- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------------
FORM 10-K
(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003
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 1-4101
TENNESSEE GAS PIPELINE COMPANY
(Exact name of registrant as specified in its charter)
<Table>
DELAWARE 74-1056569
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
EL PASO BUILDING
1001 LOUISIANA STREET
HOUSTON, TEXAS 77002
(Address of principal executive offices) (Zip Code)
</Table>
TELEPHONE NUMBER: (713) 420-2600
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes [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 an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes [ ] No [X]
STATE THE AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY NON-AFFILIATES
OF THE REGISTRANT...........................................................NONE
INDICATE THE NUMBER OF SHARES OUTSTANDING OF EACH OF THE REGISTRANT'S
CLASSES OF COMMON STOCK, AS OF THE LATEST PRACTICABLE DATE.
Common Stock, par value $5 per share. Shares outstanding on March 15, 2004:
208
TENNESSEE GAS PIPELINE COMPANY MEETS THE CONDITIONS OF GENERAL INSTRUCTION
I(1)(a) AND (b) TO FORM 10-K AND IS THEREFORE FILING THIS REPORT WITH A REDUCED
DISCLOSURE FORMAT AS PERMITTED BY SUCH INSTRUCTION.
DOCUMENTS INCORPORATED BY REFERENCE: NONE
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
TENNESSEE GAS PIPELINE COMPANY
TABLE OF CONTENTS
<Table>
<Caption>
CAPTION PAGE
------- ----
PART I
Item 1. Business.................................................... 1
Item 2. Properties.................................................. 3
Item 3. Legal Proceedings........................................... 3
Item 4. Submission of Matters to a Vote of Security Holders......... *
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters....................................... 3
Item 6. Selected Financial Data..................................... *
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 3
Risk Factors and Cautionary Statement for Purposes of the
"Safe Harbor" Provisions of the Private Securities
Litigation Reform Act of 1995............................. 8
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk...................................................... 13
Item 8. Financial Statements and Supplementary Data................. 14
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................. 36
Item 9A. Controls and Procedures..................................... 36
PART III
Item 10. Directors and Executive Officers of the Registrant.......... *
Item 11. Executive Compensation...................................... *
Item 12. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters................ *
Item 13. Certain Relationships and Related Transactions.............. *
Item 14. Principal Accountant Fees and Services...................... 37
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form
8-K....................................................... 37
Signatures.................................................. 40
</Table>
- ---------------
* We have not included a response to this item in this document since no
response is required pursuant to the reduced disclosure format permitted by
General Instruction I to Form 10-K.
Below is a list of terms that are common to our industry and used
throughout this document:
<Table>
/d = per day
BBtu = billion British thermal units
Bcf = billion cubic feet
MMcf = million cubic feet
Tcfe = trillion cubit feet of gas equivalents
</Table>
When we refer to cubic feet measurements, all measurements are at a
pressure of 14.73 pounds per square inch.
When we refer to "us", "we", "our", or "ours", we are describing Tennessee
Gas Pipeline Company and/or our subsidiaries.
i
PART I
ITEM 1. BUSINESS
GENERAL
We are a Delaware corporation incorporated in 1947 and a wholly owned
indirect subsidiary of El Paso Corporation (El Paso). Our primary business
consists of the interstate transportation and storage of natural gas. We conduct
our business activities through our natural gas pipeline system and storage
facilities, each of which are discussed below.
The Pipeline System. The Tennessee Gas Pipeline system consists of
approximately 14,200 miles of pipeline with a design capacity of approximately
6,937 MMcf/d. During 2003, 2002 and 2001, our average throughput was 4,710
BBtu/d, 4,596 BBtu/d and 4,405 BBtu/d. This multiple-line system begins in the
natural gas producing regions of Louisiana, the Gulf of Mexico and south Texas
and extends to the northeast section of the U.S., including the metropolitan
areas of New York City and Boston. Our system also has interconnects at the
U.S.-Mexico border and the U.S.-Canada border.
During the fourth quarter of 2003, we completed the construction of
pipeline, compression and border crossing facilities which expanded the
deliverability of our South Texas system by approximately 312 MMcf/d.
Storage Facilities. Along our pipeline system, we have approximately 90
Bcf of underground working natural gas storage capacity, of which 1 Bcf is
contracted from ANR Pipeline Company and 29 Bcf from Bear Creek Storage Company
(Bear Creek), both of whom are our affiliates.
Bear Creek is a joint venture that we own equally with our affiliate,
Southern Gas Storage Company, a subsidiary of Southern Natural Gas Company
(SNG). Bear Creek owns and operates an underground natural gas storage facility
located in Louisiana. The facility has a capacity of 50 Bcf of base gas and 58
Bcf of working storage. Bear Creek's working storage capacity is committed
equally to Southern Natural Gas Company and us under long-term contracts.
REGULATORY ENVIRONMENT
Our interstate natural gas transmission system and storage operations are
regulated by the FERC under the Natural Gas Act of 1938 and the Natural Gas
Policy Act of 1978. Our pipeline system and storage facilities operate under
FERC-approved tariffs that establish rates, terms and conditions for services to
their customers. Generally, the FERC's authority extends to:
- rates and charges for natural gas transportation, storage and related
services;
- certification and construction of new facilities;
- extension or abandonment of facilities;
- maintenance of accounts and records;
- relationships between pipeline and energy affiliates;
- terms and conditions of services;
- depreciation and amortization policies;
- acquisition and disposition of facilities; and
- initiation and discontinuation of services.
The fees or rates established under our tariffs are a function of our costs
of providing services to our customers, and include provisions for a reasonable
return on our invested capital. Approximately 67 percent of our 2003
transportation and storage revenue is attributable to a capacity reservation, or
demand charge, paid by firm customers. Firm customers are those who are
obligated to pay a monthly demand charge, regardless of the amount of natural
gas they transport or store, for the term of their contracts. The remaining 33
percent of our revenue is attributable to charges based solely on the volumes of
natural gas actually transported or stored
1
on our pipeline system. Consequently, our financial results have historically
been relatively stable. However, our results can be subject to volatility due to
factors such as weather, changes in natural gas prices and market conditions,
regulatory actions, competition and the credit-worthiness of our customers.
Our interstate pipeline system is also subject to federal, state and local
statutes and regulations regarding pipeline safety and environmental matters.
Our system has an ongoing inspection program designed to keep all of our
facilities in compliance with environmental and pipeline safety requirements. We
believe that our system is in material compliance with the applicable
requirements.
We are subject to regulation over the safety requirements in the design,
construction, operation and maintenance of our interstate natural gas
transmission system and storage facilities by the U.S. Department of
Transportation. Our operations on U.S. government land are regulated by the U.S.
Department of the Interior.
A discussion of our significant rate and regulatory matters is included in
Part II, Item 8, Financial Statements and Supplementary Data, Note 10 and is
incorporated herein by reference.
MARKETS AND COMPETITION
We have approximately 406 firm and interruptible customers, including
distribution and industrial companies, electric generation companies, natural
gas producers, other natural gas pipelines and natural gas marketing and trading
companies. We provide transportation services in both our natural gas supply and
market areas. We have approximately 481 firm transportation contracts with
remaining terms that extend from one month to 22 years and with a weighted
average remaining contract term of approximately five years. Approximately 87
percent of our total capacity is subscribed under firm transportation
agreements. Substantially all of the natural gas that we transport or store is
owned by our shippers and accordingly we do not assume any material natural gas
commodity price risk related to this gas.
Our interstate natural gas transmission system and natural gas storage
businesses face varying degrees of competition from other pipelines, as well as
from alternative energy sources such as electricity, hydroelectric power, coal
and fuel oil. We compete with other interstate and intrastate pipelines for
deliveries to customers who can take deliveries at multiple connection points.
Our system faces strong competition in the Northeast, Appalachian, Midwest and
Southeast market areas. In addition, we compete with pipelines and gathering
systems for connection to new supply sources in Texas, the Gulf of Mexico and
from the Canadian border.
A number of large natural gas consumers are electric utility companies who
use natural gas to fuel electric power generation facilities. Electric power
generation is the fastest growing demand sector of the natural gas market. The
potential consequences of proposed and ongoing restructuring and deregulation of
the electric power industry are currently unclear. Restructuring and
deregulation potentially benefit the natural gas industry by creating more
demand for natural gas turbine generated electric power, but this effect is
offset, in varying degrees, by increased efficiency in generation and the use of
surplus electric capacity as a result of open market access.
In response to changing market conditions, we have shifted from a
traditional dependence solely on long-term contracts to an approach that
balances short-term and long-term commitments. This shift is due to changes in
market conditions and competition driven by state utility deregulation, local
distribution company mergers, new supply sources, volatility in natural gas
prices, demand for short-term capacity and new markets in power plants.
Our existing contracts mature at various times and in varying amounts of
throughput capacity. Our ability to extend our existing contracts or re-market
expiring capacity is dependent on competitive alternatives, access to capital,
the regulatory environment at the local, state and federal levels and market
supply and demand factors at the relevant dates these contracts are extended or
expire. The duration of new or re-negotiated contracts will be affected by
current prices, competitive conditions and judgments concerning future market
trends and volatility. While we are allowed to negotiate contracts at fully
subscribed quantities and at maximum rates allowed under our tariffs, we must,
at times, discount our contracts to remain competitive.
2
ENVIRONMENTAL
A description of our environmental activities is included in Part II, Item
8, Financial Statements and Supplementary Data, Note 10, and is incorporated
herein by reference.
EMPLOYEES
As of March 9, 2004, we had approximately 1,780 full-time employees, none
of whom are subject to a collective bargaining arrangement.
ITEM 2. PROPERTIES
A description of our properties is included in Item 1, Business, and is
incorporated herein by reference.
We believe that we have satisfactory title to the properties owned and used
in our businesses, subject to liens for taxes not yet payable, liens incident to
minor encumbrances, liens for credit arrangements and easements and restrictions
that do not materially detract from the value of these properties, our interests
in these properties, or the use of these properties in our businesses. We
believe that our properties are adequate and suitable for the conduct of our
business in the future.
ITEM 3. LEGAL PROCEEDINGS
A description of our legal proceedings is included in Part II, Item 8,
Financial Statements and Supplementary Data, Note 10, and is incorporated herein
by reference.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Item 4, Submission of Matters to a Vote of Security Holders, has been
omitted from this report pursuant to the reduced disclosure format permitted by
General Instruction I to Form 10-K.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
All of our common stock, par value $5 per share, is owned by an indirect
subsidiary of El Paso and, accordingly, our stock is not publicly traded.
We pay dividends on our common stock from time to time from legally
available funds that have been approved for payment by our Board of Directors.
During 2002, a $67 million non-cash dividend of affiliated receivables was
declared and paid to our parent. No dividends were declared or paid in 2003 or
2001.
ITEM 6. SELECTED FINANCIAL DATA
Item 6, Selected Financial Data, has been omitted from this report pursuant
to the reduced disclosure format permitted by General Instruction I to Form
10-K.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The information required by this Item is presented in a reduced disclosure
format pursuant to General Instruction I to Form 10-K. The notes to our
consolidated financial statements contain information that is pertinent to the
following analysis, including a discussion of our significant accounting
policies.
3
GENERAL
Our business consists of interstate natural gas transmission and storage
operations and related services. Our interstate natural gas transmission system
and natural gas storage businesses face varying degrees of competition from
other pipelines, as well as from alternate energy sources, such as electricity,
hydroelectric power, coal and fuel oil. We are regulated by the FERC which
regulates the rates we can charge our customers. These rates are a function of
our costs of providing services to our customers, and include a return on our
invested capital. As a result, our financial results have historically been
relatively stable. However, they can be subject to volatility due to factors
such as weather, changes in natural gas prices and market conditions, regulatory
actions, competition and the credit-worthiness of our customers. In addition,
our ability to extend existing customer contracts or re-market expiring
contracted capacity is dependent on competitive alternatives, the regulatory
environment and supply and demand factors at the relevant dates these contracts
are extended or expire. We make every attempt to negotiate contracts at
fully-subscribed quantities and at maximum rates allowed under our tariff,
although at times, we discount our rates to remain competitive.
RESULTS OF OPERATIONS
Our management, as well as El Paso's management, uses earnings before
interest and income taxes (EBIT) to assess the operating results and
effectiveness of our business. We define EBIT as net income adjusted for (i)
items that do not impact our income from continuing operations, such as the
impact of accounting changes, (ii) income taxes, (iii) interest and debt expense
and (iv) affiliated interest income. Our business consists of consolidated
operations as well as investments in unconsolidated affiliates. We exclude
interest and debt expense from this measure so our management can evaluate our
operating results without regard to our financing methods. We believe the
discussion of our results of operations based on EBIT is useful to our investors
because it allows them to more effectively evaluate the operating performance of
both our consolidated business and our unconsolidated investments using the same
performance measure analyzed internally by our management. EBIT may not be
comparable to measurements used by other companies. Additionally, EBIT should be
considered in conjunction with net income and other performance measures such as
operating income or operating cash flow. The following is a reconciliation of
our operating income to our EBIT and our EBIT to our net income for the year
ended December 31:
<Table>
<Caption>
2003 2002
-------- ---------
(IN MILLIONS, EXCEPT
VOLUME AMOUNTS)
Operating revenues.......................................... $ 726 $ 702
Operating expenses.......................................... (450) (466)
----- ------
Operating income..................................... 276 236
----- ------
Other income................................................ 22 25
----- ------
EBIT................................................. 298 261
Interest and debt expense................................... (130) (126)
Affiliated interest income, net............................. 4 9
Income taxes................................................ (61) (42)
----- ------
Income before cumulative effect of accounting
change............................................ 111 102
Cumulative effect of accounting change, net of income
taxes............................................. -- 10
----- ------
Net income........................................... $ 111 $ 112
===== ======
Throughput volumes (BBtu/d)(1).............................. 4,710 4,596
===== ======
</Table>
- ---------------
(1) Throughput volumes exclude those related to our sale of our 30 percent
equity investment in Portland Natural Gas Transmission which we sold in the
fourth quarter of 2003.
4
OPERATING RESULTS (EBIT)
Our EBIT for the year ended December 31, 2003 increased $37 million
compared to 2002. The increase was due to higher throughput resulting from a
colder winter season and favorable interruptible rates during the summer season
offset by the impact of contract conversions and renewals which resulted in
higher transportation revenues and EBIT of $10 million. Also contributing
directly to the increase in EBIT was higher revenues of $33 million in 2003 from
recoveries of natural gas on our system in excess of gas used on our system. In
addition, gas prices were generally higher during 2003 versus 2002. Partially
offsetting these revenue-related increases was the favorable resolution of a
measurement dispute at a processing plant serving our system during 2002 of $18
million. In addition, lower environmental remediation, legal and other related
costs resulting primarily from a reduction in the estimated costs to complete
our internal PCB remediation project directly increased EBIT by $11 million in
2003 and lower overhead costs allocated to us by our parent increased EBIT by
$26 million. Higher depreciation expense of $8 million as a result of an
adjustment to our depreciation expense for a facility that is being depreciated
at an incremental rate of 6.67% per year instead of the general system rate of
1.62% per year and higher electric compression costs of $8 million reduced our
overall EBIT in 2003.
Our business is primarily driven by contracts with shippers transporting or
storing natural gas on our pipeline system. Our tariff structure, which is
regulated by the FERC, requires shippers to pay us on the basis of stated
transportation and storage rates. Under our tariff structure, approximately 67
percent of our 2003 transportation and storage revenue was attributed to a
capacity reservation, or demand charge, paid by firm customers. Firm customers
are those who are obligated to pay a monthly demand charge, regardless of the
amount of natural gas they actually transport or store on our pipeline system,
for the term of their contracts. As these contracts expire, our revenue varies
depending on the rates at which they are renewed.
INTEREST AND DEBT EXPENSE
<Table>
<Caption>
YEAR ENDED
DECEMBER 31,
-------------
2003 2002
----- -----
(IN MILLIONS)
Long-term debt.............................................. $122 $113
Short-term borrowings....................................... -- 7
Other....................................................... 9 9
Less: Capitalized interest.................................. (1) (3)
---- ----
Total interest and debt expense........................... $130 $126
==== ====
</Table>
Interest and debt expense was $4 million higher for the year ended December
31, 2003, than in 2002 due to higher average debt balances outstanding in 2003
than in 2002. In June 2002, we issued $240 million aggregate principal amount
8.375% notes due 2032, resulting in $9 million of increased interest expense in
2003. Also contributing to the increase was a $2 million decrease in capitalized
interest due to a lower capitalization base in 2003. These increases were offset
by lower interest expense of $7 million due to the discontinuation of commercial
paper activities in late 2002.
AFFILIATED INTEREST INCOME, NET
Affiliated interest income, net for the year ended December 31, 2003, was
$5 million lower than the same period in 2002. The decrease was due to lower
average advances to El Paso under our cash management program. The average
advances to affiliates participating in our cash management program were $166
million in 2003 versus $459 million in 2002. The average short-term interest
rates increased from 1.9% in 2002 to 2% in 2003.
5
INCOME TAXES
<Table>
<Caption>
YEAR ENDED
DECEMBER 31,
------------------
2003 2002
------ ------
(IN MILLIONS,
EXCEPT FOR RATES)
Income taxes................................................ $61 $42
Effective tax rate.......................................... 35% 29%
</Table>
Our effective tax rate for 2003 was impacted by current year state net
operating losses which reduced the effective tax rate, offset by the change in
the realizability of state net operating loss carryovers and the sale of an
equity investment. In 2002, our effective tax rate was different than the
statutory rate of 35% primarily due to state net operating losses which reduced
the effective tax rate. For a reconciliation of the statutory rate to the
effective rates, see Item 8, Financial Statements and Supplementary Data, Note
3.
LIQUIDITY AND CAPITAL RESOURCES
LIQUIDITY
Our liquidity needs have been provided by cash flow from operating
activities and the use of a cash management program with our parent company, El
Paso. Under El Paso's cash management program, depending on whether we have
short-term cash surpluses or requirements, we either provide cash to El Paso or
El Paso provides cash to us. We have historically provided cash advances to El
Paso, and we reflect these advances as investing activities in our statement of
cash flows. As of December 31, 2003, we had advanced $841 million as a result of
this program. These receivables are due upon demand; however, as of December 31,
2003, we classified this amount as non-current notes receivable from affiliates
because we do not anticipate settlement within the next twelve months. We
believe that cash flows from operating activities will be adequate to meet our
short-term capital requirements for existing operations. However, as a result of
recent announcements by El Paso related to a revision of its estimates of its
natural gas and oil reserves, our ability to borrow or recover the amounts
advanced under El Paso's cash management program could be impacted. See Item 8,
Financial Statements and Supplementary Data, Note 2 for a discussion of these
matters. Our cash flows for the years ended December 31 were as follows:
<Table>
<Caption>
2003 2002
----- -----
(IN MILLIONS)
Cash flows from operating activities........................ $ 304 $ 140
Cash flows from investing activities........................ (304) 42
Cash flows from financing activities........................ -- (186)
</Table>
In a series of credit rating agency actions beginning in 2002, and
contemporaneously with the downgrades of the senior unsecured indebtedness of
our parent company, El Paso, our senior unsecured indebtedness was downgraded to
below investment grade and is currently rated B1 by Moody's (with a negative
outlook and under review for a possible downgrade) and B- by Standard & Poor's
(with a negative outlook). These downgrades will increase our cost of capital
and collateral requirements and could impede our access to capital markets in
the future.
6
CAPITAL EXPENDITURES
Our capital expenditures during the periods indicated are listed below:
<Table>
<Caption>
YEAR ENDED
DECEMBER 31,
-------------
2003 2002
----- -----
(IN MILLIONS)
Maintenance................................................. $120 $158
Expansion/Other............................................. 43 76
---- ----
Total.................................................. $163 $234
==== ====
</Table>
Under our current plan, we expect to spend between approximately $137
million and $151 million in each of the next three years for capital
expenditures primarily to maintain the integrity of our pipelines and ensure the
reliable delivery of natural gas to our customers. In addition, we have budgeted
to spend between $42 million and $146 million in each of the next three years to
expand the capacity and services of our pipeline system. In the current
environment, we will require contract commitments for capital intensive
projects. We expect to fund our maintenance and expansion capital expenditures
through internally generated funds and external financing.
DEBT
As of December 31, 2003, we had long-term debt outstanding of $1,597
million, net of a $29 million discount, $300 million of which may mature within
the next five years. For a discussion of our debt and other credit facilities,
see Item 8, Financial Statements and Supplementary Data, Note 9, which is
incorporated herein by reference.
COMMITMENTS AND CONTINGENCIES
For a discussion of our commitments and contingencies, see Item 8,
Financial Statements and Supplementary Data, Note 10, which is incorporated
herein by reference.
NEW ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED
As of December 31, 2003, there were a number of accounting standards and
interpretations that had been issued, but not yet adopted by us. Based on our
assessment of those standards, we do not believe there are any that could have a
material impact on us.
7
RISK FACTORS AND CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR"
PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report contains or incorporates by reference forward-looking
statements within the meaning of the Private Securities Litigation Reform Act of
1995. Where any forward-looking statement includes a statement of the
assumptions or bases underlying the forward-looking statement, we caution that,
while we believe these assumptions or bases to be reasonable and in good faith,
assumed facts or bases almost always vary from the actual results, and the
differences between assumed facts or bases and actual results can be material,
depending upon the circumstances. Where, in any forward-looking statement, we or
our management express an expectation or belief as to future results, that
expectation or belief is expressed in good faith and is believed to have a
reasonable basis. We cannot assure you, however, that the statement of
expectation or belief will result or be achieved or accomplished. The words
"believe," "expect," "estimate," "anticipate," and similar expressions will
generally identify forward-looking statements. Our forward-looking statements,
whether written or oral, are expressly qualified by these cautionary statements
and any other cautionary statements that may accompany those statements. In
addition, we disclaim any obligation to update any forward-looking statements to
reflect events or circumstances after the date of this report.
With this in mind, you should consider the risks discussed elsewhere in
this report and other documents we file with the Securities and Exchange
Commission (SEC) from time to time and the following important factors that
could cause actual results to differ materially from those expressed in any
forward-looking statement made by us or on our behalf.
RISKS RELATED TO OUR BUSINESS
OUR SUCCESS DEPENDS ON FACTORS BEYOND OUR CONTROL.
Our business is the transportation and storage of natural gas for third
parties. As a result, the volume of natural gas involved in these activities
depends on the actions of those third parties and is beyond our control.
Further, the following factors, most of which are beyond our control, may
unfavorably impact our ability to maintain or increase current revenues, to
renegotiate existing contracts as they expire, or to remarket unsubscribed
capacity:
- future weather conditions, including those that favor alternative energy
sources such as hydroelectric power;
- price competition;
- drilling activity and supply availability of natural gas;
- expiration and/or turn back of significant contracts;
- service area competition;
- changes in regulation and actions of regulatory bodies;
- credit risk of our customer base;
- increased cost of capital;
- opposition to energy infrastructure development, especially in
environmentally sensitive areas;
- adverse general economic conditions; and
- unfavorable movements in natural gas and liquids prices.
THE REVENUES OF OUR PIPELINE BUSINESSES ARE GENERATED UNDER CONTRACTS THAT MUST
BE RENEGOTIATED PERIODICALLY.
Our revenues are generated under contracts which expire periodically and
must be renegotiated and extended or replaced. Although we actively pursue the
renegotiation, extension and/or replacement of these contracts, we cannot assure
you that we will be able to extend or replace these contracts when they expire
or
8
that the terms of any renegotiated contracts will be as favorable as the
existing contracts. Currently, a substantial portion of our revenues are under
contracts that are discounted at rates below the maximum rates allowed under our
tariff. For a further discussion of these matters, see Part I, Item 1,
Business -- Markets and Competition.
In particular, our ability to extend and/or replace contracts could be
adversely affected by factors we cannot control, including:
- competition by other pipelines, including the proposed construction by
other companies of additional pipeline capacity in markets served by us;
- changes in state regulation of local distribution companies, which may
cause them to negotiate short-term contracts or turn back their capacity
when their contracts expire;
- reduced demand and market conditions in the areas we serve;
- the availability of alternative energy sources or gas supply points; and
- regulatory actions.
If we are unable to renew, extend or replace these contracts or if we renew
them on less favorable terms, we may suffer a material reduction in our revenues
and earnings.
FLUCTUATIONS IN ENERGY COMMODITY PRICES COULD ADVERSELY AFFECT OUR BUSINESS.
If natural gas prices in the supply basins connected to our pipeline system
are higher than prices in other natural gas producing regions, our ability to
compete with other transporters may be negatively impacted. Revenues generated
by our contracts depend on volumes and rates, both of which can be affected by
the prices of natural gas. Increased natural gas prices could result in a
reduction of the volumes transported by our customers, such as power companies
who, depending on the price of fuel, may not dispatch gas fired power plants.
Increased prices could also result in industrial plant shutdowns or load losses
to competitive fuels and local distribution companies' loss of customer base.
The success of our operations is subject to continued development of additional
oil and natural gas reserves in the vicinity of our facilities and our ability
to access additional reserves, primarily in the Gulf of Mexico, to offset the
natural decline from existing wells connected to our systems. A decline in
energy prices could precipitate a decrease in these development activities and
could cause a decrease in the volume of reserves available for transmission or
storage on our system. If natural gas prices in the supply basins connected to
our pipeline systems are higher on a delivered basis to our off-system markets
than delivered prices from other natural gas producing regions, our ability to
compete with other transporters may be negatively impacted. Pricing volatility
may also impact the value of under or over recoveries of excess gas.
Fluctuations in energy prices are caused by a number of factors, including:
- regional, domestic and international supply and demand;
- availability and adequacy of transportation facilities;
- energy legislation;
- federal and state taxes, if any, on the transportation and storage of
natural gas;
- abundance of supplies of alternative energy sources; and
- political unrest among oil-producing countries.
THE AGENCIES THAT REGULATE US AND OUR CUSTOMERS AFFECT OUR PROFITABILITY.
Our pipeline business is regulated by the FERC, the U.S. Department of
Transportation and various state and local regulatory agencies. Regulatory
actions taken by those agencies have the potential to adversely affect our
profitability. In particular, the FERC regulates the rates we are permitted to
charge our customers for our services. If our tariff rates were reduced in a
future rate proceeding, if our volume of business under our
9
currently permitted rates was decreased significantly or if we were required to
substantially discount the rates for our services because of competition, our
profitability and liquidity could be reduced.
Further, state agencies and local governments that regulate our local
distribution company customers could impose requirements that could impact
demand for our services.
COSTS OF ENVIRONMENTAL LIABILITIES, REGULATIONS AND LITIGATION COULD EXCEED OUR
ESTIMATES.
Our operations are subject to various environmental laws and regulations.
These laws and regulations obligate us to install and maintain pollution
controls and to clean up various sites at which regulated materials may have
been disposed of or released. We are also party to legal proceedings involving
environmental matters pending in various courts and agencies.
It is not possible for us to estimate reliably the amount and timing of all
future expenditures related to environmental matters because of:
- the uncertainties in estimating clean up costs;
- the discovery of new sites or information;
- the uncertainty in quantifying liability under environmental laws that
impose joint and several liability on all potentially responsible
parties;
- the nature of environmental laws and regulations; and
- the possible introduction of future environmental laws and regulations.
Although we believe we have established appropriate reserves for
liabilities, including clean up costs, we could be required to set aside
additional reserves in the future due to these uncertainties, and these amounts
could be material. For additional information, see Item 8, Financial Statements
and Supplementary Data, Note 10.
OUR OPERATIONS ARE SUBJECT TO OPERATIONAL HAZARDS AND UNINSURED RISKS.
Our operations are subject to the inherent risks normally associated with
those operations, including pipeline ruptures, explosions, pollution, release of
toxic substances, fires and adverse weather conditions, and other hazards, each
of which could result in damage to or destruction of our facilities or damages
to persons and property. In addition, our operations face possible risks
associated with acts of aggression on our assets. If any of these events were to
occur, we could suffer substantial losses.
While we maintain insurance against many of these risks, to the extent and
in amounts that we believe are reasonable, our financial condition and
operations could be adversely affected if a significant event occurs that is not
fully covered by insurance.
RISKS RELATED TO OUR AFFILIATION WITH EL PASO
El Paso files reports, proxy statements and other information with the SEC
under the Securities Exchange Act of 1934, as amended. Each prospective investor
should consider this information and the matters disclosed therein in addition
to the matters described in this report. Such information is not incorporated by
reference herein.
OUR RELATIONSHIP WITH EL PASO AND ITS FINANCIAL CONDITION SUBJECTS US TO
POTENTIAL RISKS THAT ARE BEYOND OUR CONTROL.
Due to our relationship with El Paso, adverse developments or announcements
concerning El Paso could adversely affect our financial condition, even if we
have not suffered any similar development. The senior unsecured indebtedness of
El Paso has been downgraded to below investment grade, currently rated Caa1 by
Moody's (with a negative outlook and under review for a possible downgrade) and
CCC+ by Standard & Poor's (with a negative outlook), Our senior unsecured
indebtedness is rated B1 by Moody's (with a negative
10
outlook and under review for a possible downgrade) and B- by Standard & Poor's
(with a negative outlook). These downgrades will increase our cost of capital
and collateral requirements, and could impede our access to capital markets. As
a result of these recent downgrades, El Paso has realized substantial demands on
its liquidity. These downgrades are a result, at least in part, of the outlook
generally for the consolidated businesses of El Paso and its needs for
liquidity.
El Paso has embarked on its 2003 Long-Range Plan that, among other things,
defines El Paso's future businesses, targets significant debt reduction and
establishes financial goals. An inability to meet these objectives could
adversely affect El Paso's liquidity position, and in turn affect our financial
condition.
Pursuant to El Paso's cash management program, surplus cash is made
available to El Paso in exchange for an affiliated receivable. In addition, we
conduct commercial transactions with some of our affiliates. As of December 31,
2003, we have net receivables of approximately $839 million from El Paso and its
affiliates. El Paso provides cash management and other corporate services for
us. If El Paso is unable to meet its liquidity needs, there can be no assurance
that we will be able to access cash under the cash management program, or that
our affiliates would pay their obligations to us. However, we might still be
required to satisfy affiliated company payables. Our inability to recover any
intercompany receivables owed to us could adversely affect our ability to repay
our outstanding indebtedness. For a further discussion of these matters, see
Item 8, Financial Statements and Supplementary Data, Note 13.
Furthermore, in February 2004, El Paso announced that it had completed a
review of its estimates of natural gas and oil reserves. As a result of this
review, El Paso announced that it was reducing its proved natural gas and oil
reserves by approximately 1.8 Tcfe. El Paso also announced that this reserve
revision would result in a 2003 charge of approximately $1 billion if the full
impact of the revision was taken in that period. In March 2004, El Paso provided
an update and stated that the revisions would likely result in a restatement of
its historical financial statements, the timing and magnitude of which are still
being determined. El Paso has retained a law firm to conduct an internal
investigation, which is ongoing. Also, as a result of the reduction in reserve
estimates, several class action suits have been filed against El Paso and
several of its subsidiaries, but not against us. The reduction in reserve
estimates may also become the subject of an SEC investigation or separate
inquiries by other governmental regulatory agencies. These investigations and
lawsuits may further negatively impact El Paso's credit ratings and place
further demands on its liquidity. See Item 8, Financial Statements and
Supplementary Data, Note 2 for a further discussion of the possible impacts of
this announcement.
WE MAY BE SUBJECT TO A CHANGE IN CONTROL UNDER CERTAIN CIRCUMSTANCES.
In connection with its guarantee of El Paso's $3 billion revolving credit
facility and approximately $1 billion of other transactions our direct parent
pledged its equity interests in us and our equity in Bear Creek to collateralize
those facilities. As a result, our ownership, as well as Bear Creek's ownership
is subject to change if El Paso's lenders under these transactions exercise
rights over their collateral.
A DEFAULT UNDER EL PASO'S $3 BILLION REVOLVING CREDIT FACILITY BY ANY PARTY
COULD ACCELERATE OUR FUTURE BORROWINGS, IF ANY, UNDER THE FACILITY AND OUR
FUTURE ISSUANCES OF LONG-TERM DEBT, WHICH COULD ADVERSELY AFFECT OUR LIQUIDITY
POSITION.
We are a party to El Paso's $3 billion revolving credit facility. We are
only liable, however, for our borrowings under the facility, which were zero as
of December 31, 2003. Under the facility, a default by El Paso, or any other
party, could result in the acceleration of all outstanding borrowings under the
facility, including the borrowings of any non-defaulting party. El Paso's
revisions to its reserve estimates would likely result in a restatement of its
historical financial statements. Any such material restatement would result in
an event of default under El Paso's credit facility, which could result in the
acceleration of any outstanding borrowings by El Paso, and would preclude us
from borrowing under the facility in the future. The acceleration of our future
borrowings, if any, under the credit facility, or the inability to borrow under
the credit facility, could adversely affect our liquidity position and, in turn,
our financial condition.
11
WE COULD BE SUBSTANTIVELY CONSOLIDATED WITH EL PASO IF EL PASO WERE FORCED TO
SEEK PROTECTION FROM ITS CREDITORS IN BANKRUPTCY.
If El Paso were the subject of voluntary or involuntary bankruptcy
proceedings, El Paso and its other subsidiaries and their creditors could
attempt to make claims against us, including claims to substantively consolidate
our assets and liabilities with those of El Paso and its other subsidiaries. The
equitable doctrine of substantive consolidation permits a bankruptcy court to
disregard the separateness of related entities and to consolidate and pool the
entities' assets and liabilities and treat them as though held and incurred by
one entity where the interrelationship between the entities warrants such
consolidation. We believe that any effort to substantively consolidate us with
El Paso and/or its other subsidiaries would be without merit. However, we cannot
assure you that El Paso and/or its other subsidiaries or their respective
creditors would not attempt to advance such claims in a bankruptcy proceeding
or, if advanced, how a bankruptcy court would resolve the issue. If a bankruptcy
court were to substantively consolidate us with El Paso and/or its other
subsidiaries, there could be a material adverse effect on our financial
condition and liquidity.
WE ARE A WHOLLY OWNED SUBSIDIARY OF EL PASO TGPC INVESTMENTS, LLC, AN INDIRECT
SUBSIDIARY OF EL PASO.
As an indirect subsidiary of El Paso, El Paso has substantial control over:
- our payment of dividends;
- decisions on our financings and our capital raising activities;
- mergers or other business combinations;
- our acquisitions or dispositions of assets; and
- our participation in El Paso's cash management program.
El Paso may exercise such control in its interests and not necessarily in
the interests of us or the holders of our long-term debt.
12
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our primary market risk is exposure to changing interest rates. The table
below shows the carrying value and related weighted average effective interest
rates of our interest bearing securities, by expected maturity dates, and the
fair value of these securities. The fair values of our long-term debt securities
have been estimated based on quoted market prices for the same or similar
issues.
<Table>
<Caption>
DECEMBER 31, 2003 DECEMBER 31, 2002
-------------------------------------------------- ---------------------
EXPECTED FISCAL YEAR OF MATURITY OF CARRYING VALUE
-------------------------------------------------- CARRYING
2007 THEREAFTER TOTAL FAIR VALUE AMOUNTS FAIR VALUE
------ ------------ -------- ------------ -------- ----------
(DOLLARS IN MILLIONS)
LIABILITIES:
Long-term debt(1) -- fixed rate.......... $297 $1,300 $1,597 $1,633 $1,595 $1,350
Average interest rate............. 7.1% 7.7%
</Table>
- ---------------
(1) Holders of $300 million of our long-term debt, which has a stated maturity
date of 2027, have the option to redeem these securities in 2007 at par
value. As a result, we assume these amounts will mature in 2007.
13
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
TENNESSEE GAS PIPELINE COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(IN MILLIONS)
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
------------------------
2003 2002 2001
------ ------ ------
Operating revenues.......................................... $ 726 $ 702 $ 728
----- ----- -----
Operating expenses
Operation and maintenance................................. 240 271 238
Depreciation, depletion and amortization.................. 161 149 132
Taxes, other than income taxes............................ 49 46 44
----- ----- -----
450 466 414
----- ----- -----
Operating income............................................ 276 236 314
Earnings from unconsolidated affiliates..................... 15 16 14
Other income................................................ 7 9 9
Interest and debt expense................................... (130) (126) (112)
Affiliated interest income, net............................. 4 9 1
----- ----- -----
Income before income taxes and cumulative effect of
accounting change......................................... 172 144 226
Income taxes................................................ 61 42 72
----- ----- -----
Income before cumulative effect of accounting change........ 111 102 154
Cumulative effect of accounting change, net of income
taxes..................................................... -- 10 --
----- ----- -----
Net income.................................................. $ 111 $ 112 $ 154
Other comprehensive gain (loss)............................. 3 (3) --
----- ----- -----
Comprehensive income........................................ $ 114 $ 109 $ 154
===== ===== =====
</Table>
See accompanying notes.
14
TENNESSEE GAS PIPELINE COMPANY
CONSOLIDATED BALANCE SHEETS
(IN MILLIONS, EXCEPT SHARE AMOUNTS)
<Table>
<Caption>
DECEMBER 31,
----------------
2003 2002
------ ------
ASSETS
Current assets
Cash and cash equivalents................................. $ -- $ --
Accounts and notes receivable
Customer, net of allowance of $4 in 2003 and 2002...... 96 119
Affiliates............................................. 6 110
Other.................................................. 47 76
Materials and supplies.................................... 23 24
Deferred income taxes..................................... 32 47
Other..................................................... 10 14
------ ------
Total current assets.............................. 214 390
------ ------
Property, plant and equipment, at cost...................... 3,238 3,074
Less accumulated depreciation, depletion and
amortization........................................... 540 448
------ ------
2,698 2,626
Additional acquisition cost assigned to utility plant, net
of accumulated amortization............................... 2,198 2,236
------ ------
Total property, plant and equipment, net.......... 4,896 4,862
------ ------
Other assets
Notes receivable from affiliates.......................... 841 599
Investments in unconsolidated affiliates.................. 138 179
Other..................................................... 43 51
------ ------
1,022 829
------ ------
Total assets...................................... $6,132 $6,081
====== ======
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities
Accounts and notes payable
Trade.................................................. $ 47 $ 82
Affiliates............................................. 8 88
Other.................................................. 11 17
Taxes payable............................................. 113 37
Accrued interest.......................................... 25 25
Other..................................................... 59 61
------ ------
Total current liabilities......................... 263 310
------ ------
Long-term debt.............................................. 1,597 1,595
------ ------
Other liabilities
Deferred income taxes..................................... 1,212 1,196
Other..................................................... 208 237
------ ------
1,420 1,433
------ ------
Commitments and contingencies
Stockholder's equity
Common stock, par value $5 per share; authorized 300
shares; issued 208 shares.............................. -- --
Additional paid-in capital................................ 2,205 2,210
Retained earnings......................................... 647 536
Accumulated other comprehensive loss...................... -- (3)
------ ------
Total stockholder's equity........................ 2,852 2,743
------ ------
Total liabilities and stockholder's equity........ $6,132 $6,081
====== ======
</Table>
See accompanying notes.
15
TENNESSEE GAS PIPELINE COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN MILLIONS)
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
-----------------------
2003 2002 2001
----- ----- -----
Cash flows from operating activities
Net income................................................ $ 111 $ 112 $ 154
Adjustments to reconcile net income to net cash from
operating activities
Depreciation, depletion and amortization............... 161 149 132
Undistributed earnings from unconsolidated
affiliates............................................ (7) (16) (14)
Deferred income tax expense............................ 24 81 23
Cumulative effect of accounting change................. -- (10) --
Other non-cash income items............................ 1 (1) 1
Current asset and liability changes, net of non-cash
transactions
Accounts and notes receivable........................ 94 (123) 127
Accounts payable..................................... (122) (7) (49)
Taxes payable........................................ 76 (62) (24)
Other working capital changes
Assets............................................ 3 40 (17)
Liabilities....................................... (2) 2 5
Non-current asset and liability changes
Assets............................................... (7) 11 9
Liabilities.......................................... (28) (36) (86)
----- ----- -----
Net cash provided by operating activities......... 304 140 261
----- ----- -----
Cash flows from investing activities
Additions to property, plant and equipment................ (163) (234) (327)
Proceeds from the sale of investments and assets.......... 57 2 5
Other..................................................... 5 -- (9)
Net change in affiliated advances......................... (203) 274 (139)
----- ----- -----
Net cash provided by (used in) investing
activities...................................... (304) 42 (470)
----- ----- -----
Cash flows from financing activities
Net borrowings (repayments) of commercial paper........... -- (424) 209
Net proceeds from the issuance of long-term debt.......... -- 238 --
----- ----- -----
Net cash provided by (used in) financing
activities...................................... -- (186) 209
----- ----- -----
Decrease in cash and cash equivalents....................... -- (4) --
Cash and cash equivalents
Beginning of period....................................... -- 4 4
----- ----- -----
End of period............................................. $ -- $ -- $ 4
===== ===== =====
</Table>
See accompanying notes.
16
TENNESSEE GAS PIPELINE COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
(IN MILLIONS, EXCEPT SHARE AMOUNTS)
<Table>
<Caption>
ACCUMULATED
COMMON STOCK ADDITIONAL OTHER TOTAL
--------------- PAID-IN RETAINED COMPREHENSIVE STOCKHOLDER'S
SHARES AMOUNT CAPITAL EARNINGS INCOME (LOSS) EQUITY
------ ------ ---------- -------- ------------- -------------
January 1, 2001................... 208 $ -- $1,405 $337 $ -- $1,742
Net income...................... 154 154
Allocated tax benefit of El Paso
equity plans................. 5 5
--- ----- ------ ---- ----- ------
December 31, 2001................. 208 -- 1,410 491 -- 1,901
Net income...................... 112 112
Allocated tax benefits of El
Paso equity plans............ 2 2
Contribution from parent........ 798 798
Non-cash dividend to parent..... (67) (67)
Other comprehensive loss, net of
tax of $1.................... (3) (3)
--- ----- ------ ---- ----- ------
December 31, 2002................. 208 -- 2,210 536 (3) 2,743
Net income...................... 111 111
Allocated tax expense of El Paso
equity plans................. (5) (5)
Sale of Portland Natural Gas
investment, net of tax of
$1........................... 3 3
--- ----- ------ ---- ----- ------
December 31, 2003................. 208 $ -- $2,205 $647 $ -- $2,852
=== ===== ====== ==== ===== ======
</Table>
See accompanying notes.
17
TENNESSEE GAS PIPELINE COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
Our consolidated financial statements include the accounts of all
majority-owned controlled subsidiaries after the elimination of all significant
intercompany accounts and transactions. Our financial statements for prior
periods include reclassifications that were made to conform to the current year
presentation. Those reclassifications had no impact on reported net income or
stockholder's equity.
Principles of Consolidation
We consolidate entities when we have the ability to control the operating
and financial decisions and policies of that entity. Where we can exert
significant influence over, but do not control, those policies and decisions, we
apply the equity method of accounting. We use the cost method of accounting
where we are unable to exert significant influence over the entity. The
determination of our ability to control or exert significant influence over an
entity involves the use of judgment of the extent of our control or influence
and that of the other equity owners or participants of the entity.
Use of Estimates
The preparation of financial statements in conformity with U.S. generally
accepted accounting principles requires the use of estimates and assumptions
that affect the amounts we report as assets, liabilities, revenues and expenses
and our disclosures in these financial statements. Actual results can, and often
do, differ from those estimates.
Regulated Operations
Our natural gas system and storage operations are subject to the
jurisdiction of the Federal Energy Regulatory Commission (FERC) in accordance
with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, and we
currently apply the provisions of Statement of Financial Accounting Standards
(SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. We
perform an annual study to assess the ongoing applicability of SFAS No. 71. The
accounting required by SFAS No. 71 differs from the accounting required for
businesses that do not apply its provisions. Transactions that are generally
recorded differently as a result of applying regulatory accounting requirements
include the capitalization of an equity return component on regulated capital
projects, post retirement employee benefit plans and other costs included in, or
expected to be included in, future rates.
Cash and Cash Equivalents
We consider short-term investments with an original maturity of less than
three months to be cash equivalents.
Allowance for Doubtful Accounts
We establish provisions for losses on accounts receivable and for natural
gas imbalances due from shippers and operators if we determine that we will not
collect all or part of the outstanding balance. We regularly review
collectibility and establish or adjust our allowance as necessary using the
specific identification method.
Materials and Supplies
We value materials and supplies at the lower of cost or market value with
cost determined using the average cost method.
18
Natural Gas Imbalances
Natural gas imbalances occur when the actual amount of natural gas
delivered from or received by a pipeline system or storage facility differs from
the amount of natural gas scheduled to be delivered or received. We value these
imbalances due to or from shippers and operators at specific index prices.
Imbalances are settled in cash or in-kind, subject to the terms of our
settlement.
Imbalances due from others are reported in our balance sheet as either
accounts receivable from customers or accounts receivable from affiliates.
Imbalances owed to others are reported on the balance sheet as either trade
accounts payable or accounts payable to affiliates. In addition, we classify all
imbalances as current.
Property, Plant and Equipment
Our property, plant and equipment is recorded at its original cost of
construction or, upon acquisition, at either the fair value of the assets
acquired or the cost to the entity that first placed the asset in service. We
capitalize direct costs, such as labor and materials, and indirect costs, such
as overhead, interest and an equity return component on regulated businesses as
allowed by the FERC. We capitalize the major units of property replacements or
improvements and expense minor items.
We use the composite (group) method to depreciate property, plant and
equipment. Under this method, assets with similar lives and other
characteristics are grouped and depreciated as one asset. We apply the
FERC-accepted depreciation rate to the total cost of the group until its net
book value equals its salvage value. Currently, our depreciation rates vary from
one to 24 percent. Using these rates, the remaining depreciable lives of these
assets range from 1 to 30 years. We re-evaluate depreciation rates each time we
redevelop our transportation rates when we file with the FERC for an increase or
decrease in rates.
When we retire property, plant and equipment, we charge accumulated
depreciation and amortization for the original cost, plus the cost to remove,
sell or dispose, less its salvage value. We do not recognize a gain or loss
unless we sell an entire operating unit. We include gains or losses on
dispositions of operating units in income.
Additional acquisition cost assigned to utility plant represents the excess
of allocated purchase costs over historical costs of these facilities. These
costs are amortized on a straight-line basis using FERC approved rates, and we
do not recover those excess costs in our rates.
At December 31, 2003 and 2002, we had approximately $88 million and $115
million of construction work in progress included in our property, plant and
equipment.
As a FERC-regulated company, we capitalize a carrying cost (an allowance
for funds used during construction) on funds invested in our construction of
long-lived assets. This carrying cost consists of a return on the investment
financed by debt and a return on the investment financed by equity. The debt
portion is calculated based on our average cost of debt. Debt amounts
capitalized during the years ended December 31, 2003, 2002 and 2001, were $1
million, $3 million and $11 million. These amounts are included as a reduction
to interest expense in our income statement. The equity portion is calculated
using the most recent FERC approved equity rate of return. The equity portion
capitalized during the year ended December 31, 2003, was $3 million (exclusive
of any tax related impacts) and none was capitalized in the years ended December
31, 2002 and 2001. These amounts are included as other non-operating income on
our income statement. Capitalized carrying costs for debt and equity financed
construction are reflected as an increase in the cost of the asset on our
balance sheet.
Asset Impairments
We evaluate our assets for impairment when events or circumstances indicate
that a long-lived asset's carrying value may not be recovered. These events
include market declines, changes in the manner in which we intend to use an
asset or decisions to sell an asset and adverse changes in the legal or business
environment such as adverse actions by regulators. At the time we decide to exit
an activity or sell a long-lived asset or
19
group of assets, we adjust the carrying value of those assets downward, if
necessary, to the estimated sales price, less costs to sell. We classify these
assets as either held for sale or as discontinued operations, depending on
whether they have independently determinable cash flows.
Revenue Recognition
Our revenues consist primarily of transportation and storage services. For
our transportation and storage services, we recognize reservation revenues on
firm contracted capacity ratably over the contract period. For interruptible or
volumetric based services, we record revenues when we complete the delivery of
natural gas to the agreed upon delivery point and when gas is injected or
withdrawn from the storage facility. Revenues for all services are generally
based on the thermal quantity of gas delivered or subscribed at a price
specified in the contract. We are subject to FERC regulations and, as a result,
revenues we collect may possibly be refunded in a final order of a future rate
proceeding or as a result of a rate settlement. We establish reserves for these
potential refunds.
Environmental Costs and Other Contingencies
We record environmental liabilities when our environmental assessments
indicate that remediation efforts are probable, and the costs can be reasonably
estimated. We recognize a current period expense for the liability when the
clean-up efforts do not benefit future periods. We capitalize costs that benefit
more than one accounting period, except in instances where separate agreements
or legal and regulatory guidelines dictate otherwise. Estimates of our
liabilities are based on currently available facts, existing technology and
presently enacted laws and regulations taking into account the likely effects of
inflation and other societal and economic factors, and include estimates of
associated legal costs. These amounts also consider prior experience in
remediating contaminated sites, other companies' clean-up experience and data
released by the Environmental Protection Agency (EPA) or other organizations.
These estimates are subject to revision in future periods based on actual costs
or new circumstances and are included in our balance sheet in other current and
long-term liabilities at their undiscounted amounts. We evaluate recoveries from
insurance coverage, rate recovery, government sponsored and other programs
separately from our liability and, when recovery is assured, we record and
report an asset separately from the associated liability in our financial
statements.
We recognize liabilities for other contingencies when we have an exposure
that, when fully analyzed, indicates it is both probable that an asset has been
impaired or that a liability has been incurred and the amount of impairment or
loss can be reasonably estimated. Funds spent to remedy these contingencies are
charged against a reserve, if one exists, or expensed. When a range of probable
loss can be estimated, we accrue the most likely amount, or at least the minimum
of the range of probable loss.
Income Taxes
We report current income taxes based on our taxable income and we provide
for deferred income taxes to reflect estimated future tax payments and receipts.
Deferred taxes represent the tax impacts of differences between the financial
statement and tax bases of assets and liabilities and carryovers at each year
end. We account for tax credits under the flow-through method, which reduces the
provision for income taxes in the year the tax credits first become available.
We reduce deferred tax assets by a valuation allowance when, based on our
estimates, it is more likely than not that a portion of those assets will not be
realized in a future period. The estimates utilized in the recognition of
deferred tax assets are subject to revision, either up or down, in future
periods based on new facts or circumstances.
El Paso maintains a tax accrual policy to record both regular and
alternative minimum taxes for companies included in its consolidated federal and
state income tax returns. The policy provides, among other things, that (i) each
company in a taxable income position will accrue a current expense equivalent to
its federal and state income taxes, and (ii) each company in a tax loss position
will accrue a benefit to the extent its deductions, including general business
credits, can be utilized in the consolidated returns. El Paso pays all
consolidated U.S. federal and state income taxes directly to the appropriate
taxing jurisdictions and, under a
20
separate tax billing agreement, El Paso may bill or refund its subsidiaries for
their portion of these income tax payments.
2. LIQUIDITY
In February 2004, El Paso announced that it had completed a review of its
estimates of natural gas and oil reserves. As a result of this review, El Paso
announced that it was reducing its proved natural gas and oil reserves by
approximately 1.8 Tcfe. El Paso also announced that this reserve revision would
result in a 2003 charge of approximately $1 billion if the full impact of the
revision was taken in that period. In March 2004, El Paso provided an update and
stated that the revisions would likely result in a restatement of its historical
financial statements, the timing and magnitude of which are still being
determined.
A material restatement of El Paso's prior period financial statements may
result in an "event of default" under El Paso's revolving credit facility and
various other financing transactions; specifically under the provisions of the
facility related to representations and warranties on the accuracy of its
historical financial statements and its debt to total capitalization ratio. El
Paso has received waivers on its revolving credit facility and two other
transactions. These waivers have a condition that provides for the expiration of
the waiver in thirty days, unless El Paso successfully receives waivers on other
specified transactions within that time period. El Paso is pursuing these
additional waivers and expects to receive them. However, if El Paso is unable to
obtain these additional waivers, and there is an existing event of default, El
Paso could be required to immediately repay the amounts outstanding under the
revolving credit facility, and El Paso and we would be precluded from borrowing
under this facility. We currently have no outstanding borrowings under the
facility, have never borrowed under the facility and do not believe we will need
to borrow from the facility in the future. In addition, based upon a review of
the covenants and indentures of our other outstanding indebtedness, we do not
believe that a default on the revolving credit facility would constitute an
event of default on our other debt securities.
El Paso is a significant potential source of liquidity to us. We
participate in El Paso's cash management program. Under this program, depending
on whether we have short-term cash surpluses or requirements, we either provide
cash to El Paso or El Paso provides cash to us. We have historically and
consistently provided cash to El Paso under this program, and as of December 31,
2003, we had a cash advance receivable from El Paso of $841 million, classified
as a non-current asset in our balance sheet. If El Paso were unable to meet its
liquidity needs, we would not have access to this source of liquidity and there
is no assurance that El Paso could repay the entire amounts owed to us. In that
event, we could be required to write-off some amount of these advances, which
could have a material impact on our stockholder's equity. Furthermore, we would
still be required to repay affiliated company payables. Non-cash write-downs
that cause our debt to EBITDA (as defined in our agreements) ratio to fall below
5 to 1 could prohibit us from incurring additional debt. However, this non-cash
equity reduction would not result in a default under our existing debt
securities. In addition, based on our current estimates of cash flows, we do not
believe we will need to seek repayment of all or part of these advances in the
next year.
El Paso's ownership interest in us and our equity investment in Bear Creek
serve as collateral under El Paso's revolving credit facility and other of El
Paso's borrowings. If El Paso's lenders under this facility or those borrowings
were to exercise their rights to this collateral, our ownership could change and
our investment in Bear Creek could be liquidated. However, this change of
control and liquidation would not constitute an event of default under our
existing debt securities.
If, as a result of the events described above, El Paso were subject to
voluntary or involuntary bankruptcy proceedings, El Paso and its other
subsidiaries and their creditors could attempt to make claims against us,
including claims to substantively consolidate our assets and liabilities with
those of El Paso and its other subsidiaries. We believe that claims to
substantively consolidate us with El Paso and/or its other subsidiaries would be
without merit. However, there is no assurance that El Paso and/or its other
subsidiaries or their creditors would not advance such a claim in a bankruptcy
proceeding. If we were to be substantively consolidated in a bankruptcy
proceeding with El Paso and/or its other subsidiaries, there could be a material
adverse effect on our financial condition and our liquidity.
21
3. INCOME TAXES
The following table reflects the components of income tax expense included
in income before cumulative effect of accounting change for each of the three
years ended December 31:
<Table>
<Caption>
2003 2002 2001
---- ---- ----
(IN MILLIONS)
Current
Federal................................................... $ 37 $(35) $ 58
State..................................................... -- (4) (9)
---- ---- ----
37 (39) 49
---- ---- ----
Deferred
Federal................................................... 27 89 25
State..................................................... (3) (8) (2)
---- ---- ----
24 81 23
---- ---- ----
Total income tax expense.......................... $ 61 $ 42 $ 72
==== ==== ====
</Table>
Our income tax expense included in income before cumulative effect of
accounting change differs from the amount computed by applying the statutory
federal income tax rate of 35 percent for the following reasons for each of the
three years ended December 31:
<Table>
<Caption>
2003 2002 2001
---- ---- ----
(IN MILLIONS)
Income tax expense at the statutory federal rate of 35%..... $60 $50 $79
Items creating rate differences:
State income tax, net of federal income tax effect........ (6) (8) (7)
Change in the realizability of deferred tax assets for:
Federal net operating loss carryover of an acquired
company.............................................. -- 2 --
State net operating loss carryovers.................... 4 -- --
Sale of investment........................................ 3 -- --
Valuation allowances...................................... -- (2) --
--- --- ---
Income tax expense........................................ $61 $42 $72
=== === ===
Effective tax rate........................................ 35% 29% 32%
=== === ===
</Table>
22
The following are the components of our net deferred tax liability as of
December 31:
<Table>
<Caption>
2003 2002
------ ------
(IN MILLIONS)
Deferred tax liabilities
Property, plant and equipment............................. $1,404.. $1,402
Other..................................................... 144 147
------ ------
Total deferred tax liability...................... 1,548 1,549
------ ------
Deferred tax assets
Net operating loss and credit carryovers
U.S. Federal........................................... 156 183
State.................................................. 89 84
Accrual for regulatory issues............................. 10 23
Environmental liability................................... 56 61
Other liabilities......................................... 57 49
------ ------
Total deferred tax asset.......................... 368 400
------ ------
Net deferred tax liability.................................. $1,180.. $1,149
====== ======
</Table>
Under El Paso's tax accrual policy, we are allocated the tax effects
associated with our employees' non-qualified dispositions of employee stock
purchase plan stock, the exercise of non-qualified stock options and the vesting
of restricted stock as well as restricted stock dividends. This allocation
increased taxes payable by $5 million in 2003 and reduced taxes payable by $2
million in 2002 and $5 million in 2001. These tax effects are included in
additional paid-in capital in our balance sheet.
As of December 31, 2003, we had $1 million of alternative minimum tax
credit carryovers and $443 million of federal net operating loss carryovers. The
alternative minimum tax credits carryover indefinitely. The carryover period for
the net operating loss ends as follows: approximately $130 million in 2018; $75
million in 2019; $17 million in 2020; $179 million in 2021 and $42 million in
2023. Usage of these carryovers is subject to the limitations provided under
Sections 382 and 383 of the Internal Revenue Code as well as the separate return
limitation year rules of IRS regulations.
As of December 31, 2003, we had $1,128 million of state net operating loss
carryovers. These carryovers, if not utilized, will expire in varying amounts
over the period from 2004 to 2021.
4. FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair values of our financial instruments
are as follows at December 31:
<Table>
<Caption>
2003 2002
--------------------- ---------------------
CARRYING CARRYING
AMOUNT FAIR VALUE AMOUNT FAIR VALUE
-------- ---------- -------- ----------
(IN MILLIONS)
Balance sheet financial instruments:
Long-term debt(1).......................... $1,597 $1,633 $1,595 $1,350
</Table>
- ---------------
(1) We estimated the fair value of debt with fixed interest rates based on
quoted market prices for the same or similar issues.
As of December 31, 2003 and 2002, the carrying amounts of cash and cash
equivalents, short-term borrowings, and trade receivables and payables are
representative of fair value because of the short-term maturity of these
instruments.
23
5. CUMULATIVE EFFECT OF ACCOUNTING CHANGE
We apply the provisions of SFAS No. 141, Business Combinations, and SFAS
No. 142, Goodwill and Other Intangible Assets. SFAS No. 141 requires that upon
adoption of SFAS No. 142, any negative goodwill should be written off as a
cumulative effect of an accounting change. Prior to adoption of the standards,
we had negative goodwill associated with our 30 percent investment in Portland
Natural Gas Transmission System (PNGTS), that we amortized using the
straight-line method. As a result of our adoption of these standards on January
1, 2002, we stopped this amortization and recognized a gain of $10 million
(before and after-tax) related to the write-off of negative goodwill as a
cumulative effect of an accounting change. Had we continued to amortize negative
goodwill, our reported income for the year ended December 31, 2002, would not
have been materially different. In addition, had we applied the amortization
provisions of these standards on January 1, 2001, our reported income for the
year ended December 31, 2001, would not have materially differed.
6. ACCUMULATED OTHER COMPREHENSIVE LOSS
Our accumulated other comprehensive income at December 31, 2002, included a
loss of $3 million, net of $1 million in income taxes, representing our
proportionate share of amounts recorded in other comprehensive loss by PNGTS,
our equity investees related to their derivative hedging activities. For the
year ended December 31, 2003, and 2002 PNGTS did not record any ineffectiveness
in earnings on its cash flow hedges. In the fourth quarter of 2003, we sold our
30 percent ownership interest in PNGTS and eliminated the accumulated other
comprehensive loss associated with this investment.
7. REGULATORY ASSETS AND LIABILITIES
Below are the details of our regulatory assets and liabilities at December
31:
<Table>
<Caption>
REMAINING
DESCRIPTION 2003 2002 RECOVERY PERIOD
----------- ---- ---- ---------------
(IN MILLIONS)
Current regulatory assets(1)................... $ 2 $ 3 1 year
Non-current regulatory assets
Postretirement benefits(1)................... 15 17 9 years
Grossed-up deferred taxes on capitalized
funds used during construction(1)......... 15 13 14 years
Under-collected state income tax............. -- 3 1 year
Unamortized net loss on reacquired debt(1)... 3 4 14 years
Other(1)..................................... 2 5 1 year
---- ----
Total regulatory assets.............. $ 37 $ 45
==== ====
Current regulatory liabilities
Cashout imbalance settlement(1).............. $ 9 $ 8 N/A
Excess deferred federal income taxes......... 1 -- 1 year
Non-current regulatory liabilities
Postretirement benefits(1)................... 11 9 N/A
Excess deferred federal income taxes......... -- 9 1 year
Plant regulatory liability(1)................ 11 11 N/A
Cost of removal of off-shore assets.......... 34 36 N/A
Environmental liability(1)................... 87 55 N/A
---- ----
Total regulatory liabilities......... $153 $128
==== ====
</Table>
- ---------------
(1) These amounts are not included in our rate base on which we earn a current
return.
Our regulatory assets and liabilities are included in other current and
non-current assets and liabilities in our balance sheet.
24
8. PROPERTY, PLANT AND EQUIPMENT
As of December 31, 2003, additional acquisition costs assigned to utility
plant was approximately $2 billion and accumulated depreciation was
approximately $180 million. These excess costs are being amortized over the life
of the related pipeline assets. Our amortization expense during 2003 was
approximately $38 million and during 2002 it was $34 million.
9. DEBT AND OTHER CREDIT FACILITIES
Our long-term debt outstanding consisted of the following at December 31:
<Table>
<Caption>
2003 2002
------ ------
(IN MILLIONS)
7.0% Debentures due 2027................................... $ 300 $ 300
6.0% Debentures due 2011................................... 86 86
7.5% Debentures due 2017................................... 300 300
7.0% Debentures due 2028................................... 400 400
8.375% Notes due 2032...................................... 240 240
7.625% Debentures due 2037................................. 300 300
------ ------
1,626 1,626
Less: Unamortized discount................................. 29 31
------ ------
Long-term debt................................... $1,597 $1,595
====== ======
</Table>
The holders of the $300 million 7.0% debentures due 2027 have the option to
require us to redeem their debentures at par value in 2007. The maturity
schedule of our long-term debt presented below assumes the holders will exercise
this option.
<Table>
<Caption>
(IN MILLIONS)
2007........................................................ $ 300
Thereafter.................................................. 1,326
------
$1,626
======
</Table>
Credit Facilities
In April 2003, El Paso entered into a new $3 billion revolving credit
facility, with a $1.5 billion letter of credit sublimit, which matures on June
30, 2005. The credit facility has a borrowing cost of LIBOR plus 350 basis
points, letter of credit fees of 350 basis points and a commitment fee of 75
basis points on the unused portion of the facility. This facility replaces El
Paso's previous $3 billion revolving credit facility. El Paso's $1 billion
revolving credit facility (which matured in August 2003) and approximately $1
billion of other El Paso financing arrangements (including leases, letters of
credit and other facilities) were also amended to conform El Paso's obligations
under those arrangements to the new credit facility. We, along with El Paso and
our affiliates, ANR Pipeline Company, Colorado Interstate Gas Company and El
Paso Natural Gas Company (EPNG), are borrowers under the $3 billion revolving
credit facility and El Paso's equity in several of its subsidiaries, including
its equity in us and our equity in Bear Creek, collateralizes the credit
facility and the other financing arrangements. We are only liable for amounts we
directly borrow. As of December 31, 2003, $850 million was outstanding and $1.2
billion in letters of credit were issued, none of which were borrowed by or
issued on behalf of us. See Note 2 for a discussion regarding El Paso's possible
default on the $3 billion revolving credit facility.
We were jointly and severally liable for any outstanding amounts under El
Paso's $1 billion revolving credit facility through its maturity in August 2003,
and El Paso's $3 billion revolving credit facility through August 2003.
Under the new $3 billion revolving credit facility and other indentures, we
are subject to a number of restrictions and covenants. The most restrictive of
these include (i) limitations on the incurrence of additional debt, based on a
ratio of debt to EBITDA (as defined in the agreements); (ii) limitations on the
use of
25
proceeds from borrowings; (iii) limitations, in some cases, on transactions with
our affiliates; (iv) limitations on the incurrence of liens; (v) potential
limitations on our ability to declare and pay dividends; and (vi) potential
limitations on our ability to participate in the El Paso cash management program
discussed in Note 13. For the year ended December 31, 2003, we were in
compliance with these covenants.
10. COMMITMENTS AND CONTINGENCIES
Legal Proceedings
Grynberg. In 1997, we and a number of our affiliates were named defendants
in actions brought by Jack Grynberg on behalf of the U.S. Government under the
False Claims Act. Generally, these complaints allege an industry-wide conspiracy
to underreport the heating value as well as the volumes of the natural gas
produced from federal and Native American lands, which deprived the U.S.
Government of royalties. The plaintiff in this case seeks royalties that he
contends the government should have received had the volume and heating value
been differently measured, analyzed, calculated and reported, together with
interest, treble damages, civil penalties, expenses and future injunctive relief
to require the defendants to adopt allegedly appropriate gas measurement
practices. No monetary relief has been specified in this case. These matters
have been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui
Tam Litigation, U.S. District Court for the District of Wyoming, filed June
1997). Discovery is proceeding. Our costs and legal exposure related to these
lawsuits and claims are not currently determinable.
Will Price (formerly Quinque). We and a number of our affiliates are named
defendants in Will Price, et al. v. Gas Pipelines and Their Predecessors, et
al., filed in 1999 in the District Court of Stevens County, Kansas. Plaintiffs
allege that the defendants mismeasured natural gas volumes and heating content
of natural gas on non-federal and non-Native American lands and seek to recover
royalties that they contend they should have received had the volume and heating
value of natural gas produced from their properties been differently measured,
analyzed, calculated and reported, together with prejudgment and postjudgment
interest, punitive damages, treble damages, attorneys' fees, costs and expenses,
and future injunctive relief to require the defendants to adopt allegedly
appropriate gas measurement practices. No monetary relief has been specified in
this case. Plaintiffs' motion for class certification of a nationwide class of
natural gas working interest owners and natural gas royalty owners was denied on
April 10, 2003. Plaintiffs were granted leave to file a Fourth Amended Petition,
which narrows the proposed class to royalty owners in wells in Kansas, Wyoming
and Colorado and removes claims as to heating content. A second class action has
since been filed as to the heating content claim. Our costs and legal exposure
related to these lawsuits and claims are not currently determinable.
In addition to the above matters, we and our subsidiaries and affiliates
are named defendants in numerous lawsuits and governmental proceedings that
arise in the ordinary course of our business.
For each of our outstanding legal matters, we evaluate the merits of the
case, our exposure to the matter, possible legal or settlement strategies and
the likelihood of an unfavorable outcome. If we determine that an unfavorable
outcome is probable and can be estimated, we establish the necessary accruals.
As this information becomes available, or other relevant developments occur, we
will adjust our accrual amounts accordingly. While there are still uncertainties
related to the ultimate costs we may incur, based upon our evaluation and
experience to date, we believe our current reserves are adequate. As of December
31, 2003, we had no material accruals for our outstanding legal matters.
Environmental Matters
We are subject to federal, state and local laws and regulations governing
environmental quality and pollution control. These laws and regulations require
us to remove or remedy the effect on the environment of the disposal or release
of specified substances at current and former operating sites. As of December
31, 2003, we had accrued approximately $46 million, including approximately $45
million for expected remediation costs and associated onsite, offsite and
groundwater technical studies and approximately $1 million for related
environmental legal costs, which we anticipate incurring through 2027. Our
accrual at December 31, 2003 was
26
based on the most likely outcome that can be reasonably estimated. Below is a
reconciliation of our accrued liability as of December 31, 2003 (in millions):
<Table>
Balance as of January 1, 2003............................... $ 84
Additions/adjustments for remediation activities(1)......... (31)
Payments for remediation activities......................... (7)
----
Balance as of December 31, 2003............................. $ 46
====
</Table>
- ---------------
(1) Represents a reduction in the estimated costs to complete our internal PCB
remediation project as discussed below.
In addition, we expect to make capital expenditures for environmental
matters of approximately $42 million in the aggregate for the years 2004 through
2008. These expenditures primarily relate to compliance with clean air
regulations. For 2004, we estimate that our total remediation expenditures will
be approximately $6 million. All of this amount is being expended under
government directed clean-up plans.
Internal PCB Remediation Project. Since 1988, we have been engaged in an
internal project to identify and address the presence of polychlorinated
biphenyls (PCBs) and other substances, including those on the EPA's List of
Hazardous Substances (HSL), at compressor stations and other facilities we
operate. While conducting this project, we have been in frequent contact with
federal and state regulatory agencies, both through informal negotiation and
formal entry of consent orders. We executed a consent order in 1994 with the
EPA, governing the remediation of the relevant compressor stations and are
working with the EPA and the relevant states regarding those remediation
activities. We are also working with the Pennsylvania and New York environmental
agencies regarding remediation and post-remediation activities at our
Pennsylvania and New York stations. In May 2003 we finalized a new estimate of
the cost to complete the PCB/HSL Project. Over the years there have been
developments that impacted various individual components, but our ability to
estimate a more likely outcome for the total project has not been possible until
recently. The new estimate identified a $31 million reduction in our estimated
cost to complete the project.
PCB Cost Recoveries. In May 1995, following negotiations with our
customers, we filed an agreement with the FERC that established a mechanism for
recovering a substantial portion of the environmental costs identified in our
internal remediation project. The agreement, which was approved by the FERC in
November 1995, provided for a PCB surcharge on firm and interruptible customers'
rates to pay for eligible costs under the PCB remediation project, with these
surcharges to be collected over a defined collection period. We have twice
received approval from the FERC to extend the collection period, which is now
currently set to expire in June 2004. The agreement also provided for bi-annual
audits of eligible costs. As of December 31, 2003, we had pre-collected our PCB
costs by approximately $119 million. The pre-collection will be reduced by
future eligible costs incurred for the remainder of the remediation project. To
the extent actual eligible expenditures are less than the amounts pre-collected,
we will refund to our customers the pre-collection amount plus carrying charges
incurred up to the date of the refunds.
As of December 31, 2003, we have recorded a regulatory liability (included
in other non-current liabilities on our balance sheet) of $87 million for future
refund obligations, of which $25 million was recorded in 2003 related to the
reduction in the estimate to complete our PCB remediation project.
Kentucky PCB Project. In November 1988, the Kentucky environmental agency
filed a complaint in a Kentucky state court alleging that we discharged
pollutants into the waters of the state and disposed of PCBs without a permit.
The agency sought an injunction against future discharges, an order to remediate
or remove PCBs and a civil penalty. We entered into interim agreed orders with
the agency to resolve many of the issues raised in the complaint. The relevant
Kentucky compressor stations are being remediated under a 1994 consent order
with the EPA. Despite our remediation efforts, the agency may raise additional
technical issues or seek additional remediation work in the future.
CERCLA Matters. We have received notice that we could be designated, or
have been asked for information to determine whether we could be designated, as
a Potentially Responsible Party (PRP) with respect to three active sites under
the Comprehensive Environmental Response, Compensation and Liability
27
Act (CERCLA) or state equivalents. We have sought to resolve our liability as a
PRP at these sites through indemnification by third parties and settlements
which provide for payment of our allocable share of remediation costs. As of
December 31, 2003 we have estimated our share of the remediation costs at these
sites to be between $1 million and $2 million. Since the clean-up costs are
estimates and are subject to revision as more information becomes available
about the extent of remediation required, and because in some cases we have
asserted a defense to any liability, our estimates could change. Moreover,
liability under the federal CERCLA statute is joint and several, meaning that we
could be required to pay in excess of our pro rata share of remediation costs.
Our understanding of the financial strength of other PRPs has been considered,
where appropriate, in estimating our liabilities. Reserves for these matters are
included in the environmental reserve discussed above.
It is possible that new information or future developments could require us
to reassess our potential exposure related to environmental matters. We may
incur significant costs and liabilities in order to comply with existing
environmental laws and regulations. It is also possible that other developments,
such as increasingly strict environmental laws and regulations and claims for
damages to property, employees, other persons and the environment resulting from
our current or past operations, could result in substantial costs and
liabilities in the future. As this information becomes available, or other
relevant developments occur, we will adjust our accrual amounts accordingly.
While there are still uncertainties relating to the ultimate costs we may incur,
based upon our evaluation and experience to date, we believe our reserves are
adequate.
Rates and Regulatory Matters
Order No. 637. We filed our compliance proposal in August 2000 and
received an order on compliance from the FERC in April 2002. Most of our
compliance proposal was accepted, but the FERC rejected our proposals regarding
overlapping capacity segments, discounting and the priority of capacity. In
response, we sought rehearing and have made another compliance filing. On
October 31, 2002, FERC issued its order responding to the United States Court of
Appeals for the D.C. Circuit's order remanding the various aspects of Order No.
637. On December 2, 2002, we submitted a compliance filing with FERC to comply
with the October 31 order. We also filed for rehearing of the October 31 order.
On July 11, 2003, the FERC issued an order on our rehearing request and
compliance filing as to the April 3, 2002 Order, denying our request for
rehearing regarding a replacement shipper's ability to select additional primary
points, forwardhauls and backhauls to the same delivery point, and discounting.
We filed certain required tariff revisions in response to that order and sought
further rehearing of certain issues. The Commission has not yet issued an order
on these filings. We have implemented most of Order No. 637 provisions on
October 1, 2003, except for point elevations, for which we have sought an April
1, 2004 effective date. On February 20, 2004, the Court of Appeals for the D.C.
Circuit vacated certain Commission orders that applied its Order No. 637
discounting policy to Williston Basin pipeline. We cannot predict the outcome of
the compliance filings or the requests for rehearing.
There are other regulatory rules and orders in various stages of adoption,
review and/or implementation, none of which we believe will have a material
impact on us.
While the outcome of our outstanding rates and regulatory matters cannot be
predicted with certainty, based on current information and our existing
accruals, we do not expect the ultimate resolution of these matters to have a
material adverse effect on our financial position, operating results or cash
flows. However, it is possible that new information or future developments could
require us to reassess our potential exposure and accruals related to these
matters. The impact of these changes may have a material effect on our results
of operations, our financial position, and on our cash flows in the period the
event occurs.
Capital Commitments and Purchase Obligations
At December 31, 2003, we had capital and investment commitments of $3
million. Our other planned capital and investment projects are discretionary in
nature, with no substantial capital commitments made in advance of the actual
expenditures. We have entered into unconditional purchase obligations for
products and services, including financing commitments with one of our joint
ventures, totaling $162 million at
28
December 31, 2003. Our annual obligations under these agreements are $37 million
for 2004, $34 million for 2005, $24 million for 2006, $14 million for 2007, $11
million for 2008 and $42 million in total thereafter.
Operating Leases
We lease property, facilities and equipment under various operating leases.
Minimum future annual rental commitments on operating leases as of December 31,
2003, were as follows:
<Table>
<Caption>
YEAR ENDING
DECEMBER 31, OPERATING LEASES
- ------------------------------------------------------------ ----------------
(IN MILLIONS)
2004..................................................... $ 3
2005..................................................... 2
2006..................................................... 2
2007..................................................... 1
2008..................................................... 1
Thereafter............................................... 9
---
Total............................................. $18
===
</Table>
Rental expense for operating leases for each of the years ended December
31, 2003, 2002 and 2001 was $6 million, $5 million and $6 million.
11. RETIREMENT BENEFITS
Pension and Retirement Benefits
El Paso maintains a pension plan to provide benefits determined under a
cash balance formula covering substantially all of its U.S. employees, including
our employees. El Paso also maintains a defined contribution plan covering its
U.S. employees, including our employees. Prior to May 1, 2002, El Paso matched
75 percent of participant basic contributions up to 6 percent, with matching
contributions being made to the plan's stock fund, which participants could
diversify at any time. After May 1, 2002, the plan was amended to allow for
matching contributions to be invested in the same manner as that of participant
contributions. In March 2003, El Paso suspended the matching contribution.
Effective July 1, 2003, El Paso began making matching contributions again at a
rate of 50 percent of participant contributions up to 6 percent. El Paso is
responsible for benefits accrued under its plans and allocates the related costs
to its affiliates.
Other Postretirement Benefits
We maintain responsibility for postretirement medical and life insurance
benefits for a closed group of retirees who were eligible to retire on December
31, 1996, and did so before July 1, 1997. Medical benefits for this closed group
may be subject to deductibles, co-payment provisions, and other limitations and
dollar caps on the amount of employer costs. We have reserved the right to
change these benefits. Employees who retire after July 1, 1997 will continue to
receive limited postretirement life insurance benefits. Postretirement benefit
plan costs are prefunded to the extent these costs are recoverable through our
rates. In 1992, we began recovering through our rates the other postretirement
benefits (OPEB) costs included in the June 1993 rate case settlement. To the
extent actual OPEB costs differ from the amounts funded, a regulatory asset or
liability is recorded. We expect to contribute $4 million to our other
postretirement benefit plan in 2004.
On December 8, 2003, the Medicare Prescription Drug Improvement and
Modernization Act of 2003 was signed into law. The benefit obligations and costs
reported below, which include benefits related to prescription drug coverage, do
not reflect the impact of this legislation. Current accounting standards that
are not yet effective may require changes to previously reported benefit
information once they are finalized.
29
The following table sets forth the change in benefit obligation, change in
plan assets, reconciliation of funded status, and components of net periodic
benefit cost for other postretirement benefits as of and for the twelve months
ended September 30 (the plan reporting date):
<Table>
<Caption>
2003 2002
----- -----
(IN MILLIONS)
Change in benefit obligation
Benefit obligation at beginning of period................. $ 26 $ 26
Interest cost............................................. 2 2
Participant contributions................................. 1 1
Actuarial loss............................................ 1 1
Benefits paid............................................. (4) (4)
---- ----
Benefit obligation at end of period....................... $ 26 $ 26
==== ====
Change in plan assets
Fair value of plan assets at beginning of period.......... $ 11 $ 9
Actual return on plan assets.............................. 2 --
Employer contributions.................................... 4 5
Participant contributions................................. 1 1
Benefits paid............................................. (4) (4)
---- ----
Fair value of plan assets at end of period................ $ 14 $ 11
==== ====
Reconciliation of funded status
Under funded status at September 30,...................... $(12) $(15)
Fourth quarter contributions and income................... 2 1
Unrecognized net actuarial gain........................... (5) (4)
Unrecognized prior service cost........................... -- (1)
---- ----
Net accrued benefit cost at December 31,.................. $(15)(1) $(19)
==== ====
</Table>
- ---------------
(1) Based on our current funded status, we have reflected approximately $2
million of our accrued benefit obligation as a current liability at December
31, 2003 and 2002.
Our postretirement benefit costs recorded in operating expenses include the
following components for the year ended December 31:
<Table>
<Caption>
2003 2002 2001
----- ----- -----
(IN MILLIONS)
Interest cost............................................... $ 2 $ 2 $ 2
Expected return on plan assets.............................. (1) -- --
----- ----- -----
Net periodic benefit cost................................... $ 1 $ 2 $ 2
===== ===== =====
</Table>
The following table details the weighted average assumptions we used for
our other postretirement plans for 2003, 2002 and 2001:
<Table>
<Caption>
2003 2002 2001
----- ---- ----
Assumptions related to benefit obligations at September 30:
Discount rate............................................. 6.00% 6.75%
Assumptions related to benefit costs at December 31:
Discount rate............................................. 6.75% 7.25% 7.75%
Long-term rate return on plan assets(1)................... 7.50% 7.50% 7.50%
</Table>
- ---------------
(1) The expected return on plan assets is a pre-tax rate (before a tax rate
ranging from 38% to 39% on postretirement benefits) that is primarily based
on an expected risk-free investment return, adjusted for historical risk
premiums and specific risk adjustments associated with our debt and equity
securities. These expected returns were then weighted based on our target
asset allocations of our investment portfolio.
30
Actuarial estimates for our postretirement benefits plans assumed a
weighted average annual rate of increase in the per capita costs of covered
health care benefits of 10.0 percent in 2003, gradually decreasing to 5.5
percent by the year 2008. Assumed health care cost trends can have a significant
effect on the amounts reported for other postretirement benefit plans. However,
it does not affect our costs because our costs are limited by defined dollar
caps.
Other Postretirement Plan Assets
The following table provides the actual asset allocations in our
postretirement plan as of September 30:
<Table>
<Caption>
ASSET CATEGORY ACTUAL 2003 ACTUAL 2002
- -------------- ------------ ------------
Equity securities........................................... 24% --%
Debt securities............................................. 51 --
Other....................................................... 25 100
--- ---
Total..................................................... 100% 100%
=== ===
</Table>
The target allocation for the invested assets is 65% equity/35% fixed
income. In late 2003, we modified our target asset allocations for our
postretirement plan to increase our equity allocation to 65 percent of total
plan assets. As of September 30, 2003, we had not yet adjusted our portfolio's
investments to reflect this change in strategy. Other assets are held in cash
for payment of benefits upon presentment. Any El Paso stock held by the plan is
held indirectly through investments in mutual funds.
The primary investment objective of our plan is to ensure, that over the
long-term life of the plan, an adequate pool of sufficiently liquid assets
exists to support the benefit obligation to participants, retirees and
beneficiaries. In meeting this objective, the plan seeks to achieve a high level
of investment return consistent with a prudent level of portfolio risk.
Investment objectives are long-term in nature covering typical market cycles of
three to five years. Any shortfall or investment performance compared to
investment objectives is generally the result of general economic and capital
market conditions.
12. SUPPLEMENTAL CASH FLOW INFORMATION
The following table contains supplemental cash flow information for each of
the three years ended December 31:
<Table>
<Caption>
2003 2002 2001
---- ---- ----
(IN MILLIONS)
Interest paid, net of capitalized interest.................. $119 $107 $ 89
Income tax payments (refunds)............................... (65) 43 81
</Table>
13. INVESTMENTS IN UNCONSOLIDATED AFFILIATES AND TRANSACTIONS WITH AFFILIATES
As of December 31, 2003, we have a 50 percent ownership interest in Bear
Creek, a joint venture with Southern Gas Storage Company, our affiliate. Bear
Creek owns and operates an underground natural gas storage facility located in
Louisiana. The facility has a capacity of 50 Bcf of base gas and 58 Bcf of
working storage. Bear Creek's working storage capacity is committed equally to
SNG, and our pipeline system under long-term contracts. Our investment in Bear
Creek as of December 31, 2003 and 2002, was $138 million and $128 million. We
recognized equity earnings of $12 million in 2003 and 2002 and $14 million in
2001.
In the fourth quarter of 2003, we sold our 30 percent interest in PNGTS to
TransCanada Corporation for approximately $56 million. We recorded a pre-tax
loss of approximately of $2 million related to this sale in our earnings from
unconsolidated affiliates. As of December 31, 2002 our investment in PNGTS was
$51 million. We recognized equity earnings of $5 million in 2003, $4 million in
2002 and equity losses of less than $1 million in 2001.
Summarized financial information of our proportionate share of
unconsolidated affiliates are presented below. The difference in our carrying
amount and our equity in the net assets of these investments as of
31
December 31, 2002, was due to a $3 million other comprehensive loss, which was
eliminated in 2003 with the sale of our investment in PNGTS.
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
-------------------------
2003 2002 2001
----- ----- -----
(UNAUDITED)
(IN MILLIONS)
Operating results data:(1)
Operating revenues.......................................... $31 $34 $28
Operating expenses.......................................... 12 14 12
Income from continuing operations........................... 12 11 8
Net income.................................................. 12 11 8
</Table>
- ---------------
(1) Includes PNGTS through September 2003.
<Table>
<Caption>
DECEMBER 31,
--------------
2003 2002
----- -----
(UNAUDITED)
(IN MILLIONS)
Financial position data:
Current assets.............................................. $ 73 $ 71
Non-current assets.......................................... 89 214
Other current liabilities................................... 20 102
Other non-current liabilities............................... 4 7
Equity in net assets........................................ 138 176
</Table>
Transactions with Affiliates
We participate in El Paso's cash management program which matches
short-term cash surpluses and needs of its participating affiliates, thus
minimizing total borrowing from outside sources. As of December 31, 2003 and
2002, we had advanced to El Paso $841 million and $599 million. The market rate
of interest at December 31, 2003 was 2.8% and at December 31,2002, was 1.5%.
These receivables are due upon demand; however, as of December 31, 2003 and
2002, we have classified these amounts as non-current notes receivable from
affiliates because we do not anticipate settlement within the next twelve
months. In addition, we had a demand note receivable with El Paso of $38 million
at December 31, 2002, at an interest rate of 2.21%. See Note 2 for a discussion
regarding our participation in and the collectibility of these receivables.
At December 31, 2003 and 2002, we had accounts receivable from related
parties of $6 million and $72 million. In addition, we had accounts payable to
related parties of $8 million and $88 million at December 31, 2003 and 2002.
These balances arose in the normal course of business. We have received $5
million in deposits related to our transportation contracts with El Paso
Merchant Energy L.P. (EPME) which is included in our balance sheet as other
current liabilities as of December 31, 2003 and 2002. These deposits were
required as a result of the credit rating downgrade of El Paso.
During 2002, we received a capital contribution of $798 million of
affiliate accounts payable to our parent and other El Paso affiliates. We
accounted for the contribution as an increase in additional paid-in capital. In
addition, we declared a non-cash dividend totaling $67 million, representing a
distribution of affiliate receivables, to our parent. The dividend was recorded
as a reduction of retained earnings.
During 2003, 2002 and 2001 we transported gas for an affiliate, EPME, and
recognized revenues of $27 million, $74 million and $79 million.
El Paso allocates a portion of its general and administrative expenses to
us. The allocation is based on the estimated level of effort devoted to our
operations and the relative size of our EBIT, gross property and payroll. For
each of the years ended December 31, 2003, 2002, and 2001 the annual charges
were $69 million, $97 million and $67 million. During 2003 and 2002, we
performed operational, financial, accounting and administrative services for El
Paso's other pipeline systems. For each of the years ended December 31, 2003,
2002 and 2001, the amounts received for these services were $51 million, $39
million and $38 million. We
32
record these amounts as reimbursements of operating expenses. We believe the
allocation methods are reasonable.
We store natural gas in an affiliated storage facility and utilized an
affiliated pipeline (ANR Pipeline Company) to transport some of our natural gas
during 2003 and 2002. These costs were $2 million and $5 million for these
periods and are recorded as operating expenses. These activities were entered
into in the normal course of our business and are based on the same terms as
non-affiliates.
The following table shows revenues and charges from our affiliates for each
of the three years ended December 31:
<Table>
<Caption>
2003 2002 2001
---- ---- ----
(IN MILLIONS)
Revenues from affiliates.................................... $37 $ 82 $81
Operation and maintenance expense from affiliates........... 71 102 69
Reimbursement for operating expenses from affiliates........ 51 39 38
</Table>
14. SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Financial information by quarter is summarized below:
<Table>
<Caption>
QUARTERS ENDED
-----------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 TOTAL
-------- ------- ------------ ----------- -----
(IN MILLIONS)
2003
Operating revenues............... $212 $168 $161 $185 $726
Operating income................. 95 54 50 77 276
Income before cumulative effect
of accounting change.......... 49 20 17 25 111
Net income....................... 49 20 17 25 111
2002
Operating revenues............... $188 $165 $180 $169 $702
Operating income................. 79 41 63 53 236
Income before cumulative effect
of accounting change.......... 42 14 25 21 102
Cumulative effect of accounting
change, net of income taxes... 10 -- -- -- 10
Net income....................... 52 14 25 21 112
</Table>
33
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors and Stockholder of
Tennessee Gas Pipeline Company:
In our opinion, the consolidated financial statements listed in the Index
appearing under Item 15(a)(1) present fairly, in all material respects, the
consolidated financial position of Tennessee Gas Pipeline Company and its
subsidiaries (the "Company") at December 31, 2003 and 2002, and the consolidated
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2003 in conformity with accounting principles
generally accepted in the United States of America. In addition, in our opinion,
the financial statement schedule listed in the Index appearing under Item
15(a)(2) presents fairly, in all material respects, the information set forth
therein when read in conjunction with the related consolidated financial
statements. These financial statements and the financial statement schedule are
the responsibility of the Company's management; our responsibility is to express
an opinion on these financial statements and the financial statement schedule
based on our audits. We conducted our audits of these statements in accordance
with auditing standards generally accepted in the United States of America,
which 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 2 to the consolidated financial statements, the
Company's indirect parent, El Paso Corporation, may be in default of covenants
contained in its revolving credit facility and other financing transactions.
Such an event of default could have a material impact on the Company's
liquidity. Certain waivers have been obtained by El Paso Corporation, however,
additional waivers must be obtained and certain conditions must be satisfied to
continue the effectiveness of the waivers.
As discussed in Note 5, the Company adopted Statement of Financial
Accounting Standards No. 141, Business Combinations, and Statement of Financial
Accounting Standards No. 142, Goodwill and Other Intangible Assets, on January
1, 2002.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 15, 2004
34
SCHEDULE II
TENNESSEE GAS PIPELINE COMPANY
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
(IN MILLIONS)
<Table>
<Caption>
BALANCE AT CHARGED TO CHARGED TO BALANCE
BEGINNING COSTS AND OTHER AT END
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS OF PERIOD
----------- ---------- ---------- ---------- ---------- ---------
2003
Allowance for doubtful accounts....... $ 4 $ -- $ -- $ -- $ 4
Legal reserves........................ 4 (4) -- -- --
Environmental reserves................ 84 (31)(1) -- (7)(3) 46
Regulatory reserves................... 6 (4) -- (1) 1
2002
Allowance for doubtful accounts....... $ 6 $ (1) $ 1 $ (2)(2) $ 4
Valuation allowance on deferred tax
assets............................. 2 -- -- (2) --
Legal reserves........................ 4 -- -- -- 4
Environmental reserves................ 102 (4) -- (14)(3) 84
Regulatory reserves................... 10 (5) 1 -- 6
2001
Allowance for doubtful accounts....... $ 4 $ 2 $ -- $ -- $ 6
Valuation allowance on deferred tax
assets............................. 2 -- -- -- 2
Legal reserves........................ 7 (3) -- -- 4
Environmental reserves................ 109 -- -- (7)(3) 102
Regulatory reserves................... 33 (12)(4) (11)(4) -- 10
</Table>
- ---------------
(1) Represents a reduction in the estimated costs to complete our internal PCB
remediation project.
(2) Primarily accounts written off.
(3) Payments for remediation activities.
(4) Upon favorable resolution of issues related to natural gas purchase
contracts, we reversed the regulatory reserve to revenue and the regulatory
asset account.
35
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Controls and Procedures. Under the supervision and with the
participation of management, including our principal executive officer and
principal financial officer, we have evaluated the effectiveness of the design
and operation of our disclosure controls and procedures (Disclosure Controls)
and internal controls over financial reporting (Internal Controls) as of the end
of the period covered by this Annual Report pursuant to Rules 13a-15 and 15d-15
under the Securities Exchange Act of 1934 (Exchange Act).
Definition of Disclosure Controls and Internal Controls. Disclosure
Controls are our controls and other procedures that are designed to ensure that
information required to be disclosed by us in the reports that we file or submit
under the Exchange Act is recorded, processed, summarized and reported, within
the time periods specified under the Exchange Act. Disclosure Controls include,
without limitation, controls and procedures designed to ensure that information
required to be disclosed by us in the reports that we file under the Exchange
Act is accumulated and communicated to our management, including our principal
executive officer and principal financial officer, as appropriate to allow
timely decisions regarding required disclosure. Internal Controls are procedures
which are designed with the objective of providing reasonable assurance that (1)
our transactions are properly authorized; (2) our assets are safeguarded against
unauthorized or improper use; and (3) our transactions are properly recorded and
reported, all to permit the preparation of our financial statements in
conformity with generally accepted accounting principles.
Limitations on the Effectiveness of Controls. Tennessee Gas Pipeline
Company's management, including the principal executive officer and principal
financial officer, does not expect that our Disclosure Controls and Internal
Controls will prevent all errors and all fraud. The design of a control system
must reflect the fact that there are resource constraints, and the benefits of
controls must be considered relative to their costs. Because of the inherent
limitations in all control systems, no evaluation of controls can provide
absolute assurance that all control issues and instances of fraud, if any,
within the company have been detected. These inherent limitations include the
realities that judgments in decision-making can be faulty, and that breakdowns
can occur because of simple errors or mistakes. Additionally, controls can be
circumvented by the individual acts of some persons, by collusion of two or more
people, or by management override of the controls. The design of any system of
controls also is based in part upon certain assumptions about the likelihood of
future events. Therefore, a control system, no matter how well conceived and
operated, can provide only reasonable, not absolute, assurance that the
objectives of the control system are met. Our Disclosure Controls and Internal
Controls are designed to provide such reasonable assurances of achieving our
desired control objectives, and our principal executive officer and principal
financial officer have concluded that our Disclosure Controls and Internal
Controls are effective in achieving that level of reasonable assurance.
No Significant Changes in Internal Controls. We have sought to determine
whether there were any "significant deficiencies" or "material weaknesses" in
Tennessee Gas Pipeline Company's Internal Controls, or whether the company had
identified any acts of fraud involving personnel who have a significant role in
Tennessee Gas Pipeline Company's Internal Controls. This information was
important both for the controls evaluation generally and because the principal
executive officer and principal financial officer are required to disclose that
information to our Board's Audit Committee and our independent auditors and to
report on related matters in this section of the Annual Report. The principal
executive officer and principal financial officer note that there has not been
any change in Internal Controls that occurred during the most recent fiscal
quarter that has materially affected, or is reasonably likely to materially
affect, Internal Controls.
Effectiveness of Disclosure Controls. Based on the controls evaluation,
our principal executive officer and principal financial officer have concluded
that the Disclosure Controls are effective to ensure that material information
relating to Tennessee Gas Pipeline Company and its consolidated subsidiaries is
made known to management, including the principal executive officer and
principal financial officer, on a timely basis.
36
Officer Certifications. The certifications from the principal executive
officer and principal financial officer required under Sections 302 and 906 of
the Sarbanes-Oxley Act of 2002 have been included as Exhibits to this Annual
Report.
PART III
Item 10, "Directors and Executive Officers of the Registrant;" Item 11,
"Executive Compensation;" Item 12, "Security Ownership of Certain Beneficial
Owners and Management and Related Stockholder Matters;" and Item 13, "Certain
Relationships and Related Transactions;" have been omitted from this report
pursuant to the reduced disclosure format permitted by General Instruction I to
Form 10-K.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The Audit Fees for the years ended December 31, 2003 and 2002, of $500,000
and $470,000 were for professional services rendered by PricewaterhouseCoopers
LLP for the audits of the consolidated financial statements of Tennessee Gas
Pipeline Company. No other audit-related, tax or other services were provided by
our auditors for the years ended December 31, 2003 and 2002.
We are an indirect wholly-owned subsidiary of El Paso and do not have a
separate audit committee. El Paso's Audit Committee has adopted a pre-approval
policy for audit and non-audit services. For a description of El Paso's
pre-approval policies for audit and non-audit related services, see El Paso
Corporation's proxy statement.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) THE FOLLOWING DOCUMENTS ARE FILED AS A PART OF THIS REPORT:
1. Financial statements.
The following consolidated financial statements are included in Part II,
Item 8 of this report:
<Table>
<Caption>
PAGE
----
Consolidated Statements of Income and Comprehensive
Income................................................ 14
Consolidated Balance Sheets............................ 15
Consolidated Statements of Cash Flows.................. 16
Consolidated Statements of Stockholder's Equity........ 17
Notes to Consolidated Financial Statements............. 18
Report of Independent Auditors......................... 34
2. Financial statement schedules.
Schedule II -- Valuation and Qualifying Accounts....... 35
All other schedules are omitted because they are not
applicable, or the required information is disclosed in
the financial statements or accompanying notes.
3. Exhibit list............................................ 38
</Table>
(b) REPORTS ON FORM 8-K:
None.
37
TENNESSEE GAS PIPELINE COMPANY
EXHIBIT LIST
DECEMBER 31, 2003
Exhibits not incorporated by reference to a prior filing are designated by
an asterisk; all exhibits not so designated are incorporated herein by reference
to a prior filing as indicated.
<Table>
<Caption>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
3.A Restated Certificate of Incorporation dated May 11, 1999
(Exhibit 3.A to our 1999 Second Quarter Form 10-Q).
3.B By-laws dated as of June 24, 2002 (Exhibit 3.B to our 2002
Form 10-K).
4.A Indenture dated as of March 4, 1997, between TGP and
Wilmington Trust Company (as successor to JPMorgan Chase
Bank, formerly known as The Chase Manhattan Bank), as
Trustee (Exhibit 4.1 to EPTP's Form 10-K for 1997); First
Supplemental Indenture dated as of March 13, 1997, between
TGP and the Trustee (Exhibit 4.2 to EPTP's 1997 Form 10-K);
Second Supplemental Indenture dated as of March 13, 1997,
between TGP and the Trustee (Exhibit 4.3 to EPTP's 1997 Form
10-K); Third Supplemental Indenture dated as of March 13,
1997, between TGP and the Trustee (Exhibit 4.4 to EPTP's
1997 Form 10-K); Fourth Supplemental Indenture dated as of
October 9, 1998, between TGP and the Trustee (Exhibit 4.2 to
our Form 8-K filed October 9, 1998); Fifth Supplemental
Indenture dated June 10, 2002, between TGP and the Trustee
(Exhibit 4.1 to our Form 8-K filed June 10, 2002).
10.A $3,000,000,000 Revolving Credit Agreement dated as of April
16, 2003 among El Paso Corporation, El Paso Natural Gas
Company, Tennessee Gas Pipeline Company and ANR Pipeline
Company, as Borrowers, the Lenders Party hereto, and
JPMorgan Chase Bank, as Administrative Agent, ABN Amro Bank
N.V. and Citicorp North America, Inc., as Co-Document
Agents, Bank of America, N.A. and Credit Suisse First
Boston, as Co-Syndication Agents, J.P. Morgan Securities
Inc. and Citigroup Global Markets Inc., as Joint Bookrunners
and Co-Lead Arrangers. (Exhibit 99.1 to El Paso
Corporation's Form 8-K filed April 18, 2003).
10.B $1,000,000,000 Amended and Restated 3-Year Revolving Credit
Agreement dated as of April 16, 2003 among El Paso
Corporation, El Paso Natural Gas Company and Tennessee Gas
Pipeline Company, as Borrowers, The Lenders Party thereto,
and JPMorgan Chase Bank, as Administrative Agent, ABN Amro
Bank N.V. and Citicorp North America, Inc., as Co-Document
Agents, Bank of America, N.A., as Syndication Agent, J.P.
Morgan Securities Inc. and Citigroup Global Markets Inc., as
Joint Bookrunners and Co-Lead Arrangers. (Exhibit 99.2 to El
Paso Corporation's Form 8-K filed April 18, 2003).
10.C Security and Intercreditor Agreement dated as of April 16,
2003 among El Paso Corporation, the persons referred to
therein as Pipeline Company Borrowers, the persons referred
to therein as Grantors, each of the Representative Agents,
JPMorgan Chase Bank, as Credit Agreement Administrative
Agent and JPMorgan Chase Bank, as Collateral Agent,
Intercreditor Agent, and Depository Bank. (Exhibit 99.3 to
El Paso Corporation's Form 8-K filed April 18, 2003).
21 Omitted pursuant to the reduced disclosure format permitted
by General Instruction I to Form 10-K.
*31.A Certification of Chief Executive Officer pursuant to sec.
302 of the Sarbanes-Oxley Act of 2002.
*31.B Certification of Chief Financial Officer pursuant to sec.
302 of the Sarbanes-Oxley Act of 2002.
*32.A Certification of Chief Executive Officer pursuant to 18
U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the
Sarbanes-Oxley Act of 2002.
*32.B Certification of Chief Financial Officer pursuant to 18
U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the
Sarbanes-Oxley Act of 2002.
</Table>
38
REPORTS ON FORM 8-K
None.
UNDERTAKING
We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph
(4)(iii), to furnish to the U.S. Securities and Exchange Commission upon request
all constituent instruments defining the rights of holders of our long-term debt
and our consolidated subsidiaries not filed herewith for the reason that the
total amount of securities authorized under any of such instruments does not
exceed 10 percent of our total consolidated assets.
39
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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 on the 15th day of
March, 2004.
TENNESSEE GAS PIPELINE COMPANY
By: /s/ JOHN W. SOMERHALDER II
----------------------------------
John W. Somerhalder II
Chairman of the Board
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:
<Table>
<Caption>
SIGNATURE TITLE DATE
--------- ----- ----
/s/ JOHN W. SOMERHALDER II Chairman of the Board and March 15, 2004
- ----------------------------------------------------- Director (Principal
(John W. Somerhalder II) Executive Officer)
/s/ STEPHEN C. BEASLEY President and Director March 15, 2004
- -----------------------------------------------------
(Stephen C. Beasley)
/s/ GREG G. GRUBER Senior Vice President, Chief March 15, 2004
- ----------------------------------------------------- Financial Officer, Treasurer
(Greg G. Gruber) and Director (Principal
Financial and Accounting
Officer)
</Table>
40
TENNESSEE GAS PIPELINE COMPANY
EXHIBIT INDEX
DECEMBER 31, 2003
Exhibits not incorporated by reference to a prior filing are designated by
an asterisk, all exhibits not so designated are incorporated herein by reference
to a prior filing as indicated.
<Table>
<Caption>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
3.A Restated Certificate of Incorporation dated May 11, 1999
(Exhibit 3.A to our 1999 Second Quarter Form 10-Q).
3.B By-laws dated as of June 24, 2002 (Exhibit 3.B to our 2002
Form 10-K).
4.A Indenture dated as of March 4, 1997, between TGP and
Wilmington Trust Company (as successor to JPMorgan Chase
Bank, formerly known as The Chase Manhattan Bank), as
Trustee (Exhibit 4.1 to EPTP's Form 10-K for 1997); First
Supplemental Indenture dated as of March 13, 1997, between
TGP and the Trustee (Exhibit 4.2 to EPTP's 1997 Form 10-K);
Second Supplemental Indenture dated as of March 13, 1997,
between TGP and the Trustee (Exhibit 4.3 to EPTP's 1997 Form
10-K); Third Supplemental Indenture dated as of March 13,
1997, between TGP and the Trustee (Exhibit 4.4 to EPTP's
1997 Form 10-K); Fourth Supplemental Indenture dated as of
October 9, 1998, between TGP and the Trustee (Exhibit 4.2 to
our Form 8-K filed October 9, 1998); Fifth Supplemental
Indenture dated June 10, 2002, between TGP and the Trustee
(Exhibit 4.1 to our Form 8-K filed June 10, 2002).
10.A $3,000,000,000 Revolving Credit Agreement dated as of April
16, 2003 among El Paso Corporation, El Paso Natural Gas
Company, Tennessee Gas Pipeline Company and ANR Pipeline
Company, as Borrowers, the Lenders Party hereto, and
JPMorgan Chase Bank, as Administrative Agent, ABN Amro Bank
N.V. and Citicorp North America, Inc., as Co-Document
Agents, Bank of America, N.A. and Credit Suisse First
Boston, as Co-Syndication Agents, J.P. Morgan Securities
Inc. and Citigroup Global Markets Inc., as Joint Bookrunners
and Co-Lead Arrangers. (Exhibit 99.1 to El Paso
Corporation's Form 8-K filed April 18, 2003).
10.B $1,000,000,000 Amended and Restated 3-Year Revolving Credit
Agreement dated as of April 16, 2003 among El Paso
Corporation, El Paso Natural Gas Company and Tennessee Gas
Pipeline Company, as Borrowers, The Lenders Party thereto,
and JPMorgan Chase Bank, as Administrative Agent, ABN Amro
Bank N.V. and Citicorp North America, Inc., as Co-Document
Agents, Bank of America, N.A., as Syndication Agent, J.P.
Morgan Securities Inc. and Citigroup Global Markets Inc., as
Joint Bookrunners and Co-Lead Arrangers. (Exhibit 99.2 to El
Paso Corporation's Form 8-K filed April 18, 2003).
10.C Security and Intercreditor Agreement dated as of April 16,
2003 among El Paso Corporation, the persons referred to
therein as Pipeline Company Borrowers, the persons referred
to therein as Grantors, each of the Representative Agents,
JPMorgan Chase Bank, as Credit Agreement Administrative
Agent and JPMorgan Chase Bank, as Collateral Agent,
Intercreditor Agent, and Depository Bank. (Exhibit 99.3 to
El Paso Corporation's Form 8-K filed April 18, 2003).
21 Omitted pursuant to the reduced disclosure format permitted
by General Instruction I to Form 10-K.
*31.A Certification of Chief Executive Officer pursuant to sec.
302 of the Sarbanes-Oxley Act of 2002.
*31.B Certification of Chief Financial Officer pursuant to sec.
302 of the Sarbanes-Oxley Act of 2002.
*32.A Certification of Chief Executive Officer pursuant to 18
U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the
Sarbanes-Oxley Act of 2002.
*32.B Certification of Chief Financial Officer pursuant to 18
U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the
Sarbanes-Oxley Act of 2002.
</Table>