program. In 2006 TVA had non-cash activity
resulting from financing transactions of $13 million related to a gain on the
repurchase of Bonds. There were no non-cash activities for
2007.
Cash
flows from futures contracts,
forward contracts, option contracts, or swap contracts that are accounted for
as
hedges are classified in the same category as the item being hedged or on a
basis consistent with the nature of the instrument.
12. Fair
Value of Financial Instruments
TVA uses the methods and assumptions described below to estimate the fair value
of each significant class of financial instrument. The fair market value of
the
financial instruments held at September 30, 2007, may not be representative
of
the actual gains or losses that will be recorded when these instruments mature
or are called or presented for early redemption. The estimated values
of TVA’s financial instruments at September 30 are as follows:
|
Estimated
Values of Financial Instruments
As
of September 30
|
||||||||||||
|
2007
|
2006
|
|||||||||||
|
Carrying
Amount
|
Fair
Value
|
Carrying
Amount
|
Fair
Value
|
|||||||||
|
Cash
and cash equivalents
|
$
165
|
$ 165
|
$ 536
|
$ 536
|
||||||||
|
Restricted
cash and investments
|
150
|
150
|
198
|
198
|
||||||||
|
Investment
funds
|
1,169
|
1,169
|
972
|
972
|
||||||||
|
Loans
and other long-term receivables
|
79
|
79
|
102
|
102
|
||||||||
|
Short-term
debt, net of discount
|
1,422
|
1,422
|
2,376
|
2,376
|
||||||||
|
Long-term
debt (including current portion), net of discount
|
21,189
|
22,453
|
20,529
|
22,037
|
||||||||
|
Other
financing obligations
|
1,072
|
1,072
|
1,108
|
1,108
|
||||||||
Cash
and Cash Equivalents, Short-Term Investments, and Short-Term
Debt
Because
of the short-term maturity of
these instruments, the carrying amount approximates fair value.
Restricted Cash and Investments
Because
of the short-term maturity of
these instruments, the carrying amount approximates fair value.
Investment
Funds
Information
on investments by major
type at September 30 is as follows:
TVA
Investments By Type
As
of
September 30
|
2007
|
2006
|
||||||
|
Securities
held as trading
|
$ 1,162
|
$ 966
|
|||||
|
Other
|
7
|
6
|
|||||
|
Total
investment funds
|
$ 1,169
|
$ 972
|
|||||
Gains
and losses on trading securities
are recognized in current earnings. The gains and losses on the
nuclear decommissioning trust are subsequently reclassified to a regulatory
asset account in accordance with TVA’s decommissioning accounting
policy. The nuclear decommissioning trust had unrealized gains of $80
million in 2007, unrealized losses of $24 million in 2006, and unrealized gains
of $48 million in 2005. The nuclear decommissioning trust was
composed of 1,614 security positions as of September 30, 2007.
Loans
and Other Long-Term
Receivables
Fair
values for loans and long-term
receivables are estimated by determining the present value of future cash flows
using a discounted rate equal to lending rates for similar loans made to
borrowers with similar credit ratings and for the same remaining maturities.
The
carrying amount approximates fair value.
Long-Term
Debt
Fair
value of long-term debt traded in
the public market is determined by multiplying the par value of the debt by
the
indicative market price at the Balance Sheet date.
Other
Financing
Obligations
In
2003, 2002, and 2000, TVA received
approximately $325 million, $320 million, and $300 million, respectively, in
proceeds by entering into lease/leaseback transactions for 24 new peaking
combustion turbine units. TVA also received approximately $389
million in proceeds by entering into a lease/leaseback transaction for qualified
technological equipment and software in 2003. Due to the nature of
the transactions, the carrying amount of the obligation and the fair market
value are equal. At September 30, 2007 and 2006, the total balances
of the obligations were $1,072 million, and $1,108 million,
respectively.
Due
to TVA’s continuing involvement in
the operation and maintenance of the leased units and equipment its control
over
the distribution of power produced by the combustion turbine facilities during
the leaseback term, TVA accounted for the respective lease proceeds of $714
million, $320 million, and $300 million as financing obligations as required
in
accordance with SFAS No. 66, “Accounting for Sales of Real Estate,” and
SFAS No. 98, “Accounting for Leases.” Accordingly, the
outstanding lease/leaseback obligations of $1,072 million at September 30,
2007,
and $1,108 million at September 30, 2006, are included in Current portion of
lease/leaseback obligations ($43 million and $37 million, respectively) and
Lease/leaseback obligations ($1,029 million and $1,071 million, respectively)
in
TVA’s 2007 and 2006 year-end Balance Sheets.
13.
Benefit Plans
TVA
sponsors a defined benefit pension
plan that covers most of its full-time employees, a defined contribution plan
that covers most of its full-time employees, an unfunded postretirement medical
plan that provides for non-vested contributions toward the cost of certain
retirees’ medical coverage, other postemployment benefits such as workers’
compensation, and a supplemental executive retirement plan. Following
are discussions of each of these plans as well as discussions of 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),” and
the Medicare Prescription Drug, Improvement and Modernization Act of
2003.
Defined
Benefit Pension
Plan
Overview
of
Plan. TVA sponsors a defined benefit plan for most of its
full-time employees that provides two benefit structures: the Original Benefit
Structure and the Cash Balance Benefit Structure.
|
•
|
Original
Benefit Structure. The pension benefit for a member
participating in the Original Benefit Structure is based on the member’s
years of creditable service, the member’s average base pay for the highest
three consecutive years, and the pension rate for the member’s age and
years of service, less a Social Security
offset.
|
|
•
|
Cash
Balance Benefit Structure. The pension benefit for a
member participating in the Cash Balance Benefit Structure is based
on
credits accumulated in the member’s account and the member’s age. A
member’s account receives credits each pay period equal to 6.00 percent
of
his or her straight-time earnings. The account also increases at
an
interest rate equal to the change in the Consumer Price Index (“CPI”) plus
3.00 percent, with the provision that the rate may not be less than
6.00
percent or more than 10.00 percent. The actual changes in the CPI
for 2007
and 2006 were 3.43 percent and 3.37 percent, which resulted in interest
rates of 6.43 percent and 6.37 percent,
respectively.
|
Members
of both the Original Benefit
Structure and the Cash Balance Benefit Structure can also become eligible for
a
vested supplemental pension benefit based on age and years of service, which
is
designed to help retirees offset the cost of medical insurance.
Administration
of
Plan. The plan is administered by a separate legal entity, the
TVA Retirement System (“TVARS”), which is governed by its own board of directors
(“TVARS Board”). Upon notification by the TVARS Board of a
recommended contribution for the next fiscal year, TVA determines whether to
make the recommended contribution or any contribution that may be required
by
the rules and regulations of TVARS.
Plan
Investments. The plan assets are primarily stocks and
bonds. The 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
of 65
percent equity securities and 35 percent fixed income
securities. Under its asset allocation policy of 65 percent equity
holdings, 30 percent may be U.S. equity holdings, 25 percent may be non-U.S.
equity holdings, five percent may be private equity holdings or other similar
alternative investments, and five percent may be private real estate
holdings. Of the 35 percent fixed income securities, 15 percent may
be alternative fixed income strategies and five percent may be high yield
securities. The TVARS’ policy includes a permissible three percent deviation
from these target allocations. The TVARS Board can take action, as appropriate,
to rebalance the system’s assets consistent with the asset allocation policy.
For 2007, the asset holdings of the system included equities of about 64 percent
(comprised of U.S. equity holdings of about 38 percent, non-U.S. equity holdings
of about 22 percent, and private equity holdings of about four percent), plus
fixed income securities of about 36 percent. For 2006, the asset holdings of
the
system included equities of about 59 percent (comprised of U.S. equity holdings
of about 41 percent, non-U.S. equity holdings of about 15 percent, and private
equity holdings of about three percent), plus fixed income securities of about
41 percent.
Plan
Contributions. TVA contributed $75 million to its pension plan
in both 2007 and 2006, and $53 million in 2005. For 2008, TVA plans to
contribute $81 million to its pension plan.
Plan
Assumptions. TVA’s reported costs of providing the plan benefits
are impacted by numerous factors including the provisions of the plans, changing
employee demographics, and various assumptions, the most significant of which
are described below.
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. Based on recent market trends, TVA
increased its discount rate from 5.38 percent and 5.90 percent at the end of
2005 and 2006, respectively, to 6.25 percent at the end of 2007.
Rate
of Return. In determining
its expected long-term rate of return on pension plan assets, TVA reviews past
long-term performance, asset allocations, and long-term inflation assumptions.
TVA utilized a rate of return of 8.00 percent during 2003 in the aftermath
of
the market declines of 2002 and 2001. TVA increased its expected long-term
rate
of return on pension plan assets to 8.25 percent at the end of 2005 and 2004.
However, TVA has increased its expected rate of return to 8.75 percent at the
end of 2007 and 2006 based on revisions to future expected returns as provided
by third party professional asset managers.
Cost
of Living. The
cost of living rate was not adjusted from the 2006 rate of 3.00 percent but
rather remained at 3.00 percent for 2007 to reflect current market and
demographic conditions.
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 1/2 of 1 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 cost to changes in certain actuarial assumptions:
Sensitivity
of 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
|
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.
Plan
Results. During 2007, 2006, and 2005, TVA recognized pension
expense of $159 million, $244 million, and $243 million,
respectively. Based on the use of the assumptions described above,
the projected benefit obligation (“PBO”) of $8,598 million at September 30,
2007, decreased approximately $2 million when compared to the PBO of $8,600
million at September 30, 2006. The decrease of $2 million represents, in part,
an increase of $120 million due to normal operation of the plan (primarily
in
the form of service cost and interest accruals), a decrease of $333 million
in
the PBO due to changes in the discount rate (from 5.90 percent to 6.25 percent),
and incurred liability losses of $211 million related primarily to
more-than-assumed early retirements. The assumptions used in the 2007
end-of-year actuarial valuation process had no effect on pension costs for
2007,
2006, or 2005.
The
accumulated benefit obligations at
September 30, 2007, and September 30, 2006, were $8.2 billion and $8.2 billion,
respectively.
Components
of
Plan. The changes in plan obligations, assets, and funded status
for the years ended September 30 were as follows:
Components
of Pension Benefits Plan
As
of
September 30
|
Pension
Benefits
|
||||||||
|
2007
|
2006
|
|||||||
|
Change
in benefit obligation
|
||||||||
|
Benefit
obligation at beginning of year
|
$ 8,600
|
$8,433
|
||||||
|
Service
cost
|
120
|
127
|
||||||
|
Interest
cost
|
492
|
440
|
||||||
|
Plan
participants’ contributions
|
35
|
35
|
||||||
|
Actuarial
(gain) / loss
|
(175
|
) |
3
|
|||||
|
Net
transfers from variable fund/401(k) plan
|
11
|
9
|
||||||
|
Expenses
paid
|
(4
|
) |
(4
|
) | ||||
|
Benefits
paid
|
(481
|
) |
(443
|
) | ||||
|
Benefit
obligation at end of year
|
$ 8,598
|
$8,600
|
||||||
|
|
||||||||
|
Change
in plan assets
|
||||||||
|
Fair
value of plan assets at beginning of year
|
$ 7,328
|
$7,015
|
||||||
|
Adjustment
to reconcile to system asset value
|
–
|
–
|
|
|||||
|
Actual
return on plan assets
|
1,013
|
641
|
||||||
|
Plan
participants’ contributions
|
35
|
35
|
||||||
|
Net
transfers from variable fund/401(k) plan
|
11
|
9
|
||||||
|
Employer
contributions
|
75
|
75
|
||||||
|
Expenses
paid
|
(4
|
) |
(4
|
) | ||||
|
Benefits
paid
|
(481
|
) |
(443
|
) | ||||
|
Fair
value of plan assets at end of year
|
$7,977
|
$7,328
|
||||||
|
|
||||||||
|
Funded
status
|
$(621
|
) |
$ (1,272
|
) | ||||
|
Unrecognized
net actuarial loss
|
–
|
1,275
|
||||||
|
Unrecognized
prior service cost
|
–
|
275
|
||||||
|
Prepaid
(accrued) benefit cost
|
$(621
|
) |
$ 278
|
|||||
|
Assumptions
as of September 30
|
||||||||
|
Discount
rate
|
6.25%
|
5.90%
|
||||||
|
Expected
return on plan assets
|
8.75%
|
8.75%
|
||||||
|
Rate
of compensation increase
|
3.3%
– 10.1%
|
3.3%
– 10.1%
|
||||||
The
components of pension expense for
the years ended September 30 were as follows:
Components
of Pension Benefits Plan
For
the
years ended September 30
|
Pension
Benefits
|
|||||||||||
|
2007
|
2006
|
2005
|
|||||||||
|
Components
of net periodic benefit cost
|
|||||||||||
|
Service
cost
|
$120
|
$127
|
$117
|
||||||||
|
Interest
cost
|
492
|
440
|
429
|
||||||||
|
Expected
return on plan assets
|
(571)
|
(490)
|
(457)
|
||||||||
|
Amortization
of prior service cost
|
36
|
36
|
36
|
||||||||
|
Recognized
net actuarial loss
|
82
|
131
|
118
|
||||||||
|
Total
net periodic benefit cost
|
$159
|
$244
|
$243
|
||||||||
|
Assumptions
utilized include:
|
|||||||||||
|
Discount
rate
|
5.90%
|
5.38%
|
5.81%
|
||||||||
|
Expected
return on plan assets
|
8.75%
|
8.25%
|
8.25%
|
||||||||
|
Rate
of compensation increase
|
3.3%-10.1%
|
3.3%-10.1%
|
3.3%-10.1%
|
||||||||
Estimated
Future Benefit
Payments. The following table sets forth the estimated future
benefit payments under the pension plan.
Estimated
Future Benefit Payments
As
of
September 30, 2007
|
Pension
|
||||
|
2008
|
$574
|
|||
|
2009
|
579
|
|||
|
2010
|
591
|
|||
|
2011
|
603
|
|||
|
2012
|
617
|
|||
|
2013-2017
|
3,306
|
|||
Defined
Contribution
Plan
TVARS
also administers a defined
contribution 401(k) plan to which TVA makes matching contributions of 25 cents
on the dollar (up to 1.5 percent of annual pay) for members participating in
the
Original Benefit Structure and of 75 cents on the dollar (up to 4.5 percent
of
annual pay) for members participating in the Cash Balance Benefit Structure.
TVA
made matching contributions of about $21 million to the plan during 2007, $19
million during 2006, and $17 million during 2005.
Other
Postretirement
Benefits
Overview
of
Plan. TVA sponsors an unfunded postretirement plan that provides
for non-vested contributions toward the cost of certain retirees’ medical
coverage. This plan formerly covered all eligible retirees participating in
the
TVA medical plan, and TVA’s contributions were a flat dollar amount based on the
participants’ ages and years of service and certain payments toward the plan
costs. This plan now operates on a much more limited basis, covering only
certain retirees and surviving dependents who do not qualify for TVARS benefits,
including the vested supplemental pension benefit.
Plan
Assumptions. The initial annual assumed cost trend for covered
benefits was 8.0 percent in 2007, decreasing by one-half percent per year to
a
level of 5.0 percent beginning on October 1, 2013, and thereafter. For 2006
and
2005, annual trend rates of 8.5 percent and 9.0 percent, respectively, were
assumed. The effect of the change in assumptions on the cost basis was not
significant. Increasing/(reducing) the assumed health-care cost trend rates
by
one percent would increase/(reduce) the accumulated postretirement benefit
obligation (“APBO”) as of September 30, 2007, by $62 million/($65 million) and
the aggregated service and interest cost components of net periodic
postretirement benefit cost for 2007 by $4 million/($5 million). The weighted
average discount rate used in determining the end-of-year APBO was
6.25
percent for 2007, 5.90 percent for 2006, and 5.38 percent for 2005. Any net
unrecognized gain or loss resulting from experience different from that assumed
or from changes in assumptions, and exceeding 10 percent of the APBO, is
amortized over the average remaining service period of active plan
participants.
Plan
Results. Based
on the use of the assumptions described above, the 2007 APBO of $464 million
for
postretirement benefits increased approximately $13 million compared to the
prior year. The change in the obligation was comprised of an $11
million increase due to normal operation of the plan (primarily in the form
of
service cost and interest accruals offset by claims paid during the year) and
an
increase of $2 million due to other actuarial and experience adjustments
including gains and losses. The $2 million increase in the obligation is
comprised of three components. The first component of the actuarial and
experience adjustments is comprised of an actuarial gain of approximately $15
million related to the actuarial discount rate which was increased to 6.25
percent in 2007 from 5.90 percent in 2006. The second component is comprised
of
an actuarial gain of approximately $11 million related to better-than-expected
claims experience. The third component is comprised of an actuarial loss of
approximately $28 million related to more-than-assumed retirements during the
year.
The
set of assumptions used for the
end-of-year actuarial valuation process had no effect on postretirement benefit
costs for 2007, 2006, or 2005 but, when coupled with further experience
adjustments related to claims and contributions, is expected to increase
postretirement benefits expense for 2008 by approximately $2 million compared
to
2007. TVA expects 2008 postretirement health care cost to approximate $44
million, an increase of $2 million over 2007 costs.
Components
of Other Postretirement
Benefits. The changes in plan obligations, assets, and funded
status for the years ended September 30 were as follows:
Components
of Other Postretirement Benefits Plan
As
of
September 30
|
Other
Postretirement Benefits
|
||||||||
|
2007
|
2006
|
|||||||
|
Change
in benefit obligation
|
||||||||
|
Benefit
obligation at beginning of year
|
$ 451
|
$544
|
||||||
|
Service
cost
|
5
|
9
|
||||||
|
Interest
cost
|
26
|
29
|
||||||
|
Plan
participants’ contributions
|
77
|
64
|
||||||
|
Actuarial
(gain) / loss
|
2
|
(108
|
) | |||||
|
Net
transfers from variable fund/401(k) plan
|
–
|
–
|
||||||
|
Expenses
paid
|
–
|
–
|
||||||
|
Benefits
paid
|
(97
|
) |
(87
|
) | ||||
|
Benefit
obligation at end of year
|
$ 464
|
$451
|
||||||
|
|
||||||||
|
Change
in plan assets
|
||||||||
|
Fair
value of plan assets at beginning of year
|
$ –
|
$–
|
||||||
|
Adjustment
to reconcile to system asset value
|
–
|
–
|
|
|||||
|
Actual
return on plan assets
|
–
|
–
|
||||||
|
Plan
participants’ contributions
|
77
|
64
|
||||||
|
Net
transfers from variable fund/401(k) plan
|
–
|
–
|
||||||
|
Employer
contributions
|
20
|
23
|
||||||
|
Expenses
paid
|
–
|
–
|
||||||
|
Benefits
paid
|
(97
|
) |
(87
|
) | ||||
|
Fair
value of plan assets at end of year
|
$–
|
$–
|
||||||
|
|
||||||||
|
Funded
status
|
$(464
|
) |
$ (451
|
) | ||||
|
Unrecognized
net actuarial loss
|
–
|
113
|
||||||
|
Unrecognized
prior service cost
|
–
|
39
|
||||||
|
Prepaid
(accrued) benefit cost
|
$(464
|
) |
$ (299
|
) | ||||
|
Assumptions
as of September 30
|
||||||||
|
Discount
rate
|
6.25%
|
5.90%
|
||||||
| Expected return on plan assets |
NA
|
NA
|
||||||
|
Rate
of compensation increase
|
NA
|
NA
|
||||||
| Initial health care trend rate |
8.00%
|
8.50%
|
||||||
| Ultimate health care trend rate |
5.00%
|
5.00%
|
||||||
| Ultimate trend rate is reached in year beginning |
2013
|
2013
|
||||||
The
components of postretirement benefits expense for the years ended September
30
were as follows:
Components
of Other Postretirement Benefits Plan
For
the
years ended September 30
|
Other
Postretirement Benefits
|
|||||||||||
|
2007
|
2006
|
2005
|
|||||||||
|
Components
of net periodic benefit cost
|
|||||||||||
|
Service
cost
|
$5
|
$ 9
|
$6
|
||||||||
|
Interest
cost
|
26
|
29
|
25
|
||||||||
|
Expected
return on plan assets
|
NA
|
NA
|
NA
|
||||||||
|
Amortization
of prior service cost
|
5
|
5
|
5
|
||||||||
|
Recognized
net actuarial loss
|
6
|
15
|
10
|
||||||||
|
Total
net periodic benefit cost
|
$42
|
$58
|
$ 46
|
||||||||
|
Assumptions
used to determine expense
|
|||||||||||
|
Discount
rate
|
5.90%
|
5.38%
|
5.81%
|
||||||||
|
Expected
return on plan assets
|
NA
|
NA
|
NA
|
||||||||
|
Rate
of compensation increase
|
NA
|
NA
|
NA
|
||||||||
|
Initial
health care trend rate
|
8.50%
|
9.00%
|
9.00%
|
||||||||
|
Ultimate
health care trend rate
|
5.00%
|
5.00%
|
5.00%
|
||||||||
|
Ultimate
trend rate is reached in year beginning
|
2013
|
2013
|
2012
|
||||||||
Sensitivity
to Changes in
Assumptions. The following chart reflects the sensitivity of
postretirement benefit cost to changes in the health care trend
rate:
Components
of Other Postretirement Benefits Plan
As
of
September 30, 2007
|
1%
Increase
|
1%
Decrease
|
||||||
|
Effect
on total of service and interest cost components
|
$ 4
|
$ (5)
|
|||||
|
Effect
on end-of-year accumulated postretirement benefit
obligation
|
$ 62
|
$
(65)
|
|||||
Estimated
Future Postretirement
Benefit Payments. The following table sets forth the estimated
future benefit payments under the postretirement benefit plan.
Estimated
Future Postretirement Benefit Payments
As
of
September 30, 2007
|
Postretirement
Benefits Plans
|
||||
|
2008
|
$25
|
|||
|
2009
|
27
|
|||
|
2010
|
30
|
|||
|
2011
|
32
|
|||
|
2012
|
33
|
|||
|
2013-2017
|
171
|
|||
Other
Postemployment
Benefits
Other
postemployment benefits include
workers’ compensation provided to former or inactive employees and their
beneficiaries and covered dependents for the period after employment but before
retirement. TVA employees injured in work-related incidents are covered by
the
TVA’s workers’ compensation program for federal employees administered through
the Department of Labor by the Office of Workers’ Compensation Programs in
accordance with the provisions of the Federal Employees’ Compensation Act
(“FECA”). FECA provides compensation benefits to federal employees for permanent
and temporary disability due to employment-related injury or
disease.
Postemployment
benefit cost estimates
are revised to properly reflect changes in actuarial assumptions made at the
end
of the year. In accordance with SEC recommendations related to the
selection of discount rates, TVA utilizes a discount rate determined by
reference to the U.S. Treasury Constant Maturities rate for a 10-year
maturity. For 2007, TVA has determined to utilize a discount rate of
4.59 percent representing the risk-free rate corresponding to the U.S. Treasury
Constant Maturities rate for a 10-year maturity. Use of the 10-year maturity
corresponds to calculated average durations of TVA’s future estimated
postemployment claims payments. The use of a 4.59 percent discount rate resulted
in the recognition of 2007 annual expense of approximately $49 million and
an
unpaid benefit obligation of about $406 million at year end. TVA utilized a
discount rate of 4.64 percent and 4.34 percent in 2006 and 2005, respectively.
The use of the discount rates described resulted in expense and unpaid benefit
obligations of $44 million and $413 million, respectively, for 2006 and expense
and unpaid benefit obligations of $72 million and $429 million, respectively,
for 2005. The changes in 2007 assumptions had no effect on
postemployment expense for 2006 and 2005.
Supplemental
Executive Retirement
Plan
In
1995, TVA established a Supplemental
Executive Retirement Plan (“SERP”) to provide additional benefits to specified
individuals in addition to those available under the qualified pension plan
because of Internal Revenue Service (“IRS”) limits applicable to qualified
plans. The SERP funds are invested in securities generally designed to achieve
a
return in line with overall equity market performance. The nature of these
investments comprises commingled funds. Commingled funds are similar in nature
to a mutual fund. Investments held in the SERP are stated at fair
value, which is determined by the trustee of the fund. TVA has historically
funded the annual calculated expense. Due to the immaterial amounts related
to
the SERP, TVA has elected to not make full SFAS No. 132R disclosures, but rather
has disclosed amounts related to recorded balances and expense as determined
through the application of SFAS No. 87, “Employers' Accounting for
Pensions,” and the adoption of 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).”
As
of and for the year ended September
30, 2007, TVA recognized certain amounts related to the SERP plan
including:
|
|
•
|
Plan
assets in trust of $36 million,
|
|
|
•
|
A
regulatory asset of $15 million,
|
|
|
•
|
An
estimated accrued and unfunded pension plan obligation of $44
million,
|
|
|
•
|
Expense
of $6 million, and
|
|
|
•
|
Current
year gains on plan assets of $3 million, of which approximately $3
million
was unrealized.
|
In
addition, $3 million in benefit
payments were made from the plan during the year, and TVA made contributions
of
$6 million to the plan.
As
of and for the year ended September
30, 2006, TVA recognized certain amounts related to the plan
including:
|
•
|
Plan
assets in trust of $30 million,
|
|
•
|
A
regulatory asset of $7 million,
|
|
•
|
An
intangible asset of $5 million,
|
|
•
|
An
estimated accrued and minimum pension plan obligation of $38
million,
|
|
•
|
Expense
of $7 million, and
|
|
•
|
Current
year gains on plan assets of $2 million, of which $0.6 million was
realized.
|
In
addition, $3 million in benefit
payments were made from the plan during the year, and TVA made contributions
of
$13 million to the plan during 2006.
Impact
of SFAS No.
158
On
September 30, 2007, TVA adopted SFAS
No. 158, which requires companies, among other things, (1) to recognize the
funded status of their pension and other postretirement benefit plans as a
net
liability or asset, measured as the difference between the benefit obligation
and the fair market value of plan assets, (2) to derecognize additional minimum
liabilities (“AML”) and related intangible assets upon adoption of the new
standard, and (3) to include unrecognized prior service costs, net actuarial
gains or losses, and subsequent changes in the funded status as components
of
Accumulated other comprehensive loss within Proprietary capital.
As
a regulated entity, however, TVA has
reclassified all amounts related to unrecognized prior service costs, net
actuarial gains or losses, and subsequent changes in the funded status into
a
regulatory asset in accordance with the provisions of SFAS No.
71,“Accounting for the Effects of Certain Types of
Regulation.” Under this guidance, the deferral of incurred costs
is allowed if the costs are probable of future recovery in customer
rates. In conjunction with TVA’s 2007 adoption of SFAS No. 158 and
the application of SFAS No. 71, TVA deferred $973 million of unamortized prior
service costs and net actuarial losses related to its pension and postretirement
benefit plans. Of the $973 million deferred by TVA, $582 million
represents net actuarial losses that have been expressly authorized for deferral
by the TVA Board. The remaining $391 million represents unamortized
prior service costs incurred by TVA that TVA management believes (1) are
probable of recovery in future periods and (2) qualify for regulatory accounting
treatment under SFAS No. 71. TVA management intends to seek approval
from the TVA Board of regulatory accounting treatment for these unamortized
prior service costs in 2008.
SFAS
No. 158 requires initial
application for fiscal years ending after December 15, 2006, and for certain
other entities after June 15, 2007. TVA adopted the standard as of
September 30, 2007.
The
following tables summarize the
effect of required changes in the AML as of September 30, 2007, prior to the
adoption of SFAS No. 158, as well as the impact of the initial adoption of
SFAS
No. 158 and the reclassification of certain deferred costs in accordance with
SFAS No. 71. The first table depicts the specific elements impacted by the
transition and adoption of the standard. The second table presents
all financial statement line items impacted by the adoption of the
standard. Both tables begin with the ending book balances before SFAS
No. 87 adjustments are made to recognize the AML and are followed by the SFAS
No. 87 adjustments made to recognize AML. The remaining portion of the tables
reflects adjustments related to the adoption of SFAS No. 158 whereby various
balances created by SFAS No. 87 are derecognized and transitioned to conform
to
the new requirements of SFAS 158.
Specific
Elements Impacted by SFAS No. 158
As
of
September 30, 2007
|
|
Prior
to AML
|
AML
|
SFAS
158
|
Post
AML
|
|||||||||||
|
Adjustments
pre and post SFAS 158 adoption:
|
and
SFAS 158
|
Adjustment
|
Adjustment
|
and
SFAS 158
|
|||||||||||
|
Other
regulatory assets
|
$ 914
|
$
(662
|
) |
$ 721
|
$ 973
|
||||||||||
|
Intangible
asset (unamortized prior service cost)
|
243
|
3
|
(246
|
) |
–
|
||||||||||
|
Other
liabilities (Pension and SERP)
|
991
|
(657
|
) |
330
|
664
|
||||||||||
|
Current
liabilities (Postretirement)
|
–
|
–
|
25
|
25
|
|||||||||||
|
Other
liabilities (Postretirement)
|
321
|
–
|
118
|
439
|
|||||||||||
|
Accumulated
other comprehensive income (loss)
|
–
|
(2
|
) |
2
|
–
|
||||||||||
Financial
Statement Elements Impacted by SFAS No. 158
As
of
September 30, 2007
|
Prior
to AML
|
AML
|
SFAS
158
|
Post
AML
|
||||||||||||
|
Line
items pre and post SFAS 158 adoption:
|
and
SFAS 158
|
Adjustment
|
Adjustment
|
and
SFAS 158
|
|||||||||||
|
Regulatory
and other long-term assets
|
|||||||||||||||
|
Other
regulatory assets
|
$ 1,910
|
$ (662
|
) |
$ 721
|
$ 1,969
|
||||||||||
|
Subtotal
|
5,040
|
(662
|
) |
721
|
5,099
|
||||||||||
|
Other
long-term assets
|
618
|
3
|
(246
|
) |
375
|
||||||||||
|
Total
regulatory and other long-term assets
|
5,658
|
(659
|
) |
475
|
5,474
|
||||||||||
|
Total
assets
|
34,086
|
(659
|
) |
475
|
33,902
|
||||||||||
|
|
|||||||||||||||
|
Current
liabilities
|
|||||||||||||||
|
Accounts
payable
|
975
|
–
|
25
|
1,000
|
|||||||||||
|
Total
current liabilities
|
3,398
|
–
|
25
|
3,423
|
|||||||||||
|
Other
liabilities
|
|||||||||||||||
|
Other
pension liabilities
|
991
|
(657
|
) |
330
|
664
|
||||||||||
|
Other
postretirement liabilities
|
321
|
–
|
118
|
439
|
|||||||||||
|
Other
liabilities
|
2,276
|
(657
|
) |
448
|
2,067
|
||||||||||
|
Total
other liabilities
|
6,584
|
(657
|
) |
473
|
6,400
|
||||||||||
|
Total
liabilities
|
31,106
|
(657
|
) |
473
|
30,922
|
||||||||||
|
Proprietary
capital
|
|||||||||||||||
|
Accumulated
other comprehensive income (loss)
|
(19
|
) |
(2
|
) |
2
|
(19
|
) | ||||||||
|
Total
proprietary capital
|
2,980
|
(2
|
) |
2
|
2,980
|
||||||||||
|
Total
liabilities and proprietary capital
|
34,086
|
(659
|
) |
475
|
33,902
|
||||||||||
The
amounts in the regulatory asset
that are expected to be recognized as components of net periodic benefit cost
during the next fiscal year are as follows:
Regulatory
Asset
As
of
September 30, 2007
|
Pension
|
Postretirement
|
Postemployment
|
SERP
|
Total
|
|||||||||||||||
|
Prior
service cost
|
$ 36
|
$
5
|
$ –
|
$ 1
|
$ 42
|
||||||||||||||
|
Net
actuarial loss
|
41
|
5
|
–
|
1
|
47
|
||||||||||||||
The
projected benefit obligation,
accumulated benefit obligation and fair value of plan assets for the pension
plans with accumulated benefit obligations in excess of plan assets at September
30, 2007 and 2006, were as follows:
Pension
Benefits
As
of
September 30
|
2007
|
2006
|
||||||
|
Projected
benefit obligation
|
$ 8,598
|
$ 8,600
|
|||||
|
Accumulated
benefit obligation
|
8,276
|
8,231
|
|||||
|
Fair
value of plan assets
|
7,977
|
7,328
|
|||||
Medicare
Prescription Drug, Improvement
and Modernization Act of 2003
In
2006, Medicare began providing
prescription drug coverage to Medicare-eligible beneficiaries under Medicare
Part D. Under the Medicare Prescription Drug, Improvement and Modernization
Act
of 2003, which created Medicare Part D, employers that provide retiree
prescription drug coverage, which is “actuarially equivalent” to standard
coverage under Medicare Part D, may receive retiree drug subsidies for retirees
who enroll in the employer’s retiree prescription drug plan instead of Medicare
Part D. TVA determined that its retiree prescription drug coverage did not
qualify for retiree drug subsidies and accordingly has not included or utilized
any manner of subsidy in the determination of APBO or postretirement benefit
cost, for the current or prior periods, in accordance with the requirements
contained within the FASB Staff Position FAS 106-2, “Accounting and
Disclosure Requirements Related to the Medicare Prescription Drug, Improvement
and Modernization Act of 2003.” After analyzing a number of options
available to plan sponsors for integration with the new Medicare Part D, TVA
elected to provide an employer-sponsored Part D prescription drug plan ("PDP"),
with alternative coverage over and above Medicare standard Part D coverage,
for
Medicare-eligible retirees who participate in TVA's Medicare supplement. By
providing an employer-sponsored PDP, any Medicare subsidies will be passed
through to retirees in the form of lower participant premiums and should not
affect TVA's cost of providing prescription drug coverage.
14.
Commitments and Contingencies
Commitments
As
of
September 30, 2007, the amounts of contractual cash commitments maturing in
each
of the next five years and beyond are shown below:
|
Commitments
and Contingencies
Payments
Due in the Year Ending September 30
|
|
2008
|
2009
|
2010
|
2011
|
2012
|
Thereafter
|
Total
|
|||||||||||||||||||||
|
Debt
|
$1,512
|
$2,030
|
$ 62
|
$1,015
|
$1,525
|
$16,357
|
$22,501
|
* | |||||||||||||||||||
|
Lease
obligations
|
|
||||||||||||||||||||||||||
|
Capital
|
59
|
58
|
57
|
29
|
3
|
3
|
209
|
||||||||||||||||||||
|
Non-cancelable
operating
|
63
|
47
|
37
|
28
|
27
|
219
|
421
|
||||||||||||||||||||
|
Purchase
obligations
|
|
|
|||||||||||||||||||||||||
|
Power
|
186
|
183
|
194
|
195
|
196
|
3,806
|
4,760
|
||||||||||||||||||||
|
Fuel
|
1,220
|
527
|
504
|
232
|
223
|
443
|
3,149
|
||||||||||||||||||||
|
Other
|
310
|
157
|
24
|
16
|
15
|
39
|
561
|
||||||||||||||||||||
|
Total
|
$
3,350
|
$3,002
|
$878
|
$1,515
|
$1,989
|
$20,867
|
$31,601
|
||||||||||||||||||||
| Notes
* Does
not include noncash items of foreign currency valuation loss of
$299
million and net discount on sale of bonds of $189
million.
|
|||||||||||||||||||||||||||
In
addition to the cash requirements
above, TVA has contractual obligations in the form of revenue discounts related
to energy prepayments. See Note 1 — Energy Prepayment
Obligations.
Energy
Prepayment Obligations
Payments
Due in the Year Ending September 30
|
2008
|
2009
|
2010
|
2011
|
2012
|
Thereafter
|
Total
|
|||||||||||||||||||||
|
Energy
Prepayment Obligations
|
$ 106
|
$ 105
|
$ 105
|
$ 105
|
$ 105
|
$ 612
|
$ 1,138
|
||||||||||||||||||||
Debt. At
September
30, 2007, TVA had outstanding discount notes of $1.4 billion and long-term
debt
(including current maturities) at varying maturities and interest rates of
$21.2
billion for total outstanding indebtedness of $22.6 billion. See Note
10.
Leases. TVA
leases
certain property, plant, and equipment under agreements with terms ranging
from
one to 30 years. Obligations under capital lease agreements in effect
at September 30, 2007, totaled $59 million for 2008, $58 million for 2009,
$57
million for 2010, $29 million for 2011, $3 million for 2012, and an aggregate
of
$3 million thereafter, for a total commitment of $209 million. Of
this amount, $38 million represents the cost of
financing. Obligations under non-cancelable operating lease
agreements (primarily related to facilities and equipment) in effect at
September 30, 2007, totaled $63 million for 2008, $47 million for 2009, $37
million for 2010, $28 million for 2011, $27 million for 2012, and an aggregate
$219 million thereafter for a total commitment of $421 million.
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.
Power
Purchase Obligations.
TVA has contracted with various independent power producers and power
distributor customers for additional capacity to be made available to
TVA. In total, these agreements provide 3,504 megawatts of winter net
dependable capacity and 29 megawatts of capacity from renewable resources that
are not included in the determination of winter net dependable
capacity. The total financial commitment for non-renewable power
supply contracts is approximately $4.7 billion. As of September 30,
2007, 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. Costs under TVA’s power purchase agreements are included
in the Statements of Income for 2007, 2006, and 2005 as Fuel and purchased
power
expense and are expensed as incurred in accordance with the normal purchases
and
sales exemption described in SFAS No. 133, “Accounting for Derivative
Instruments and Hedging Activities,” as amended.
Under
the Public Utility Regulatory
Policies Act of 1978 as amended by the Energy Policy Acts of 1992 and 1995,
TVA
is obligated to purchase power from qualifying facilities. At
September 30, 2007, there were six suppliers, with a combined capacity of 903
megawatts, which qualify under this program.
TVA,
along with others, contracted with
the Southeastern Power Administration (“SEPA”) to obtain power from eight U.S.
Army Corp 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;
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•
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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;
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•
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Provides
for TVA to receive all of the remaining hourly generation (minus
station
service for those facilities);
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•
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Eliminates
the payment of demand charges by customers (including TVA) since
there is
significantly reduced dependable capacity on the Cumberland River
system;
and
|
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•
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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.
Fuel
Purchase Obligations. TVA
has approximately $1.5 billion in long-term fuel purchase commitments ranging
in
terms of up to four years for the purchase and transportation of coal and
approximately an additional $1.6 billion of long-term commitments ranging in
terms of up to 10 years for the purchase of enriched uranium and fabrication
of
nuclear fuel assemblies.
Other
Obligations. Other
obligations of $561 million consist of contracts as of September 30, 2007,
for
goods and services primarily related to capital projects as well as other major
recurring operating costs.
Bear
Creek
Dam. Bear Creek Dam, a small flood-control, non-generating dam
in northern Alabama, is experiencing foundation problems as evidenced by seepage
through the foundation of the dam. An Environmental Impact Statement
was completed in 2007, which concluded the preferred alternative is to repair
the dam. The total estimated cost for repair is $35
million. Site work to mitigate the problem began in 2007 and is
scheduled to be completed in 2009.
Contingencies
Nuclear
Insurance. The Price-Anderson Act provides a layered framework
of protection to compensate for losses arising from a nuclear
event. For the first layer, all NRC nuclear plant licensees,
including TVA, purchase $300 million of nuclear liability insurance from
American Nuclear Insurers 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
reactor. 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 Builder 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.
Decommissioning Costs. Provision for decommissioning costs of
nuclear generating units is based on options prescribed by NRC procedures to
dismantle and decontaminate the facilities to meet NRC criteria for license
termination.
TVA recognizes as incurred all obligations related to closure and removal of
its
nuclear units. The liability for closure is measured as the present
value of the weighted estimated cash flows required to satisfy the related
obligation and discounted at the credit adjusted rate of interest in effect
at
the time the liability was actually incurred or originally accrued, and
subsequently modified to comply with the prevailing accounting
provisions. The charge to recognize the additional obligation is
effected by adjusting the corresponding regulatory asset. Earnings
from decommissioning fund investments, amortization expense of the
decommissioning regulatory asset, and interest expense on the decommissioning
liability are deferred in accordance with SFAS No. 71, “Accounting for the
Effects of Certain Types of Regulation.” At September 30, 2007,
the present value of the estimated future decommissioning cost of $1.6 billion
was included in Asset retirement obligations, and the unamortized regulatory
asset of $419 million was included in Other regulatory assets. This
decommissioning cost estimate is based on amounts prescribed by the NRC for
removing a plant from service, releasing the property for unrestricted use,
and
terminating the operating license. The actual decommissioning costs
may vary from the derived estimates because of, among other things, changes
in
the assumed dates of decommissioning, changes in regulatory requirements,
changes in technology, and changes in the cost of labor, materials, and
equipment. Utilities that own and operate nuclear plants are required
to use different procedures in calculating nuclear decommissioning costs under
SFAS No. 143 than those that are used in calculating nuclear decommissioning
costs when reporting to the NRC. 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. See Note 4.
TVA maintains a nuclear decommissioning trust to provide funding for the
ultimate decommissioning of its nuclear power plants. The fund is
invested in securities generally designed to achieve a return in line with
overall equity market performance. The assets of the fund are
invested in debt and equity securities and certain derivative
instruments. These derivative instruments are used across various
asset classes to achieve a desired investment structure and were comprised
of
3,067 contracts with a market value of $3 million at September 30,
2007. These contracts include futures, options, options on futures,
swap agreements, and options on swap agreements. Investments held in the
decommissioning fund are stated at fair value, which is determined by the
trustee of the fund. Futures and options on futures positions are
marked to market on a daily basis. The swap agreements are marked to
market on a monthly basis. The assets of the fund as of September 30,
2007, totaled $1.1 billion including total gains of $150 million of which $80
million was unrealized. The assets of the fund as of September 30,
2006, totaled $937 million and reflected total gains of $125 million and
unrealized losses of $24 million for a net gain of $101 million. The
balance as of September 30, 2007 is greater than the present value of the
estimated future nuclear decommissioning costs. TVA monitors the monetary value
of its nuclear decommissioning trust and believes that, over the long term
and
before cessation of nuclear plant operations and commencement of decommissioning
activities, adequate funds from investments will be available to support
decommissioning. TVA’s nuclear power units are currently authorized
to operate until 2020-2036, depending on the unit. It may be possible
to extend the operating life of some of the units with approval from the
NRC.
Environmental Matters. TVA’s activities are subject to certain federal,
state, and local environmental statutes and regulations. Major areas
of regulation affecting TVA’s activities include air quality control, water
quality control, and management and disposal of solid and hazardous
wastes. Some of the more comprehensive requirements with which
TVA is required to comply include:
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•
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The
Clean Air Act (“CAA”) and the Clean Air Interstate Rule (“CAIR”) and Clean
Air Mercury Rule (“CAMR”)
|
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•
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The
Clean Water Act and regulations under Sections 316a and
316b
|
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•
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The
Comprehensive Environmental Response, Compensation, and Liability
Act
(“CERCLA”)
|
TVA
has incurred and continues to incur
substantial capital and operating and maintenance costs in order to comply
with
evolving environmental requirements. Many of these costs are
associated with the operation of TVA’s 59 coal-fired generating
units. While it is not possible to predict how these evolving
requirements will impact the operation of existing and new coal-fired and other
fossil-fuel generating units, it is virtually certain that environmental
requirements placed on the operation of these generating units will continue
to
become more restrictive. Litigation over emissions from coal-fired
generating units is also occurring, including litigation against
TVA. See Legal Proceedings.
The
total cost of compliance with future clean air regulations beyond CAIR and
CAMR
cannot reasonably be determined at this time because of the unknowns and
uncertainties surrounding emerging EPA regulations, resultant compliance
strategies, the potential for the development of new emission control
technologies, litigation, and future amendments to the Clean Air
Act. However, TVA does estimate that spending on emission controls
for CAIR and CAMR into the decade beginning in 2011 could cost between $3.0
billion to $3.6 billion. There could be other substantial costs if
reductions of carbon dioxide (“CO2”) are
mandated. Predicting how and when CO2 may be
regulated is
very difficult, even more so than the future regulation of other
substances. TVA will continue to monitor this issue and will assess
and respond to potential financial impacts as they become more
certain.
TVA’s
total cost related to emission reduction regulatory programs for sulfur dioxide,
nitrogen oxide, and particulates from 1977 through 2010 is expected to reach
$5.8 billion, $4.8 billion of which had already been spent as of September
30,
2007. (The cost estimates for complying with CAIR and CAMR, above,
are in addition to these costs.) Increasingly stringent regulation of some
or
all of these substances will continue to result in significant capital and
operating costs for coal-fired generating units, including those operated by
TVA.
Liability
for releases and cleanup of
hazardous substances is regulated by the federal Comprehensive Environmental
Response, Compensation, and Liability Act, among others, and similar state
statutes. In a manner similar to many other industries and power
systems, TVA has generated or used hazardous substances over the
years. TVA operations at some TVA-owned facilities have resulted in
releases of hazardous substances and/or oil which require cleanup and/or
remediation. TVA also is aware of alleged hazardous-substance
releases at 10 non-TVA areas for which it may have some
liability. TVA has reached agreements with EPA to settle its
liability at two of the non-TVA areas for a total of less than
$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 at this time to
estimate its liability related to these sites.
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.
Legal
Proceedings
TVA
is subject to various legal
proceedings and claims that have arisen in the ordinary course of business.
These proceedings and claims include the matters discussed below. 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 $1.1 million with respect to other
proceedings that have arisen in the normal course of TVA’s business. No
assurance can be given that TVA will not be subject to significant additional
claims and liabilities. If actual liabilities significantly exceed the estimates
made, TVA’s results of operations, liquidity, and financial condition could be
materially adversely affected.
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 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 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.
15.
Related Parties
TVA
is a
wholly-owned corporate agency of the federal government, and because of this
relationship, TVA’s revenues and expenses are included as part of the federal
budget. TVA’s purpose and responsibilities as an agency are described
under the “Other Agencies” section of the federal budget.
TVA
currently receives no
appropriations from Congress and funds its business using generated power system
revenues, power financings, and other revenues. TVA is a source of
cash to the federal government. Until TVA meets its remaining
obligation to pay $130 million of the Power Facility Appropriation Investment
under the TVA Act, TVA will continue to repay a portion of the Power Facility
Appropriation Investment in the TVA power system. TVA will also
continue to pay a return on the outstanding balance of this investment
indefinitely. See Note 8 — Appropriation
Investment.
In
the normal course of business, TVA
contracts with other federal agencies for sales of electricity and other
services. Transactions with agencies of the federal government were
as follows:
|
Related
Party Transactions
For
the years ended, or as of September 30
|
|||||||||||
|
2007
|
2006
|
2005
|
|||||||||
|
Sales
of electricity services
|
$188
|
$181
|
$168
|
||||||||
|
Other
revenues
|
47
|
24
|
15
|
||||||||
|
Other
expenses
|
237
|
226
|
222
|
||||||||
|
Receivables
at September 30
|
19
|
21
|
26
|
||||||||
|
Payables
at September 30
|
126
|
123
|
131
|
||||||||
|
Return
on Power Facility Appropriation Investment
|
20
|
18
|
16
|
||||||||
|
Repayment
of Power Facility Appropriation Investment
|
20
|
20
|
20
|
||||||||
16.
Unaudited Consolidated Quarterly Financial Information
A
summary of the unaudited quarterly
results of operations for the years 2007 and 2006 follows. This
summary should be read in conjunction with the audited financial statements
appearing herein. Results for interim periods may fluctuate as a
result of seasonal weather conditions, changes in rates, and other
factors. The $53 million loss in the first quarter of 2006 was
primarily due to increased fuel and purchased power costs.
Unaudited
Consolidated Quarterly Financial Information
|
2007
|
|||||||||||||||||||
|
First
|
Second
|
Third
|
Fourth
|
Total
|
|||||||||||||||
|
Operating
revenues
|
$2,104
|
1,2 |
$2,280
|
2 |
$2,236
|
$2,624
|
$9,244
|
||||||||||||
|
Revenue
capitalized during pre-commercial plant
operations
|
–
|
–
|
23
|
3
|
34
|
57
|
|||||||||||||
|
Operating
expenses
|
1,788
|
1,891
|
1,853
|
3 |
2,191
|
7,723
|
|||||||||||||
|
Operating
income
|
316
|
1,2 |
389
|
2 |
360
|
399
|
1,464
|
||||||||||||
|
Net
income
|
$51
|
$126
|
$194
|
$12
|
$383
|
||||||||||||||
|
2006
|
|||||||||||||||||||
|
First
|
Second
|
Third
|
Fourth
|
Total
|
|||||||||||||||
|
Operating
revenues 4
|
$2,050
|
$2,055
|
$2,242
|
$2,828
|
$9,175
|
||||||||||||||
|
Operating
expenses
|
1,827
|
1,766
|
1,874
|
2,115
|
7,582
|
||||||||||||||
|
Operating
income 4
|
223
|
289
|
368
|
713
|
1,593
|
||||||||||||||
|
Income
before cumulativeeffect
of accounting changes
|
(53)
|
14
|
162
|
315
|
438
|
||||||||||||||
|
Cumulative
effect of accounting
changes
|
–
|
–
|
–
|
(109)
|
(109)
|
||||||||||||||
|
Net
(loss)/income
|
$(53)
|
$14
|
$162
|
$206
|
$329
|
||||||||||||||
|
Notes:
|
|
|
|
(1)
|
Prior
to the second quarter of 2007, TVA reported certain items not directly
associated with the sale of electricity as Sales of
electricity. This revenue of $7 million for the first quarter
of 2007 has been reclassified from Sales of electricity to Other
revenue. See Note 1 —
Reclassifications.
|
|
|
(2)
|
Prior
to the third quarter of 2007, TVA reported certain revenue not directly
associated with revenue derived from electric operations as Other
revenue. This loss of $3 million for the second quarter of 2007
has been reclassified from Other revenue to Other income. See
Note 1 —
Reclassifications.
|
|
|
(3)
|
Prior
to the fourth quarter of 2007, TVA reported certain revenue realized
from
pre-commercial plant operations as an increase to Operating and
maintenance expense. This revenue of $23 million for the third
quarter of 2007 has been reclassified from Operating and maintenance
expense to Revenue capitalized during pre-commercial plant
operations. See Note 1 — Capitalized Revenue During
Pre-Commercial Plant
Operations.
|
|
(4)
|
Prior
to 2007, TVA reported certain revenue not directly associated with
revenue
derived from electric operations as Other revenue. This income
(loss) of $2 million, ($7 million), $8 million, and $7 million for
the
first quarter of 2006, the second quarter of 2006, the third quarter
of
2006, and the fourth quarter of 2006, 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 $5 million,
$6 million, $5 million, and $6 million for the first quarter of 2006,
the
second quarter of 2006, the third quarter of 2006, and the fourth
quarter
of 2006, respectively, has been reclassified from Sales of electricity
to
Other revenue. See Note 1 —
Reclassifications.
|
17.
Subsequent Events
Debt
Securities
In
October 2007, TVA issued $24 million
of electronotes® with an
interest
rate of 5.5 percent which mature in October 2022 and are callable beginning
in
October 2008.
In
November 2007, TVA issued $17
million of electronotes® with an
interest
rate of 4.8 percent which mature in November 2014 and are callable beginning
in
November 2008.
Revolving
Credit Facility Agreement
In
November 2007, TVA renewed the
credit facility with the November 11, 2007, maturity date. The new
maturity date for this credit facility is November 10, 2008.
Management
Changes
On
November 26, 2007, TVA’s principal
accounting officer, Randall P. Trusley, Vice President and Controller, announced
he would be retiring from TVA effective January 4, 2008.
On
December 4, 2007, John Thomas,
General Manager for Operations Business Services, was named Vice President
and
Controller, effective January 7, 2008.
Impacts
of Recent Financial Market Conditions on Investment Portfolios
Financial
markets have experienced
significant uncertainty in recent months due to deteriorating credit conditions
associated with increased default rates on sub-prime mortgages. The uncertainty
has resulted in significantly lower market valuations for many asset backed
investments. TVA’s investment portfolios contain a variety of
diversified investments, including securities directly impacted by these
events. The impact of these events on TVA’s retirement system and
nuclear decommissioning trust investment portfolios is reflected in changes
in
these portfolio values from September 30, 2007 to November 30, 2007, which
are
outlined in the following table:
|
2007
|
|||||||||||||||
|
September
30*
|
October
30*
|
November
30*
|
Percent
Change Since
September
30
|
||||||||||||
|
Retirement
System
|
$7,977
|
$
8,082
|
$7,797
|
(2.26%
|
) | ||||||||||
|
Nuclear
Decommissioning Trust
|
1,086
|
1,115
|
1,065
|
(1.93%
|
) | ||||||||||
|
|
*
|
Investment
balances at September 30, 2007, as reported in Notes 13 and
14. Investment balances at October 31, 2007, are based on final
trustee statements, and investment balances at November 30, 2007,
are
based on preliminary trustee
balances.
|
During
the period of September 30,
2007, through November 30, 2007, the change in the Standard & Poor’s 500
benchmark index was a decrease of 2.66 percent.
To
the
Board of Directors of the Tennessee Valley Authority:
In
our
opinion, the accompanying balance sheets and the related statements of income,
of changes in proprietary capital and of cash flows present fairly, in all
material respects, the financial position of Tennessee Valley
Authority at September 30, 2007 and 2006, and the results
of its operations and its cash flows for each of the three years in the period
ended September 30, 2007 in conformity with accounting principles generally
accepted in the United States of America. In addition, in our
opinion, the financial statement schedule appearing under Item 15(a)(2) presents
fairly, in all material respects, the information set forth therein when read
in
conjunction with the related financial statements. These financial
statements and financial statement schedule are the responsibility of the
Tennessee Valley Authority's management. Our responsibility is to
express an opinion on these financial statements and financial statement
schedule based on our audits. We conducted our audits of these
statements in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures
in
the financial statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
As
discussed in note 1 to the financial statements, effective September 30, 2006,
Tennessee Valley Authority adopted Financial Accounting Standards Board
Interpretation No. 47, Accounting for Conditional Asset Retirement
Obligations--an Interpretation of FASB Statement No. 143.
PricewaterhouseCoopers LLP
Knoxville,
Tennessee
December
10, 2007
For information regarding TVA’s decision to change independent registered public
accounting firms, please refer to the disclosure in TVA’s Current Report on
Form 8-K dated September 27, 2007, which was filed with the SEC on October
2,
2007.
An evaluation has been performed under the supervision of TVA management
(including the president and chief executive officer) and members of the
disclosure control committee (including the chief financial officer and the
vice
president and controller) of the effectiveness of the design and operation
of
TVA’s disclosure controls and procedures as of September 30,
2007. Based on that evaluation, the president and chief executive
officer and members of the disclosure control committee (including the chief
financial officer and the vice president and controller) concluded that TVA’s
disclosure controls and procedures, except as described in the following
paragraph, were effective as of September 30, 2007, to ensure that
information required to be disclosed in reports TVA files or submits under
the
Securities Exchange Act of 1934, as amended, is recorded, processed, summarized,
and reported within the time periods specified in Securities and Exchange
Commission rules and forms. This includes controls and procedures designed
to
ensure that such information is accumulated and communicated to TVA management,
including the president and chief executive officer, the disclosure control
committee, and the chief financial officer, as appropriate, to allow timely
decisions regarding required disclosure.
During
the preparation of this Annual
Report on Form 10-K, TVA determined that certain information for which Current
Report on Form 8-K disclosure was called for was not reported on such form.
This
information concerned executive compensation and the renewal of credit
facilities. These matters are discussed in detail in a Current Report on
Form
8-K filed by TVA on December 11, 2007. The majority of the relevant information
had already been disclosed in the Quarterly Reports on Form 10-Q and Current
Reports on Form-8-K TVA filed during the year, or is being disclosed in this
Annual Report on Form 10-K. The failures were the result of control deficiencies
and human error. TVA has identified improvements to its disclosure controls,
which involve both additional controls and additional training. TVA has begun
to
implement these improvements.
TVA
management believes that a control
system, no matter how well designed and operated, cannot provide absolute
assurance that the objectives of the control system are met, and no evaluation
of controls can provide absolute assurance that all control issues and instances
of fraud, if any, within a company can be detected.
TVA’s
controls and procedures 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.
During
the most recent fiscal quarter,
there were changes in TVA’s internal control over financial reporting that have
materially affected TVA’s internal control over financial
reporting. In particular, TVA completed the remediation of material
internal control weaknesses related to (1) TVA’s end-use billing arrangements
with wholesale power customers and (2) the completeness, accuracy, and
authorization of TVA’s property, plant, and equipment transactions and balances,
the calculation of AFUDC, and the review of construction work in progress
accounts for proper closure to completed plant.
ITEM
9B. OTHER INFORMATION
Not
applicable.
TVA is administered by a board of nine part-time members appointed by the
President of the United States with the advice and consent of the
Senate. The Chairman of the TVA Board is selected by the members of
the TVA Board.
The
TVA Board at December 12, 2007, consisted of the following individuals with
their ages and terms of office provided:
|
Directors
|
Age
|
Year
Appointed
|
Year
Term Expires
|
|
William
B. Sansom, Chairman
|
66
|
2006
|
2009
|
|
Bishop
William Graves
|
70
|
2006
|
2007 *
|
|
Susan
Richardson Williams
|
62
|
2006
|
2007 *
|
|
Skila
S. Harris
|
57
|
1999
|
2008
|
|
Donald
R. DePriest
|
68
|
2006
|
2009
|
|
Howard
A. Thrailkill
|
68
|
2006
|
2010
|
|
Dennis
C. Bottorff
|
63
|
2006
|
2011
|
|
Robert
M. Duncan
|
56
|
2006
|
2011
|
|
|
*
|
Although
the terms of Directors Graves and Williams expired in May 2007, they
are
entitled to remain in office until the end of the current session
of
Congress. Both directors have been nominated by President
George W. Bush for new terms.
|
There is currently one vacant position on the TVA Board, and President Bush
has
nominated Thomas C. Gilliland to fill this position. A hearing on Mr.
Gilliland’s nomination was held before the Senate Environment & Public Works
Committee on October 2, 2007, but the Senate has not yet completed action on
his
nomination.
Mr. Sansom of Knoxville, Tennessee, joined the TVA Board
in March 2006 and was elected Chairman by the TVA Board in March
2006. He is Chairman and Chief Executive Officer of The H.T. Hackney
Co., a diversified company involved in wholesale grocery, gas and oil, and
furniture manufacturing, and has held that position since 1983. Since
1995, Mr. Sansom has also been a director of Astec Industries, Inc., a
corporation based in Chattanooga, Tennessee, that manufactures equipment and
components used in road construction, and since 1984, he has been a director
at
First Horizon National Corporation, a Memphis, Tennessee, bank holding
company. In 2006, he was named a director of Mid-America Apartment
Communities, Inc., a real estate investment trust with ownership interests
in
apartment homes. From 1994 to 2006, he was a director of Martin
Marietta Materials, Inc., a company based in Raleigh, North Carolina, that
supplies minerals, chemicals, and composites for various
industries.
Bishop Graves of Memphis, Tennessee, joined the TVA Board in October 2006.
He has been presiding Bishop of the Christian Methodist Episcopal Church in
Memphis, Tennessee since being elected at the 2006 General
Conference held in June to July 2006. Previously, he was pastor of
the Phillips Temple CME Church of Los Angeles, California. He is the
immediate Past President of the Board of the National Congress of Black
Churches, and from September 1993 to July 2004 Bishop Graves was a member of
the
Board of Memphis Light, Gas and Water, a TVA distributor customer.
Ms. Williams of Knoxville, Tennessee, joined the TVA Board
in March 2006. Since June 2004, she has been the owner of Susan
Williams Public Affairs in Knoxville, Tennessee, and is affiliated with SRW
& Associates, where, along with five other independent contractors involved
with SRW & Associates, she provides public relations consulting services for
various clients. From 1996 to 2004, she managed the Knoxville,
Tennessee, office of the Ingram Group, a statewide public-relations
firm.
Ms. Harris joined the TVA Board in November 1999. Prior to her current position, she served at the Department of Energy as Executive Director of the Secretary of Energy Advisory Board. From 1993 until 1997, she was a Special Assistant to Vice President Gore and Mrs. Gore’s Chief of Staff.
Mr.
DePriest of Columbus, Mississippi, joined the TVA Board in
March 2006. He is President of MCT Investors L.P, an Alexandria,
Virginia, venture capital firm that he founded in 1987 and that develops
telecommunications and healthcare ventures. He has founded other
companies, including Boundary Healthcare Products Corporation in 1987, where
he
served as Chairman until 1992. He also founded Charisma
Communications Corporation in 1982, a telecommunications company, where he
served as Chairman and President.
Mr.
Thrailkill of Huntsville, Alabama, joined the TVA Board in March
2006. He retired in September 2005 as President and Chief Operating
Officer of Adtran, Inc., in Huntsville, which supplies equipment for
telecommunications service providers and corporate end-users. He
joined Adtran, Inc., in 1992.
Mr. Bottorff of Nashville, Tennessee, joined the TVA Board in March
2006. Since January 2001, he has served as Chairman and Partner of
Council Ventures, a venture capital firm. He was Chairman of AmSouth
Bancorporation until his retirement in 2001 and from 1991 to 1999 was Chief
Executive Officer of First American Bank. He has served since 1998 as
a director of Dollar General, a variety store company. In addition,
he is a director of Ingram Industries, a privately held provider of wholesale
distribution, inland marine transportation, and insurance services; a director
of AppForge, a privately held developer of multi-platform mobile and wireless
application solutions; a director of Lancope, Inc., a privately held developer
of behavioral-based intrusion detection systems for network security; and a
member of the Board of Trustees of Vanderbilt University.
Mr. Duncan of Inez, Kentucky, joined the TVA Board in March 2006. He
is the Chairman, Chief Executive Officer, and Director of Inez Deposit Bank,
FSB
in Louisa, Kentucky (since April 1984, with a one-year leave of absence from
1989 to 1990 to serve as Assistant Director of Public Liaison in the White
House); Chairman, Chief Executive Officer, and Director of Inez Deposit Bank
in
Inez, Kentucky (since September 1974 with a one-year leave of absence);
Chairman, Chief Executive Officer, and Director of Community Holding Company,
a
single-bank holding company (since 1984 with a one-year leave of absence);
Chairman, Chief Executive Officer, and Director of Community Thrift Holding
Company, a unitary thrift holding company (since 1999); and Chairman of the
Republican National Committee since January 2007. From 1998 to 2007,
Mr. Duncan was the Chairman of the Big Sandy Regional Industrial Development
Authority, which manages industrial parks in five eastern Kentucky
counties. Mr. Duncan remains on the board of directors of the Big
Sandy Regional Industrial Development Authority. He is also the
Secretary for the Highlands Regional Medical Center in Prestonburg, Kentucky,
which manages a regional hospital.
Mr. Gilliland, the nominee, is from Blairsville, Georgia and is age
59. Mr. Gilliland has been Executive Vice President and Director of
United Community Banks, Inc., a bank holding company with assets of
approximately $8.0 billion, since 1992. He has also been the
Secretary and General Counsel of this company since 2000. If
confirmed by the Senate, his term would extend until May 2011.
On
January 19, 2007,
William W. Baxter informed the Honorable George W. Bush, the President of the
United States, that he was resigning his position as a director of the Tennessee
Valley Authority, effective immediately, to return full-time to the private
sector.
TVA’s
executive officers
as of December 12, 2007, their titles, their ages, and the date their employment
with TVA commenced are as follows:
|
Executive
Officers
|
Title
|
Age
|
Employment
Commenced
|
|
Tom
D. Kilgore
|
President
and Chief Executive Officer
|
59
|
2005
|
|
Kimberly
S. Greene
|
Chief
Financial Officer & Executive Vice President, Financial
Services
|
41
|
2007
|
|
William
R. McCollum, Jr.
|
Chief
Operating Officer
|
56
|
2007
|
|
Maureen
H. Dunn
|
Executive
Vice President and General Counsel
|
58
|
1978
|
|
John
E. Long, Jr.
|
Chief
Administrative Officer and Executive Vice President, Administrative
Services
|
55
|
1980
|
|
Kenneth
R. Breeden
|
Executive
Vice President, Customer Resources
|
59
|
2004
|
|
William
T. Boston
|
Executive
Vice President, Power System Operations
|
57
|
1972
|
|
William
R. Campbell
|
Chief
Nuclear Officer and Executive Vice President
|
56
|
2007
|
|
Preston
D. Swafford
|
Executive
Vice President, Fossil Power Group
|
47
|
2006
|
|
Ashok
S. Bhatnagar
|
Senior
Vice President, Nuclear Generation Development and
Construction
|
51
|
1999
|
|
Janet
C. Herrin
|
Senior
Vice President, River Operations
|
53
|
1978
|
|
John
M. Hoskins
|
Senior
Vice President and Treasurer
|
52
|
1978
|
|
Peyton
T. Hairston, Jr.
|
Senior
Vice President, Corporate Responsibility and
Diversity
|
52
|
1993
|
|
Emily
J. Reynolds
|
Senior
Vice President, Communications, Government and Valley
Relations
|
51
|
2007
|
|
Bridgette
Ellis
|
Senior
Vice President, Office of Environment and Research
|
51
|
1979
|
|
Randy
Trusley
|
Vice
President and Controller
|
51
|
1978
|
Mr.
Kilgore was named President and
Chief Executive Officer in October 2006 after having served as President and
Chief Operating Officer since joining TVA in March 2005. He
previously served as President and Chief Executive Officer of Progress Energy
Ventures, a subsidiary of Progress Energy Company created to manage various
operations of Progress Energy Company, including fuel extraction and energy
marketing, from April 2000 to February 2005. Prior to taking that
position, Mr. Kilgore had been Senior Vice President of Power Operations for
Carolina Power & Light (which became Progress Energy) since August
1998. From 1991 to 1998, Mr. Kilgore was President and Chief
Executive Officer of Oglethorpe Power Corporation in Atlanta,
Georgia.
Ms.
Greene was named Chief Financial
Officer and Executive Vice President, Financial Services in September
2007. Ms. Greene previously served as Senior Vice President, Finance,
and Treasurer at Southern Company Services, an energy company, from July 2003
to
September 2007, where she was responsible for financial planning and analysis,
capital markets and leasing, treasury and investor relations. From
July 2002 to July 2003, Ms. Greene was director of portfolio management for
Southern Company Generation and Energy Marketing.
Mr.
McCollum joined TVA in May 2007 as
Chief Operating Officer. Prior to joining TVA, Mr. McCollum was
Executive Vice President and Chief Regulated Generation Officer at Duke Energy
Corporation, an energy company, from October 2006 to May 2007. Mr.
McCollum was with Duke Energy Corporation (and its predecessor) since 1974
and
held a variety of leadership positions there, including Group Vice President,
Regulated Fossil-Hydro Generation (from April 2006 to October 2006), Vice
President, Strategic Planning and Business Development (from January 2005 to
April 2006), and Vice President, Nuclear Support (from November 2002 to December
2004).
Ms.
Dunn joined TVA as an attorney in
May 1978, assumed the position of Assistant General Counsel in September 1986,
and assumed the position of Executive Vice President and General Counsel in
January 2001.
Mr.
Long was named Executive Vice
President, Administrative Services as well as Chief Administrative Officer
in
September 2005. From October 2000 to September 2005, he was Executive
Vice President, Human Resources. Mr. Long joined TVA in 1980 as a
Personnel Officer in the Engineering Design Organization and has held various
Human Resources positions within TVA. From 1992 to 2005, he served on
the TVA Retirement System Board.
Mr.
Breeden was named Executive Vice
President, Customer Resources in September 2006 after having served as Executive
Vice President, Customer Service and Marketing since joining TVA in August
2004. From March 2002 to August 2004, he was the Program Executive
for Executive Conversation, Inc., where he was responsible for executive
training programs. From September 1997 to March 2002, he was
President of TXU Energy Services, Enterprise Division, in Dallas, Texas, where
he had accountability for a new venture created to address customers’ changing
energy needs. Mr. Breeden had joined TXU Corporation in May 1995 as
Senior Vice President of TXU Electric & Gas, where he was responsible for
marketing and sales.
Mr.
Boston is Executive Vice President, Power System Operations, a position he
has
held since May 1999. He joined TVA as a Power Supply Engineer in 1972
and held various technical and managerial positions until becoming Division
Manager of Electric System Reliability in May 1991. In December 1996,
he was named Senior Manager, Pricing, and held that position until April
1999. Mr. Boston serves as Vice President of CIGRE-U.S., the
International Council on Large Electric Systems, as Vice President of the NERC
Transmission Forum, and as a member of the Board for the Association of Edison
Illuminating Company.
Mr.
Campbell joined TVA as Chief
Nuclear Officer and Executive Vice President in May 2007. Mr. Campbell
served as Executive Vice President, Engineering and Projects for Entergy
Operations, Inc. (“Entergy”), an energy company, from February 2007 to May
2007. In that capacity, he was responsible for engineering, technical
support, and project management functions for all regulated and non-regulated
Entergy nuclear units. Mr. Campbell served as Senior Vice President
and Chief Operating Officer of Entergy from February 2003 to February 2007,
and
was responsible for the operation of all Entergy regulated nuclear
units. He also served as Vice President, Engineering, of Entergy from
June 2000 to February 2003.
Mr.
Swafford joined TVA in May 2006 and
was named Executive Vice President, Fossil Power Group, in June
2007. From May 2006 until May 2007, he was Senior Vice President,
Nuclear Support of TVA. From December 1995 to April 2006, Mr.
Swafford held various positions at Exelon Corporation, an energy company based
in Illinois, and its subsidiaries. From 2002 to 2006, he served as
Senior Vice President, Exelon Energy Delivery, and was responsible for
transmission and distribution of electricity. From 2002 to 2003, he
was Vice President, Exelon Power, and was responsible for its fleet of gas,
coal-fired, and hydroelectric generating facilities. From 2000 to
2002, he was Vice President, Dresden Nuclear Station.
Mr.
Bhatnagar is the Senior Vice
President of Nuclear Generation Development and Construction, a position he
has
held since April 2007. He joined TVA in August 1999 as Site Support
Manager at Browns Ferry and was subsequently appointed Browns Ferry Plant
Manager in July 2000, Browns Ferry Site Vice President in July 2001, and Senior
Vice President, Nuclear Operations, in June 2004.
Ms.
Herrin is the Senior Vice
President, River Operations, a position she has held since February
1999. Ms. Herrin is responsible for establishing river operations
policies, procedures, and standards for TVA and serves as TVA’s Dam Safety
Officer. She began her career at TVA in 1978 as a Civil
Engineer. She has served on the TVA Retirement System Board since
2005.
Mr.
Hoskins, Senior Vice President and
Treasurer, joined TVA in 1978 and worked in several areas of TVA business
including accounting, audit, and revenue before joining the Treasurer’s office
in 1987. He was named Vice President and Treasurer in 1994 and Senior
Vice President and Treasurer in 2000. He has served on the TVA
Retirement System Board of Directors since 2003. Mr. Hoskins also
served as Interim Chief Financial Officer of TVA from November 2006 to September
2007.
Mr.
Hairston was named Senior Vice
President, Corporate Responsibility and Diversity, in March 2007, and was
additionally named TVA’s Chief Ethics and Compliance Officer in July
2007. He previously served as Senior Vice President, Communications,
a position he assumed in March 2006. From October 2002 to March 2006,
he held the position of Senior Vice President, Employee Relations and
Diversity. Mr. Hairston served as Senior Vice President, Labor
Relations, from October 2000 to October 2002, and had held that position
previously from June 1994 to June 1998. From August 1998 to October
2000, he was Senior Vice President, Strategic Initiatives. Mr.
Hairston also served as Senior Manager, Strategic Planning and Support from
May
1993 to June 1994.
Ms.
Reynolds joined TVA in April 2007
as Senior Vice President of Communications, Government and Valley
Relations. Ms. Reynolds served as the 31st secretary
of the
U.S. Senate (“Secretary”) (from January 2003 to January 2007), where she managed
the legislative, financial, and administrative operations of the
Senate. She also served as a consultant to the Secretary from January
2007 to April 2007. She previously served as chief of staff for
Senator Frist (from January 2001 to January 2003), where she had overall
responsibility for the management and coordination of staffing, legislative
activity, communications, constituent relations, and scheduling.
Ms.
Ellis is the Senior Vice President,
Office of Environment and Research, and TVA’s Environmental Executive and
Federal Preservation Officer, positions she has held since May
2007. Ms. Ellis is responsible for corporate environmental policies
and strategies, management of reservoir lands, and research and
development. She previously served as the Senior Vice President,
Environmental Stewardship and Policy (from February 2006 to May 2007), the
Vice
President, Resource Stewardship and Acting Vice President, Environmental Policy
and Planning (from July 2005 to February 2006), and Vice President, Resource
Stewardship (from November 2000 to July 2005). Ms. Ellis began her
career at TVA in 1979 as a forester.
Mr.
Trusley is TVA’s Vice President and
Controller, a position he has held since January 2001. He joined TVA
in October 1978 as an auditor and was budget officer from July 1981 until March
1984, at which time he briefly left TVA. He returned to TVA in
January 1988 as a financial analyst, and he held the positions of Accounting
Manager from April 1989 to September 1994 and Business Manager from October
1994
to December 2001.
TVA
has a Disclosure and Financial
Ethics Code (“Financial Ethics Code”) that applies to all executive officers and
directors of TVA as well as to all employees who certify information contained
in quarterly reports, annual reports, or information statements or who have
responsibility for internal control self-assessments. The Financial
Ethics Code includes provisions covering conflicts of interest, ethical conduct,
compliance with applicable laws, rules, and regulations, responsibility for
full, fair, accurate, timely, and understandable disclosures, and accountability
for adherence to the Financial Ethics Code. TVA will provide a
current copy of the Financial Ethics Code to any person, without charge, upon
request. Requests may be made by calling 888-882-4975 or by sending
an e-mail to: investor@tva.com. Any waivers of or changes to
provisions of the Financial Ethics Code will be promptly disclosed to the
public, subject to limitations imposed by law, on TVA’s website
at: www.tva.gov. Information contained on TVA’s website
shall not be deemed incorporated into, or to be a part of, this Annual
Report.
TVA
does not have a
Nominating Committee. Each member of the TVA Board is appointed by
the President of the United States with the advice and consent of the U.S.
Senate. The TVA Act provides that to be eligible to be appointed as a
member of the TVA Board, an individual must (1) be a citizen of the United
States, (2) have management expertise relative to a large for-profit or
nonprofit corporate, government, or academic structure, (3) not be an employee
of TVA, (4) make full disclosure to Congress of any investment or other
financial interest that the individual holds in the energy industry, and (5)
affirm support for the objectives and missions of TVA, including being a
national leader in technological innovation, low-cost power, and environmental
stewardship. No more than two of the Board members may be legal
residents outside of TVA’s service area.
The
TVA Board has an Audit and Ethics
Committee established in accordance with the TVA Act. TVA’s Audit and
Ethics Committee consists of Robert M. Duncan, its chair, Susan Richardson
Williams, and Donald R. DePriest. None of the members of the Audit
and Ethics Committee has been determined to be an “audit committee financial
expert” under applicable SEC rules, as none of the appointed TVA Board members
was required by the TVA Act to meet the criteria of an “audit committee
financial expert” under applicable SEC rules.
TVA
is exempted by section 37 of the
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. Notwithstanding this
exemption and the fact that TVA is not a listed company, the TVA Act contains
certain provisions that are similar to the considerations for independence
under section 10A(m)(3) of the Exchange Act, including that to be eligible
for
appointment to the TVA Board, an individual shall not be an employee of TVA
and
shall make full disclosure to Congress of any investment or other financial
interest that the individual holds in the energy industry. These
provisions became applicable to TVA Board members on March 31,
2006.
Under
section 10A(m)(2) of
the Exchange Act, which applies to TVA, the audit committee is directly
responsible for the appointment, compensation, and oversight of the external
auditor; however, the TVA Act assigns the responsibility for engaging
the services of the external auditor to the TVA Board.
The
TVA Board has also established the
following committees in addition to the Audit and Ethics Committee:
|
•
|
Human
Resources Committee
|
|
•
|
Corporate
Governance Committee
|
|
•
|
Finance,
Strategy and Rates Committee
|
|
•
|
Operations,
Environment and Safety Committee
|
|
•
|
Community
Relations Committee
|
This
Compensation Discussion and
Analysis provides information about TVA’s compensation philosophy and strategy,
as well as the policies and decisions that guided TVA in 2007 in establishing
the level and nature of the compensation provided to the President and Chief
Executive Officer (“CEO”), the Chief Financial Officer and Executive Vice
President, Financial Services (“CFO”), and the three most highly compensated
executive officers other than the CEO and CFO. References to the
“Named Executive Officers” throughout this section refer to the executive
officers listed in the Summary Compensation Table.
Authority
for the Executive Compensation Program
The
TVA Act is the primary statutory
authority for establishing the compensation of all TVA employees, including
the
Named Executive Officers, and places responsibility for doing so with the TVA
Board. Under section 2 of the TVA Act, as amended by the Consolidated
Appropriations Act, 2005 (the “Consolidated Appropriations Act”), which became
effective on March 31, 2006, the TVA Board is directed to establish a
compensation plan for all TVA employees which:
|
•
|
Specifies
all compensation (including salary or any other pay, bonuses, benefits,
incentives, and any other form of remuneration) for the CEO and TVA
employees;
|
|
•
|
Is
based on an annual survey of the prevailing compensation for similar
positions in private industry, including engineering and electric
utility
companies, publicly owned electric utilities, and federal, state
and local
governments; and
|
|
•
|
Provides
that education, experience, level of responsibility, geographic
differences, and retention and recruitment needs will be taken into
account in determining compensation of
employees.
|
The
TVA Act, as amended by the
Consolidated Appropriations Act, also provides that:
|
•
|
The
TVA Board will annually approve all compensation (including salary
or any
other pay, bonuses, benefits, incentives, and any other form of
remuneration) of all managers and technical personnel who report
directly
to the CEO (including any adjustment to
compensation);
|
|
•
|
On
the recommendation of the CEO, the TVA Board will approve the salaries
of
employees whose salaries would be in excess of Level IV of the Executive
Schedule ($145,400 in 2007); and
|
|
•
|
The
CEO will determine the salary and benefits of employees whose annual
salary is not greater than Level IV of the Executive Schedule ($145,400
in
2007).
|
In
light
of the statutory authorities described above, the charter of the Human Resources
Committee, which was approved by the TVA Board, calls for the Human Resources
Committee to review a TVA compensation plan and to make a recommendation to
the
full TVA Board for approval. The Human Resources Committee, in
conjunction with its independent compensation consultant, developed a
compensation plan in conjunction with TVA management and recommended a proposed
compensation plan to the TVA Board. The TVA Board approved the proposed
compensation plan for all TVA employees, including the Named Executive Officers
and other executives, at its May 31, 2007, meeting (the “Compensation
Plan”). The Compensation Plan will be reviewed from time to time by
the Human Resources Committee to ensure consistency and future alignment with
TVA’s mission and Strategic Plan, and any recommended changes to the
Compensation Plan will be submitted to the TVA Board for approval.
Objective
of the Executive Compensation
Program
The
philosophy of the Compensation Plan
is based on the statutory requirements of the TVA Act, as amended by the
Consolidated Appropriations Act, and recognizes that many employees, including
executives, are called on to accomplish specialized aspects of TVA’s mission
safely, reliably, and efficiently, and must have the requisite education,
experience, and professional qualifications. These requirements make it
necessary for TVA to offer compensation to its specialized employees that
motivates them to stay with TVA and makes it possible for TVA to attract highly
qualified candidates for positions similar to those in relevant
industries. Accordingly, the Compensation Plan is designed to fulfill
the following purposes:
|
•
|
Provide
a competitive level of compensation that enables TVA to attract,
retain,
and motivate highly competent employees. Each position in
TVA has a pay level determined by market pricing based on a level
needed
to attract, retain, and motivate employees critical to TVA’s success in
achieving its mission. Overall compensation levels are targeted
at the median (50th
percentile)
of the relevant labor market for most positions. However, for
positions affected by market scarcity, recruitment and retention
issues,
and other business reasons, overall compensation levels are targeted
above
the median (typically between the 50th
and 75th
percentile). Certain generation and transmission positions, for
example, are targeted at higher overall compensation levels because
of
these factors. Information about TVA’s peer group and
benchmarking practices is provided below under the heading “Use of Market
Data and Benchmarking.”
|
|
•
|
Encourage
and reward executives for their performance and contributions to
the
successful achievement of financial and operational
goals. A key component of the Compensation Plan is a
strong orientation toward “pay for performance,” which rewards improvement
in TVA’s overall performance, as well as that of individual business units
and individual participants. Approximately 40 to 50 percent of
overall compensation for the Named Executive Officers is performance-based
compensation. “At risk” incentive pay for 2007 was directly
linked to the achievement of performance goals at the TVA level and
the
business unit level. In 2007, the TVA Board approved the TVA
level performance goals and delegated authority to approve the business
level performance goals to TVA’s CEO, Mr. Kilgore. This
substantial emphasis on performance-based goals provides incentives
to
executives to perform at the highest levels to achieve the goals
that are
important for TVA.
|
|
•
|
Provide
executives with the focus to achieve short-term and long-term business
goals that are important to TVA, TVA’s customers, and the people TVA
serves. TVA seeks to hire and retain executives who are
focused on both the short-term and long-term success of
TVA. The Compensation Plan is designed to achieve this goal by
providing a mix of fixed base compensation and at-risk annual and
long-term incentive compensation. Base compensation is fixed
and designed to provide an immediate financial incentive to
executives. Annual and long-term incentive compensation is
at-risk based on performance and is designed to focus executives
on the
short-term and long-term goals of
TVA.
|
|
•
|
Improve
overall company performance through productivity
enhancement. No executive can help meet TVA’s goals and
improve performance without the work of all employees of
TVA. For this reason, the performance goals set at the TVA
level and business unit level are the same for both executives and
all
non-executive employees. In this way, all TVA employees receive
compensation in a manner that aligns their work with the same goals
and
encourages and rewards them for the successful achievement of TVA’s
goals.
|
Given
the structure of TVA as an agency
and instrumentality of the United States, there are limits on TVA’s ability to
set compensation for its employees, including the Named Executive Officers,
that
must be balanced with TVA’s compensation philosophy and strategy. One
limit is TVA’s statutory obligation to sell power at rates as low as
feasible. Implicit in this obligation is the requirement that TVA
operate its power system as efficiently and economically as possible, including
limiting total compensation for executives to that required to recruit, retain,
and motivate them. However, providing inadequate compensation levels
to executives could adversely affect TVA’s efficiency and economy to an even
greater extent. A second limitation exists as a result of TVA’s
capital structure. The United States government is TVA’s sole
owner. As a result, TVA does not have equity securities and has no
equity-based compensation. Accordingly, TVA is not able to provide
some of the types of compensation that many companies typically offer their
executives.
Use
of Market Data and Benchmarking
TVA
seeks to establish overall
compensation for executives at a competitive level with respect to the relevant
labor market. Market information for total compensation, as well as
each element of compensation within total compensation, for the Named Executive
Officers is obtained from:
|
•
|
Published
and customized compensation surveys reflecting the relevant labor
markets
identified for designated positions,
and
|
|
•
|
Publicly
disclosed information from the proxy statements and annual reports
on Form
10-K of energy services companies with revenues of $3 billion and
greater.
|
When
the
competitive market compensation is compiled for positions, the Human Resources
department, with the assistance of an independent compensation consultant,
analyzes the data, and provides its analysis to the Human Resources
Committee. The Human Resources Committee uses this information
to:
|
•
|
Test
compensation level and incentive opportunity
competitiveness,
|
|
•
|
Serve
as a point of reference for establishing pay packages for recruiting
executives, and
|
|
•
|
Determine
appropriate adjustments to compensation levels and incentive opportunities
to maintain the desired degree of market
competitiveness.
|
TVA’s
relevant labor market for most
executives, including the Named Executive Officers, is comprised of both private
and publicly-owned companies in the energy services industry of similar revenue
and scope to TVA. When reviewing comparative compensation information
for executives, including the Named Executive Officers, as a part of the
survey-based analysis, TVA looked at the following energy services companies
with annual revenues of $3 billion and greater from the 2006 Towers Perrin
Energy Services Executive Compensation Database:
|
AES
Corp.*
|
Energy
East Corp.
|
PPL
Corp.*
|
|
Allegheny
Energy, Inc.
|
Entergy
Corp.*
|
Progress
Energy, Inc.*
|
|
Ameren
Corp.*
|
Exelon
Corp.*
|
Public
Service Enterprise Group, Inc.*
|
|
American
Electric Power Co., Inc.*
|
FirstEnergy
Corp.*
|
Reliant
Energy, Inc.*
|
|
Atmos
Energy Corp.
|
FPL
Group, Inc.*
|
SCANA
Corp.
|
|
CenterPoint
Energy, Inc.
|
MDU
Resources, Inc.
|
Sempra
Energy*
|
|
CMS
Energy Corp.*
|
Mirant
Corp.
|
The
Southern Company*
|
|
Consolidated
Edison, Inc.*
|
Nicor
Inc.
|
SUEZ
Energy North America
|
|
Constellation
Energy Group, Inc.*
|
NSTAR
Electric Co.
|
TECO
Energy, Inc.
|
|
Dominion
Resources, Inc.*
|
OGE
Energy Corp.
|
TXU
Corp.*
|
|
DTE
Energy Co.*
|
ONEOK
Inc.
|
The
Williams Companies, Inc.
|
|
Duke
Energy Corp.*
|
Pacific
Gas & Electric Co.*
|
Wisconsin
Energy Corp.
|
|
Edison
International*
El
Paso Corp.
|
PacifiCorp
Pepco
Holdings, Inc.*
|
WPS
Resources Corp. (now Intergrys Energy Group, Inc.)*
Xcel
Energy, Inc.*
|
When
reviewing comparative compensation information for executives, including the
Named Executive Officers, from proxy statements and annual reports on Form
10-K,
TVA looked at a subset of the peer group above, identified with asterisks,
as
well as three additional companies in the energy services industry (KeySpan
Corporation, NiSource Inc., and Northeast Utilities), as recommended by the
independent compensation consultant of the Human Resources
Committee.
Executive
Compensation Program Components
TVA’s
compensation program for the
Named Executive Officers consists primarily of the following
components:
|
•
|
base
compensation, consisting entirely of annual salary paid biweekly,
and a
combination of annual salary paid biweekly and additional annual
compensation paid in quarterly installments prior to May 31, 2007,
as
described more fully below;
|
|
•
|
annual
incentive compensation, which is at-risk and based on the attainment
of
certain pre-established performance
goals;
|
|
•
|
long-term
incentive compensation, which is at-risk and based on the attainment
of
certain pre-established performance
goals;
|
|
•
|
long-term
deferred compensation, which is awarded to participating executives
in the
form of annual credits that vest after a specified period of time,
typically three to five years; and
|
|
•
|
pension
plans, both qualified and supplemental, which provide compensation
beginning with retirement or termination of employment, provided
certain
eligibility and vesting requirements are
met.
|
More
information about the value of
these various compensation components for the Named Executive Officers is
provided below under the Summary Compensation Table and the Grants of Plan-Based
Awards Table.
Base
Compensation. For the
Named Executive Officers, base compensation includes salary plus any additional
annual compensation. Base compensation received by executives is
based on their levels of responsibility, their individual merit performances,
and the competitive levels of compensation for executives in similar positions
in the energy services industry.
Prior
to March 31, 2006, the TVA Act
provided that salaries for TVA employees, including the Named Executive
Officers, could match but not exceed the salary of a TVA Board member, which
was
itself set by the TVA Act and by executive order of the President of the United
States. However, the TVA Act, as amended by the Consolidated
Appropriations Act, removed this limitation on salary and requires that the
TVA
Board approve (i) the salaries of the CEO and the CEO’s direct reports, which
include the CFO and Chief Operating Officer (“COO”), and (ii) on the
recommendation of the CEO, the salaries of employees whose annual salaries
would
be in excess of Executive Schedule Level IV ($145,400 in 2007).
As
a result, salaries were limited to
$145,400 for a portion of 2007, and additional annual compensation, which was
paid in quarterly installments, was used in conjunction with the salaries to
provide a competitive level of base compensation. On May 31, 2007, as
part of its approval of the Compensation Plan, the TVA Board approved the
conversion of base compensation to all salary for the CEO, thereby eliminating
additional annual compensation for the CEO, and delegated to the CEO the
authority to approve the conversion of base compensation to all salary for
all
executives
whose base compensation exceeded Executive Schedule Level IV. The CEO
exercised this authority as to the Named Executive Officers as of May 31, 2007,
so since that time, no Named Executive Officer has received additional annual
compensation. The total amounts of additional annual compensation paid to the
Named Executive Officers in 2007 appear in the “Bonus” column in the Summary
Compensation Table.
Base
compensation of the CEO and Named
Executive Officers who are direct reports to the CEO is reviewed annually by
the
Human Resources Committee, and any recommended adjustments are submitted by
the
Human Resources Committee to the TVA Board for approval. Base
compensation of the Named Executive Officers who are not direct reports to
the
CEO is reviewed and approved throughout the year by the CEO and any recommended
adjustments as approved by the CEO are submitted by the Human Resources
Committee to the TVA Board for approval on an annual basis. Since the Human
Resources Committee was still in the process of reviewing a proposed
compensation plan at the beginning of 2007, the base compensation for the Named
Executive Officers as of October 1, 2006, was not changed from 2006
levels. On March 5, 2007, the TVA Board notationally approved the
hiring of Mr. McCollum as COO and fixed his compensation, including his salary,
for 2007. At its August 1, 2007, meeting, the TVA Board delegated to
the CEO the authority to hire Ms. Greene as CFO and to fix her compensation,
including her salary, within the guidelines set forth in the Compensation
Plan.
Annual
Incentive Compensation.
All executives, including the Named
Executive Officers, participate in the Executive Annual Incentive Plan
(“EAIP”). The EAIP is designed to encourage and reward executives for
their contributions to successfully achieving short-term financial and
operational goals of TVA and applicable business units. Under the
EAIP, an executive’s annual incentive payment is calculated as
follows:
EAIP = Base x Annual
Incentive x Percent of
Opportunity
Payout Compensation Opportunity Achieved
Annual
incentive opportunities increase with position and
responsibility. The annual incentive opportunity is established for
each of the Named Executive Officers based on the opportunities other companies
provide to those in comparable positions in the energy services
industry. Incentive opportunities of the CEO and Named Executive
Officers who are direct reports to the CEO are reviewed annually by the Human
Resources Committee, and any recommended adjustments are submitted by the Human
Resources Committee to the TVA Board for approval. Incentive
opportunities of the Named Executive Officers who are not direct reports to
the
CEO are reviewed and approved annually and throughout the year by the CEO.
Since
the Human Resources Committee was still in the process of reviewing a proposed
compensation plan at the beginning of 2007, the annual incentive opportunities
for the Named Executive Officers for 2007 were not changed from 2006
levels. The TVA Board directly approved the annual incentive
opportunity for Mr. McCollum pursuant to its selection of him as
COO. The authority delegated to the CEO to hire Ms. Greene as CFO
included the authority to fix her annual incentive opportunity within the
guidelines set forth in the Compensation Plan.
The
percent of opportunity achieved, as used in the formula above, was determined
in
2007 by a weighted average of the results of a combination of performance
measures at the TVA level and the business unit level. Performance
measures at the TVA level and their weights are identified in TVA’s Winning
Performance Balanced Scorecard. The performance measures and weights
that are incorporated into TVA’s Winning Performance Balanced Scorecard are used
in determining annual incentive payouts not just for the Named Executive
Officers but also for all other participants in the EAIP as well as all other
non-executive TVA employees who participate in TVA’s Winning Performance Team
Incentive Plan. The performance measures, weights, and goals approved
by the TVA Board for the 2007 Winning Performance Balanced Scorecard, as well
as
the results for 2007, are set forth below:
2007
Winning Performance Balanced Scorecard
|
Performance
Metric
|
Weight
|
Results
Achieved
|
Goals
|
|||||||
|
Threshold
(75%)
|
Target
(100%)
|
Maximum
(125%)
|
||||||||
|
Safe
Workplace 1
(Recordable
Injuries/Hours Worked)
|
10%
|
1.58
|
1.82
|
1.56
|
1.30
|
|||||
|
Productivity
($/MWh Sales)
|
10%
|
9.73
|
9.47
|
9.42
|
9.37
|
|||||
|
Connection
Point Interruptions
(Interruptions
per Connection Point)
|
15%
|
0.81
|
0.84
|
0.81
|
0.78
|
|||||
|
Customer
Satisfaction Survey
(Percent
Satisfied)
|
10%
|
89.2
|
82.0
|
84.0
|
86.0
|
|||||
|
Economic
Development
(Jobs
+ Investments + Job impact)
|
5%
|
142
|
100
|
115
|
130
|
|||||
|
Equivalent
Availability Factor (Ratio)
|
15%
|
87.8
|
87.2
|
87.7
|
88.2
|
|||||
|
Environmental
Impact (Index)
|
10%
|
79.8
|
65.2
|
58.3
|
50.6
|
|||||
|
Delivered
Cost of Power Excluding FCA 2
Costs ($/MWh
Sales)
|
20%
|
32.26
|
32.61
|
32.41
|
32.21
|
|||||
|
FCA
2
Costs
($/MWh Sales)
|
5%
|
19.29
|
17.54
|
17.19
|
16.84
|
|||||
|
1
Any TVA employee or staff augmentation contractor fatality will prevent
payout for this indicator.
2
Fuel Cost Adjustment.
|
||||||||||
As
shown in the table above, the
Winning Performance Balanced Scorecard established threshold, target, and
maximum achievement levels for each of the performance
measures. Performance levels between threshold and target achievement
levels, and between target and maximum achievement levels, were calculated
using
straight line interpolation. Threshold achievement levels were set to
recognize normal, satisfactory performance for each performance measure based on
the budget and business plans for 2007. Target achievement levels
were set to recognize good performance over and above threshold achievement
levels. Maximum achievement levels were set to recognize excellent
performance substantially above threshold achievement levels. This approach
to
establishing achievement levels resulted in a good likelihood (approximately
80 percent chance) of meeting threshold achievement levels, a reasonable
likelihood (approximately 60 percent chance) of meeting target achievement
levels, and a small likelihood (approximately 20 percent chance) of meeting
maximum achievement levels.
The
Winning Performance Balanced
Scorecard represented 30 percent of the potential payout under the EAIP in
2007
for the Named Executive Officers. The remaining 70 percent was tied
to the average composite performance of their appropriate business units or,
in
the case of Mr. Kilgore, Ms. Greene, Mr. Hoskins, Mr. Rescoe, and Mr.
McCollum, a composite average of all TVA business units. Under the
EAIP, awards may be adjusted based on the evaluation of individual achievements
and performance results. In 2007, no discretion was exercised by the
TVA Board, CEO, or any other TVA officer or employee to adjust either upward
or
downward the amount of the payout for the Named Executive Officers, except
for
Mr. Singer, whose payout was specified in a separation agreement, without regard
to actual performance.
Awards
provided to the Named Executive
Officers under the EAIP for the performance period that ended on September
30,
2007, are reported in the “Non-Equity Incentive Plan Compensation” column in the
Summary Compensation Table. Additional information regarding the
basis of the payouts under the EAIP is presented in the narrative that
accompanies the Grants of Plan-Based Awards Table.
Long-Term
Incentive Compensation.
In addition to the EAIP, certain executives in critical positions,
including the Named Executive Officers, participate in the Executive Long-Term
Incentive Plan (“ELTIP”). Executives in critical positions are those
who make decisions that impact TVA’s long-term strategic
objectives. The ELTIP is designed to encourage and reward executives
for their contributions to successfully achieving TVA’s long-term financial and
operational goals, typically over a three-year performance cycle. The
ELTIP performance cycles run concurrently, and participating executives receive
awards under the plan on an annual basis if targets are
met. Accordingly, in 2007, the ELTIP performed more as an annual
incentive.
Under
the ELTIP, an executive’s
incentive payment is calculated as follows:
ELTIP = Base x ELTIP
Incentive x Percent of
Opportunity
Payout Compensation Opportunity Achieved
The
ELTIP incentive opportunity is
established for each of the Named Executive Officers at a level that is similar
to the opportunities other companies provide to those in comparable positions
in
the energy services industry. The percent of opportunity achieved, as
used in the formula above, is determined based on the results of one or more
measures at the TVA level critical to satisfying TVA’s long-term strategic
goals. In 2007, the performance metric used was the delivered cost of
power. This metric was selected by the CEO and senior Human Resources
management in consultation with the Human Resources Committee.
Incentive
opportunities of the CEO and Named Executive Officers who are direct reports
to
the CEO are reviewed annually by the Human Resources Committee, and any
recommended adjustments are submitted by the Human Resources Committee to the
TVA Board for approval. Incentive opportunities of the Named
Executive Officers who are not direct reports to the CEO are reviewed and
approved annually and throughout the year by the CEO. Since the Human Resources
Committee was still in the process of reviewing a proposed compensation plan
at
the beginning of 2007, the ELTIP incentive opportunities for the Named Executive
Officers for 2007 were not changed from 2006 levels. The TVA Board
directly approved the ELTIP incentive opportunity for Mr. McCollum pursuant
to
its selection of him as COO. The authority delegated to the CEO to
hire Ms. Greene as CFO included the authority to fix her ELTIP incentive
opportunity within the guidelines set forth in the Compensation
Plan.
Awards
provided to the Named Executive
Officers under the ELTIP for the performance period that ended on September
30,
2007, are reported in the “Non-Equity Incentive Plan Compensation” column in the
Summary Compensation Table. Additional information regarding the
basis of the payouts under the ELTIP is presented in the narrative that
accompanies the Grants of Plan-Based Awards Table.
Long-Term
Deferred
Compensation. Unlike private sector
companies in the energy services industry, TVA is a corporate agency and
instrumentality of the United States and thus does not have equity securities
to
provide stock awards or options as a form of compensation for its
employees. In order to provide a benefit similar to restricted stock,
TVA enters into agreements with certain executives, including the Named
Executive Officers, that are administered under TVA’s Long-Term Deferred
Compensation Plan (“LTDCP”). The LTDCP agreements are designed to
provide retention incentives to executives to encourage them to remain with
TVA
and to provide, in combination with base compensation and EAIP and ELTIP
incentive awards, a competitive level of total compensation. Under
these agreements, credits (which may be vested or unvested) are made to an
account in an executive’s name (typically on an annual basis) for a
predetermined period. If the executive remains employed at TVA until
the end of this period (typically three to five years), the executive becomes
vested in the balance of the account, including any return on investment on
the
credits in the account. Annual credits provided to the Named
Executive Officers under LTDCP agreements in 2007 are reported in the “All Other
Compensation” column in the Summary Compensation Table. These credits
are also reported in the “Registrant Contributions in Last FY” column in the
Nonqualified Deferred Compensation Table since the credits were placed in
deferred compensation accounts in the Named Executives Officers’
names.
TVA
has also entered into additional
LTDCP agreements with Mr. Singer and Mr. Bhatnagar where the amount of
annual credits is based on the achievement of certain milestones with respect
to
the recovery of Browns Ferry Unit 1 (“Browns Ferry Unit 1 Recovery
Project”). The annual credits provided to Mr. Singer and Mr.
Bhatnagar under these agreements for 2007 are reported in the “Non-Equity
Incentive Plan Compensation” column in the Summary Compensation Table and the
“Registrant Contributions in Last FY” column in the Nonqualified Deferred
Compensation Table.
Descriptions
of all the LTDCP
agreements with the Named Executive Officers are found following the Grants
of
Plan-Based Awards Table.
Pension
Benefits. All of the Named Executive Officers are eligible to
participate in the following qualified plans available to all annual TVA
employees:
|
•
|
Defined
benefit plan
|
|
–
|
Original
Benefit Structure (“OBS”) for employees covered under the plan prior to
January 1, 1996, with a pension based on a final average pay
formula
|
|
–
|
Cash
Balance Benefit Structure (“CBBS”) for employees first hired on or after
January 1, 1996, with a pension based on an account that receives
pay
credits equal to six percent of compensation plus
interest
|
|
•
|
401(k)
plan
|
|
–
|
For
OBS members, TVA provides matching contributions of 25 cents on every
dollar up to 1.5 percent of annual
salary.
|
|
–
|
For
CBBS members, TVA provides matching contributions of 75 cents on
every
dollar up to 4.5 percent of annual
salary.
|
The
availability of these qualified plans is consistent with similar qualified
plans
provided by other companies in TVA’s peer group.
In
addition, certain executives in
critical positions, as determined by TVA on an individual basis, are eligible
to
participate in a Supplemental Executive Retirement Plan
(“SERP”). Each of the Named Executive Officers participates in the
SERP. The SERP is a non-qualified pension plan that provides
supplemental pension benefits tied to compensation levels that exceed limits
imposed by IRS regulations applicable to TVA’s qualified plans. The
availability of this supplemental pension plan helps TVA to remain competitive
in attracting and retaining top-level executives. In 2007, for
benefit calculation purposes under the SERP, TVA granted additional years of
credited service to and waived the prior employer pension benefits offset for
Ms. Greene and Mr. McCollum in connection with their acceptance of employment
with TVA. The value associated with the credited years of service and
waiver of prior employer offset under the SERP is reported in the “Change in
Pension Value and Nonqualified Deferred Compensation Earnings” column in the
Summary Compensation Table. These grants of additional credited
service and waivers of offsets of prior employer pension benefits were arrived
at in negotiations with Ms. Greene and Mr. McCollum during their recruitment
to
TVA. Generally, the purpose for granting additional years of credited
service and waiving the offset for any prior employer pension benefits is to
give credit for prior and potential future years of service at a previous
employer.
More
information regarding these
retirement and pension plans is found following the Pension Benefits
Table.
Perquisites.
In 2007, TVA provided to certain executives,
including Ms. Greene, Mr. McCollum, Mr. Singer, and Mr. Bhatnagar, a flat-dollar
biweekly vehicle allowance that may be applied toward the purchase or lease
of a
vehicle, operating fees, excess mileage, maintenance, repairs, and
insurance. Vehicle allowances are granted on a “business need” basis
to a very limited number of executives. The amount of the vehicle
allowances granted to the Named Executive Officers is reported in the “All Other
Compensation” column in the Summary Compensation Table.
In
2007, TVA also provided relocation
incentive payments to Ms. Greene and Mr. McCollum in connection with their
acceptance of employment with TVA and move to Tennessee. These
relocation incentive payments are reported in the “All Other Compensation”
column in the Summary Compensation Table. In addition, both Ms.
Greene and Mr. McCollum were eligible to participate in TVA’s Relocation
Services Program. Payments made to date under the Relocation Services
Program are reported in the “All Other Compensation” column in the Summary
Compensation Table.
TVA
did not provide any other
perquisites to the Named Executive Officers in 2007.
Health
and Other Benefits.
TVA offers a group of health and other benefits
(medical, dental, vision, life and accidental death and disability insurance,
and long-term disability insurance) that are available to a broad group of
employees. The Named Executive Officers are eligible to participate
in TVA’s health benefit plans and other non-retirement benefit plans on the same
terms and at the same contribution rates as other TVA employees.
Summary
Compensation and Grants of
Plan-Based Awards
The
following table sets forth
information regarding compensation earned by each of the Named Executive
Officers in 2007.
Summary
Compensation Table
|
Name
and Principal Position
(a)
|
Year
(b)
|
Salary
($)
(c)
|
Bonus
1
($)
(d)
|
Stock
Awards
($)
(e)
|
Option
Awards
($)
(f)
|
Non-Equity
Incentive Plan Compensation
($)
(g)
|
Change
in Pension Value and Nonqualified Deferred Compensation
Earnings
2
($)
(h)
|
All
Other Compensation
($)
(i)
|
Total
($)
(j)
|
|
Tom
D. Kilgore
President
and
Chief
Executive Officer
|
2007
2006
|
$308,693
$140,000
|
$341,293
$511,984
|
–
–
|
–
–
|
$890,507
3
$627,861
6
|
$138,274
4
$98,172
7
|
$309,900
5
$306,300
|
$1,988,667
$1,684,317
|
|
Kimberly
S. Greene
Chief
Financial Officer and
Executive
Vice President,
Financial
Services
|
2007
2006
|
$38,462
–
|
–
–
|
–
–
|
–
–
|
$36,159
8
–
|
$242,752
9
–
|
$370,900
10
–
|
$688,273
–
|
|
John
M. Hoskins
Interim
Chief Financial Officer and
Executive
Vice President,
Financial
Services
|
2007
2006
|
$178,888
–
|
$72,608
–
|
–
–
|
–
–
|
$169,158
11
–
|
$75,616
12
–
|
$62,619
13
–
|
$558,889
–
|
|
Michael
E. Rescoe
Chief
Financial Officer and
Executive
Vice President,
Financial
Services
|
2007
2006
|
$26,250
$140,000
|
$23,935
$286,109
|
–
–
|
–
–
|
–
14
$295,096
17
|
–
15
–
15
|
$1,646,875
16
$6,300
|
$1,697,060
$727,505
|
|
William
R. McCollum, Jr.
Chief
Operating Officer
|
2007
2006
|
$293,461
–
|
–
–
|
–
–
|
–
–
|
$1,042,132
18
–
|
$1,430,162
19
–
|
$468,727
20
–
|
$3,234,482
–
|
|
Karl
W. Singer
Chief
Nuclear Officer and
Executive
Vice President,
TVA
Nuclear
|
2007
2006
|
$253,000
$140,000
|
$227,528
$341,323
|
–
–
|
–
–
|
$724,000
21
$580,275
24
|
$357,490
22
$365,355
25
|
$221,600
23
$211,250
|
$1,783,618
$1,638,203
|
|
Ashok
S. Bhatnagar
Senior
Vice President,
Nuclear
Generation Development
and
Construction
|
2007
2006
|
$236,608
$140,000
|
$189,384
$276,070
|
–
–
|
–
–
|
$470,668
26
$390,648
29
|
$154,937
27
$160,615
30
|
$165,405
28
$158,655
|
$1,217,002
$1,125,988
|
Notes:
(1) Represents
additional annual compensation paid in quarterly installments through May
31,
2007.
(2) Represents
the aggregate change in pension value under TVA’s qualified defined benefit plan
and TVA’s Supplemental Executive Retirement Plan (“SERP”).
(3) Includes
$427,382 paid out under the EAIP and $463,125 paid out under the
ELTIP.
(4) Includes
increases of $11,088 under TVA’s qualified defined benefit plan and $127,186
under the SERP.
(5) Includes
an unvested annual credit in the amount of $300,000 provided under a LTDCP
agreement with Mr. Kilgore. Mr. Kilgore will become vested in the
$300,000 credit in accordance with the terms of the LTDCP
agreement. See information regarding the details of the LTDCP
agreement under “Long-Term Deferred Compensation Plan Agreements.”
(6) Includes
$334,152 paid out under the EAIP and $293,709 paid out under the
ELTIP.
(7) Includes
increases of $8,882 under TVA’s qualified defined benefit plan and $89,290 under
the SERP. The $98,172 amount represents a correction of the $169,614
amount reported in TVA’s 2006 Annual Report on Form 10-K/A, which included
increases of $8,882 under TVA’s qualified defined benefit plan and $160,732
under the SERP.
(8) Includes
$25,439 paid out under the EAIP and $10,720 paid out under the
ELTIP. Ms. Greene joined TVA on September 1, 2007, and both the EAIP
and ELTIP incentive awards were prorated based on the number of months she
participated in the performance cycles.
(9) Includes
increases of $5,598 under TVA’s qualified defined benefit plan and $237,154
under the SERP.
(10) Includes
a vested credit in the amount of $280,000 provided under a LTDCP agreement
with
Ms. Greene, a relocation incentive in the amount of $90,000, and $900 in
vehicle
allowance payments. Ms. Greene was vested in the $280,000 LTDCP
credit at the time it was made to her account in accordance with the terms
of
the LTDCP agreement. See information regarding the details of the
LTDCP agreement under “Long-Term Deferred Compensation Plan
Agreements.”
(11) Includes
$94,494 paid out under the EAIP and $74,664 paid out under the
ELTIP.
(12) Includes
an increase of $76,893 under TVA’s qualified defined benefit plan and a decrease
of $1,277 under the SERP.
(13) Includes
an unvested annual credit in the amount of $60,000 provided under a LTDCP
agreement with Mr. Hoskins. Mr. Hoskins will become vested in the
$60,000 credit in accordance with the terms of the LTDCP
agreement. See information regarding the details of the LTDCP
agreement under “Long-Term Deferred Compensation Plan Agreements.”
(14) Mr.
Rescoe left TVA effective November 13, 2006, and was not eligible to receive
awards under the EAIP or ELTIP in 2007.
(15) Mr.
Rescoe left TVA effective November 13, 2006, and did not meet the minimum five
years of creditable service required to become vested in TVA’s qualified
retirement plan and the SERP.
(16) Includes
an initial installment in the amount of $823,437.50 provided under the April
2004 agreement with Mr. Rescoe and accrual of an additional installment in
the
amount of $823,437.50 paid in November 2007. See information
regarding the details of the April 2004 agreement under “Other
Agreements.”
(17) Includes
$195,075 paid out under the EAIP and $100,021 paid out under the
ELTIP.
(18) Includes
$460,257 paid out under the EAIP and $581,875 paid out under the
ELTIP.
(19) Includes
increases of $5,385 under TVA’s qualified defined benefit plan and $1,424,777
under the SERP.
(20) Includes
a vested credit in the amount of $350,000 provided under a LTDCP agreement
with
Mr. McCollum, a relocation incentive in the amount of $75,000, $33,169 in
relocation assistance payments which includes $2,390 in tax reimbursements,
and
$4,500 in vehicle allowance payments. Mr. McCollum was vested in the
$350,000 LTDCP credit at the time it was made to his account in accordance
with
the terms of the LTDCP agreement. See information regarding the
details of the LTDCP agreement under “Long-Term Deferred Compensation Plan
Agreements.”
(21) Includes
$336,000 paid out under the EAIP, $288,000 paid out under the ELTIP, and a
credit in the amount of $100,000 made to Mr. Singer’s deferred compensation
account, as provided under a separation agreement with Mr.
Singer. See information regarding the details of the separation
agreement under “Other Agreements.”
(22) Includes
increases of $21,276 under TVA’s qualified defined benefit plan and $336,214
under the SERP.
(23) Includes
an unvested annual credit in the amount of $200,000 provided under a LTDCP
agreement with Mr. Singer and $11,700 in vehicle allowance
payments. Mr. Singer was vested in the $200,000 credit in
accordance with the terms of his separation agreement. See
information regarding the details of the separation agreement under “Other
Agreements.”
(24) Includes
$283,382 paid out under the EAIP, $216,893 paid out under the ELTIP, and a
credit in the amount of $80,000 made to Mr. Singer’s deferred compensation
account provided under a LTDCP agreement with Mr. Singer for achievement of
major milestones in 2006 associated with the Browns Ferry Unit 1 Recovery
Project. See information regarding the details of the LTDCP agreement
under “Browns Ferry Unit 1 Recovery Milestone LTDCP Agreements.”
(25) Includes
increases of $17,905 under TVA’s qualified defined benefit plan and $347,450
under the SERP.
(26) Includes
$199,572 paid out under the EAIP, $227,644 paid out under the ELTIP, and a
credit in the amount of $43,452 made to Mr. Bhatnagar’s deferred compensation
account provided under a LTDCP agreement with Mr. Bhatnagar for achievement
of
major milestones in 2007 associated with the Browns Ferry Unit 1 Recovery
Project. See information regarding the details of the LTDCP agreement
under “Browns Ferry Unit 1 Recovery Milestone LTDCP Agreements.”
(27) Includes
increases of $16,030 under TVA’s qualified defined benefit plan and $138,907
under the SERP.
(28) Includes
an unvested annual credit in the amount of $150,000 provided under a LTDCP
agreement with Mr. Bhatnagar and $11,700 in vehicle allowance
payments. Mr. Bhatnagar will become vested in the $150,000 credit in
accordance with the terms of the LTDCP agreement. See information
regarding the details of the LTDCP agreement under “Long-Term Deferred
Compensation Plan Agreements.”
(29) Includes
$210,007 paid out under the EAIP, $140,641 paid out under the ELTIP, and a
credit in the amount of $40,000 made to Mr. Bhatnagar’s deferred compensation
account provided under a LTDCP agreement with Mr. Bhatnagar for achievement
of
major milestones in 2006 associated with the Browns Ferry Unit 1 Recovery
Project. See information regarding the details of the LTDCP agreement
under “Browns Ferry Unit 1 Recovery Milestone LTDCP Agreements.”
(30) Includes
increases of $12,945 under TVA’s qualified defined benefit plan and $147,670
under the SERP.
The
following table provides
information regarding non-equity incentive plan awards and the possible range
of
payouts associated with incentives the Named Executive Officers were eligible
to
receive for performance in the performance cycles ending in 2007.
Grants
of Plan-Based Awards Table
|
Name
(a)
|
Grant
Date
(b)
|
Estimated
Possible Payouts Under Non-Equity Incentive Plan
Awards
|
Estimated
Future Payouts Under Equity Incentive Plan Awards
|
All
Other Stock Awards: Number of Shares of Stock or
Units
(#)
(i)
|
All
Other Option Awards:
Number
of Securities Underlying Options
(#)
(j)
|
Exercise
or Base Price of Option Awards
($/Sh)
(k)
|
Grant
Date Fair Value of Stock and Option Awards
($)
(l)
|
|||||
|
Threshold
($)
(c)
|
Target
($)
(d)
|
Maximum
($)
(e)
|
Threshold
($)
(f)
|
Target
($)
(g)
|
Maximum
($)
(h)
|
|||||||
|
Tom
D. Kilgore
|
EAIP
1
ELTIP2
|
$341,250
$292,500
|
$455,000
$390,000
|
$568,750
$487,500
|
|
|
|
|
|
|
|
|
|
Kimberly
S. Greene 3
|
EAIP
1
ELTIP
2
|
$20,313
$6,771
|
$27,083
$9,028
|
$33,854
$11,285
|
|
|
|
|
|
|
|
|
|
John
M. Hoskins
|
EAIP
1
ELTIP
2
|
$75,450
$47,156
|
$100,600
$62,875
|
$125,750
$78,594
|
|
|
|
|
|
|
|
|
|
Michael
E. Rescoe 4
|
EAIP
1
ELTIP
2
|
|
|
|
|
|
|
|
|
|
|
|
|
William
R. McCollum, Jr.
|
EAIP
1
ELTIP
2
|
$367,500
$367,500
|
$490,000
$490,000
|
$612,500
$612,500
|
|
|
|
|
|
|
|
|
|
Karl
W. Singer
|
EAIP
1
ELTIP
2
BFNU1-LTDCP
5
|
$252,000
$216,000
|
$336,000
$288,000
$100,000
6
|
$420,000
$360,000
|
|
|
|
|
|
|
|
|
|
Ashok
S. Bhatnagar
|
EAIP
1
ELTIP
2
BFNU1-LTDCP
5
|
$191,700
$143,775
|
$255,600
$191,700
$50,000
7
|
$319,500
$239,625
|
|
|
|
|
|
|
|
|
Notes
(1) Actual
awards earned for performance in 2007 are reported for each of the Named
Executive Officers under “Non-Equity Incentive Plan Compensation” in the Summary
Compensation Table.
(2) Actual
awards earned for the performance cycle ended on September 30, 2007, are
reported for each of the Named Executive Officers under “Non-Equity Incentive
Plan Compensation” in the Summary Compensation Table.
(3) Ms.
Greene joined TVA on September 1, 2007, and the awards she earned in 2007
were
to be prorated based on the number of months she participated in each
performance cycle. The amounts presented represent the possible
prorated awards she was eligible to receive for the performance cycles ending
on
September 30, 2007.
(4) Mr.
Rescoe left TVA on November 13, 2006, and was not eligible to receive a payout
under either the EAIP or ELTIP in 2007.
(5) In
accordance with the agreements administered under TVA’s LTDCP, Mr. Singer and
Mr. Bhatnagar were eligible to receive these credits based on the achievement
of
major milestones in association with the Browns Ferry Unit 1 Recovery
Project. The actual credits earned and vested are reported under
“Non-Equity Incentive Plan Compensation” in the Summary Compensation
Table.
(6) In
accordance with the terms set forth in his separation agreement, Mr. Singer
was
entitled to receive the full payout of $100,000 for 2007 without regard to
the
achievement of the milestone. See information regarding the details
of the separation agreement under “Other Agreements.”
(7) For
2007, payout was based on the date of successful restart of Browns Ferry
Unit 1
with a $50,000 payout for restart by May 22, 2007, a $37,500 payout for restart
by June 15, 2007, and no payout for restart after June 15, 2007, with amounts
for dates in between determined by straight-line interpolation.
Executive
Annual Incentive Plan
Awards. All of the Named Executive Officers
were participants in the Executive Annual Incentive Plan (“EAIP”) in
2007. As discussed in the Compensation Discussion and Analysis, the
EAIP is designed to encourage and reward executives for their contributions
to
successfully achieving short-term financial and operational goals of TVA and
applicable business units. Incentive opportunities approved by the
TVA Board for Mr. Kilgore, Mr. Rescoe, and Mr. McCollum, and by Mr. Kilgore
for Ms. Greene, Mr. Hoskins, Mr. Singer, and Mr. Bhatnagar, under the EAIP
for
the performance cycle ended on September 30, 2007, are set forth in the
table below.
Executive
Annual Incentive Plan
|
Name
|
EAIP
Incentive
Opportunity 1
|
|
|
Tom
D. Kilgore
|
70%
|
|
|
Kimberly
S. Greene
|
65%
|
|
|
John
M. Hoskins
|
40%
|
|
|
Michael
E. Rescoe
|
–
2
|
|
|
William
R. McCollum, Jr.
|
70%
|
|
|
Karl
W. Singer
|
70%
|
|
|
Ashok
S. Bhatnagar
|
60%
|
|
Note
(1) Represents a percentage of each
participant’s base compensation.
(2) Mr. Rescoe left TVA in
November 2006 and was not eligible to receive an award in 2007.
The
percent of opportunity achieved was
determined by a weighted average of the results of a combination of performance
measures at the TVA level and business unit level. For 2007, the
performance measures at the TVA level were approved by the TVA Board and set
forth in TVA’s Winning Performance Balanced Scorecard. The
performance measures for TVA’s business units were approved by Mr.
Kilgore. Based on the performance of TVA and TVA’s business units
during 2007, the percentages of opportunity achieved for the Named Executive
Officers were 93.93 percent for Mr. Kilgore, 93.93 percent for Ms. Greene,
93.93
percent for Mr. Hoskins, 93.93 percent for Mr. McCollum, and 78.08 percent
for
Mr. Bhatnagar. The percentages of opportunity achieved were
calculated based on a 30 percent weight to TVA’s Winning Performance Balanced
Scorecard and a 70 percent weight to either the average composite performance
of
the business unit (Mr. Bhatnagar) or the composite average of all TVA business
units (Mr. Kilgore, Ms. Greene, Mr. Hoskins, and Mr. McCollum). Mr.
Singer’s percentage of opportunity achieved was 100 percent and was determined
pursuant to his separation agreement discussed in “Other
Agreements.” Absent this separation agreement, Mr. Singer’s percent
of opportunity achieved would have been 78.08 percent.
As
discussed in the Compensation
Discussion and Analysis, awards earned under the EAIP for 2007 were calculated
as the product of base compensation times the annual incentive opportunity
times
the percent of opportunity achieved for each Named Executive
Officer. Based on this calculation, the EAIP payouts as a percentage
of base compensation for the Named Executive Officers were 65.75 percent for
Mr.
Kilgore, 61.05 percent for Ms. Greene, 37.57 percent for Mr. Hoskins, 65.75
percent for Mr. McCollum, 70 percent for Mr. Singer, and 46.85 percent for
Mr.
Bhatnagar. Absent his separation agreement, Mr. Singer’s EAIP payout
as a percentage of base compensation would have been 54.66
percent. All awards were paid in cash during the first quarter of
2008 with a deferral option. Mr. Kilgore elected to defer 75 percent, Mr.
Hoskins elected to defer 50 percent, and Mr. McCollum elected to defer 75
percent, of their respective EAIP awards earned for 2007.
Executive
Long-Term Incentive Plan
Awards. All of the Named Executive Officers were participants in
the Executive Long-Term Incentive Plan (“ELTIP”) in 2007. As
discussed in the Compensation Discussion and Analysis, the ELTIP is designed
to
encourage and reward executives for their contributions to successfully
achieving long-term financial and operational goals, typically over a three-year
performance cycle. Even though the ELTIP is based on three-year
performance cycles, the cycles run concurrently to provide participating
executives potential ELTIP awards on an annual basis. As a result,
the ELTIP has administratively functioned in a manner similar to an annual
incentive plan with targets set and awards made with respect to a one-year
period.
Incentive
opportunities approved by the TVA Board for Mr. Kilgore, Mr. Rescoe, and
Mr. McCollum, and by Mr. Kilgore for Ms. Greene, Mr. Hoskins, Mr. Singer, and
Mr. Bhatnagar, under the ELTIP for the performance cycle ended on
September 30, 2007, are set forth in the table below:
Executive
Long-Term Incentive Plan
|
Name
|
ELTIP
Incentive
Opportunity 1
|
|
|
Tom
D. Kilgore
|
60%
|
|
|
Kimberly
S. Greene
|
65%
|
|
|
John
M. Hoskins
|
25%
|
|
|
Michael
E. Rescoe
|
–
2
|
|
|
William
R. McCollum, Jr.
|
70%
|
|
|
Karl
W. Singer
|
60%
|
|
|
Ashok
S. Bhatnagar
|
45%
|
|
Note
(1)
Represents a percentage of each participant’s base
compensation.
(2) Mr. Rescoe left TVA in November 2006 and was not eligible to
receive an award in 2007.
As
discussed in the Compensation
Discussion and Analysis, the calculation of the ELTIP awards for the performance
period ended on September 30, 2007, was based solely on the performance of
a
financial measure, namely, the delivered cost of power. The following
goals were established related to the delivered cost of power: threshold ($32.61
per MWh sold), target ($32.41 per MWh sold), and maximum ($32.21 per MWh
sold). The threshold, target, and maximum awards were equal to 75
percent, 100 percent, and 125 percent of the participant’s ELTIP incentive
opportunity. In 2007, TVA achieved a delivered cost of power of
$32.26 per MWh sold, which equaled 118.75 percent of the target
goal. As a result, the percent of opportunity achieved for the Named
Executive Officers, with the exception of Mr. Rescoe and Mr. Singer, was 118.75
percent. The percent of opportunity achieved for Mr. Singer was 100
percent pursuant to his separation agreement discussed in “Other
Agreements.”
Awards
earned under the ELTIP for the
performance period ended on September 30, 2007, were calculated as the product
of base compensation times the ELTIP incentive opportunity times the percent
of
opportunity achieved for each Named Executive Officer. Based on this
calculation, the ELTIP payouts as a percentage of base compensation for the
Named Executive Officers were 71.25 percent for Mr. Kilgore, 77.19 percent
for
Ms. Greene, 29.69 percent for Mr. Hoskins, 83.13 percent for Mr. McCollum,
60
percent for Mr. Singer, and 53.44 percent for Mr. Bhatnagar. Absent
his separation agreement, Mr. Singer’s ELTIP payout as a percentage of base
compensation would have been 71.25 percent. All awards were paid in
cash during the first quarter of 2008 with a deferral option. Mr.
Kilgore elected to defer 100 percent, Mr. Hoskins elected to defer 50 percent,
and Mr. McCollum elected to defer 75 percent, of their respective ELTIP awards
earned for the performance cycle ended on September 30, 2007.
Long-Term
Deferred Compensation
Plan Agreements. Agreements administered
under TVA’s Long-Term Deferred Compensation Plan (“LTDCP”) are designed to
provide retention incentives to executives to encourage them to remain with
TVA
and to provide, in combination with base compensation and EAIP and ELTIP
incentive awards, a competitive level of total compensation. LTDCP
agreements act as substitutes for restricted stock awards, which investor-owned
utilities in TVA’s peer group can offer to their executives, but which TVA
cannot offer. Under the LTDCP agreements, credits (which may be
vested or unvested) are made to an account in an executive’s name (typically on
an annual basis) for a predetermined period. If the executive remains
employed at TVA until the end of the vesting period (typically three to five
years), the executive becomes vested in the balance of the account, including
any return on investment on the credits in the account, and receives a
distribution in accordance with an earlier deferral election.
In
March 2005, TVA entered into a LTDCP
agreement with Mr. Kilgore. Under the terms of the agreement,
Mr. Kilgore received deferred compensation credits of $300,000 on March 31,
2005, October 1, 2005, October 1, 2006, and October 1, 2007, and will receive
another credit of $300,000 if he remains employed by TVA on October 1,
2008. Pursuant to the agreement, Mr. Kilgore was vested in the first
credit of $300,000 at the time the credit was made in March 2005 and will be
vested in any earnings on this amount. Mr. Kilgore will vest in the
remaining balance of his account only if he remains employed by TVA until the
expiration of the agreement on September 30, 2009, after which the
account will be distributed to him in a lump sum following the termination
of
his employment with TVA. In the event TVA terminates Mr. Kilgore’s
employment during the term of the LTDCP agreement through no act or delinquency
of his own, any credits and earnings on those credits in Mr. Kilgore’s account
at the time of termination will become vested and distributed to him in a lump
sum. If Mr. Kilgore voluntarily terminates his employment or TVA
terminates Mr. Kilgore’s employment for cause prior to the expiration of the
agreement, all credits in Mr. Kilgore’s account, except the initial $300,000
credit and any earnings on this amount, will be forfeited.
In
September 2007, TVA entered into a
LTDCP agreement with Ms. Greene. Under the terms of the
agreement, Ms. Greene received an initial credit of $280,000 on September 4,
2007. Ms. Greene will also receive deferred compensation credits in
the amount of $100,000 each on October 1, 2008, October 1, 2009, and October
1,
2010, if she remains employed by TVA on these dates. Pursuant to the
agreement, Ms. Greene was vested in the first credit of $280,000 at the time
the
credit was made and will be vested in any earnings on this
amount. Ms. Greene will vest in the remaining balance of her account
only if she remains employed by TVA until the expiration of the agreement on
September 30, 2011. All vested credits in her account under
this LTDCP agreement will be distributed to her in five annual installments
following the termination of her employment with TVA. In the event
TVA terminates Ms. Greene’s employment during the term of the LTDCP agreement
through no act or delinquency of her own, any credits and earnings on those
credits in Ms. Greene’s account at the time of termination will become vested
and distributed to her in five annual installments. If Ms. Greene
voluntarily terminates her employment or TVA terminates Ms. Greene’s employment
for cause prior to the expiration of the agreement, all credits in Ms. Greene’s
account, except the initial $280,000 credit and any earnings on this amount,
will be forfeited.
In
October 2006, TVA entered into a
LTDCP agreement with Mr. Hoskins. Under the terms of the
agreement, Mr. Hoskins received deferred compensation credits of $60,000 on
October 1, 2006, and October 1, 2007, and will receive another credit of $60,000
if he remains employed by TVA on October 1, 2008. Mr. Hoskins will
vest in his account only if he remains employed by TVA until the expiration
of
the agreement on September 30, 2009, after which the account will be
distributed to him in a lump sum. In the event TVA terminates Mr.
Hoskins’ employment during the term of the LTDCP agreement through no act or
delinquency of his own, any credits and earnings on those credits in Mr.
Hoskins’ account at the time of termination will become vested and distributed
to him in a lump sum. If Mr. Hoskins voluntarily terminates his
employment or TVA terminates Mr. Hoskins’ employment for cause prior to the
expiration of the agreement, all credits in Mr. Hoskins’ account will be
forfeited.
In
May
2007, TVA entered into a LTDCP agreement with
Mr. McCollum. Under the terms of the agreement, Mr. McCollum
received an initial credit of $350,000 on May 1, 2007, and received a credit
of
$200,000 on October 1, 2007. Mr. McCollum will also receive deferred
compensation credits in the amount of $200,000 each on October 1, 2008, October
1, 2009, and October 1, 2010, if he remains employed by TVA on these
dates. Pursuant to the agreement, Mr. McCollum was vested in the
first credit of $350,000 at the time the credit was made and will be vested
in
any earnings on this amount. Mr. McCollum will vest in the remaining
balance of his account only if he remains employed by TVA until the expiration
of the agreement on September 30, 2011. All vested credits
in his account under this LTDCP agreement will be distributed to him in five
annual installments following the termination of his employment with
TVA. In the event TVA terminates Mr. McCollum’s employment during the
term of the LTDCP agreement through no act or delinquency of his own, any
credits and earnings on those credits in Mr. McCollum’s account at the time of
termination will become vested and distributed to him in five annual
installments. If Mr. McCollum voluntarily terminates his employment
or TVA terminates Mr. McCollum’s employment for cause prior to the expiration of
the agreement, all credits in Mr. McCollum’s account, except the initial
$350,000 credit and any earnings on this amount, will be forfeited.
In
May
2004, TVA entered into a LTDCP agreement with Mr. Singer. Under the
terms of the agreement, Mr. Singer received credits of $200,000 on October
1,
2004, October 1, 2005, and October 1, 2006. Under the
terms of the separation agreement with Mr. Singer described in “Other
Agreements,” Mr. Singer was vested in his account as of September 30, 2007, the
effective date of his resignation, and the amount in this account was
distributed to Mr. Singer in a lump sum, in accordance with his previous
election, on October 26, 2007.
In
September 2004, TVA entered into a
LTDCP agreement with Mr. Bhatnagar. Under the terms of the agreement,
Mr. Bhatnagar received deferred compensation credits of $150,000 on October
1,
2004, October 1, 2005, October 1, 2006, and October 1, 2007, and will receive
another credit of $150,000 if he remains employed by TVA on October 1,
2008. Mr. Bhatnagar will vest in his account only if he remains
employed by TVA until the expiration of the agreement on
September 30, 2009, after which the account will be distributed to him
in a lump sum. In the event TVA terminates Mr. Bhatnagar’s employment
during the term of the LTDCP agreement through no act or delinquency of his
own,
any credits and earnings on those credits in Mr. Bhatnagar’s account at the time
of termination will become vested and distributed to him in a lump
sum. If Mr. Bhatnagar voluntarily terminates his employment or TVA
terminates Mr. Bhatnagar’s employment for cause prior to the expiration of the
agreement, all credits in Mr. Bhatnagar’s account will be
forfeited.
Browns
Ferry Unit 1 Recovery
Milestone LTDCP Agreements. In addition to the LTDCP agreement
with Mr. Singer described above, TVA had a second LTDCP agreement with Mr.
Singer that provided annual credits of up to $100,000 for a period of four
years
based on the accomplishment of major milestones associated with the Browns
Ferry
Unit 1 Recovery Project. The actual amount credited each year was
based on the achievement of specific milestones established at the beginning
of
each fiscal year. Under this agreement, credits earned were vested
and credited to a
deferred
compensation account in Mr. Singer’s name at the end of each fiscal
year. For 2007, the milestone objective established for Mr. Singer’s
agreement was the successful restart date of Browns Ferry Unit 1 with a 100
percent payout for restart by May 22, 2007, 75 percent payout for restart by
June 15, 2007, and no payout for restart after June 15, 2007. The
payout percentage for a completion date between May 22, 2007, and June 15,
2007,
was determined by straight-line interpolation. For purposes of the
agreement, Browns Ferry Unit 1 was considered successfully restarted on June
2,
2007. However, under the terms of the separation agreement with Mr.
Singer described in “Other Agreements,” TVA agreed to award Mr. Singer the full
credit of $100,000 which, under the terms of the LTDCP agreement, was
distributed to him in a lump sum following his termination of
employment.
In
addition to the LTDCP agreement with
Mr. Bhatnagar described above, TVA has entered into a second LTDCP agreement
with Mr. Bhatnagar that provides annual credits of up to $50,000 for a period
of
four years based on the accomplishment of major milestones associated with
the
Browns Ferry Unit 1 Recovery Project. The actual amount credited each
year is based on the achievement of specific milestones established at the
beginning of each fiscal year. Under this agreement, credits earned
will be vested and credited to a deferred compensation account in Mr.
Bhatnagar’s name at the end of each fiscal year. For 2007, the
milestone objective established for Mr. Bhatnagar’s agreement was the successful
restart date of Browns Ferry Unit 1 with a 100 percent payout for restart by
May
22, 2007, 75 percent payout for restart by June 15, 2007, and no payout for
restart after June 15, 2007. The payout percentage for a successful
restart date between May 22, 2007, and June 15, 2007, was determined by
straight-line interpolation. For purposes of the agreement, Browns
Ferry Unit 1 was considered successfully restarted on June 2,
2007. As a result, Mr. Bhatnagar was awarded a credit of $43,452 for
2007, which, under the terms of the agreement, has been placed in a deferred
compensation account in his name to be distributed in a lump sum upon
termination of employment.
Retirement
and Pension
Plans
The
following table provides the
actuarial present value of the Named Executive Officer’s accumulated benefits,
including the number of years of credited service, under TVA’s retirement and
pension plans as of September 30, 2007, determined using a methodology and
interest rate and mortality rate assumptions that are consistent with those
used
in the financial statements contained in this Annual Report as set forth in
Note
13.
Pension
Benefits Table
|
Name
(a)
|
Plan
Name
(b)
|
Number
of Years of Credited Service 1
(#)
(c)
|
Present
Value of Accumulated Benefit
($)
(d)
|
Payments
During Last Fiscal Year
($)
(e)
|
||
|
Tom
D. Kilgore
|
(1)
Qualified Plan – CBBS
(2)
Non-Qualified – SERP Tier 1
|
2.58
8.00
2
|
$24,577
$1,584,884
|
$0
$0
|
||
|
Kimberly
S. Greene
|
(1)
Qualified Plan – CBBS
(2)
Non-Qualified – SERP Tier 1
|
0.08
15.08
3
|
$5,598
$237,154
|
$0
$0
|
||
|
John
M. Hoskins
|
(1)
Qualified Plan – OBS
(2)
Non-Qualified – SERP Tier 2
|
32.72
29.67
|
$930,841
$421,806
|
$0
$0
|
||
|
Michael
E. Rescoe
|
(1)
Qualified Plan – CBBS
(2)
Non-Qualified – SERP Tier 1
|
3.33
3.33
|
$0
4
$0
4
|
$0
$0
|
||
|
William
R. McCollum, Jr.
|
(1)
Qualified Plan – CBBS
(2)
Non-Qualified – SERP Tier 1
|
0.42
10.42
5
|
$5,385
$1,424,777
|
$0
$0
|
||
|
Karl
W. Singer
|
(1)
Qualified Plan – CBBS
(2)
Non-Qualified – SERP Tier 1
|
14.50
16.50
6
|
$190,614
$1,570,874
|
$0
$0
|
||
|
Ashok
S. Bhatnagar
|
(1)
Qualified Plan – CBBS
(2)
Non-Qualified – SERP Tier 1
|
8.08
8.08
|
$98,277
$554,988
|
$0
$0
|
||
Notes:
(1) Limited
to 24 years when determining supplemental benefits available under SERP Tier
1.
(2) Mr.
Kilgore has been granted three additional years of credited service for pre-TVA
employment following five years of actual TVA service. In the event
his employment is terminated during the first five years (other than for
cause),
the five-year vesting requirement will be waived and he will receive credit
for
eight years of service. In addition, the offset for prior employer
pension benefits will be waived, and the offset for benefits provided under
TVA’s defined benefit plan will be calculated based on the actual pension
benefit he will receive as a participant in the CBBS. Without the
additional years of credited service, the present value of Mr. Kilgore’s
accumulated benefit would be $0.
(3) Ms.
Greene has been granted 15 additional years of credited service for pre-TVA
employment and the offset for prior employment pension benefits has been
waived. The offset for benefits provided under TVA’s defined benefit
plan will be calculated based on the benefit she will be eligible to receive
as
a participant in the CBBS taking into account the additional years of credited
service being used for SERP benefit calculation purposes. In the
event that she voluntarily terminates her employment with TVA, or is terminated
for cause, prior to satisfying the minimum five-year vesting requirement,
no
benefits will be provided to her under the SERP. In the event of
termination for any other reason, prior to five years of employment, the
five-year vesting requirement will be waived and the benefit Ms. Greene will
be
eligible to receive will be payable no earlier than age 55. As of
September 30, 2007, the present value of this benefit is
$237,154. Without the additional years of credited service, the
present value of Ms. Greene’s accumulated benefit would be $0.
(4) Mr.
Rescoe left TVA in November 2006 and did not have the minimum five years
of
vesting service required to become vested and receive a retirement benefit
under
TVA’s defined benefit plan or the SERP.
(5) Mr.
McCollum has been granted 10 additional years of credited service for pre-TVA
employment and the offset for prior employment benefits has been
waived. The additional years of credited service will be used for
SERP benefit calculation purposes only and will not count toward the minimum
five-year vesting requirement. In the event Mr. McCollum voluntarily
terminates his employment with TVA or is terminated for cause prior to
satisfying the minimum five-year vesting requirement, no benefits will be
provided under the SERP. In the event of termination for any other
reason, prior to five years of employment, the five-year vesting requirement
will be waived as long as the termination is considered acceptable to TVA,
and
Mr. McCollum would be eligible to receive benefits payable in five annual
installments following termination. The present value of this benefit
as of September 30, 2007, is $1,424,777. Without the additional years
of credited service, the present value of Mr. McCollum’s accumulated benefit
would be $0.
(6) TVA
granted Mr. Singer one additional year of service for each year of TVA service
on each of August 17, 2006, and August 17, 2007. Therefore, as of
September 30, 2007, Mr. Singer has been granted two years of additional service
for purposes of the calculation of his benefits under the
SERP. Without the additional two years of credited service, the
present value of Mr. Singer’s accumulated benefit would have been
$1,368,549.
TVA
sponsors a qualified defined
benefit plan with two structures for all employees, including the Named
Executive Officers, which is administered by the TVA Retirement
System. The structures are the OBS and the
CBBS. Participation in the OBS is limited to employees who were
covered under the plan prior to January 1, 1996. All employees first
hired by TVA on or after January 1, 1996, participate in the CBBS. As
with any other qualified retirement plan, there are limits on employee and
employer contributions and compensation that can be counted for benefit
calculations set by the TVA Retirement System rules and IRS
regulations.
TVA’s
Original Benefit Structure.
Mr. Hoskins is the only Named Executive
Officer who participates in the OBS. The pension provided under the
OBS is based on a final average pay formula that includes the member’s years of
creditable service (to the nearest month), highest average compensation during
any three consecutive years of creditable service, and a pension factor, less
a
small Social Security offset. For executives who are members of the
OBS, compensation is defined as annual salary only for benefit calculation
purposes and, for the Named Executive Officers, is shown under the column titled
“Salary” in the Summary Compensation Table, although compensation cannot exceed
$220,000 in 2007 pursuant to the IRS annual compensation limit applicable to
qualified plans. Creditable service is the length of time spent as a
member of the TVA Retirement System and may also include certain military
service, some periods of leave without pay, forfeited annual leave, and unused
sick leave. The pension factor, which can reach a maximum of
1.3 percent, is determined by a member’s age and/or whether the member has
obtained the Rule of 80. The Rule of 80 is the sum of a member’s age
and creditable service at the time of termination. For example, a
member who has reached age 55 and has 25 years of creditable service has
obtained the Rule of 80. Mr. Hoskins has obtained the Rule of
80. The Social Security offset is equal to the product of a member’s
actual years of service times $1.75 times a factor based on the member’s actual
age at retirement. Members must have at least five years of
creditable service in order to be eligible for a pension benefit.
Members
in the OBS who are 55 with five years of creditable service are eligible to
receive an immediate benefit upon retirement. Members whose age plus
service, including unused sick leave and forfeited annual leave, equals 80
points or more receive the maximum pension factor of 1.3
percent. Members who reach age 60 with at least five years of
credited service receive the maximum pension factor of 1.3 percent even if
they
do not have 80 points. The OBS does not provide early retirement
benefits to any Named Executive Officer or any other member in the
OBS.
TVA’s
Cash Balance Benefit
Structure. Mr. Kilgore, Ms. Greene, Mr. McCollum, Mr. Singer,
and Mr. Bhatnagar are members of the CBBS, and Mr. Rescoe was a member of the
CBBS. Under the CBBS, each member has a cash balance account that
receives pay credits equal to six percent of his/her compensation each pay
period (every two weeks). For executives who are members of the CBBS,
compensation is defined as annual base salary only for benefit calculation
purposes and, for the Named Executive Officers, is shown under the column titled
“Salary” in the Summary Compensation Table, although compensation cannot exceed
$220,000 in 2007 pursuant to the IRS annual compensation limit applicable to
qualified plans. The account is credited with interest each month,
and interest is compounded on an annual basis. The annual interest
rate used for interest credits is determined each January 1. The
interest rate is 3 percent greater than the percentage increase in the 12-month
average of the Consumer Price Index for the period ending on the previous
October 31. The minimum interest rate is 6 percent and the
maximum interest rate is 10 percent unless the TVA Retirement System Board,
with
TVA’s approval, selects a higher interest rate. When a member elects
to begin receiving retirement benefits, the cash balance account is converted
to
a monthly pension payment by dividing the ending value of the cash balance
account by a conversion factor set forth in the plan based on the member’s
actual age in years and months.
Members
with at least five years of
CBBS service are eligible to receive an immediate benefit. CBBS
service is the length of time spent as a member of the TVA Retirement System
and
does not include credit for unused sick leave, forfeited annual leave, or
pre-TVA employment military service. The CBBS does not provide early
retirement benefits to any Named Executive Officer or any other member in the
CBBS.
Supplemental
Executive Retirement
Plan. The SERP is a non-qualified defined benefit pension plan similar to
those typically found in other companies in TVA’s peer group and is provided to
a limited number of executives, including the Named Executive
Officers. TVA’s SERP was created to recruit and retain key
executives. The plan is designed to provide a competitive level of
retirement benefits in excess of the limitations on contributions and benefits
imposed by TVA’s qualified defined benefit plan and IRS code section 415 limits
on qualified retirement plans.
The
SERP
provides two distinct levels of participation, Tier 1 and Tier
2. Each employee is assigned to one of the two tiers at the time he
or she is approved to participate in the SERP. The level of
participation (“Tier”) defines the level of retirement benefits provided under
the SERP at the time of retirement.
Under
the SERP, normal retirement
eligibility is age 62 with five years of vesting service. No vested
and accrued benefits are payable prior to age 55, and benefits are reduced
for
retirements prior to age 62. The level of reduction in benefits for
retirements prior to age 62 depends on whether a participant’s termination is
“approved” or “unapproved.” In the event of an approved termination
of TVA employment, any vested and accrued benefits are reduced by 5/12 percent
for each month that the date of benefit commencement precedes the participant’s
62nd birthday up to a maximum reduction of 35 percent. In the event
of an unapproved termination of TVA employment, the participant’s accrued
benefits are first subject to a reduced percentage of vesting if the
participant’s years of service are between five and ten. At five
years of vesting service, the vested percentage of retirement benefits is 50
percent and increases thereafter by 10 percent for each full additional year
of
service, reaching 100 percent vesting for ten or more years of vesting
service. Thereafter, any vested and accrued benefits are reduced by
10/12 percent for each month that the date of benefit commencement precedes
the
participant’s 62nd birthday up to a maximum reduction of 70
percent.
For
purposes of the SERP, an “approved”
termination means termination of employment with TVA due to (i) retirement
on or
after the participant’s 62nd birthday, (ii) retirement on or after attainment of
actual age 55, if such retirement has the approval of the TVA Board, (iii)
death
in service as an employee, (iv) disability (as such term is defined under TVA’s
long-term disability plan), or (iv) any other circumstances approved by the
TVA
Board. For purposes of the SERP, an “unapproved” termination means a
termination of employment with TVA when such termination does not constitute
an
“approved” termination as defined in the preceding sentence.
SERP
Tier 1. The Tier 1 structure is designed to replace 60
percent of the amount of a participant’s compensation at the time the
participant reaches age 62 and has accrued 24 years of service at
TVA.
Tier
1 benefits are based on a
participant’s highest average compensation during three consecutive SERP years
and a pension multiple of 2.5 percent for each year of credited service up
to a
maximum of 24 years. Compensation is defined as salary, additional
annual compensation, and EAIP for benefit calculation purposes. Tier
1 benefits are offset by Social Security benefits, benefits provided under
TVA’s
defined benefit plan, and prior employer pension benefits when
applicable. Mr. Kilgore, Ms. Greene, Mr. McCollum, Mr. Singer, and
Mr. Bhatnagar are participants in SERP Tier 1. Mr. Rescoe was a
participant in SERP Tier 1 prior to his termination in November
2006.
In
2007, for benefit calculation
purposes under the SERP, TVA granted additional years of credited service to
and
waived the prior employer pension benefits offset for Ms. Greene and Mr.
McCollum in connection with their acceptance of employment with
TVA. The value associated with the credited years of service and
waiver of prior employer offset under the SERP is reported in the “Change in
Pension Value and Nonqualified Deferred Compensation Earnings” column in the
Summary Compensation Table. These grants of additional credited
service and waivers of offsets of prior employer pension benefits were arrived
at in negotiations with Ms. Greene and Mr. McCollum during their recruitment
to
TVA. Generally, the purpose for granting additional years of credited
service and waiving the offset for any prior employer pension benefits is to
compensate for any loss of benefits and to give credit for prior and potential
future years of service at a previous employer.
SERP
Tier 2. The
Tier 2 structure provides retirement benefits that recognize compensation in
excess of that provided by TVA’s qualified defined benefit plan and is similar
to restoration retirement benefits provided by investor-owned
utilities.
Tier
2 benefits are based on a
participant’s highest average compensation during three consecutive SERP years
and a pension multiple of 1.3 percent for each year of credited
service. Compensation is defined as salary, additional annual
compensation, and EAIP for benefit calculation purposes. Mr. Hoskins
is the only Named Executive Officer who is a participant in SERP Tier
2.
The
TVA Sponsored 401(k)
Plan. Members of the TVA Retirement System,
including the Named Executive Officers, may elect to participate in the TVA
Retirement System’s 401(k) plan on a before- and/or after-tax
basis. For OBS members, TVA provides a matching contribution of 25
cents on every dollar contributed on a before- and/or after-tax basis up to
1.5
percent of the participant’s annual salary. For CBBS members, TVA
provides a matching contribution of 75 cents on every dollar contributed on
a
before- and/or after-tax basis up to 4.5 percent of the participant’s annual
salary.
Nonqualified
Deferred
Compensation
The
following table provides
information regarding deferred contributions, earnings, and balances for each
of
the Named Executive Officers. The amounts reported under this table
do not represent compensation in addition to the compensation that was earned
in
2007 and already reported in the Summary Compensation Table but rather the
amounts of compensation earned by the Named Executive Officers in 2007 or prior
years that was or has been deferred.
Nonqualified
Deferred Compensation Table
|
Name
(a)
|
Executive
Contributions
in
Last
FY
($)
(b)
|
Registrant
Contributions
in
Last
FY
($)
(c)
|
Aggregate
Earnings
in
Last
FY 1
($)
(d)
|
Aggregate
Withdrawals/
Distributions
($)
(e)
|
Aggregate
Balance
at
Last
FYE 2
($)
(f)
|
|
Tom
D. Kilgore
|
$783,661
3
|
$300,000
4
|
$149,527
|
$0
|
$1,957,547
5
|
|
Kimberly
S. Greene
|
$0
|
$280,000
6
|
$976
|
$0
|
$280,976
|
|
John
M. Hoskins
|
$84,579
7
|
$60,000
8
|
$48,530
|
$340,243
9
|
$1,021,492
10
|
|
Michael
E. Rescoe
|
$0
|
$0
|
$28,913
|
$457,328
11
|
$0
|
|
William
R. McCollum, Jr.
|
$781,599
12
|
$350,000
13
|
$7,187
|
$0
|
$357,187
14
|
|
Karl
W. Singer
|
$0
|
$300,000
15
|
$168,986
|
$0
|
$2,852,164
16
|
|
Ashok
S. Bhatnagar
|
$0
|
$193,452
17
|
$333,811
|
$0
|
$2,385,674
18
|
Notes
(1) Includes
vested and unvested earnings. None of these amounts are included in the Summary
Compensation Table.
(2) Includes
vested and unvested amounts.
(3) Mr.
Kilgore elected to defer 75 percent of the $427,382 paid out under the EAIP
for
2007 and 100 percent of the $463,125 paid out under the ELTIP for the
performance period that ended on September 30, 2007. These amounts
are reported in the “Non-Equity Incentive Plan Compensation” column in the
Summary Compensation Table.
(4) Represents
an unvested annual credit in the amount of $300,000 provided under a LTDCP
agreement with Mr. Kilgore (reported in the “All Other Compensation” column in
the Summary Compensation Table).
(5) Represents
the balance of Mr. Kilgore’s account, including unvested credits and earnings
totaling $643,293, as of September 30, 2007. The amount in the
“Aggregate Balance at Last FYE” column includes $927,861 reported in the Summary
Compensation Table for 2006. The amount reported in the “Executive
Contributions in Last FY” column was credited to his account in the first
quarter of 2008 and is not included in the balance.
(6) Represents
a vested credit in the amount of $280,000 provided under a LTDCP agreement
with
Ms. Greene (reported in the “Non-Equity Incentive Plan Compensation” column in
the Summary Compensation Table).
(7) Mr.
Hoskins elected to defer 50 percent of the $94,494 paid out under the EAIP
for
2007 and 50 percent of the $74,664 paid out under the ELTIP for the performance
period that ended on September 30, 2007. These amounts are reported
in the “Non-Equity Incentive Plan Compensation” column in the Summary
Compensation Table.
(8) Represents
an unvested annual credit in the amount of $60,000 provided under a LTDCP
agreement with Mr. Hoskins (reported in the “All Other Compensation” column in
the Summary Compensation Table).
(9) Represents
a lump sum distribution of the balance of Mr. Hoskins’ LTDCP account, including
interest and/or return on investments, upon expiration of a LTDCP agreement
on
September 30, 2006.
(10) Represents
the balance of Mr. Hoskins’ account, including unvested credits and earnings
totaling $63,088, as of September 30, 2007. The amount reported in
the “Executive Contributions in Last FY” column was credited to his account in
the first quarter of 2008 and is not included in the balance.
(11) Represents
a lump sum distribution of the balance of Mr. Rescoe’s deferred compensation
account, including interest and/or return on investments, at the time of
termination.
(12) Mr.
McCollum elected to defer 75 percent of the $460,257 paid out under the EAIP
for
2007 and 75 percent of the $581,875 paid out under the ELTIP for the performance
period that ended on September 30, 2007. These amounts are reported
in the “Non-Equity Incentive Plan Compensation” column in the Summary
Compensation Table.
(13) Represents
a vested credit in the amount of $350,000 provided under a LTDCP agreement
with
Mr. McCollum (reported in the “Non-Equity Incentive Plan Compensation” column in
the Summary Compensation Table).
(14) Represents
the balance of Mr. McCollum’s account. The amount reported in the
“Executive Contributions in Last FY” column was credited to his account in the
first quarter of 2008 and is not included in the balance.
(15) Represents
(1) an unvested annual credit in the amount of $200,000 provided under a
LTDCP
agreement with Mr. Singer (reported in the “All Other Compensation” column in
the Summary Compensation Table) and (2) a vested credit in the amount of
$100,000 provided under a separation agreement with Mr. Singer based on his
second LTDCP agreement for achievement of major milestones in 2007 associated
with the Browns Ferry Unit 1 Recovery Project (reported in the “Non-Equity
Incentive Plan Compensation” column in the Summary Compensation
Table). Mr. Singer was vested in the $200,000 credit under the LTDCP
agreement in accordance with the terms of his separation agreement.
(16) Represents
the balance of Mr. Singer’s account, including unvested credits and earnings
totaling $648,938, as of September 30, 2007. The amount in the
“Aggregate Balance at Last FYE” column includes $280,000 reported in the Summary
Compensation Table for 2006. The $100,000 credit provided under a
separation agreement with Mr. Singer based on his second LTDCP agreement
for the
achievement of major milestones in 2007 associated with the Browns Ferry
Unit 1
Recovery Project, reported in the "Registrant Contributions in the Last FY"
column, was credited to his account in the first quarter of 2008 and is not
included in the balance.
(17) Represents
(1) an unvested annual credit in the amount of $150,000 provided under a
LTDCP
agreement with Mr. Bhatnagar (reported in the “All Other Compensation” column in
the Summary Compensation Table) and (2) a vested credit in the amount of
$43,452
provided under a second LTDCP agreement with Mr. Bhatnagar for achievement
of
major milestones in 2007 associated with the Browns Ferry Unit 1 Recovery
Project (reported in the “Non-Equity Incentive Plan Compensation” column in the
Summary Compensation Table).
(18) Represents
the balance of Mr. Bhatnagar’s account, including unvested credits and earnings
totaling $519,774, as of September 30, 2007. The amount in the
“Aggregate Balance at Last FYE” column includes $190,000 reported in the Summary
Compensation Table for 2006. The $43,452 credit provided under the
LTDCP agreement with Mr. Bhatnagar for the achievement of major milestones
in
2007 associated with the Browns Ferry Unit 1 Recovery Project, reported in
the
"Registrant Contributions in the Last FY" column, was credited to his
account in the first quarter of 2008 and is not included in the
balance.
In
order to further assist executives,
including the Named Executive Officers, in saving for retirement, TVA allows
participants in the EAIP, ELTIP, and LTDCP to elect to defer all or a portion
of
the compensation earned under those plans. All deferrals are credited
to each participant, and the deferral amounts are then funded into a rabbi
trust. Each participant may elect one or more of several notional
investment options made available by TVA or allow some or all funds to accrue
interest at the rate established at the beginning of each fiscal
year. Participants may elect to change from either one notional
investment option or the TVA interest bearing option to another at any
time. Participants do not have the ability to withdraw funds from
their accounts prior to termination of employment with TVA. Upon
termination, funds are distributed in accordance with elections made in
accordance with applicable IRS regulations.
No
executives, including the Named
Executive Officers, were permitted to defer any portion of their annual salary
or additional annual compensation in 2007. Participants in the EAIP
and ELTIP, including the Named Executive Officers, are permitted to elect
annually to defer all or a portion of their awards (25, 50, 75 or 100 percent)
received under the plans.
In
March 2005, TVA entered into an
agreement with Mr. Kilgore that provides a lump sum payment equal to one year’s
annual compensation if (1) his duties, responsibilities, or compensation is
substantially reduced, and he terminates his employment with TVA, or (2) his
employment is terminated for any reason other than “for cause.” For
purposes of this agreement, “annual compensation” is defined as annual salary
plus additional annual compensation plus the amount of the annual and long-term
incentive awards he would have been eligible to receive based on 100 percent
achievement of target performance goals. As of September 30, 2007,
this lump sum payment would have been equal to $1,495,000. In
addition, if his employment had been terminated on September 30, 2007, other
than for cause or as a result of a voluntary resignation, Mr. Kilgore would
have
received $643,293 under his LTDCP agreement payable in a lump sum following
termination and $1,584,884 under the SERP payable in five annual installments
following termination. Upon termination of employment for any reason,
Mr. Kilgore would be eligible to receive any amount in his 401(k) plan account
that he contributed and any earnings on these amounts, subject to plan rules,
and any amounts that he earned in past years but elected to defer.
In
August
2007, TVA entered into an agreement with Ms. Greene that provides a lump sum
payment in an amount equal to two years’ annual compensation in the event that
TVA’s current Chief Executive Officer no longer occupies that position and Ms.
Greene is asked to leave TVA employment for any reason other than for cause
or
she terminates her employment because she is asked to take a position with
TVA
other than her then current position as Chief Financial Officer and Executive
Vice President, Financial Services. For purposes of this agreement,
“annual compensation” is defined as annual salary plus the amount of the annual
incentive award based on 100 percent achievement of target performance
goals. As of September 30, 2007, this lump sum payment would have
been equal to $1,650,000. In addition, if her employment had been
terminated on September 30, 2007, other than for cause or as a result of a
voluntary resignation, Ms. Greene would have received $280,976 under her LTDCP
agreement payable in five annual installments following termination and would
have been eligible to receive SERP benefits payable in five annual installments
beginning no earlier than age 55. As of September 30, 2007, the
present value of these SERP benefits is $237,154.
Neither
Mr. Hoskins, Mr. McCollum, nor
Mr. Bhatnagar has a severance agreement with TVA. However, had Mr.
Hoskins’ employment been terminated on September 30, 2007, other than for cause
or as a result of a voluntary resignation, Mr. Hoskins would have received
$63,088 under his LTDCP agreement payable in a lump sum following termination
and $421,806 under the SERP payable in five annual installments following
termination. In addition, upon termination of employment for any
reason, Mr. Hoskins would be eligible to receive $930,841 under TVA’s qualified
defined benefit plan payable in the form of an actuarial equivalent lifetime
annuity, any amounts in his 401(k) plan account subject to plan rules, and
any
amounts that he earned in past years but elected to defer. Had Mr.
McCollum’s employment been terminated on September 30, 2007, other than for
cause or as a result of a voluntary resignation, Mr. McCollum would have
received $357,187 under his LTDCP agreement payable in five annual installments
following termination and $1,424,777 under the SERP payable in five annual
installments following termination. In addition, upon termination of
employment for any reason, Mr. McCollum would be eligible to receive any amounts
in his 401(k) plan account that he contributed and any earnings on these
amounts, subject to plan rules. Had Mr. Bhatnagar’s employment been
terminated on September 30, 2007, other than for cause or as a result of a
voluntary resignation, Mr. Bhatnagar would have received $519,774 under his
LTDCP agreement payable in a lump sum following termination, and SERP benefits
payable in five annual installments beginning no earlier than age 55, which
as
of September 30, 2007, had a value of $554,988 assuming the termination was
determined an approved termination under the SERP. In addition, upon
termination of employment for any reason, Mr. Bhatnagar would be eligible to
receive $98,277 under TVA’s qualified defined benefit plan payable in the form
of an actuarial equivalent lifetime annuity, any amounts in his 401(k) plan
account subject to plan rules, and any amounts that he earned in past years
but
elected to defer.
In
April 2004, TVA entered into an
agreement with Mr. Rescoe that provided a lump sum payment in an amount equal
to
two years’ annual compensation in the event that there is a change in his
reporting relationship with the TVA Board such that he would report to a Chief
Executive Officer or other similarly named executive and is asked to leave
TVA
employment or is asked to take a position with TVA other than his then-current
position as Chief Financial Officer and Executive Vice President, Financial
Services, prior to July 10, 2008. For purposes of this agreement,
“annual compensation” was defined as annual salary plus additional annual
compensation plus the amount of the annual and long-term incentive awards he
would have been eligible to receive based on 100 percent achievement of target
performance goals. Under the agreement, Mr. Rescoe was to receive the
lump sum payment in two equal installments: the first installment was to be
paid
within ten days of the effective date he leaves TVA and the second was to be
paid on the one-year anniversary of that date. Mr. Rescoe left TVA
effective November 13, 2006. Pursuant to the agreement, TVA paid Mr.
Rescoe $823,437.50 in November 2006 and $823,437.50 in November
2007.
In
March 2007, TVA entered into a
separation agreement with Mr. Singer, under which Mr. Singer voluntarily
resigned effective as of September 30, 2007. The terms of the
agreement included the following:
|
|
•
|
TVA
agreed to award Mr. Singer EAIP and ELTIP award payouts assuming
achievement of 100 percent of the target goals for the EAIP for 2007
and
the ELTIP for the performance period ended September 30, 2007, without
regard to actual performance;
|
|
|
•
|
Mr.
Singer would receive the full $100,000 credit associated with the
Browns
Ferry Unit 1 Recovery Project for 2007, without regard to the actual
milestone achievement;
|
|
|
•
|
Mr.
Singer would become vested in the balance of his LTDCP account as
of
September 30, 2007, and this amount would be distributed to Mr. Singer
in
a lump sum, in accordance with his previous election, within 30 days
of
the effective date of his
resignation;
|
|
|
•
|
Mr.
Singer’s resignation would be considered an approved termination under the
SERP; and
|
|
|
•
|
Mr.
Singer would be eligible to continue TVA medical insurance available
to
active employees for 12 months after the effective date of his resignation
(October 2007 through September 2008) at the cost an active employee
would
pay for such insurance.
|
Pursuant
to the terms of the separation
agreement set forth above, Mr. Singer became eligible to receive the following
amounts: $336,000 under the EAIP payable in a lump sum following termination,
$288,000 under the ELTIP payable in a lump sum following termination, $100,000
under the LTDCP agreement based on the accomplishment of major milestones
associated with the Browns Ferry Unit 1 Recovery Project payable in a lump
sum
following termination, $648,937 under his LTDCP agreement payable in a lump
sum
following termination, and SERP benefits payable in five
annual
installments beginning no earlier than age 55, which as of September 30, 2007,
had a value of $1,570,874. In addition, upon his termination of
employment, Mr. Singer was eligible to receive $190,614 under TVA’s qualified
defined benefit plan payable in the form of an actuarial equivalent lifetime
annuity, any amounts in his 401(k) plan account subject to plan rules, and
any
amounts that he earned in past years but elected to defer.
On
March 31, 2006, the TVA Board
became a nine-member part-time board in accordance with the provisions of the
Consolidated Appropriations Act, which amended the TVA Act. Under the
TVA Act, as amended by the Consolidated Appropriations Act, each of the nine
directors receives a stipend of $45,000 per year unless (1) the director is
the
chair of a TVA Board committee, in which case the stipend is $46,000 per year,
or (2) the director is the chairman of the TVA Board, in which case the stipend
is $50,000 per year. Effective January 8, 2007, the $45,000 stipend
was increased to $45,800, the same percentage increase applicable to adjustments
under 5 U.S.C. § 5318, which provides for adjustments in the annual rates of pay
of employees on the Executive Schedule of the United States
Government. TVA is seeking amendment of the TVA Act to provide for
the same adjustments to the stipend of directors who are chair of a TVA Board
committee or chairman of the TVA Board. Directors are also reimbursed
under federal law for travel, lodging, and related expenses that they incur
in
attending meetings and for other official TVA business in the same manner as
other persons employed intermittently in federal government
service.
The
annual stipends provided to each
director and to the chairman of the TVA Board as of September 30, 2007, were
as
follows:
|
Name
|
Annual
Stipend
($)
|
|
|
Dennis
C. Bottorff
|
$46,000
|
|
|
Donald
R. DePriest
|
$46,000
|
|
|
Robert
M. Duncan
|
$46,000
|
|
|
Bishop
William H. Graves
|
$45,800
|
|
|
Skila
S. Harris
|
$46,000
|
|
|
William
B. Sansom
|
$50,000
|
|
|
Howard
A. Thrailkill
|
$46,000
|
|
|
Susan
Richardson Williams
|
$46,000
|
|
The
following table set outs the
compensation received by TVA’s directors during 2007.
Director
Compensation
|
Name
(a)
|
Fees
Earned or Paid in Cash
($)
(b)
|
Stock
Awards
($)
(c)
|
Option
Awards
($)
(d)
|
Non-Equity
Incentive
Plan
Compensation
($)
(e)
|
Change
in
Pension
Value
and
Nonqualified
Deferred
Compensation
Earnings
1
($)
(f)
|
All
Other Compensation
($)
(g)
|
Total
($)
(h)
|
|
|
William
W. Baxter 2
|
$13,846
|
|
|
|
|
$250
|
$14,096
|
|
|
Dennis
C. Bottorff
|
$46,176
|
|
|
|
|
$739
|
$46,915
|
|
|
Donald
R. DePriest
|
$46,176
|
|
|
|
|
$2,154
|
$48,330
|
|
|
Robert
M. Duncan
|
$46,176
|
|
|
|
|
$739
|
$46,915
|
|
|
Bishop
William H. Graves 3
|
$44,685
|
|
|
|
|
$356
|
$45,041
|
|
|
Skila
S. Harris
|
$46,176
|
|
|
|
|
$2,597
|
$48,773
|
|
|
William
B. Sansom
|
$50,190
|
|
|
|
|
$804
|
$50,994
|
|
|
Howard
A. Thrailkill
|
$46,176
|
|
|
|
|
$2,225
|
$48,401
|
|
|
Susan
Richardson Williams
|
$46,176
|
|
|
|
|
$2,211
|
$48,387
|
|
Notes
(1) TVA
directors do not participate in the TVA Retirement System, TVA’s Supplemental
Executive Retirement Plan, or any non-qualified deferred compensation plan
available to TVA employees. However, as appointed officers of the
United States government, the directors are members of the Federal Employees
Retirement System (“FERS”). FERS is administered by the federal
Office of Personnel Management (“OPM”), and information regarding the value of
FERS pension benefits is not available to TVA.
(2) Mr.
Baxter resigned as a director as of January 24, 2007.
(3) Bishop
William H. Graves did not become a director until October 10, 2006.
Directors
are eligible to participate
in TVA’s health benefit plans and other non-retirement benefit plans on the
same terms and at the same contribution rates as other TVA
employees. The directors are not eligible to participate in any
incentive programs available to TVA employees. The directors do not
participate in the TVA Retirement System and do not participate in TVA’s
Supplemental Executive Retirement Plan. However, as appointed
officers of the United States government, the directors are members of the
Federal Employees Retirement System (“FERS”). FERS is a tiered
retirement plan that includes three components: (1) Social Security benefits,
(2) the Basic Benefit Plan, and (3) the Thrift Savings Plan. Each
director pays full Social Security taxes and makes a small contribution (0.8
percent of salary or stipend) to the Basic Benefit Plan.
The
FERS Basic Benefit Plan is a
qualified defined benefit plan that provides a retirement benefit based on
a
final average pay formula that includes age, highest average salary during
any
three consecutive years of service, and years of creditable
service. A director must have at least five years of creditable
service in order to be eligible to receive retirement
benefits. Directors are eligible for immediate, unreduced retirement
benefits once (1) they reach age 62 and have five years of creditable service,
(2) they reach age 60 and have 20 years of creditable service, or (3) they
attain the minimum retirement age and accumulate the specified years of
service. Generally, benefits are calculated by multiplying 1.0
percent of the highest average salary during any three consecutive years of
service by the number of years of creditable service. Directors who
retire at age 62 or later with at least 20 years of service receive an enhanced
benefit (a factor of 1.1 percent is used rather than 1.0 percent).
Directors
may also retire with an
immediate benefit under FERS if they reach their minimum retirement age and
have
accumulated at least 10 years of creditable service. For directors
who reach the minimum retirement age and have at least 10 years of creditable
service, the annuity will be reduced by five percent for each year the director
is under age 62.
Each
director is also eligible to
participate in the Thrift Savings Plan. The Thrift Savings Plan is a
tax-deferred retirement savings and investment plan that offers the same type
of
savings and tax benefits offered under 401(k) plans. Once a director
becomes eligible, after a mandatory waiting period, TVA contributes an amount
equal to one percent of the director’s stipend into a Thrift Savings Plan
account for the director. These contributions are made automatically
every two weeks regardless of whether the director makes a contribution of
his
or her own money. Directors are eligible to contribute up to the
Internal Revenue Service (“IRS”) elective deferral limit. Directors
receive a matching contribution according to the following
schedule: 100 percent of each dollar for the first three percent
of the director’s stipend, 50 percent of each dollar for the next two percent of
the director’s stipend, and zero percent for contributions above five percent of
the director’s stipend.
The
Human Resources Committee consists
of the following four directors: Skila S. Harris, Chair, Dennis C. Bottorff,
Howard A. Thrailkill, and Susan Richardson Williams. Under the
Compensation Plan, the Human Resources Committee will review the compensation
of
the CEO and his direct reports, monitor the process for approving compensation
for TVA employees compensated in excess of the federal government’s Executive
Schedule Level IV ($145,400 as of September 30, 2007), monitor TVA executive
compensation programs, and periodically review the compensation and benefits
programs for all TVA employees.
Under
the TVA Act, as amended by the
Consolidated Appropriations Act, the TVA Board has the authority to approve
the
compensation of the CEO and his direct reports as well as the salaries of
employees whose salaries exceed Executive Schedule Level IV. While
the Human Resources Committee can recommend that the TVA Board approve the
compensation of the CEO and his direct reports and the salaries of employees
whose salaries exceed Executive Schedule Level IV, the Human Resources Committee
has no approval authority.
No
executive officer of TVA serves on
the board of an entity which in turn has an executive officer of the entity
serving as a director of TVA.
The
Human Resources Committee has
reviewed and discussed the Compensation Discussion and Analysis with management,
and based on the review and discussions, the Human Resources Committee
recommended to the TVA Board that the Compensation Discussion and Analysis
be
included in this Annual Report.
THE
HUMAN
RESOURCES COMMITTEE
Skila
S.
Harris, Chair
Dennis
C.
Bottorff
Howard
A.
Thrailkill
Susan
Richardson Williams
Not
applicable.
The
composition of the TVA Board is
governed by the TVA Act. The TVA Act contains certain provisions that
are similar to the considerations for independence under section 10A(m)(3)
of
the Exchange Act, including that to be eligible for appointment to the TVA
Board, an individual shall not be an employee of TVA and shall make full
disclosure to Congress of any investment or other financial interest that the
individual holds in the energy industry. These provisions became
applicable to TVA Board members on March 31, 2006.
Conflict
of Interest
Provisions
All
TVA employees, including
directors and executive officers, are subject to the conflict of interest laws
and regulations applicable to employees of the federal
government. Accordingly, the general federal conflict of interest
statute (18 U.S.C. § 208) and the Standards of Ethical Conduct for Employees of
the Executive Branch (5 C.F.R. part 2635) (“Standards of Ethical Conduct”)
form the basis of TVA’s policies and procedures for the review, approval, or
ratification of related party transactions. The general federal
conflict of interest statute, subject to certain exceptions, prohibits each
government employee, including TVA’s directors and executive officers, from
participating personally and substantially (by advice, decision, or otherwise)
as a government employee in any contract, controversy, proceeding, request
for
determination, or other official particular matter in which, to his or her
knowledge, he or she (or his or her spouse, minor child, general partner,
organization with which he or she serves as officer, director, employee,
trustee, or general partner, or any person or organization with which he or
she
is negotiating, or has an arrangement, for future employment) has a financial
interest. Exceptions to the statutory prohibition relevant to TVA
employees are (1) financial interests which have been deemed by the Office
of
Government Ethics, in published regulations, to be too remote or inconsequential
to affect the integrity of the employee’s services, or (2) interests which
are determined in writing, after full disclosure and on a case by case basis,
to
be not so substantial as to be deemed likely to affect the integrity of the
employee’s services for TVA. In accordance with the statute,
individual waiver determinations are made by the official responsible for the
employee’s appointment. In the case of TVA directors, the
determination may be made by the Chairman of the TVA Board, and in the case
of
the Chairman of the TVA Board, the determination may be made by the Counsel
to
the President of the United States.
More
broadly, Subpart E of the
Standards of Ethical Conduct provides that where an employee (1) knows that
a
particular matter involving specific parties is likely to have a direct and
predictable effect on the financial interests of a member of his or her
household, or that a person with whom the employee has a “covered relationship”
(which includes, but is not limited to, persons with whom the employee has
a
close family relationship and organizations in which the employee is an active
participant) is or represents a party to the matter, and (2) determines
that the circumstances would cause a reasonable person with knowledge of
relevant facts to question his or her impartiality in the matter, the employee
should not participate in the matter absent agency
authorization. This authorization may be given by the
employee’s
supervising
officer, as agency designee, in consultation with the TVA Designated Agency
Ethics Official, upon the determination that TVA’s interest in the employee’s
participation in the matter outweighs the concern that a reasonable person
may
question the integrity of TVA’s programs and operations.
The
previously described restrictions
are reflected in TVA’s Employment Practice 1, Business Ethics, which
requires employees, including TVA’s directors and executive officers, to comply
with the guidelines outlined in the Standards of Ethical Conduct and which
restates the standard of the conflict of interest statute.
Additionally,
on November 30, 2006,
the TVA Board approved a written conflict of interest policy that applies to
all
TVA employees, including TVA’s directors and executive officers. The
conflict of interest policy reaffirms the requirement that all TVA employees
must comply with applicable federal conflict of interest laws, regulations,
and policies. It also establishes an additional policy that is
applicable to TVA’s directors and Chief Executive Officer, which provides as
follows:
In
addition to the law and policy applicable to all TVA employees, TVA Directors
and the Chief Executive Officer shall comply with the following additional
policy restricting the holding of certain financial interests:
|
1.
|
For
purposes of this policy, “financial interest” means an interest of a
person, or of a person’s spouse or minor child, arising by virtue of
investment or credit relationship, ownership, employment, consultancy,
or
fiduciary relationship such as director, trustee, or partner. However,
financial interest does not include an interest in TVA or any
interest:
|
|
•
|
comprised
solely of a right to payment of retirement benefits resulting from
former
employment or fiduciary
relationship,
|
|
•
|
arising
solely by virtue of cooperative membership or similar interest as
a
consumer in a distributor of TVA power,
or
|
|
•
|
arising
by virtue of ownership of publicly traded securities in any single
entity
with a value of $25,000 or less, or within a diversified mutual fund
investment in any amount.
|
|
2.
|
Directors
and the Chief Executive Officer shall not hold a financial interest
in any
distributor of TVA power.
|
|
3.
|
Directors
and the Chief Executive Officer shall not hold a financial interest
in any
entity engaged in the wholesale or retail generation, transmission,
or
sale of electricity.
|
|
4.
|
Directors
and the Chief Executive Officer shall not hold a financial interest
in any
entity that may reasonably be perceived as likely to be adversely
affected
by the success of TVA as a producer or transmitter of electric
power.
|
|
5.
|
Any
action taken or interest held that creates, or may reasonably be
perceived
as creating, a conflict of interest restricted by this additional
policy
applicable to TVA Directors and the Chief Executive Officer should
immediately be disclosed to the Chairman of Board of Directors and
the
Chairman of the Audit and Ethics Committee. The Audit and
Ethics Committee shall be responsible for initially reviewing all
such
disclosures and making recommendations to the entire Board on what
action,
if any, should be taken. The entire Board, without the vote of
any Director(s) involved, shall determine the appropriate action
to be
taken.
|
|
6.
|
Any
waiver of this additional policy applicable to TVA Directors and
the Chief
Executive Officer may be made only by the Board, and will be disclosed
promptly to the public, subject to the limitations on disclosure
imposed
by law.
|
TVA
relies on the policies,
practices, laws, and regulations discussed above to regulate conflicts of
interest involving employees, including directors and executive
officers. TVA has no other written or unwritten policy for the
review, approval, or ratification of any transactions in which TVA was or is
to
be a participant and in which any director or executive officer of TVA (or
any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law,
father-in-law, son-in-law, daughter-in-law, brother-in-law, or sister-in-law
of
any director or executive officer of TVA) had or will have a direct or indirect
material interest.
Note
with U.S.
Treasury
TVA
has access to a financing
arrangement with the U.S. Treasury under which the U.S. Treasury is authorized
to accept a short-term note with the maturity of one year or less in an amount
not to exceed $150 million. TVA may draw any portion of the
authorized $150 million. Interest is accrued daily at a rate
determined by the United States Secretary of the Treasury each month based
on
the average rate on outstanding marketable obligations of the United States
with
maturities of one year or less. During 2007, the daily average
outstanding balance was approximately $132 million. See Note 10 —
Short-Term Debt.
Power
Facility Appropriation
Investment
In
addition, TVA makes payments to the
U.S. Treasury as a repayment of and a return on the Power Facility Appropriation
Investment. Under the TVA Act, TVA is required to repay $1 billion of
the Power Facility Appropriation Investment, and $130 million of this
amount remained unpaid as of September 30, 2007. Once TVA repays this
$130 million, there will still be an outstanding balance on the Power Facility
Appropriation Investment, and TVA is obligated under the TVA Act to pay the
U.S.
Treasury a return on this remaining balance indefinitely. See Notes 8
and 15.
The
following table presents fees for
professional services rendered by PricewaterhouseCoopers LLP for the years
ended
September 30, 2007 and 2006.
Principal
Accountant Fees and Services
(In
actual dollars)
|
2007
|
2006
|
||||||
|
Audit
Fees 1
|
$1,409,876
|
$1,125,992
|
4 | ||||
|
Audit-Related
Fees 2
|
68,843
|
259,038
|
5 | ||||
|
All
Other Fees
3
|
–
|
|
14,000
|
||||
|
Total
|
$
1,478,719
|
$
1,399,030
|
|||||
Notes
(1) Audit fees consist of fees for professional services rendered for
the audit of TVA’s annual financial statements, the fees for review of the
interim financial statements included in TVA’s quarterly reports, and fees for
Bond offering comfort letters.
(2) Audit-related
fees are fees for services which are usually performed by the auditor and
consist primarily of accounting assistance on proposed transactions and
accounting standards, accounting assistance related to reviewing internal
control over financial reporting, and assistance in preparing for the filing
of
TVA’s initial Annual Report on Form 10-K.
(3) All
other fees relate to in-house training of TVA personnel.
(4) Fees
of $15,250 for the SEC advisory services for 2006 have been reclassified
from
Audit-Related Fees.
(5) The
Audit-Related Fees for 2006 include an adjustment of $920 related to an invoice
which was not included in the 2006 Annual Reports on Forms 10-K and
10-K/A.
The
TVA Board has an Audit and Ethics
Committee. Under the TVA Act, the Audit and Ethics Committee, in
consultation with the Inspector General, recommends to the TVA Board the
selection of an external auditor. In 2006 and 2007, TVA’s Audit and
Ethics Committee in consultation with the Inspector General recommended that
the
TVA Board select PricewaterhouseCoopers LLP as TVA’s external auditor for the
2006 and 2007 audits and other related services, and the TVA Board approved
these recommendations.
At
the Audit and Ethics Committee’s
August 6, 2007, meeting, the Audit and Ethics Committee approved a policy on
audit and permissible non-audit services (the “Policy”). The Policy
provides that all auditing services and permissible non-auditing services shall
be pre-approved by the Audit and Ethics Committee unless:
|
•
|
The
aggregate amount of all such non-audit services provided to TVA does
not
exceed five percent of the total amount TVA pays the external auditor
during the fiscal year in which the non-audit services are
provided;
|
|
•
|
Such
services were not recognized by TVA at the time of the engagement
to be
non-audit services or non-audit related services;
and
|
|
•
|
Such
services are promptly brought to the attention of the Audit and Ethics
Committee and approved at the next scheduled Audit and Ethics Committee
meeting or by one or more members of the Audit and Ethics Committee
to
whom the authority to grant such approvals has been
delegated.
|
The
Policy also lists the following
services as ones the external auditor is not permitted to
perform. The prohibited non-audit services are:
|
•
|
Bookkeeping
or other services related to the accounting records or financial
statements of TVA;
|
|
•
|
Financial
information system design and
implementation;
|
|
•
|
Appraisal
or valuation services, fairness opinions, and contribution-in-kind
reports;
|
|
•
|
Actuarial
services;
|
|
•
|
Internal
audit outsourcing services;
|
|
•
|
Management
functions or human resources;
|
|
•
|
Broker
or dealer, investment adviser, or investment banking
services;
|
|
•
|
Legal
services and expert services unrelated to the audit;
and
|
|
•
|
Any
other services that the Public Company Accounting Oversight Board
determines, by regulation, is
impermissible.
|
The
Policy also delegates to the
Chairman of the Audit and Ethics Committee the authority to pre-approve a
permissible service so long as the amount of the service does not exceed
$100,000 and the Chairman reports for informational purposes the services
pre-approved at the Audit and Ethics Committee’s next meeting.
The
Audit and Ethics Committee
pre-approved all of the audit and audit-related services for 2007.
(a) The
following documents have been filed as part of this Annual Report:
(1) Financial
Statements. The following documents are provided in Item 8
herein.
Statements
of Income
Balance
Sheets
Statements
of Cash Flow
Statements
of Changes in Proprietary
Capital
Notes
to Financial
Statements
Report
of Independent Registered
Public Accounting Firm
(PricewaterhouseCoopers
LLP)
(2) Financial
Statement Schedules.
|
|
Schedules
not included are omitted because they are not required or because
the
required information is provided in the financial statements, including
the notes thereto.
|
|
Schedule
II — Valuation and Qualifying Accounts
(in
millions)
|
|||||||||||||||
|
Description
|
Balance
at beginning of year
|
Additions
charged to expense
|
Deductions
|
Balance
at end of year
|
|||||||||||
|
For
the year ended September 30, 2007
|
|||||||||||||||
|
Allowance
for doubtful accounts
|
|||||||||||||||
|
Receivables
|
$10
|
$ –
|
$(8)
|
$ 2
|
|||||||||||
|
Loans
|
15
|
–
|
–
|
15
|
|||||||||||
|
Inventories
|
38
|
7
|
(2)
|
43
|
|||||||||||
|
Total
allowances deducted from assets
|
$63
|
$ 7
|
$(10)
|
$60
|
|||||||||||
|
For
the year ended September 30, 2006
|
|||||||||||||||
|
Allowance
for doubtful accounts
|
|
||||||||||||||
|
Receivables
|
$ 7
|
$ 3
|
$ –
|
$10
|
|||||||||||
|
Loans
|
15
|
1
|
(1)
|
15
|
|||||||||||
|
Inventories
|
36
|
13
|
(11)
|
38
|
|||||||||||
|
|
|||||||||||||||
|
Total
allowances deducted from assets
|
$58
|
$17
|
$(12)
|
$
63
|
|||||||||||
|
For
the year ended September 30, 2005
|
|||||||||||||||
|
Allowance
for doubtful accounts
|
|||||||||||||||
|
Receivables
|
$ 8
|
$ –
|
$
(1)
|
$
7
|
|||||||||||
|
Loans
|
14
|
1
|
–
|
15
|
|||||||||||
|
Inventories
|
36
|
15
|
(15)
|
36
|
|||||||||||
|
|
|||||||||||||||
|
Total
allowances deducted from assets
|
$58
|
$16
|
$
(16)
|
$
58
|
|||||||||||
(3) List
of Exhibits
|
Exhibit No.
|
Description
|
|
3.1
|
Tennessee
Valley Authority Act of 1933, as amended, 16 U.S.C.
§§ 831-831ee (Incorporated by reference to Exhibit 3.1 to TVA’s
Annual Report on Form 10-K for the year ended September 30, 2006,
File No.
000-52313)
|
|
3.2
|
By-laws
of Tennessee Valley Authority Adopted by the TVA Board of Directors
on May
18, 2006 (Incorporated by reference to Exhibit 3.2 to TVA’s Annual Report
on Form 10-K for the year ended September 30, 2006, File No.
000-52313)
|
|
4.1
|
Basic
Tennessee Valley Authority Power Bond Resolution Adopted by the
TVA Board
of Directors on October 6, 1960, as amended on September 28,
1976, October
17, 1989, and March 25, 1992 (Incorporated by reference to Exhibit
4.1 to
TVA’s Annual Report on Form 10-K for the year ended September 30,
2006,
File No. 000-52313)
|
|
10.1
|
$1,250,000,000
Fall Maturity Credit Agreement Dated as of May 17, 2006, Among
TVA, Bank
of America, N.A., as Administrative Agent, Bank of America, N.A.,
as a
Lender, and the Other Lenders Party Thereto (Incorporated by
reference to
Exhibit 10.1 to TVA’s Annual Report on Form 10-K for the year ended
September 30, 2006, File No. 000-52313)
|
|
10.2
|
$1,250,000,000
Spring Maturity Credit Agreement Dated as of May 17, 2006, Among
TVA, Bank
of America, N.A., as Administrative Agent, Bank of America, N.A.,
as a
Lender, and the Other Lenders Party Thereto (Incorporated by
reference to
Exhibit 10.2 to TVA’s Annual Report on Form 10-K for the year ended
September 30, 2006, File No. 000-52313)
|
|
10.3
|
Amendment
Dated as of November 2, 2006, to $1,250,000,000 Fall Maturity Credit
Agreement Dated as of May 17, 2006, Among TVA, Bank of America, N.A.,
as Administrative Agent, Bank of America, N.A., as a Lender,
and the Other
Lenders Party Thereto (Incorporated by reference to Exhibit 10.1
to TVA’s
Quarterly Report on Form 10-Q for the quarter ended December
31, 2006,
File No. 000-52313)
|
|
10.4
|
Amendment
dated as of May 11, 2007, to $1,250,000,000 Spring Maturity Credit
Agreement Dated as of May 17, 2006, Among TVA, Bank of America, N.A.,
as Administrative Agent, Bank of America, N.A., as a Lender,
and the Other
Lenders Party Thereto (Incorporated by reference to Exhibit 10.1
to TVA’s
Quarterly Report on Form 10-Q for the quarter ended June 30,
2007, File
No. 000-52313)
|
|
10.5
|
Second
Amendment dated as of November 2, 2007, to $1,250,000,000 Fall
Maturity
Credit Agreement Dated as of May 17, 2006, and amended as of November
2, 2006, Among TVA, Bank of America, N.A., as Administrative
Agent, Bank
of America, N.A., as a Lender, and the Other Lenders Party
Thereto
|
|
10.6
|
TVA
Discount Notes Selling Group Agreement (Incorporated by reference
to
Exhibit 10.3 to TVA’s Annual Report on Form 10-K for the year ended
September 30, 2006, File No. 000-52313)
|
|
10.7
|
Electronotes®
Selling Agent
Agreement Dated as of June 1, 2006, Among TVA, LaSalle Financial
Services,
Inc., A.G. Edwards & Sons, Inc., Citigroup Global Markets Inc., Edward
D. Jones & Co., L.P., First Tennessee Bank National Association,
J.J.B. Hilliard, W.L. Lyons, Inc., Merrill Lynch, Pierce, Fenner
&
Smith Incorporated, Morgan Stanley & Co. Incorporated, and Wachovia
Securities, LLC (Incorporated by reference to Exhibit 10.4 to
TVA’s Annual
Report on Form 10-K for the year ended September 30, 2006, File
No.
000-52313)
|
|
10.8
|
Commitment
Agreement Among Memphis Light, Gas and Water Division, the City
of
Memphis, Tennessee, and TVA Dated as of November 19, 2003 (Incorporated
by
reference to Exhibit 10.5 to TVA’s Annual Report on Form 10-K for the year
ended September 30, 2006, File No. 000-52313)
|
|
10.9
|
Power
Contract Supplement No. 95 Among Memphis Light, Gas and Water
Division,
the City of Memphis, Tennessee, and TVA Dated as of November
19, 2003
(Incorporated by reference to Exhibit 10.6 to TVA’s Annual Report on Form
10-K for the year ended September 30, 2006, File No.
000-52313)
|
|
10.10
|
Void
Walk Away Agreement Among Memphis Light, Gas and Water Division,
the City
of Memphis, Tennessee, and TVA Dated as of November 20, 2003
(Incorporated
by reference to Exhibit 10.7 to TVA’s Annual Report on Form 10-K for the
year ended September 30, 2006, File No. 000-52313)
|
|
10.11
|
Power
Contract Supplement No. 96 Among Memphis Light, Gas and Water
Division,
the City of Memphis, Tennessee, and TVA Dated as of November
20, 2003
(Incorporated by reference to Exhibit 10.8 to TVA’s Annual Report on Form
10-K for the year ended September 30, 2006, File No.
000-52313)
|
|
10.12
|
Overview
of TVA’s September 26, 2003, Lease and Leaseback of Control, Monitoring,
and Data Analysis Network with Respect to TVA’s Transmission System in
Tennessee, Kentucky, Georgia, and Mississippi (Incorporated by
reference
to Exhibit 10.9 to TVA’s Annual Report on Form 10-K for the year ended
September 30, 2006, File No. 000-52313)
|
|
10.13*
|
Participation
Agreement Dated as of September 22, 2003, Among (1) TVA, (2)
NVG Network I
Statutory Trust, (3) Wells Fargo Delaware Trust Company, Not in Its
Individual Capacity, Except to the Extent Expressly Provided
in the
Participation Agreement, But as Owner Trustee, (4) Wachovia Mortgage
Corporation, (5) Wilmington Trust Company, Not in Its Individual
Capacity,
Except to the Extent Expressly Provided in the Participation
Agreement,
But as Lease Indenture Trustee, and (6) Wilmington Trust Company,
Not in
Its Individual Capacity, Except to the Extent Expressly Provided
in the
Participation Agreement, But as Pass Through Trustee (Incorporated
by
reference to Exhibit 10.10 to TVA’s Annual Report on Form 10-K for the
year ended September 30, 2006, File No. 000-52313)
|
|
10.14*
|
Network
Lease Agreement Dated as of September 26, 2003, Between NVG Network
I
Statutory Trust, as Owner Lessor, and TVA, as Lessee (Incorporated
by
reference to Exhibit 10.11 to TVA’s Annual Report on Form 10-K for the
year ended September 30, 2006, File No. 000-52313)
|
|
10.15*
|
Head
Lease Agreement Dated as of September 26, 2003, Between TVA,
as Head
Lessor, and NVG Network I Statutory Trust, as Head Lessee (Incorporated
by
reference to Exhibit 10.12 to TVA’s Annual Report on Form 10-K for the
year ended September 30, 2006, File No. 000-52313)
|
|
10.16*
|
Leasehold
Security Agreement Dated as of September 26, 2003, Made by NVG
Network I
Statutory Trust to TVA (Incorporated by reference to Exhibit
10.13 to
TVA’s Annual Report on Form 10-K for the year ended September 30,
2006,
File No. 000-52313)
|
|
10.17†
|
TVA
Compensation Plan Approved by the TVA Board on May 31, 2007 (Incorporated
by reference to Exhibit 99.3 to TVA’s Current Report on Form 8-K filed on
December 11, 2007, File No. 000-52313)
|
|
10.18†
|
TVA
Vehicle Allowance Guidelines, Effective April 1, 2006
|
|
10.19†
|
Tennessee
Valley Authority Supplemental Executive Retirement Plan, Effective
as of
October 1, 1995 (Incorporated by reference to Exhibit 10.15 to
TVA’s
Annual Report on Form 10-K for the year ended September 30, 2006,
File No.
000-52313)
|
|
10.20†
|
Tennessee
Valley Authority Executive Annual Incentive Plan, Effective in
Fiscal Year
1999 (Incorporated by reference to Exhibit 10.16 to TVA’s Annual Report on
Form 10-K for the year ended September 30, 2006, File No.
000-52313)
|
|
10.21†
|
Tennessee
Valley Authority Executive Long-Term Incentive Plan, Effective
in Fiscal
Year 1999 (Incorporated by reference to Exhibit 10.17 to TVA’s Annual
Report on Form 10-K for the year ended September 30, 2006, File
No.
000-52313)
|
|
10.22†
|
Tennessee
Valley Authority Long Term Deferred Compensation Plan (Incorporated
by
reference to Exhibit 10.18 to TVA’s Annual Report on Form 10-K for the
year ended September 30, 2006, File No. 000-52313)
|
|
10.23†
|
TVA
Merit Incentive Supplemental Retirement Income Plan, Effective
January
1996
|
|
10.24†
|
Offer
Letter to Tom D. Kilgore Accepted as of January 19, 2005 (Incorporated
by
reference to Exhibit 10.19 to TVA’s Annual Report on Form 10-K for the
year ended September 30, 2006, File No. 000-52313)
|
|
10.25†
|
Offer
Letter to Michael E. Rescoe Accepted as of April 21, 2004 (Incorporated
by
reference to Exhibit 10.20 to TVA’s Annual Report on Form 10-K for the
year ended September 30, 2006, File No. 000-52313)
|
|
10.26†
|
Offer
Letter to William R. McCollum, Jr., Accepted as of March 9,
2007
|
|
10.27†
|
Offer
Letter to Kimberly S. Greene Accepted as of August 3, 2007
|
|
10.28†
|
Deferral
Agreement Between TVA and Tom D. Kilgore Dated as of March 29,
2005
(Incorporated by reference to Exhibit 10.24 to TVA’s Annual Report on Form
10-K for the year ended September 30, 2006, File No.
000-52313)
|
|
10.29†
|
First
Deferral Agreement Between TVA and Karl W. Singer Dated as of
May 7, 2004
(Incorporated by reference to Exhibit 10.25 to TVA’s Annual Report on Form
10-K for the year ended September 30, 2006, File No.
000-52313)
|
|
10.30†
|
Second
Deferral Agreement Between TVA and Karl W. Singer Dated as of
May 7, 2004
(Incorporated by reference to Exhibit 10.26 to TVA’s Annual Report on Form
10-K for the year ended September 30, 2006, File No.
000-52313)
|
|
10.31†
|
First
Deferral Agreement Between TVA and Ashok S. Bhatnagar Dated as
of
September 28, 2004 (Incorporated by reference to Exhibit 10.21
to TVA’s
Annual Report on Form 10-K for the year ended September 30, 2006,
File No.
000-52313)
|
|
10.32†
|
Second
Deferral Agreement Between TVA and Ashok S. Bhatnagar Dated as
of
September 28, 2004 (Incorporated by reference to Exhibit 10.22
to TVA’s
Annual Report on Form 10-K for the year ended September 30, 2006,
File No.
000-52313)
|
|
10.33†
|
Deferral
Agreement Between TVA and William R. McCollum, Jr., Dated as
of May 3,
2007
|
|
10.34†
|
Deferral
Agreement Between TVA and Kimberly S. Greene Dated as of September
4,
2007
|
|
10.35†
|
Deferral
Agreement Between TVA and John M. Hoskins Dated as of October
30,
2006
|
|
10.36†
|
Separation
Agreement Between TVA and Karl W. Singer Dated as of March 28,
2007
(Incorporated by reference to Exhibit 99.1 to TVA’s Current Report on Form
8-K filed on December 11, 2007, File No. 000-52313)
|
|
14
|
Disclosure
and Financial Ethics Code (Incorporated by reference to Exhibit
14 to
TVA’s Annual Report on Form 10-K for the year ended September 30,
2006,
File No. 000-52313)
|
|
31.1
|
Rule
13a-14(a)/15d-14(a) Certification Executed by the Chief Executive
Officer
|
|
31.2
|
Rule
13a-14(a)/15d-14(a) Certification Executed by the Chief Financial
Officer
|
|
32.1
|
Section
1350 Certification Executed by the Chief Executive Officer
|
|
32.2
|
Section
1350 Certification Executed by the Chief Financial Officer
|
†
Management contract or compensatory arrangement.
*
Certain
schedules and exhibits have been omitted. The Tennessee Valley
Authority hereby undertakes to furnish supplementally copies of any of the
omitted schedules and exhibits upon request by the Securities and Exchange
Commission.
Pursuant
to the requirements of Section
13, 15(d), or 37 of the Securities Exchange Act of 1934, the registrant has
duly
caused this report to be signed on its behalf by the undersigned, thereunto
duly
authorized.
Date: December
12,
2007 TENNESSEE
VALLEY AUTHORITY
(Registrant)
By:
/s/
Tom D.
Kilgore
Tom
D. Kilgore
President and Chief Executive Officer
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has
been
signed below by the following persons on behalf of the registrant and in the
capacities and on the dates indicated.
|
Signature
|
Title
|
Date
|
|
/s/
Tom D.
Kilgore
Tom
D. Kilgore
|
President
and Chief Executive Officer
(Principal
Executive Officer)
|
December
12, 2007
|
|
/s/ Kimberly S.
Greene
Kimberly
S. Greene
|
Chief
Financial Officer and Executive Vice President, Financial
Services
(Principal
Financial Officer)
|
December
12, 2007
|
|
/s/ Randy P. Trusley
Randy
P. Trusley
|
Vice
President and Controller
(Principal
Accounting Officer)
|
December
12, 2007
|
|
/s/ William B. Sansom
|
Chairman
and Director
|
December
12, 2007
|
|
William
B. Sansom
|
||
|
/s/ Dennis C. Bottorff
|
Director
|
December
12, 2007
|
|
Dennis
C. Bottorff
|
||
|
/s/ Donald R. DePriest
|
Director
|
December
12, 2007
|
|
Donald
R. DePriest
|
||
|
/s/ Robert M. Duncan
|
Director
|
December
12, 2007
|
|
Robert
M. Duncan
|
||
|
/s/
Bishop William H. Graves
|
Director
|
December
12, 2007
|
|
Bishop
William H. Graves
|
||
|
/s/ Skila S.
Harris
|
Director
|
December
12, 2007
|
|
Skila
S. Harris
|
||
|
/s/ Howard A. Thrailkill
|
Director
|
December
12, 2007
|
|
Howard
A. Thrailkill
|
||
|
/s/
Susan Richardson Williams
|
Director
|
December
12, 2007
|
|
Susan
Richardson Williams
|
||
|
Exhibit No.
|
Description
|
|
3.1
|
Tennessee
Valley Authority Act of 1933, as amended, 16 U.S.C.
§§ 831-831ee (Incorporated by reference to Exhibit 3.1 to TVA’s
Annual Report on Form 10-K for the year ended September 30, 2006,
File No.
000-52313)
|
|
3.2
|
By-laws
of Tennessee Valley Authority Adopted by the TVA Board of Directors
on May
18, 2006 (Incorporated by reference to Exhibit 3.2 to TVA’s Annual Report
on Form 10-K for the year ended September 30, 2006, File No.
000-52313)
|
|
4.1
|
Basic
Tennessee Valley Authority Power Bond Resolution Adopted by the
TVA Board
of Directors on October 6, 1960, as amended on September 28, 1976,
October
17, 1989, and March 25, 1992 (Incorporated by reference to Exhibit
4.1 to
TVA’s Annual Report on Form 10-K for the year ended September 30, 2006,
File No. 000-52313)
|
|
10.1
|
$1,250,000,000
Fall Maturity Credit Agreement Dated as of May 17, 2006, Among
TVA, Bank
of America, N.A., as Administrative Agent, Bank of America, N.A.,
as a
Lender, and the Other Lenders Party Thereto (Incorporated by reference
to
Exhibit 10.1 to TVA’s Annual Report on Form 10-K for the year ended
September 30, 2006, File No. 000-52313)
|
|
10.2
|
$1,250,000,000
Spring Maturity Credit Agreement Dated as of May 17, 2006, Among
TVA, Bank
of America, N.A., as Administrative Agent, Bank of America, N.A.,
as a
Lender, and the Other Lenders Party Thereto (Incorporated by reference
to
Exhibit 10.2 to TVA’s Annual Report on Form 10-K for the year ended
September 30, 2006, File No. 000-52313)
|
|
10.3
|
Amendment
Dated as of November 2, 2006, to $1,250,000,000 Fall Maturity Credit
Agreement Dated as of May 17, 2006, Among TVA, Bank of America, N.A.,
as Administrative Agent, Bank of America, N.A., as a Lender, and
the Other
Lenders Party Thereto (Incorporated by reference to Exhibit 10.1
to TVA’s
Quarterly Report on Form 10-Q for the quarter ended December 31,
2006,
File No. 000-52313)
|
|
10.4
|
Amendment
dated as of May 11, 2007, to $1,250,000,000 Spring Maturity Credit
Agreement Dated as of May 17, 2006, Among TVA, Bank of America, N.A.,
as Administrative Agent, Bank of America, N.A., as a Lender, and
the Other
Lenders Party Thereto (Incorporated by reference to Exhibit 10.1
to TVA’s
Quarterly Report on Form 10-Q for the quarter ended June 30, 2007,
File
No. 000-52313)
|
|
10.5
|
Second
Amendment dated as of November 2, 2007, to $1,250,000,000 Fall
Maturity
Credit Agreement Dated as of May 17, 2006, and amended as of November
2, 2006, Among TVA, Bank of America, N.A., as Administrative Agent,
Bank
of America, N.A., as a Lender, and the Other Lenders Party
Thereto
|
|
10.6
|
TVA
Discount Notes Selling Group Agreement (Incorporated by reference
to
Exhibit 10.3 to TVA’s Annual Report on Form 10-K for the year ended
September 30, 2006, File No. 000-52313)
|
|
10.7
|
Electronotes®
Selling Agent
Agreement Dated as of June 1, 2006, Among TVA, LaSalle Financial
Services,
Inc., A.G. Edwards & Sons, Inc., Citigroup Global Markets Inc., Edward
D. Jones & Co., L.P., First Tennessee Bank National Association,
J.J.B. Hilliard, W.L. Lyons, Inc., Merrill Lynch, Pierce, Fenner
&
Smith Incorporated, Morgan Stanley & Co. Incorporated, and Wachovia
Securities, LLC (Incorporated by reference to Exhibit 10.4 to TVA’s Annual
Report on Form 10-K for the year ended September 30, 2006, File
No.
000-52313)
|
|
10.8
|
Commitment
Agreement Among Memphis Light, Gas and Water Division, the City
of
Memphis, Tennessee, and TVA Dated as of November 19, 2003 (Incorporated
by
reference to Exhibit 10.5 to TVA’s Annual Report on Form 10-K for the year
ended September 30, 2006, File No. 000-52313)
|
|
10.9
|
Power
Contract Supplement No. 95 Among Memphis Light, Gas and Water Division,
the City of Memphis, Tennessee, and TVA Dated as of November 19,
2003
(Incorporated by reference to Exhibit 10.6 to TVA’s Annual Report on Form
10-K for the year ended September 30, 2006, File No.
000-52313)
|
|
10.10
|
Void
Walk Away Agreement Among Memphis Light, Gas and Water Division,
the City
of Memphis, Tennessee, and TVA Dated as of November 20, 2003 (Incorporated
by reference to Exhibit 10.7 to TVA’s Annual Report on Form 10-K for the
year ended September 30, 2006, File No. 000-52313)
|
|
10.11
|
Power
Contract Supplement No. 96 Among Memphis Light, Gas and Water Division,
the City of Memphis, Tennessee, and TVA Dated as of November 20,
2003
(Incorporated by reference to Exhibit 10.8 to TVA’s Annual Report on Form
10-K for the year ended September 30, 2006, File No.
000-52313)
|
|
10.12
|
Overview
of TVA’s September 26, 2003, Lease and Leaseback of Control, Monitoring,
and Data Analysis Network with Respect to TVA’s Transmission System in
Tennessee, Kentucky, Georgia, and Mississippi (Incorporated by reference
to Exhibit 10.9 to TVA’s Annual Report on Form 10-K for the year ended
September 30, 2006, File No. 000-52313)
|
|
10.13*
|
Participation
Agreement Dated as of September 22, 2003, Among (1) TVA, (2) NVG
Network I
Statutory Trust, (3) Wells Fargo Delaware Trust Company, Not in Its
Individual Capacity, Except to the Extent Expressly Provided in the
Participation Agreement, But as Owner Trustee, (4) Wachovia Mortgage
Corporation, (5) Wilmington Trust Company, Not in Its Individual
Capacity,
Except to the Extent Expressly Provided in the Participation Agreement,
But as Lease Indenture Trustee, and (6) Wilmington Trust Company,
Not in
Its Individual Capacity, Except to the Extent Expressly Provided
in the
Participation Agreement, But as Pass Through Trustee (Incorporated
by
reference to Exhibit 10.10 to TVA’s Annual Report on Form 10-K for the
year ended September 30, 2006, File No. 000-52313)
|
|
10.14*
|
Network
Lease Agreement Dated as of September 26, 2003, Between NVG Network
I
Statutory Trust, as Owner Lessor, and TVA, as Lessee (Incorporated
by
reference to Exhibit 10.11 to TVA’s Annual Report on Form 10-K for the
year ended September 30, 2006, File No. 000-52313)
|
|
10.15*
|
Head
Lease Agreement Dated as of September 26, 2003, Between TVA, as Head
Lessor, and NVG Network I Statutory Trust, as Head Lessee (Incorporated
by
reference to Exhibit 10.12 to TVA’s Annual Report on Form 10-K for the
year ended September 30, 2006, File No. 000-52313)
|
|
10.16*
|
Leasehold
Security Agreement Dated as of September 26, 2003, Made by NVG Network
I
Statutory Trust to TVA (Incorporated by reference to Exhibit 10.13
to
TVA’s Annual Report on Form 10-K for the year ended September 30, 2006,
File No. 000-52313)
|
|
10.17†
|
TVA
Compensation Plan Approved by the TVA Board on May 31, 2007 (Incorporated
by reference to Exhibit 99.3 to TVA’s Current Report on Form 8-K filed on
December 11, 2007, File No. 000-52313)
|
|
10.18†
|
TVA
Vehicle Allowance Guidelines, Effective April 1, 2006
|
|
10.19†
|
Tennessee
Valley Authority Supplemental Executive Retirement Plan, Effective
as of
October 1, 1995 (Incorporated by reference to Exhibit 10.15 to TVA’s
Annual Report on Form 10-K for the year ended September 30, 2006,
File No.
000-52313)
|
|
10.20†
|
Tennessee
Valley Authority Executive Annual Incentive Plan, Effective in Fiscal
Year
1999 (Incorporated by reference to Exhibit 10.16 to TVA’s Annual Report on
Form 10-K for the year ended September 30, 2006, File No.
000-52313)
|
|
10.21†
|
Tennessee
Valley Authority Executive Long-Term Incentive Plan, Effective in
Fiscal
Year 1999 (Incorporated by reference to Exhibit 10.17 to TVA’s Annual
Report on Form 10-K for the year ended September 30, 2006, File No.
000-52313)
|
|
10.22†
|
Tennessee
Valley Authority Long Term Deferred Compensation Plan (Incorporated
by
reference to Exhibit 10.18 to TVA’s Annual Report on Form 10-K for the
year ended September 30, 2006, File No. 000-52313)
|
|
10.23†
|
TVA
Merit Incentive Supplemental Retirement Income Plan, Effective January
1996
|
|
10.24†
|
Offer
Letter to Tom D. Kilgore Accepted as of January 19, 2005 (Incorporated
by
reference to Exhibit 10.19 to TVA’s Annual Report on Form 10-K for the
year ended September 30, 2006, File No. 000-52313)
|
|
10.25†
|
Offer
Letter to Michael E. Rescoe Accepted as of April 21, 2004 (Incorporated
by
reference to Exhibit 10.20 to TVA’s Annual Report on Form 10-K for the
year ended September 30, 2006, File No. 000-52313)
|
|
10.26†
|
Offer
Letter to William R. McCollum, Jr., Accepted as of March 9,
2007
|
|
10.27†
|
Offer
Letter to Kimberly S. Greene Accepted as of August 3, 2007
|
|
10.28†
|
Deferral
Agreement Between TVA and Tom D. Kilgore Dated as of March 29, 2005
(Incorporated by reference to Exhibit 10.24 to TVA’s Annual Report on Form
10-K for the year ended September 30, 2006, File No.
000-52313)
|
|
10.29†
|
First
Deferral Agreement Between TVA and Karl W. Singer Dated as of May
7, 2004
(Incorporated by reference to Exhibit 10.25 to TVA’s Annual Report on Form
10-K for the year ended September 30, 2006, File No.
000-52313)
|
|
10.30†
|
Second
Deferral Agreement Between TVA and Karl W. Singer Dated as of May
7, 2004
(Incorporated by reference to Exhibit 10.26 to TVA’s Annual Report on Form
10-K for the year ended September 30, 2006, File No.
000-52313)
|
|
10.31†
|
First
Deferral Agreement Between TVA and Ashok S. Bhatnagar Dated as of
September 28, 2004 (Incorporated by reference to Exhibit 10.21 to
TVA’s
Annual Report on Form 10-K for the year ended September 30, 2006,
File No.
000-52313)
|
|
10.32†
|
Second
Deferral Agreement Between TVA and Ashok S. Bhatnagar Dated as of
September 28, 2004 (Incorporated by reference to Exhibit 10.22 to
TVA’s
Annual Report on Form 10-K for the year ended September 30, 2006,
File No.
000-52313)
|
|
10.33†
|
Deferral
Agreement Between TVA and William R. McCollum, Jr., Dated as of May
3,
2007
|
|
10.34†
|
Deferral
Agreement Between TVA and Kimberly S. Greene Dated as of September
4,
2007
|
|
10.35†
|
Deferral
Agreement Between TVA and John M. Hoskins Dated as of October 30,
2006
|
|
10.36†
|
Separation
Agreement Between TVA and Karl W. Singer Dated as of March 28, 2007
(Incorporated by reference to Exhibit 99.1 to TVA’s Current Report on Form
8-K filed on December 11, 2007, File No. 000-52313)
|
|
14
|
Disclosure
and Financial Ethics Code (Incorporated by reference to Exhibit 14
to
TVA’s Annual Report on Form 10-K for the year ended September 30, 2006,
File No. 000-52313)
|
|
31.1
|
Rule
13a-14(a)/15d-14(a) Certification Executed by the Chief Executive
Officer
|
|
31.2
|
Rule
13a-14(a)/15d-14(a) Certification Executed by the Chief Financial
Officer
|
|
32.1
|
Section
1350 Certification Executed by the Chief Executive Officer
|
|
32.2
|
Section
1350 Certification Executed by the Chief Financial
Officer
|
†
Management contract or compensatory arrangement.
*
Certain
schedules and exhibits have been omitted. The Tennessee Valley
Authority hereby undertakes to furnish supplementally copies of any of the
omitted schedules and exhibits upon request by the Securities and Exchange
Commission.
Page
181