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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, 2001
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 1-2700
EL PASO NATURAL GAS COMPANY
(Exact Name of Registrant as Specified in Its Charter)
DELAWARE 74-0608280
(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)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 420-2600
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) 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]
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 $1 per share. Shares outstanding on March 20, 2002:
1,000
EL PASO NATURAL GAS 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
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EL PASO NATURAL GAS COMPANY
TABLE OF CONTENTS
CAPTION PAGE
------- ----
PART I
Item 1. Business.................................................... 1
Item 2. Properties.................................................. 4
Item 3. Legal Proceedings........................................... 4
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....................................... 4
Item 6. Selected Financial Data..................................... *
Item 7. Management's Discussion and Analysis of Financial Condition
and Results
of Operations............................................. 5
Cautionary Statement for Purposes of the "Safe Harbor"
Provisions
of the Private Securities Litigation Reform Act of 1995... 6
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk...................................................... 6
Item 8. Financial Statements and Supplementary Data................. 7
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................. 27
PART III
Item 10. Directors and Executive Officers of the Registrant.......... *
Item 11. Executive Compensation...................................... *
Item 12. Security Ownership of Management............................ *
Item 13. Certain Relationships and Related Transactions.............. *
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K....................................................... 27
Signatures.................................................. 29
---------------
* 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:
/d = per day
BBtu = billion British thermal units
Bcf = billion cubic feet
MMcf = million cubic feet
When we refer to cubic feet measurements, all measurements are at a
pressure of 14.73 pounds per square inch.
When we refer to "we", "us", "our" or "ours", we are describing El Paso
Natural Gas Company and/or our subsidiaries.
i
PART I
ITEM 1. BUSINESS
GENERAL
We are a Delaware corporation incorporated in 1928, and a wholly owned
subsidiary of El Paso Corporation. Our primary business is the interstate
transportation of natural gas. We conduct our business activities through two
pipeline systems, each of which is discussed below:
The EPNG system. The El Paso Natural Gas system consists of approximately
10,000 miles of pipeline with a design capacity of 4,744 MMcf/d. During 2001,
2000 and 1999, average throughput on the EPNG system was 4,253 BBtu/d, 3,937
BBtu/d and 3,603 BBtu/d. This system delivers natural gas from the San Juan
Basin of northern New Mexico and southern Colorado and the Permian and Anadarko
Basins to California, which is our single largest market, as well as markets in
Arizona, Nevada, New Mexico, Oklahoma, Texas and northern Mexico.
The MPC system. The Mojave Pipeline system consists of approximately 400
miles of pipeline with a design capacity of approximately 400 MMcf/d. During
2001, 2000 and 1999, average throughput on the MPC system was 283 BBtu/d, 407
BBtu/d and 391 BBtu/d. This system connects with the EPNG transmission system at
Topock, Arizona, the Kern River Gas Transmission Company and Transwestern
transmission systems in California and extends to customers and a pipeline
interconnect in the vicinity of Bakersfield, California.
In addition to our existing systems, the Federal Energy Regulatory
Commission (FERC) has approved EPNG's Line 2000 expansion project. This project
will convert a pipeline from oil transmission to natural gas transmission from
West Texas to the Arizona and California border. The pipeline will add
approximately 230 MMcf/d to our capacity and is anticipated to be completed in
September 2002.
In January 2001, El Paso Corporation completed its merger with The Coastal
Corporation. As a result of this transaction, we relocated our headquarters from
El Paso, Texas to Colorado Springs, Colorado.
REGULATORY ENVIRONMENT
Our interstate natural gas transmission systems are regulated by the FERC
under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Each
of our systems operate under separate FERC approved tariffs that establish
rates, terms and conditions under which we provide services to our customers.
Generally, the FERC's authority extends to:
- transportation of natural gas, rates and charges;
- certification and construction of new facilities;
- extension or abandonment of services and facilities;
- maintenance of accounts and records;
- relationships between pipeline and marketing affiliates;
- depreciation and amortization policies;
- acquisition and disposition of facilities; and
- initiation and discontinuation of services.
Our pipeline systems have tariffs established through filings with the FERC
that have a variety of terms and conditions, each of which affects our
operations and our ability to recover fees for the services we provide.
Generally, changes to these fees or terms of service can only be implemented
upon approval by the FERC.
1
Our interstate pipeline systems are also subject to the Natural Gas
Pipeline Safety Act of 1968, which establishes pipeline safety requirements, the
National Environmental Policy Act and other environmental legislation. Each of
our systems has a continuing program of inspection designed to keep all of our
facilities in compliance with pollution control and pipeline safety
requirements. We believe that our systems are in compliance with the applicable
requirements.
We are also subject to regulation over the safety requirements in the
design, construction, operation and maintenance of our interstate natural gas
transmission systems by the U.S. Department of Transportation. Operations on
U.S. government land are regulated by the U.S. Department of the Interior.
For a discussion of significant rate and regulatory matters, see Part II,
Item 8, Financial Statements and Supplementary Data, Note 7.
MARKETS AND COMPETITION
Our interstate transmission systems face varying degrees of competition
from other pipelines, as well as alternative energy sources, such as
electricity, hydroelectric power, coal and fuel oil. Also, the potential
consequences of proposed and ongoing restructuring and deregulation of the
electric power industry are currently unclear. Restructuring and deregulation
may benefit the natural gas industry by creating more demand for natural gas
turbine generated electric power, or it may hamper demand by allowing a more
effective use of surplus electric capacity through increased wheeling as a
result of open access. The following table details our markets and competition
on each of our interstate pipeline systems:
PIPELINE
SYSTEM CUSTOMER INFORMATION(1) CONTRACT INFORMATION COMPETITION
------------ ---------------------------- ------------------------------- -------------------------------------
EPNG Approximately 390 firm and Approximately 200 firm EPNG faces competition from other
interruptible customers contracts pipeline companies that transport
Contracted capacity: 100% natural gas to the California market
Remaining contract term: 1 as well as hydroelectric power
month producers who provide a significant
to 29 years amount of power to that state.
Major Customer: Average remaining contract
Southern California Gas term:
Company (1,175 BBtu/d) 6 years
Contract term expires in 2006
MPC Approximately 15 firm and Approximately 10 firm contracts MPC faces competitive pressures from
interruptible customers Contracted capacity: 98% supplies in the Rocky Mountains, new
Remaining contract term: 5 supplies within California,
years interstate pipeline expansions,
Major Customers: Average remaining contract changes in local distribution
Texaco Natural Gas Inc. term: companies and California intrastate
(185 BBtu/d) 5 years pipeline operating procedures, as
Burlington Resources well as deregulation of electric
Trading Inc. Contract term expires in 2007. generation facilities.
(76 BBtu/d)
Los Angeles Department of
Water and Power Contract term expires in 2007.
(50 BBtu/d)
Contract term expires in 2007.
---------------
(1)Includes natural gas producers, marketers, end-users and other natural gas
transmission, distribution and electric generation companies.
Our current capacity to deliver natural gas to California is approximately
3.3 Bcf/d, and the combined capacity of all pipeline companies serving the
California market is approximately 7.1 Bcf/d. In 2001, the demand for interstate
pipeline capacity to California averaged 5.7 Bcf/d, equivalent to approximately
80 percent of the total interstate pipeline capacity serving that state. Natural
gas shipped to California across our system represented approximately 39 percent
of the natural gas consumed in the state in 2001. Our ability to remarket our
capacity under expiring contracts may be adversely affected by excess capacity
into California.
Our ability to extend existing contracts or re-market expiring capacity
with our customers is based on a variety of factors, including competitive
alternatives, the regulatory environment at the local, state and federal levels
and market supply and demand factors at the relevant extension or expiration
dates. While every
2
attempt is made to re-negotiate contract terms at fully-subscribed quantities
and at maximum rates allowed under our tariffs, we must, at times, discount our
rates to remain competitive.
ENVIRONMENTAL
A description of our environmental activities is included in Part II, Item
8, Financial Statements and Supplementary Data, Note 7, which is incorporated
herein by reference.
EMPLOYEES
As of March 12, 2002, we had approximately 700 full-time employees, none of
whom are subject to collective bargaining arrangements.
3
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 current taxes, liens incident to minor
encumbrances, and easements and restrictions that do not materially detract from
the value of these properties or our interests therein, 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 7, 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 $1 per share, is owned by El Paso and,
accordingly, there is no public trading market for our stock.
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.
In 2000, we declared and paid to El Paso a non-cash dividend of a non-regulated
asset in the amount of $9 million. There were no common stock dividends declared
during 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.
4
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.
RESULTS OF OPERATIONS
Below are the operating results and an analysis of those results for the
year ended December 31:
2001 2000
------- -------
(IN MILLIONS, EXCEPT
VOLUME AMOUNTS)
Operating revenues.......................................... $ 572 $ 508
Operating expenses.......................................... (386) (285)
Other income (expense), net................................. (2) 4
------ ------
Earnings before interest and income taxes (EBIT).......... $ 184 $ 227
====== ======
Total throughput (BBtu/d)(1)...................... 4,535 4,310
====== ======
---------------
(1) Excludes MPC throughput on behalf of EPNG.
Included in our results of operations for the year ended December 31, 2001,
are merger-related costs of $98 million associated with El Paso Corporation's
merger with The Coastal Corporation in January 2001. These costs include
employee severance, retention and transition costs, as well as business and
operational integration costs, all of which are related to the relocation of our
headquarters from El Paso, Texas to Colorado Springs, Colorado.
YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000
Operating revenues for the year ended December 31, 2001, were $64 million
higher than the same period in 2000. The increase was due to higher reservation
revenues as a result of a larger portion of our capacity earning maximum tariff
rates compared to the same period in 2000 and higher throughput from increased
deliveries to California and other western states. The increase was partially
offset by the impact of lower prices on fuel recoveries.
Operating expenses for the year ended December 31, 2001, were $101 million
higher than the same period in 2000. The increase was primarily due to
merger-related costs incurred related to the relocation of our headquarters as
part of El Paso's merger with Coastal, the impact of price changes on natural
gas imbalances, higher power costs for compression and increases to our reserve
for bad debts during the fourth quarter of 2001 in connection with the
bankruptcy of Enron Corp. The increase was partially offset by unfavorable
shipper and producer settlements in 2000.
Other income (expense), net for the year ended December 31, 2001, was $6
million lower than the same period in 2000 due primarily to the sales of
non-pipeline related assets in 2000.
INTEREST AND DEBT EXPENSE
Non-affiliated Interest and Debt Expense
Non-affiliated interest and debt expense for the year ended December 31,
2001, was $9 million lower than 2000 due primarily to lower average interest
rates on short-term borrowings.
Affiliated Interest Income, Net
Affiliated interest income, net for the year ended December 31, 2001, was
$17 million lower than 2000 due primarily to lower short-term interest rates in
2001 on advances to our parent under our cash management program.
5
INCOME TAXES
The effective income tax rate for the years ended December 31, 2001 and
2000 was 38 percent for both years. The effective tax rates were higher than the
statutory rate of 35 percent primarily due to state income taxes. For a
reconciliation of the statutory rate to the effective rates, see Item 8,
Financial Statements and Supplementary Data, Note 4.
COMMITMENTS AND CONTINGENCIES
For a discussion of our commitments and contingencies, see Item 8,
Financial Statements and Supplementary Data, Note 7, which is incorporated
herein by reference.
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.
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 interest rates of
our interest bearing securities, by expected maturity dates. As of December 31,
2001, the carrying amounts of short-term borrowings are representative of fair
values because of the short-term maturity of these instruments. The fair value
of the long-term debt has been estimated based on quoted market prices for the
same or similar issues.
DECEMBER 31, 2001 DECEMBER 31, 2000
-------------------------------------------------------------------------- ---------------------
EXPECTED FISCAL YEAR OF MATURITY OF CARRYING AMOUNTS
-------------------------------------------------------------------------- CARRYING
2002 2003 2004 2005 2006 THEREAFTER TOTAL FAIR VALUE AMOUNTS FAIR VALUE
------ ----- ----- ---- ---- ---------- ------ ------------- -------- ----------
(DOLLARS IN MILLIONS)
LIABILITIES:
Short-term debt -- variable
rate....................... $ 439 $ 439 $ 439 $ 280 $ 280
Average interest
rate................. 2.4%
Long-term debt, including
current portion -- fixed
rate..................... $ 215 $ 200 $ 459 $ 874 $ 891 $ 873 $ 889
Average interest
rate................. 7.8% 6.8% 8.2%
6
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
EL PASO NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(IN MILLIONS)
YEAR ENDED DECEMBER 31,
-----------------------
2001 2000 1999
----- ----- -----
Operating revenues...................... $572 $508 $501
---- ---- ----
Operating expenses
Operation and maintenance............. 190 189 195
Merger-related costs.................. 98 -- --
Depreciation, depletion and
amortization....................... 70 66 63
Taxes, other than income taxes........ 28 30 29
---- ---- ----
386 285 287
---- ---- ----
Operating income........................ 186 223 214
---- ---- ----
Other income (expense), net............. (2) 4 1
---- ---- ----
Income before interest and income
taxes................................. 184 227 215
---- ---- ----
Non-affiliated interest and debt
expense............................... 87 96 107
Affiliated interest income, net......... (58) (75) (62)
Income taxes............................ 60 78 64
---- ---- ----
89 99 109
---- ---- ----
Net income.............................. $ 95 $128 $106
==== ==== ====
See accompanying notes.
7
EL PASO NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
(IN MILLIONS, EXCEPT SHARE AMOUNTS)
ASSETS
DECEMBER 31,
----------------
2001 2000
------ ------
Current assets
Cash and cash equivalents............. $ -- $ --
Accounts and notes receivable, net of
allowance of $6 in 2001 and $2 in
2000
Customer........................... 97 128
Affiliates......................... 1,298 1,001
Other.............................. 6 5
Materials and supplies................ 39 33
Other................................. 16 10
------ ------
Total current assets.......... 1,456 1,177
------ ------
Property, plant and equipment, at
cost.................................. 2,940 2,818
Less accumulated depreciation,
depletion and amortization......... 1,142 1,107
------ ------
Total property, plant and
equipment, net.................... 1,798 1,711
------ ------
Other................................... 90 105
------ ------
Total assets.................. $3,344 $2,993
====== ======
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities
Accounts payable
Trade.............................. $ 54 $ 66
Affiliates......................... 9 7
Other.............................. 9 4
Short-term debt and other
obligations........................ 654 280
Taxes payable......................... 117 99
Other................................. 93 84
------ ------
Total current liabilities..... 936 540
------ ------
Long-term debt and other obligations.... 659 873
------ ------
Deferred income taxes................... 282 227
------ ------
Other................................... 169 126
------ ------
Commitments and contingencies
Stockholder's equity
Preferred stock, 8%, par value $0.01
per share; authorized 1,000,000
shares; issued 500,000 shares;
stated at liquidation value........ 350 350
Common stock, par value $1 per share;
authorized and issued 1,000
shares............................. -- --
Additional paid-in capital............ 714 710
Retained earnings..................... 234 167
------ ------
Total stockholder's equity.... 1,298 1,227
------ ------
Total liabilities and
stockholder's equity......... $3,344 $2,993
====== ======
See accompanying notes.
8
EL PASO NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN MILLIONS)
YEAR ENDED DECEMBER 31,
-------------------------
2001 2000 1999
----- ----- -------
Cash flows from operating activities
Net income.............................. $ 95 $ 128 $ 106
Adjustments to reconcile net income to
net cash from operating activities
Depreciation, depletion and
amortization...................... 70 66 63
Deferred income tax expense......... 29 34 --
Net gain on the sale of assets...... -- (3) --
Risk-sharing revenue................ (32) (32) (31)
Non-cash portion of merger-related
costs............................. 92 -- --
Working capital changes, net of
non-cash transactions
Accounts receivable.............. 30 (63) (11)
Accounts payable................. (7) 8 27
Accounts payable/receivable with
affiliates....................... 3 3 44
Taxes payable.................... 17 16 39
Other working capital changes.... 6 (9) (28)
Non-working capital changes and
other............................. 21 12 (3)
----- ----- -------
Net cash provided by operating
activities................... 324 160 206
----- ----- -------
Cash flows from investing activities
Additions to property, plant and
equipment........................... (157) (228) (51)
Net proceeds from the sale of
assets.............................. -- 36 6
Net change in affiliated advances
receivable.......................... (298) 344 (341)
Other................................. -- 3 5
----- ----- -------
Net cash provided by (used in)
investing activities......... (455) 155 (381)
----- ----- -------
Cash flows from financing activities
Net borrowings (repayments) of
commercial paper.................... 159 (287) 356
Payments to retire long-term debt..... -- -- (164)
Dividends paid........................ (28) (28) (26)
----- ----- -------
Net cash provided by (used in)
financing activities......... 131 (315) 166
----- ----- -------
Decrease in cash and cash equivalents... -- -- (9)
Cash and cash equivalents
Beginning of period................... -- -- 9
----- ----- -------
End of period......................... $ -- $ -- $ --
===== ===== =======
See accompanying notes.
9
EL PASO NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
(IN MILLIONS, EXCEPT SHARE AMOUNTS)
8% COMMON STOCK ADDITIONAL TOTAL
PREFERRED --------------- PAID-IN RETAINED STOCKHOLDER'S
STOCK SHARES AMOUNT CAPITAL EARNINGS EQUITY
--------- ------ ------ ---------- -------- -------------
January 1, 1999.................... $350 1,000 $ -- $ 694 $ -- $ 1,044
Net income....................... 106 106
Preferred stock dividends........ (28) (28)
Allocated tax benefit of El Paso
equity plans.................. 6 6
Dividends........................ -- (2) (2)
---- ----- ---- ------- ----- -------
December 31, 1999.................. $350 1,000 -- 700 76 1,126
Net income....................... 128 128
Preferred stock dividends........ (28) (28)
Allocated tax benefit of El Paso
equity plans.................. 5 5
Non-cash capital contributions
from El Paso.................. 5 5
Dividends........................ (9) (9)
---- ----- ---- ------- ----- -------
December 31, 2000.................. $350 1,000 -- 710 167 1,227
Net income....................... 95 95
Preferred stock dividends........ (28) (28)
Allocated tax benefit of El Paso
equity plans.................. 4 4
---- ----- ---- ------- ----- -------
December 31, 2001.................. $350 1,000 $ -- $ 714 $ 234 $ 1,298
==== ===== ==== ======= ===== =======
See accompanying notes.
10
EL PASO NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation and Principles of Consolidation
Our consolidated financial statements include the accounts of all
majority-owned, controlled subsidiaries after the elimination of all significant
intercompany accounts and transactions. We consolidate entities when we have the
ability to control the operating and financial decisions and policies of that
entity. Our consolidated financial statements and disclosures for prior periods
include reclassifications that were made to conform to the current year
presentation. Those reclassifications have no impact on reported net income or
stockholder's equity.
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.
Accounting for Regulated Operations
Our interstate natural gas systems are subject to the jurisdiction of FERC
in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of
1978, and we apply the provisions of Statement of Financial Accounting Standards
(SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation.
Accounting requirements for regulated businesses can differ from the accounting
requirements for non-regulated businesses. Transactions that have been recorded
differently as a result of regulatory accounting requirements include the
capitalization of an equity return component on regulated capital projects,
employee related benefits and other costs and taxes included in, or expected to
be included in, future rates.
We will continue to evaluate the application of regulatory accounting
principles as there are on-going changes in the regulatory and economic
environment. Things that may influence this assessment are:
- inability to recover cost increases due to rate caps and rate case
moratoriums;
- inability to recover capitalized costs, including an adequate return on
those costs through the ratemaking process;
- excess capacity;
- discounting rates in the markets we serve; and
- impacts of ongoing initiatives in, and deregulation of, the natural gas
industry.
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.
11
Materials and Supplies
We value materials and supplies at the lower of cost or market value with
cost determined using the average cost method.
Natural Gas Imbalances
Natural gas imbalances occur when the actual amount of natural gas
delivered from or received by a pipeline system differs from the contractual
amount scheduled to be delivered or received. We value these imbalances due to
or from shippers and operators at an appropriate index price based on when we
expect to settle the imbalance. Imbalances are settled in cash or made up
in-kind, subject to the contractual terms of 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 since we expect to settle them within the next twelve
months.
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 for our regulated business.
We capitalize the major units of property replacements or improvements and
expense minor items. Included in our pipeline property balances are additional
acquisition costs which represent the excess purchase costs associated with
purchase business combinations allocated to our regulated interstate systems.
These costs are amortized on a straight-line basis, and we do not recover these
excess costs in our rates. As of December 31, 2001, we had additional
acquisition costs, of $76 million, net of accumulated amortization.
We use the composite (group) method to depreciate regulated property, plant
and equipment. Under this method, assets with similar lives and other
characteristics are grouped and depreciated as one asset. We apply the
depreciation rate approved in our tariff to the total cost of the group until
its net book value equals its salvage value. Currently, our depreciation rates
vary from 2 to 33 percent. Using these rates, the remaining useful lives of
these assets range from 2 to 35 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 of retirement
(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.
At December 31, 2001 and 2000, we had approximately $262 million and $227
million of construction work in progress included in our property, plant and
equipment.
Asset Impairments
We evaluate our long-lived assets for impairment in accordance with SFAS
No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of. If an adverse event or change in circumstances occurs,
we estimate the future cash flows from the asset, grouped together at the lowest
level for which separate cash flows can be measured, to determine if the asset
is impaired. If the total of the undiscounted future cash flows is less than the
carrying amount for the assets, we calculate the fair value of the assets either
through reference to sales data for similar assets, or by estimating the fair
value using a discounted cash flow approach. These cash flow estimates require
us to make estimates and assumptions for many years into the future for pricing,
demand, competition, operating costs, legal, regulatory and other factors, and
these assumptions can change either positively or negatively.
12
On January 1, 2002, we adopted the provision of SFAS No. 144, Accounting
for the Impairment or Disposal of Long-lived Assets, which will impact how we
account for asset impairments and the accounting for discontinued operations in
the future.
Revenue Recognition
We recognize revenues from natural gas transportation service and services
other than transportation in the period the service is provided. Reserves are
provided on revenues collected that may be subject to refund in our pending rate
proceedings.
Environmental Costs and Other Contingencies
We expense or capitalize expenditures for ongoing compliance with
environmental regulations that relate to past or current operations as
appropriate. We expense amounts for clean up of existing environmental
contamination caused by past operations which do not benefit future periods by
preventing or eliminating future contamination. We record liabilities when our
environmental assessments indicate that remediation efforts are probable, and
the costs can be reasonably estimated. Estimates of our liabilities are based on
currently available facts, existing technology and presently enacted laws and
regulations taking into consideration 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,
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 along with a
provision for deferred income taxes. Deferred income taxes reflect the estimated
future tax consequences 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 sharing policy for companies included in its
consolidated federal income tax return which provides, among other things, that
(i) each company in a taxable income position will be currently charged with an
amount equivalent to its federal income tax computed on a separate return basis,
and (ii) each company in a tax loss position will be reimbursed currently to the
extent its deductions, including general business credits, were utilized in the
consolidated return. Under the policy, El Paso pays all federal income taxes
directly to the IRS and bills or refunds its subsidiaries for their portion of
these income tax payments.
Accounting for Asset Retirement Obligations.
In August 2001, the FASB issued SFAS No. 143, Accounting for Asset
Retirement Obligations. This Statement requires companies to record a liability
relating to the retirement and removal of assets used in their
13
business. The liability is discounted to its present value, and the related
asset value is increased by the amount of the resulting liability. Over the life
of the asset, the liability will be accreted to its future value and eventually
extinguished when the asset is taken out of service. The provisions of this
Statement are effective for fiscal years beginning after June 15, 2002. We are
currently evaluating the effects of this pronouncement.
2. ACQUISITIONS
In March 2000, we purchased the All American Pipeline, a crude oil
transportation system, for $129 million. The system consists of 1,088 miles of
pipeline which runs from McCamey, Texas to the Emidio Station near Bakersfield,
California. On May 7, 2001, the FERC issued an order granting us authorization
to convert the 785 miles of pipeline that extends from West Texas to the Arizona
and California border (Line 2000) from oil transmission to natural gas
transmission. This pipeline will add approximately 230 MMcf/d to EPNG's
transportation system. Conversion began in February 2002.
3. MERGER-RELATED COSTS
During the year ended December 31, 2001, we incurred merger-related costs
of $98 million associated with El Paso Corporation's merger with The Coastal
Corporation. Our merger-related costs consist of approximately $6 million of
employee severance, retention and transition costs for severed employees. These
costs were expensed as incurred and have been paid. Our merger related costs
also include approximately $92 million in estimated lease and facility-related
costs to relocate our headquarters to Colorado Springs, Colorado. These charges
were accrued in the second quarter of 2001 at the time we completed our
relocations and closed these offices. The amounts accrued will be paid over the
term of the applicable non-cancelable lease agreements. Future developments,
such as termination of the lease or sub-leases could impact the accrued amounts.
4. INCOME TAXES
The following table reflects the components of income taxes included in net
income for each of the three years ended December 31:
2001 2000 1999
---- ---- ----
(IN MILLIONS)
Current
Federal................................................... $25 $37 $58
State..................................................... 6 7 6
--- --- ---
31 44 64
--- --- ---
Deferred
Federal................................................... 27 36 (4)
State..................................................... 2 (2) 4
--- --- ---
29 34 --
--- --- ---
Total income taxes................................ $60 $78 $64
=== === ===
Our income taxes included in net income differ 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:
2001 2000 1999
---- ---- ----
(IN MILLIONS)
Income tax expense at the statutory federal rate of 35%..... $54 $72 $59
Increase (decrease)
State income tax, net of federal income tax benefit....... 5 3 7
Other..................................................... 1 3 (2)
--- --- ---
Income tax expense.......................................... $60 $78 $64
=== === ===
Effective tax rate.......................................... 38% 38% 38%
=== === ===
14
The following are the components of our net deferred tax liability as of
December 31:
2001 2000
----- -----
(IN MILLIONS)
Deferred tax liabilities
Property, plant and equipment............................. $284 $302
Employee benefits and deferred compensation obligations... 27 18
Regulatory and other assets............................... 86 67
---- ----
Total deferred tax liability...................... 397 387
---- ----
Deferred tax assets
U.S. net operating loss and tax credit carryovers......... 20 25
Other liabilities......................................... 79 116
---- ----
Total deferred tax asset.......................... 99 141
---- ----
Net deferred tax liability.................................. $298 $246
==== ====
Under El Paso's tax sharing policy, we are allocated the tax benefit
associated with our employees' exercise of non-qualified stock options and the
vesting of restricted stock as well as restricted stock dividends. This
allocation reduced taxes payable by $4 million in 2001, $5 million in 2000 and
$6 million in 1999. These benefits are included in additional paid-in capital in
our balance sheet.
As of December 31, 2001, we had approximately $20 million of alternative
minimum tax credits and $1 million of net operating loss carryovers available to
offset future regular tax liabilities. The alternative minimum tax credits
carryover indefinitely. The net operating loss carryover period ends in 2019.
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.
5. FINANCIAL INSTRUMENTS
Fair Value of Financial Instruments
As of December 31, 2001 and 2000, 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. We estimated the fair value of debt with fixed interest rates based
on quoted market prices for the same or similar issues.
The carrying amounts and estimated fair values of our financial instruments
are as follows at December 31:
2001 2000
--------------------- ---------------------
CARRYING CARRYING
AMOUNT FAIR VALUE AMOUNT FAIR VALUE
-------- ---------- -------- ----------
(IN MILLIONS)
Balance sheet financial instruments:
Long-term debt, including current
maturities................................. $874 $891 $873 $889
6. DEBT AND OTHER CREDIT FACILITIES
At December 31, 2001, our weighted average interest rate on our commercial
paper was 3.3%, and at December 31, 2000, it was 7.5%. We had the following
short-term borrowings including current maturities of long-term debt, at
December 31:
2001 2000
----- -----
(IN MILLIONS)
Commercial paper............................................ $439 $280
Current maturities of long-term debt........................ 215 --
---- ----
$654 $280
==== ====
15
Our long-term debt outstanding consisted of the following at December 31:
2001 2000
---- ----
(IN MILLIONS)
7.75% Note due 2002.................................... $215 $215
6.75% Note due 2003.................................... 200 200
8.63% Debenture due 2022............................... 260 260
7.50% Debenture due 2026............................... 200 200
---- ----
875 875
Less: Unamortized discount................................ 1 2
Current maturities................................... 215 --
---- ----
Total long-term debt, less current maturities..... $659 $873
==== ====
Aggregate maturities of the principal amounts of long-term debt for the
next 5 years and in total thereafter are as follows:
YEAR (IN MILLIONS)
---- -------------
2002........................................................ $ 215
2003........................................................ 200
2004........................................................ --
2005........................................................ --
2006........................................................ --
Thereafter.................................................. 460
------
Total long-term debt, including current
maturities....................................... $ 875
======
Other Financing Arrangements
We are eligible to borrow up to $1 billion under a commercial paper
program. The program is used to manage our short-term cash requirements.
As of December 31, 2001, El Paso has a $3 billion, 364-day revolving credit
and competitive advance facility, which replaced its $2 billion renewable credit
and competitive advance facility in June 2001, and a $1 billion, 3-year
revolving credit and competitive advance facility. We are a designated borrower
under these facilities and, as such, are liable for any amounts outstanding
under these facilities. Our interest rate for these facilities varies and was
LIBOR plus 50 basis points on December 31, 2001. No amounts were outstanding
under these facilities at December 31, 2001.
In January 2002, we retired long-term debt with an aggregate principal
amount of $215 million.
During 1999, our parent company formed Sabine Investors, L.L.C., a wholly
owned limited liability company, and other separate legal entities, for the
purpose of generating funds to invest in capital projects and other assets. The
proceeds are collateralized by various assets of our parent, including our
Mojave Pipeline system.
7. COMMITMENTS AND CONTINGENCIES
Legal Proceedings
El Paso and several of its subsidiaries were named defendants in eleven
purported class action, municipal or individual lawsuits, and in one shareholder
derivative lawsuit, filed in the California state courts. We are a defendant in
ten of these lawsuits. The eleven suits contend that El Paso entities acted
improperly to limit the construction of new pipeline capacity to California
and/or to manipulate the price of natural gas sold into the California
marketplace. The shareholder derivative suit contends that El Paso, through its
directors, failed to prevent the conduct alleged in several of these underlying
cases. El Paso has consolidated nine of the underlying suits into a single San
Diego court proceeding, and expects to consolidate the remaining suit in the
16
near future. In March 2002, the derivative lawsuit was dismissed in California,
to be refiled in a state court in Houston, Texas. A listing of the these cases
is included under the heading Cases below.
In September 2001, we received a subpoena from the California Department of
Justice, seeking information said to be relevant to the Department's ongoing
investigation into the high electricity prices in California. We have produced
and expect to continue to produce materials under this subpoena.
On August 19, 2000, a main transmission line owned and operated by us
ruptured at the crossing of the Pecos River near Carlsbad, New Mexico. Twelve
individuals at the site were fatally injured. On June 20, 2001, the U.S.
Department of Transportation's Office of Pipeline Safety issued a Notice of
Proposed Violation to us. The Notice alleged five probable violations of its
regulations, proposed fines totaling $2.5 million and proposed corrective
actions. On October 15, 2001, we filed a detailed response with the Office of
Pipeline Safety disputing each of the alleged violations. The alleged five
probable violations of the regulations of the Department of Transportation's
Office of Pipeline Safety are: 1) failure to perform appropriate tasks to
prevent corrosion, with an associated proposed fine of $500,000; 2) failure to
investigate and minimize internal corrosion, with an associated proposed fine of
$1,000,000; 3) failure to consider unusual operating and maintenance conditions
and respond appropriately, with an associated proposed fine of $500,000; 4)
failure to follow company procedure, with an associated proposed fine of
$500,000; and 5) failure to maintain topographical diagrams, with an associated
proposed fine of $25,000. We are cooperating with the National Transportation
Safety Board in an investigation into the facts and circumstances concerning the
possible causes of the rupture. If we are required to pay the proposed fines, it
will not have a material adverse effect on our financial position, operating
results or cash flows. In addition, a number of personal injury and wrongful
death lawsuits were filed against us in connection with the rupture. Several of
these suits have been settled, with payments fully covered by insurance. Seven
Carlsbad lawsuits remain, with one of those seven having reached a contingent
settlement within insurance coverage. A listing of these cases is included under
the heading Cases below.
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 under
report 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. 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). In May 2001, the court denied the defendants'
motions to dismiss.
We and a number of our affiliates were named defendants in Quinque
Operating Company, et al v. Gas Pipelines and Their Predecessors, et al, filed
in 1999 in the District Court of Stevens County, Kansas. This class action
complaint alleges that the defendants mismeasured natural gas volumes and
heating content of natural gas on non-federal and non-Native American lands. The
Quinque complaint was transferred to the same court handling the Grynberg
complaint and has now been sent back to Kansas State Court for further
proceedings. A motion to dismiss this case is pending.
We are also a named defendant in numerous lawsuits and a named party in
numerous governmental proceedings arising in the ordinary course of our
business.
While the outcome of the matters discussed above cannot be predicted with
certainty, based on information known to date and our existing accruals, we do
not expect the ultimate resolution of these matters will have a material adverse
effect on our financial position, operating results or cash flows.
Environmental Matters
We are subject to extensive 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, 2001, we had a reserve of $29 million for expected
remediation costs. In addition, we expect to
17
make capital expenditures for environmental matters of approximately $11 million
in the aggregate for the years 2002 through 2006. These expenditures primarily
relate to compliance with clean air regulations.
We have been designated, 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 4 active sites under
the Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA) or state equivalents. We have sought to resolve our liability as a PRP
at these CERCLA sites, as appropriate, through indemnification by third parties
and settlements which provide for payment of our allocable share of remediation
costs. As of December 31, 2001, we have estimated our share of the remediation
costs at these sites to be between $15 million and $19 million and have provided
reserves that we believe are adequate for such costs. 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 the determination of our estimated liabilities. We
presently believe that, based on our existing reserves and information known to
date, the impact of the costs associated with these CERCLA sites will not have a
material adverse effect on our financial position, operating results or cash
flows.
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 the recorded
reserves are adequate.
Rates and Regulatory Matters
In April 2000, the California Public Utilities Commission (CPUC) filed a
complaint with FERC alleging that our sale of approximately 1.2 Bcf/d of
California capacity to our affiliate, El Paso Merchant Energy Company, was
anti-competitive and an abuse of the affiliate relationship under FERC's
policies. Other parties in the proceeding requested that the original complaint
be set for hearing and that Merchant Energy pay back any profits it earned under
the contract. In March 2001, FERC established a hearing, before an
administrative law judge, to address the issue of whether we and/or Merchant
Energy had market power and, if so, had exercised it. In October 2001, the
administrative law judge issued a proposed decision finding that El Paso did not
exercise market power and that the market power portion of the CPUC's complaint
should be dismissed. The decision further found that El Paso had violated FERC's
marketing affiliate regulations. The judge's proposed decision has been briefed
to, and will be effective only if approved by, the FERC. On October 30, 2001,
the Market Oversight and Enforcement (MOE) section of the FERC's office of the
General Counsel filed comments in this proceeding stating that record
development at the trial was inadequate to conclude that we complied with FERC's
regulation. We filed a motion to strike the MOE's pleading, but in December
2001, the FERC denied our motion and remanded the proceeding to the
administrative law judge for a supplemental hearing on the availability of
capacity at El Paso's California delivery points. The hearing is set to commence
on March 20, 2002.
In late 1999, several of our customers filed complaints requesting that
FERC order us to cease and desist from selling primary firm delivery point
capacity at the Southern California Gas Company Topock delivery point in excess
of the downstream capacity available at that point and to cease and desist from
overselling firm mainline capacity on the east-end of our mainline system.
Several technical conferences and alternative dispute resolution meetings were
held during the summer of 2000 but they failed to produce a settlement. In
October 2000, FERC ordered us to make a one time allocation of available
delivery point capacity at the Southern California Gas Company Topock delivery
point among affected firm shippers, but deferred action on east-end and
systemwide capacity allocation issues. In February 2001, the FERC issued an
order accepting
18
our tariff filing affirming the results of the Topock delivery point allocation
process and directing us to formulate a system wide capacity allocation
methodology. In March 2001, we filed our proposed system-wide allocation
methodology with FERC. In April 2001, the February 2001 FERC order was appealed
by a customer to the U.S. Court of Appeals for the 9th Circuit, and that appeal
is pending a decision. In July 2001 and August 2001, at technical conferences
conducted by FERC on other matters, our system-wide capacity allocation proposal
was discussed. The parties have submitted position papers to the FERC regarding
the appropriate method for allocating receipt point capacity on our system.
Two groups of our customers, those within California and those east of
California, have filed complaints against us with FERC. On July 13, 2001, twelve
parties composed of California customers, natural gas producers and natural gas
marketers, filed a complaint alleging that our full requirements contracts with
our customers east of California should be converted to contracts with specific
volumetric entitlements, that we should be required to expand our interstate
pipeline system and that firm shippers who experience reductions in their
nominated gas volumes should be awarded demand charge credits. Also, on July 17,
2001, ten parties, most of which are east of California full-requirement
contract customers, filed a complaint against us with FERC, alleging that we
violated the Natural Gas Act of 1938 and breached our contractual obligations by
failing to expand our system in order to serve the needs of the full-requirement
contract shippers. The complainants have requested that FERC require us to show
cause why we should not be required to augment our system capacity. On September
10, 2001, the July 17, 2001 complainants filed a motion for partial summary
disposition of their complaint, to which we responded on September 25, 2001. In
addition, on November 13, 2001, one of the July 17, 2001 complainants submitted
a type of settlement proposal that we and most other parties have opposed. At
its March 13, 2002 public meeting, the FERC Staff made a presentation to the
FERC Commissioners recommending that FERC address the capacity allocation issues
raised in these and our other related proceedings by, among other things,
eliminating the full requirements provisions from all of our contracts except
those in a small customer category and converting them to contracts with
specific volumetric entitlements. The Staff also recommended scheduling a
technical conference. FERC authorized its Staff to provide notice of a technical
conference to be attended by the Commissioners. It is expected that this
conference will be held no later than the spring of this year.
Our current rate settlement establishes, among other things, base rates
through December 31, 2005. According to the settlement, our base rates began
escalating annually in 1998 as a result of inflationary factors. We have the
right to increase or decrease our base rates if changes in laws or regulations
result in increased or decreased costs in excess of $10 million a year. In
addition, all of our settling customers participate in risk sharing provisions
under our rate case settlement, Under these provisions, we are to receive cash
payments totaling $295 million for a portion of the risk we assumed from
capacity relinquishments by our customers at the end of 1997. The cash received
is deferred, and we recognize this deferral in revenues ratably over the risk
sharing period. As of December 31, 2001, we had unearned risk sharing revenues
of approximately $64 million and had $27 million remaining to be collected from
customers under this provision. Amounts received for relinquished capacity to
customers above certain dollar levels specified in the rate settlement obligate
us to refund a portion of the excess to customers. Under this provision, we
refunded $14 million of 2000 revenues to customers during 2000 and 2001. During
2001, we established a refund obligation of $46 million, of which $29 million
was refunded in 2001, and the remaining $17 million will be refunded in early
2002. Both the risk and revenue sharing provisions of the rate settlement extend
through 2003. One unresolved matter in our current rate settlement involves the
application of our existing fuel recovery mechanism as it relates to compression
facilities that were abandoned. An appeal was filed in the Fifth Circuit Court
of Appeals and was recently transferred to the D.C. Circuit Court of Appeals.
The appeal has been briefed and is pending a decision at this time.
In September 2001, FERC issued a Notice of Proposed Rulemaking (NOPR). The
NOPR proposes to apply the standards of conduct governing the relationship
between interstate pipelines and marketing affiliates to all energy affiliates.
The proposed regulations, if adopted by FERC, would dictate how all our energy
affiliates conduct business and interact with our interstate pipelines. In
December 2001, we filed comments with the FERC addressing our concerns with the
proposed rules. We cannot predict the outcome of the NOPR, but adoption of the
regulations in substantially the form proposed would, at a minimum, place
additional administrative and operational burdens on us.
19
In January 2002, we were selected for an industry-wide audit by the FERC's
office of the Executive Director, Division of Regulatory Audits. The audit will
focus on FERC Form 2 and affiliated transactions for the period January 1, 2000
through December 31, 2001.
While we cannot predict with certainty the final outcome or timing of the
resolution of all of our rates and regulatory matters, we believe the ultimate
resolution of these issues, based on information known to date, will not have a
material adverse effect on our financial position, results of operations or cash
flows.
Other matters
In December 2001, Enron Corp. and a number of its subsidiaries, including
Enron North America Corp. and Enron Power Marketing, Inc., filed for Chapter 11
bankruptcy protection in the United States Bankruptcy Court for the Southern
District of New York. Affiliates of Enron have contracts for both short-term and
long-term transportation on our pipeline systems. As a result of Enron's
bankruptcy filing, we are uncertain as to their intent to maintain or release
this pipeline capacity and also as to their ability to honor the terms of these
contracts. As of December 31, 2001, we established reserves for potential losses
related to receivables from these contracts and continue to establish reserves
on a monthly basis. Future revenue related to these contracts will depend upon
Enron's bankruptcy proceedings and our ability to re-market any subsequently
released pipeline capacity. While we expect to re-market any such capacity on
favorable terms, we cannot at this time predict that we will be successful in
this effort or that the rates we will receive will be as high as those we
currently earn.
Cases
The California cases discussed above are: five filed in the Superior Court
of Los Angeles County (Continental Forge Company. et al v. Southern California
Gas Company, et al, filed September 25, 2000; Berg v. Southern California Gas
Company, et al, filed December 18, 2000; County of Los Angelos v. Southern
California Gas Company, et al, filed January 8, 2002; The City of Los Angeles,
et al v. Southern California Gas Company, et al and The City of Long Beach, et
al v. Southern California Gas Company, et al, both filed March 20, 2001); two
filed in the Superior Court of San Diego County (John W.H.K. Phillip v. El Paso
Merchant Energy; and John Phillip v. El Paso Merchant Energy, both filed
December 13, 2000); and two filed in the Superior Court of San Francisco County
(Sweetie's et al v. El Paso Corporation, et al, filed March 22, 2001; and
California Dairies, Inc., et al v. El Paso Corporation, et al, filed May 21,
2001); one filed in the Superior Court of the State of California, County of Los
Angeles (County of Los Angeles v Southern California Gas Company, et al, filed
January 8, 2002); and one filed in the Superior Court of the State of
California, County of Alameda (Dry Creek Corporation v. El Paso Natural Gas
Company, et al filed December 10, 2001). The shareholder derivative suit now
dismissed was styled Clark, et al v. Allumbaugh, et al, Superior Court of Orange
County, filed August 23, 2001.
The six remaining Carlsbad lawsuits are discussed above as follows: one
filed in district court in Harris County, Texas (Geneva Smith, et al v. EPEC and
EPNG, filed October 23, 2000), and five filed in state district court in
Carlsbad, New Mexico (Chapman, as Personal Representative of the Estate of Amy
Smith Heady, v. EPEC, EPNG and John Cole, filed February 9, 2001; and Chapman,
as Personal Representative of the Estate of Dustin Wayne Smith, v. EPEC, EPNG
and John Cole; Chapman, as Personal Representative of the Estate of Terry Wayne
Smith, v. EPNG, EPEC and John Cole; Green, as Personal Representative of the
Estate of Jesse Don Sumler, v. EPEC, EPNG and John Cole; Rackley, as Personal
Representative of the Estate of Glenda Gail Sumler, v. EPEC, EPNG and John Cole;
and Rackley, as Personal Representative of the Estate of Amanda Sumler Smith, v.
EPEC, EPNG and John Cole, all filed March 16, 2001). We have reached a
contingent settlement in an additional case (Dawson, as Personal Representative
of Kirsten Janay Sumler, v. EPEC and EPNG, filed November 8, 2000).
Capital Commitments
At December 31, 2001, we had capital and investment commitments of $38
million for 2002 primarily relating to ongoing capital projects, with no
commitments thereafter. Our other planned capital and
20
investment projects are discretionary in nature, with no substantial capital
commitments made in advance of the actual expenditures.
Operating Leases
We lease property, facilities and equipment under various operating leases.
Minimum annual rental commitments at December 31, 2001, were as follows:
YEAR ENDING
DECEMBER 31, OPERATING LEASES
------------------------------------------------------------ ----------------
(IN MILLIONS)
2002..................................................... $12
2003..................................................... 13
2004..................................................... 13
2005..................................................... 14
2006..................................................... 14
Thereafter............................................... 6
---
Total............................................. $72
===
Aggregate minimum commitments have not been reduced by minimum sublease
rentals of approximately $9 million due in the future under noncancelable
subleases. In addition, as part of our relocation from El Paso to Colorado
Springs, we accrued these minimum lease commitments as merger-related charges.
These accruals were reduced by our estimated minimum sublease rentals.
Rental expense for operating leases for the years ended December 31, 2001,
2000 and 1999 was $3 million, $10 million and $12 million. Our rental expense in
2001 was charged against our merger accrual following the relocation of our
headquarters.
Guarantees
At December 31, 2001, we had guarantees of $162 million associated with our
affiliates' development activities and various other programs.
8. RETIREMENT BENEFITS
Pension and Retirement Benefits
Prior to January 1, 1997, El Paso maintained a defined benefit pension plan
covering substantially all of our employees. Pension benefits were based on
years of credited service and final five year average compensation, subject to
maximum limitations as defined in the pension plan. Effective January 1, 1997,
the plan was amended to provide benefits determined by a cash balance formula.
Employees who were pension plan participants on December 31, 1996, receive the
greater of cash balance benefits or prior plan benefits accrued through December
31, 2001. In addition, El Paso maintains a defined contribution plan covering
its U.S. employees, including our employees. El Paso matches 75 percent of
participant basic contributions of up to 6 percent, with the matching
contribution being made in El Paso common stock, which participants may
diversify at any time. El Paso is responsible for benefits accrued under its
plans and allocates the related costs to its affiliates. See Note 10 for a
summary of transactions with affiliates.
Other Postretirement Benefits
We provide postretirement medical benefits for a closed group of employees
who retired on or before March 1, 1986, and limited postretirement life
insurance for employees who retired after January 1, 1985. As such, our
obligation to accrue for other postretirement employee benefits (OPEB) is
primarily limited to the fixed population of retirees who retired on or before
March 1, 1986. The medical plan is pre-funded to the extent employer
contributions are recoverable through rates. To the extent actual OPEB costs
differ from amounts recovered in rates, a regulatory asset or liability is
recorded.
21
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:
2001 2000
----- -----
(IN MILLIONS)
Change in benefit obligation
Benefit obligation at beginning of period................. $ 83 $ 90
Interest cost............................................. 6 7
Actuarial (gain) or loss.................................. 13 (9)
Benefits paid............................................. (7) (5)
---- ----
Benefit obligation at end of period....................... $ 95 $ 83
==== ====
Change in plan assets
Fair value of plan assets at beginning period............. $ 77 $ 67
Actual return on plan assets.............................. (20) 4
Employer contributions.................................... 11 11
Benefits paid............................................. (7) (5)
---- ----
Fair value of plan assets at end of period................ $ 61 $ 77
==== ====
Reconciliation of funded status
Funded status as of September 30.......................... $(34) $ (6)
Fourth quarter contributions.............................. 3 3
Unrecognized net actuarial gain........................... 14 (24)
Unrecognized net transition obligation.................... 31 38
---- ----
Prepaid benefit cost at December 31....................... $ 14 $ 11
==== ====
Benefit obligations are based upon actuarial estimates as described below.
YEAR ENDED
DECEMBER 31,
--------------------
2001 2000 1999
---- ---- ----
(IN MILLIONS)
Benefit cost for the plans includes the following components
Interest cost............................................. $ 6 $ 7 $ 6
Expected return on plan assets............................ (5) (4) (4)
Amortization of net actuarial gain........................ (1) (1) (1)
Amortization of transition obligation..................... 8 7 8
--- --- ---
Net benefit cost.......................................... $ 8 $ 9 $ 9
=== === ===
2001 2000
----- -----
Weighted average assumptions
Discount rate............................................. 7.25% 7.75%
Expected return on plan assets............................ 7.50% 7.50%
22
Actuarial estimates for our postretirement benefits plans assume a weighted
average annual rate of increase in the per capita costs of covered health care
benefits of 9.5 percent in 2001, gradually decreasing to 6 percent by the year
2008. Assumed health care cost trends have a significant effect on the amounts
reported for other postretirement benefit plans. A one-percentage point change
in assumed health care cost trends would have the following effects:
2001 2000
----- -----
(IN MILLIONS)
One Percentage Point Increase
Aggregate of Service Cost and Interest Cost............... $ 1 $ 1
Accumulated Postretirement Benefit Obligation............. $ 8 $ 7
One Percentage Point Decrease
Aggregate of Service Cost and Interest Cost............... $(1) $(1)
Accumulated Postretirement Benefit Obligation............. $(7) $(7)
9. PREFERRED STOCK
In December 1998, we issued 500,000 shares of 8% Cumulative Preferred Stock
to El Paso. We used the proceeds of $350 million to reduce our outstanding debt.
El Paso is entitled to receive dividends at the rate of 8% on a liquidation
value of $700 per share annually. On or after January 1, 2003, these shares are
redeemable at our option, in whole or in part, upon not less than 30 days'
notice at a redemption price of $700 per share, plus unpaid dividends.
At December 31, 2001, we had accrued $2 million in dividends payable on our
8% preferred stock.
For each of the years ended December 31, 2001 and 2000, we paid $28 million
in dividends on our preferred stock.
10. TRANSACTIONS WITH AFFILIATES
We participate in El Paso's cash management program which matches
short-term cash surplus and need requirements of its participating affiliates,
thus minimizing total borrowing from outside sources. We had advanced $1,294
million at December 31, 2001, at a market rate of interest which was 2.1
percent. At December 31, 2000, we had advanced $995 million, at a market rate of
interest which was 6.7 percent.
At December 31, 2001 and 2000, we had other accounts receivable from
related parties of $4 million and $6 million. In addition, we had accounts
payable to related parties of $9 million versus $7 million at December 31, 2000.
These balances arose in the normal course of business.
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 revenues, gross property and payroll.
During 2001, Tennessee Gas Pipeline allocated payroll to us and other expenses
associated with our shared pipeline services. In addition, during 2001 we
performed operational, financial, accounting and administrative services for, an
affiliate, Colorado Interstate Gas Company. These services are recorded as
reimbursement of costs. We believe all the allocation methods are reasonable.
In addition, we enter into transactions with other El Paso subsidiaries in
the ordinary course of business to transport natural gas. Services provided to
these affiliates are based on the same terms as nonaffiliates.
The following table shows revenues and charges from our affiliates:
YEARS ENDED
DECEMBER 31,
--------------------
2001 2000 1999
---- ---- ----
(IN MILLIONS)
Revenues from affiliates.................................... $72 $35 $ 2
Charges from affiliates..................................... 49 58 70
Reimbursement of costs...................................... 7 -- --
23
11. TRANSACTIONS WITH MAJOR CUSTOMER
The following table shows revenues from our major customer for the years
ended December 31:
2001 2000 1999
---- ---- ----
(IN MILLIONS)
Southern California Gas Company........................... $135 $132 $131
12. SUPPLEMENTAL CASH FLOW INFORMATION
The following table contains supplemental cash flow information for the
years ended December 31:
2001 2000 1999
---- ---- ----
(IN MILLIONS)
Interest paid.............................................. $84 $99 $112
Income tax payments........................................ 14 23 26
13. SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Financial information by quarter is summarized below.
OPERATING OPERATING NET
QUARTER REVENUES INCOME INCOME
------- --------- --------- ------
(IN MILLIONS)
2001 1st............................................. $141 $ 67 $ 40
2nd............................................ 138 (25) (21)
3rd............................................ 148 75 41
4th............................................ 145 69 35
---- ---- ----
$572 $186 $ 95
==== ==== ====
2000 1st............................................. $122 $ 56 $ 30
2nd............................................ 119 50 28
3rd............................................ 129 61 37
4th............................................ 138 56 33
---- ---- ----
$508 $223 $128
==== ==== ====
24
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholder of
El Paso Natural Gas Company:
In our opinion, the consolidated financial statements listed in the Index
appearing under Item 14(a)(1) present fairly, in all material respects the
financial position of El Paso Natural Gas Company and its subsidiaries at
December 31, 2001 and 2000, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 2001 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 14(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 financial
statement schedule are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements and
financial statement schedule based on our audits. We conducted our audits of
these statements in accordance with 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.
PricewaterhouseCoopers LLP
Houston, Texas
March 6, 2002
25
SCHEDULE II
EL PASO NATURAL GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
(IN MILLIONS)
BALANCE AT CHARGED TO CHARGED TO BALANCE
BEGINNING COSTS AND OTHER AT END
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS OF PERIOD
----------- ---------- ---------- ---------- ---------- ---------
2001
Allowance for doubtful accounts........ $ 2 $ 6 $ -- $ (2) $ 6
Legal Reserves......................... -- -- -- -- --
Environmental Reserves................. 25 4 -- -- 29
Regulatory Reserves.................... 15 6 -- (2) 19
2000
Allowance for doubtful accounts........ $ 1 $ 1 $ -- $ -- $ 2
Legal Reserves......................... 3 -- (3) (3)
Environmental Reserves................. 22 3 -- -- 25
Regulatory Reserves.................... 49 1 -- (35)(1) 15
1999
Allowance for doubtful accounts........ $ 3 $ 1 $ -- $ (3) $ 1
Legal Reserves......................... 3 -- -- -- 3
Environmental Reserves................. 23 (1) -- -- 22
Regulatory Reserves.................... 26 23(2) -- -- 49
---------------
(1) Relates to the resolution of a contested rate matter.
(2) Relates to an accrual for a contested rate matter.
26
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
Item 10, "Directors and Executive Officers of the Registrant;" Item 11,
"Executive Compensation;" Item 12, "Security Ownership of Management;" 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.
PART IV
ITEM 14. 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:
PAGE
----
Consolidated Statements of Income................... 7
Consolidated Balance Sheets......................... 8
Consolidated Statements of Cash Flows............... 9
Consolidated Statements of Stockholder's Equity..... 10
Notes to Consolidated Financial Statements.......... 11
Report of Independent Accountants................... 25
2. Financial statement schedules and supplementary
information required to be submitted.
Schedule II -- Valuation and Qualifying Accounts.. 26
Schedules other than that listed above are omitted
because they are not applicable.
3. Exhibit list........................................ 28
(b) REPORTS ON FORM 8-K:
None.
27
EL PASO NATURAL GAS COMPANY
EXHIBIT LIST
DECEMBER 31, 2001
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.
EXHIBIT
NUMBER DESCRIPTION
------- -----------
3.A -- Restated Certificate of Incorporation dated May 11, 1999
(Exhibit 3.A to our 1999 First Quarter Form 10-Q).
3.B -- By-Laws dated October 22, 1997 (Exhibit 3.B to our 1999
Third Quarter Form 10-Q).
4.A -- Indenture dated as of January 1, 1992, between EPNG and
Citibank, N.A., Trustee with respect to 7 3/4% Notes due
2002 and 8 5/8% Debentures due 2022 (Exhibit 4.A to our
1998 Form 10-K).
4.B -- Indenture dated as of November 13, 1996, between EPNG and
The Chase Manhattan Bank, as Trustee, (Exhibit 4.1 to our
Form 8-K, filed November 13, 1996); Form of 6 3/4% Notes
Due 2003, (Exhibit 4.2 to EPNG's Form 8-K, filed November
13, 1996); Form of 7 1/2% Debentures Due 2026 (Exhibit
4.2 to our Form 8-K, filed November 13, 1996).
10.A -- $3,000,000,000 364-Day Revolving Credit and Competitive
Advance Facility Agreement, dated as of June 11, 2001, by
and among El Paso Corporation, EPNG, Tennessee Gas
Pipeline, the several banks and other financial
institutions from time to time parties to the Agreement,
The Chase Manhattan Bank, ABN Amro Bank, N.V., and
Citibank N.A., as co-documentation agents for the Lenders
and Bank of America, N.A. and Credit Suisse First Boston,
as co-syndication agents for the Lenders (Exhibit 10.A to
our 2001 Second Quarter Form 10-Q).
10.B -- $1,000,000,000 3-Year Revolving Credit and Competitive
Advance Facility Agreement dated as of August 4, 2000, by
and among El Paso Corporation, EPNG, Tennessee Gas
Pipeline, the several banks and other financial
institutions form time to time parties to the Agreement,
The Chase Manhattan Bank, Citibank N.A., and ABN Amro
Bank, N.V. as co-documentation agents for the Lenders and
Bank of America, N.A. as syndication agent for the
Lenders (Exhibit 10.B to our 2000 Third Form Quarter
10-Q).
21 -- Omitted pursuant to the reduced disclosure format
permitted by General Instruction I to Form 10-K.
UNDERTAKING
We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph
(4)(iii), to furnish to the 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.
28
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934 as amended, El Paso Natural Gas Company has duly caused
this report to be signed on its behalf by the undersigned, thereunto duly
authorized on the 20th day of March 2002.
EL PASO NATURAL GAS COMPANY
Registrant
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 as
amended, this report has been signed below by the following persons on behalf of
El Paso Natural Gas Company and in the capacities and on the dates indicated:
SIGNATURE TITLE DATE
--------- ----- ----
/s/ JOHN W. SOMERHALDER II Chairman of the Board and March 20, 2002
----------------------------------------------------- Director (Principal Executive
(John W. Somerhalder II) Officer)
/s/ PATRICIA A. SHELTON President and Director March 20, 2002
-----------------------------------------------------
(Patricia A. Shelton)
/s/ GREG G. GRUBER Senior Vice President, Chief March 20, 2002
----------------------------------------------------- Financial Officer and
(Greg G. Gruber) Treasurer (Principal Financial
and Accounting Officer)
29
EXHIBIT INDEX
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.
EXHIBIT
NUMBER DESCRIPTION
------- -----------
3.A -- Restated Certificate of Incorporation dated May 11, 1999
(Exhibit 3.A to our 1999 First Quarter Form 10-Q).
3.B -- By-Laws dated October 22, 1997 (Exhibit 3.B to our 1999
Third Quarter Form 10-Q).
4.A -- Indenture dated as of January 1, 1992, between EPNG and
Citibank, N.A., Trustee with respect to 7 3/4% Notes due
2002 and 8 5/8% Debentures due 2022 (Exhibit 4.A to our
1998 Form 10-K).
4.B -- Indenture dated as of November 13, 1996, between EPNG and
The Chase Manhattan Bank, as Trustee, (Exhibit 4.1 to our
Form 8-K, filed November 13, 1996); Form of 6 3/4% Notes
Due 2003, (Exhibit 4.2 to EPNG's Form 8-K, filed November
13, 1996); Form of 7 1/2% Debentures Due 2026 (Exhibit
4.2 to our Form 8-K, filed November 13, 1996).
10.A -- $3,000,000,000 364-Day Revolving Credit and Competitive
Advance Facility Agreement, dated as of June 11, 2001, by
and among El Paso Corporation, EPNG, Tennessee Gas
Pipeline, the several banks and other financial
institutions from time to time parties to the Agreement,
The Chase Manhattan Bank, ABN Amro Bank, N.V., and
Citibank N.A., as co-documentation agents for the Lenders
and Bank of America, N.A. and Credit Suisse First Boston,
as co-syndication agents for the Lenders (Exhibit 10.A to
our 2001 Second Quarter Form 10-Q).
10.B -- $1,000,000,000 3-Year Revolving Credit and Competitive
Advance Facility Agreement dated as of August 4, 2000, by
and among El Paso Corporation, EPNG, Tennessee Gas
Pipeline, the several banks and other financial
institutions form time to time parties to the Agreement,
The Chase Manhattan Bank, Citibank N.A., and ABN Amro
Bank, N.V. as co-documentation agents for the Lenders and
Bank of America, N.A. as syndication agent for the
Lenders (Exhibit 10.B to our 2000 Third Form Quarter
10-Q).
21 -- Omitted pursuant to the reduced disclosure format
permitted by General Instruction I to Form 10-K.