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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 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 1-2700
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EL PASO NATURAL GAS COMPANY
(Exact Name of Registrant as Specified in its Charter)
<Table>
DELAWARE 74-0608280
(State or Other Jurisdiction (I.R.S. Employer
of 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
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 whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X]
Indicate the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date.
Common Stock, par value $1 per share. Shares outstanding on August 13,
2003: 1,000
EL PASO NATURAL GAS COMPANY MEETS THE CONDITIONS OF GENERAL INSTRUCTION
H(1)(a) AND (b) OF FORM 10-Q AND IS THEREFORE FILING THIS REPORT WITH A REDUCED
DISCLOSURE FORMAT AS PERMITTED BY SUCH INSTRUCTION.
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EL PASO NATURAL GAS COMPANY
TABLE OF CONTENTS
<Table>
<Caption>
CAPTION PAGE
------- ----
PART I -- Financial Information
Item 1. Financial Statements........................................ 1
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 16
Cautionary Statement Regarding Forward-Looking Statements... 20
Item 3. Quantitative and Qualitative Disclosures About Market
Risk...................................................... 20
Item 4. Controls and Procedures..................................... 20
PART II -- Other Information
Item 1. Legal Proceedings........................................... 22
Item 2. Changes in Securities and Use of Proceeds................... 22
Item 3. Defaults Upon Senior Securities............................. 22
Item 4. Submission of Matters to a Vote of Security Holders......... 22
Item 5. Other Information........................................... 22
Item 6. Exhibits and Reports on Form 8-K............................ 23
Signatures.................................................. 25
</Table>
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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
MMDth = million dekatherm
</Table>
When we refer to cubic feet measurements, all measurements are at a pressure
of 14.73 pounds per square inch.
i
PART I -- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
EL PASO NATURAL GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(IN MILLIONS)
(UNAUDITED)
<Table>
<Caption>
QUARTER ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
--------------- ----------------
2003 2002 2003 2002
----- ---- ----- -----
Operating revenues........................................ $ 134 $144 $266 $296
----- ---- ---- ----
Operating expenses
Operation and maintenance............................... 52 43 86 93
Depreciation, depletion and amortization................ 16 17 33 30
Western Energy Settlement............................... 146 -- 146 --
Gain on long-lived assets............................... -- (3) -- (4)
Taxes, other than income taxes.......................... 7 5 15 13
----- ---- ---- ----
221 62 280 132
----- ---- ---- ----
Operating income (loss)................................... (87) 82 (14) 164
Other income.............................................. 1 -- 2 --
Interest and debt expense................................. (20) (18) (40) (34)
Affiliated interest income, net........................... 4 6 7 12
----- ---- ---- ----
Income (loss) before income taxes......................... (102) 70 (45) 142
Income taxes.............................................. (39) 26 (17) 54
----- ---- ---- ----
Net income (loss)......................................... $ (63) $ 44 $(28) $ 88
===== ==== ==== ====
</Table>
See accompanying notes.
1
EL PASO NATURAL GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(IN MILLIONS, EXCEPT SHARE AMOUNTS)
(UNAUDITED)
<Table>
<Caption>
JUNE 30, DECEMBER 31,
2003 2002
-------- ------------
ASSETS
Current assets
Cash and cash equivalents................................. $ -- $ 3
Accounts and notes receivable
Customer, net of allowance of $18 in 2003 and 2002..... 75 79
Affiliates............................................. 204 432
Other.................................................. 16 13
Materials and supplies.................................... 43 43
Deferred income taxes..................................... 145 36
Other..................................................... 22 27
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Total current assets.............................. 505 633
------ ------
Property, plant and equipment, at cost...................... 3,087 3,060
Less accumulated depreciation, depletion and
amortization........................................... 1,163 1,152
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Total property, plant and equipment, net.......... 1,924 1,908
------ ------
Notes receivable from affiliate............................. 845 565
Other....................................................... 81 83
------ ------
Total assets...................................... $3,355 $3,189
====== ======
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities
Accounts payable
Trade.................................................. $ 36 $ 43
Affiliates............................................. 20 33
Other.................................................. 3 11
Current maturities of long-term debt...................... 200 200
Accrued interest.......................................... 15 15
Taxes payable............................................. 78 133
Contractual deposits...................................... 30 35
Western Energy Settlement................................. 556 100
Other..................................................... 44 53
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Total current liabilities......................... 982 623
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Long-term debt, less current maturities..................... 758 758
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Other liabilities
Deferred income taxes..................................... 368 221
Western Energy Settlement................................. -- 312
Other..................................................... 119 122
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487 655
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Commitments and contingencies
Stockholder's equity
Preferred stock, 8%, par value $0.01 per share; authorized
1,000,000 shares; issued and outstanding 500,000
shares; stated at liquidation value.................... -- 350
Common stock, par value $1 per share; authorized and
issued 1,000 shares.................................... -- --
Additional paid-in capital................................ 1,074 715
Retained earnings......................................... 54 88
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Total stockholder's equity........................ 1,128 1,153
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Total liabilities and stockholder's equity........ $3,355 $3,189
====== ======
</Table>
See accompanying notes.
2
EL PASO NATURAL GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN MILLIONS)
(UNAUDITED)
<Table>
<Caption>
SIX MONTHS ENDED
JUNE 30,
----------------
2003 2002
----- -----
Cash flows from operating activities
Net income (loss)......................................... $ (28) $ 88
Adjustments to reconcile net income (loss) to net cash
from operating activities
Depreciation, depletion and amortization............... 33 30
Deferred income tax expense............................ 36 17
Net gain on long-lived assets.......................... -- (4)
Risk-sharing revenue................................... (16) (16)
Bad debt expense....................................... -- 12
Western Energy Settlement.............................. 136 --
Other non-cash income items............................ 9 --
Working capital changes................................... (96) 21
Non-working capital changes............................... 39 1
----- -----
Net cash provided by operating activities......... 113 149
----- -----
Cash flows from investing activities
Additions to property, plant and equipment................ (98) (94)
Net proceeds from the sale of assets...................... 38 2
Net change in affiliate advances receivable............... (56) (118)
----- -----
Net cash used in investing activities............. (116) (210)
----- -----
Cash flows from financing activities
Payments to retire long-term debt......................... -- (215)
Net repayments under commercial paper and short-term
credit facilities...................................... -- (21)
Net proceeds from the issuance of long-term debt.......... -- 297
----- -----
Net cash provided by financing activities......... -- 61
----- -----
Net change in cash and cash equivalents..................... (3) --
Cash and cash equivalents
Beginning of period....................................... 3 --
----- -----
End of period............................................. $ -- $ --
===== =====
</Table>
See accompanying notes.
3
EL PASO NATURAL GAS COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
We are an indirect wholly owned subsidiary of El Paso Corporation (El
Paso). We prepared this Quarterly Report on Form 10-Q under the rules and
regulations of the United States Securities and Exchange Commission. Because
this is an interim period filing presented using a condensed format, it does not
include all of the disclosures required by generally accepted accounting
principles. You should read it along with our 2002 Annual Report on Form 10-K,
which includes a summary of our significant accounting policies and other
disclosures. The financial statements as of June 30, 2003, and for the quarters
and six months ended June 30, 2003 and 2002, are unaudited. We derived the
balance sheet as of December 31, 2002, from the audited balance sheet filed in
our 2002 Form 10-K. In our opinion, we have made all adjustments which are of a
normal, recurring nature to fairly present our interim period results. Due to
the seasonal nature of our business, information for interim periods may not
necessarily indicate the results of operations for the entire year. In addition,
prior period information presented in these financial statements includes
reclassifications which were made to conform to the current period presentation.
These reclassifications have no effect on our previously reported net income or
stockholder's equity.
Our accounting policies are consistent with those discussed in our 2002
Form 10-K, except as discussed below:
Accounting for Costs Associated with Exit or Disposal Activities. As of
January 1, 2003, we adopted Statement of Financial Accounting Standards (SFAS)
No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS
No. 146 requires that we recognize costs associated with exit or disposal
activities when they are incurred rather than when we commit to an exit or
disposal plan. There was no initial financial statement impact of adopting this
standard.
Accounting for Guarantees. On January 1, 2003, we adopted Financial
Accounting Standards Board Interpretation (FIN) No. 45, Guarantor's Accounting
and Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others. FIN No. 45 requires that we record a liability for all
guarantees, including financial performance and fair value guarantees, issued
after December 31, 2002, at fair value when they are issued. There was no
initial financial statement impact of adopting this standard.
Accounting for Regulated Operations. Our natural gas system is 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 apply the provisions of SFAS No. 71, Accounting for the Effects of
Certain Types of Regulation. We continue to evaluate the application of SFAS No.
71 for changes in the competitive environment and our operating cost structures.
See a further discussion of our accounting for regulated operations in our 2002
Form 10-K.
2. WESTERN ENERGY SETTLEMENT
In June, 2003, El Paso and its affiliated companies, entered into two
definitive agreements (referred to as the Western Energy Settlement) with a
number of public and private claimants, including the states of California,
Washington, Oregon and Nevada to resolve the principal litigation and claims
against us and our affiliates relating to the sale or delivery of natural gas
and/or electricity to or in the Western United States from September 1996 to the
date of the settlement. For a further discussion of these settlements, including
our guarantee of El Paso and El Paso Merchant Energy L.P.'s (EPME), an affiliate
of El Paso, obligations, see Note 5. In connection with our obligations related
to the Western Energy Settlement, we agreed to pay (i) cash totaling
approximately $350 million and (ii) an amount equal to the proceeds from the
issuance, by El Paso, of El Paso common stock, to be issued on behalf of the
settling parties.
The definitive settlement agreements modified the agreement in principle
reached on March 20, 2003 discussed in our 2002 Form 10-K, and resulted in an
additional obligation and a pre-tax charge of $146 million
4
during the second quarter of 2003. The charge was a result of changes in the
timing of settlement payments and changes in the value of common stock to be
issued in connection with the definitive settlement agreements. This charge was
also in addition to accretion expense on the originally recorded discounted
Western Energy Settlement obligation and other charges included as part of
operation and maintenance expense of $8 million during the second quarter of
2003. For the six months ended June 30, 2003 these accretion and other charges
were approximately $12 million. As of June 30, 2003, our total Western Energy
Settlement obligation was $556 million, all of which is reflected as a current
liability since we estimate the finalization on the settlement to occur in the
next twelve months. The obligation related to the stock was approximately $213
million which is also classified as current. This stock-related obligation will
continue to impact our income statement positively or negatively based upon
changes in El Paso's stock price until the settling parties elect to have the
shares issued on their behalf. As of June 30, 2003, $10 million had been paid
related to these settlement obligations.
3. DIVESTITURES
During the first six months of 2003, we sold a non-pipeline asset with a
net book value of approximately $38 million. Net proceeds from the sale were
approximately $38 million, including approximately $8 million from our parent,
and no gain or loss was recognized on the sale of this asset.
4. DEBT AND OTHER CREDIT FACILITIES
In July 2003, we issued $355 million of senior unsecured notes with an
annual interest rate of 7.625% due 2010. Net proceeds of $347 million will be
deposited into an escrow account benefiting the settling parties of the Western
Energy Settlement.
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 $3 billion revolving credit facility has a borrowing cost of LIBOR
plus 350 basis points and letter of credit fees of 350 basis points. This
facility replaces El Paso's previous $3 billion revolving credit facility.
Approximately $1 billion of El Paso financing arrangements (including leases,
letters of credit and other facilities) were also amended to conform El Paso's
obligations to the new $3 billion revolving credit facility. We, along with El
Paso and our affiliates, ANR Pipeline Company and Tennessee Gas Pipeline Company
(TGP), are borrowers under El Paso's $3 billion revolving credit facility, and
El Paso's equity in several of its subsidiaries, including us and our equity in
Mojave Pipeline Company, collateralize the revolving credit facility and the
other financing arrangements. We remain jointly and severally liable under the
$3 billion revolving credit facility through August 19, 2003. Except for the
following conditions, after that date we will only be liable for the amounts we
borrow under the $3 billion revolving credit facility. If, on August 19, 2003,
(1) an event of default is continuing with respect to the $3 billion revolving
credit facility or (2) El Paso or any of the subsidiary guarantors under the $3
billion revolving credit facility or any of El Paso's restricted subsidiaries
(each as defined in the $3 billion revolving credit facility) is subject to a
bankruptcy or similar proceeding, then we will continue to be jointly and
severally liable for any amounts outstanding under $3 billion the revolving
credit facility until none of the events described in (1) or (2) above exists.
As of August 11, 2003, none of these conditions existed. Once our joint and
several liability expires on August 19, 2003, there are no circumstances in
which we could again become liable under El Paso's $3 billion facility except
for amounts borrowed by us under the $3 billion revolving credit facility. As of
June 30, 2003, $1.5 billion was outstanding and $1.1 billion in letters of
credit were issued under the $3 billion revolving credit facility, none of which
were borrowed by or issued on behalf of us.
We, TGP and El Paso were borrowers under El Paso's $1 billion revolving
credit facility, which expired on August 4, 2003. As of June 30, 2003, $132
million in letters of credit were issued under the $1 billion revolving credit
facility, none of which were issued on our behalf. The letters of credit either
expired or were reissued under the $3 billion revolving credit facility prior to
August 4, 2003.
Under our revolving credit facilities and other credit 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
5
on a ratio of debt to EBITDA (as defined in the agreements); (ii) limitations on
the use of 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 6. For the six months ended June 30, 2003,
we were in compliance with these covenants.
In March 2003, El Paso retired the outstanding balance under its Trinity
River financing arrangement. Our ownership in Mojave, along with various assets
of El Paso, collateralized that arrangement.
5. COMMITMENTS AND CONTINGENCIES
Legal Proceedings
Western Energy Settlement. On June 26, 2003, El Paso announced that it had
executed definitive settlement agreements to resolve the principal litigation
and claims against it relating to the sale or delivery of natural gas and/or
electricity to or in the Western United States. Parties to the settlement
agreements include private class action litigants in California; the governor
and lieutenant governor of California; the attorneys general of California,
Washington, Oregon and Nevada; the California Public Utilities Commission; the
California Electricity Oversight Board; the California Department of Water
Resources; Pacific Gas and Electric Company, Southern California Edison Company,
five California municipalities and six non-class private plaintiffs. We are a
party to these definitive settlement agreements, and as such, will bear a
portion of the costs and obligations of the settlements, as discussed more fully
below. For a discussion of the charges taken in connection with the Western
Energy Settlement, see Note 2.
These definitive settlements were in addition to a structural settlement
announced on June 4, 2003 where we agreed to provide structural relief to the
settling parties. In the structural settlement, we agreed to do the following:
- Subject to the conditions in the settlement, provide 3.29 Bcf/d of
primary firm pipeline capacity on our system to California delivery
points during a five year period from the date of settlement, and not add
any firm incremental load to our system that would prevent us from
satisfying our obligation to provide this capacity;
- Construct a new $173 million, 320 MMcf/d, Line 2000 Power-up expansion
project, and forgo recovery of the cost of service of this expansion
until our next rate case before the FERC;
- Clarify the rights of Northern California shippers to recall some of our
system capacity (Block II capacity) to serve markets in PG&E Company's
service area; and
- With limited exceptions, bar any of our affiliated companies from
obtaining additional firm capacity on our pipeline system during a five
year period from the effective date of the settlement.
In connection with this structural settlement, a Stipulated Judgment was
filed with the United States District Court for the Central District of
California. This Stipulated Judgment provides for the enforcement of some of the
obligations contained in the structural settlement.
In the definitive settlement agreements announced on June 26, 2003, we
agreed to the following terms:
- We admitted to no wrongdoing;
- We will make cash payments totaling $93.5 million for the benefit of the
parties to the definitive settlement agreements subsequent to the signing
of these agreements. This amount represents the originally announced $100
million cash payment less credits for amounts that have been paid to
other settling parties;
- We agreed to pay amounts equal to the proceeds from the issuance of
approximately 26.4 million shares by El Paso of El Paso common stock on
behalf of the settling parties. In this transaction, El Paso will sell
its common stock and provide the proceeds from the issuance to us
(through an equity contribution, an inter-company loan repayment or a
combination of both) to satisfy this obligation. If
6
this issuance is completed prior to final approval of the settlement
agreements, the proceeds from any sale will be deposited into an escrow
account for the benefit of the settling parties until final approval is
received;
- We will eliminate the originally announced 20-year obligation to pay $22
million per year in cash by depositing $250 million for the benefit of
the settling parties within 180 days of the signing of the definitive
settlement agreements. This prepayment eliminates any collateral that
might have been required on the $22 million per year payment over the
next 20 years.
EPME was also a party to the settlement agreements and, along with El Paso,
is obligated to provide a total of $1,027 million (on an undiscounted basis)
under these agreements. Of this amount, $2 million will be paid by El Paso upon
final approval of the definitive settlement agreements, $125 million represents
a contractual price discount that will be realized over the remaining 30-month
life of an existing power contract between EPME and one of the settling parties,
and $900 million will be paid by EPME in installments over the next 20 years.
The long-term payment obligation is a direct obligation of El Paso and EPME and
will be supported by collateral posted by El Paso's affiliates in amounts
specified by the settlement agreements. We have guaranteed the payment of these
obligations in the event El Paso and EPME fail to pay these amounts.
The definitive settlement agreements are subject to approval by the
California Superior Court for San Diego County, and the structural settlement is
subject to the approval by the FERC. In June 2003, in anticipation of the
execution of the definitive settlement agreements, El Paso, the Public Utilities
Commission of the State of California, Pacific Gas & Electric Company, Southern
California Edison Company, and the City of Los Angeles filed the structural
settlement described above with the FERC in resolution of certain specific
proceedings before that agency. The structural settlement was protested by our
East of California shippers and certain other shippers requested clarification
and/or modification of the settlement. We and the other settling parties have
responded to these protests and requests for clarification and/or modification
and have urged the FERC to approve the structural settlement as filed. We
currently expect final approval of these settlement agreements in late 2003 or
early 2004.
California Lawsuits. We have been named as a defendant in fifteen
purported class action, municipal or individual lawsuits, filed in California
state courts. These suits contend that we 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. Specifically, the
plaintiffs argue that our conduct violates California's antitrust statute
(Cartwright Act), constitutes unfair and unlawful business practices prohibited
by California statutes, and amounts to a violation of California's common law
restrictions against monopolization. In general, the plaintiffs are seeking (i)
declaratory and injunctive relief regarding allegedly anticompetitive actions,
(ii) restitution, including treble damages, (iii) disgorgement of profits, (iv)
prejudgment and postjudgment interest, (v) costs of prosecuting the actions and
(vi) attorney's fees. All fifteen cases have been consolidated before a single
judge, under two omnibus complaints, one of which has been set for trial in
September 2003. All of the class action lawsuits and all but one of the
individual lawsuits will be resolved upon finalization and approval of the
Western Energy Settlement. As to the remaining individual lawsuit, on May 8,
2003, a settlement agreement between the plaintiffs and defendants in that case
became effective and resolved all disputes between the parties in return for a
single payment by El Paso. Pursuant to the settlement, the plaintiffs' action
was dismissed with prejudice.
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 Angeles 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,
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* Cases to be dismissed upon finalization and approval of the Western Energy
Settlement.
7
filed March 22, 2001*; and California Dairies, Inc., et al v. El Paso
Corporation, et al, filed May 21, 2001); 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*); and five filed in the
Superior Court of Los Angeles County (The City of San Bernardino v. Southern
California Gas Company, et al; The City of Vernon v. Southern California Gas
Company; The City of Upland v. Southern California Gas Company, et al; Edgington
Oil Company v. Southern California Gas Company, et al; World Oil Corp. v.
Southern California Gas Company, et al, filed December 27, 2002*).
In November 2002, a lawsuit titled Gus M. Bustamante v. The McGraw-Hill
Companies was filed in the Superior Court of California, County of Los Angeles
by several individuals, including Lt. Governor Bustamante acting as a private
citizen, against numerous defendants, including us, alleging the creation of
artificially high natural gas index prices via the reporting of false price and
volume information. This purported class action on behalf of California
consumers alleges various unfair business practices and seeks restitution,
disgorgement of profits, compensatory and punitive damages, and civil fines.
This lawsuit will be resolved upon finalization and approval of the Western
Energy Settlement.
In January 2003, a lawsuit titled IMC Chemicals v. EPME, et al. was filed
in California state court against us, El Paso and EPME. The suit arises out of a
gas supply contract between IMC Chemicals (IMCC) and EPME and seeks to void the
Gas Purchase Agreement between IMCC and EPME for gas purchases until December
2003. IMCC contends that EPME and its affiliates manipulated market prices for
natural gas and, as part of that manipulation, induced IMCC to enter into the
contract. In furtherance of its attempt to void the contract, IMCC repeats the
allegations and claims of the California lawsuits described above. EPME intends
to enforce the terms of the contract and counterclaim for contract damages. Our
costs and legal exposure related to this lawsuit and claims are not currently
determinable.
In September 2001, we received a civil document subpoena from the
California Attorney General, seeking information said to be relevant to the
Department's ongoing investigation into the high electricity prices in
California. We are continuing to cooperate in responding to their discovery
requests. This proceeding will be resolved upon finalization and approval of the
Western Energy Settlement.
Other Energy Market Lawsuits. The state of Nevada and two individuals
filed a class action lawsuit in Nevada state court naming us and a number of our
affiliates as defendants. The allegations are similar to those in the California
cases. The suit seeks monetary damages and other relief under Nevada antitrust
and consumer protection laws. This proceeding will be resolved upon finalization
and approval of the Western Energy Settlement.
A purported class action suit titled Henry W. Perlman et. al. v. Southern
California Gas Company, San Diego Gas & Electric; Sempra Energy, El Paso
Corporation, El Paso Natural Gas Company and El Paso Merchant Energy, L.P. was
filed in federal court in New York City in December 2002 alleging that the
defendants manipulated California's natural gas market by manipulating the spot
market of gas traded on the NYMEX. Our costs and legal exposure related to this
lawsuit are not currently determinable.
In March 2003, the State of Arizona sued us, our affiliates and other
unrelated entities on behalf of Arizona consumers. The suit alleges that the
defendants conspired to artificially inflate prices of natural gas and
electricity during 2000 and 2001. Making factual allegations similar to those
alleged in the California cases, the suit seeks relief similar to the California
cases as well, but under Arizona antitrust and consumer fraud statutes. Our
costs and legal exposure related to these lawsuits and claims are not currently
determinable.
On April 21, 2003, Sierra Pacific Resources and its subsidiary, Nevada
Power Company, filed a lawsuit titled Sierra Pacific Resources et al. v. El Paso
Corporation et al. in the U.S. District Court for the District of Nevada against
us, El Paso, El Paso Tennessee Pipeline, EPME and several other non-El Paso
defendants. In the now-amended complaint, the lawsuit alleges that the
defendants conspired to manipulate supplies and prices of natural gas in the
California-Arizona border market from 1996 through 2001. The allegations are
similar to those raised in the several cases that are the subject of the Western
Energy Settlement described above. The plaintiffs allege that they entered into
contracts at inappropriately high prices and hedging
8
transactions because of the alleged manipulated prices. They allege that the
defendants' activities constituted (1) violations of the Sherman Act, California
Anti-Trust Statutes and the Nevada Unfair Trade Practices Act; (2) fraud; (3)
both a conspiracy to violate and a violation of Nevada's RICO act; (4) a
violation of the federal civil RICO Statute; and (5) a civil conspiracy. The
amended complaint seeks unspecified actual damages from all the defendants and
requests that such damages be trebled. Our costs and legal exposure related to
this lawsuit are not currently determinable.
Shareholder Class Action Suit. In November 2002, we were named as a
defendant in a shareholder derivative suit titled Marilyn Clark v. Byron
Allumbaugh, David A. Arledge, John M. Bissell, Juan Carlos Braniff, James F.
Gibbons, Anthony W. Hall, Ronald L. Kuehn, J. Carleton MacNeil, Thomas McDade,
Malcolm Wallop, William Wise, Joe B. Wyatt, El Paso Natural Gas Company and El
Paso Merchant Energy Company filed in state court in Houston. This shareholder
derivative suit generally alleges that manipulation of California gas supply and
gas prices exposed our parent, El Paso, to claims of antitrust conspiracy, FERC
penalties and erosion of share value. The plaintiffs have not asked for any
relief with regards to us. Our costs and legal exposure related to this
proceeding are not currently determinable.
Carlsbad. In August 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
Probable Violation and Proposed Civil Penalty to us. The Notice alleged five
violations of DOT regulations, proposed fines totaling $2.5 million and proposed
corrective actions. We have fully accrued for these fines. The alleged five
probable violations of the regulations of the Department of Transportation's
Office of Pipeline Safety are: (1) failure to develop an adequate internal
corrosion control program, 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 conduct continuing surveillance on
our pipeline and consider, and respond appropriately to, unusual operating and
maintenance conditions, with an associated proposed fine of $500,000; (4)
failure to follow company procedures relating to investigating pipeline failures
and thereby to minimize the chance of recurrence, with an associated proposed
fine of $500,000; and (5) failure to maintain elevation profile drawings, with
an associated proposed fine of $25,000. On October 2001, we filed a response
with the Office of Pipeline Safety disputing each of the alleged violations. If
we are required to pay the proposed fines, it will not have a material adverse
effect on our financial position, operations results or cash flows.
On February 11, 2003, the National Transportation Safety Board (NTSB)
conducted a public hearing on its investigation of the Carlsbad rupture at which
the NTSB adopted Findings, Conclusions and Recommendation based upon its
investigation. In April 2003, the NTSB published its final report. The NTSB
stated that it had determined that the probable cause of the August 19, 2000
rupture was a significant reduction in pipe wall thickness due to severe
internal corrosion, which occurred because our corrosion control program "failed
to prevent, detect, or control internal corrosion" in the pipeline. The NTSB
also determined that ineffective federal preaccident inspections contributed to
the accident by not identifying deficiencies in our internal corrosion control
program.
On November 1, 2002, we received a federal grand jury subpoena for
documents relating to the rupture and we are cooperating fully with the grand
jury.
A number of personal injury and wrongful death lawsuits were filed against
us in connection with the rupture. All of these suits have been settled, with
settlement payments fully covered by insurance. In connection with the
settlement of the cases, we contributed $10 million to a charitable foundation
as a memorial to the families involved. The contribution was not covered by
insurance.
Parties to four settled lawsuits have since filed an additional lawsuit
titled Diane Heady et al. v. EPEC and EPNG in Harris County, Texas on November
20, 2002 seeking an additional $85 million based upon their interpretation of
earlier agreements. Parties to another of the settled lawsuits have filed a
lawsuit titled In the Matter of Jennifer Smith, in Eddy County, New Mexico, on
May 7, 2003, seeking an additional $86 million based upon their interpretation
of earlier agreements. The Jennifer Smith case was settled with the settlement
payment fully covered by insurance. In addition, a lawsuit entitled Baldonado et
al vs. EPNG was filed on June 30, 2003 in state court in Eddy County, New Mexico
on behalf of firemen and EMS personnel who
9
responded to the fire and who allegedly have suffered psychological trauma. Our
costs and legal exposure related to the Heady and Baldonado lawsuits are
currently not determinable. However, we believe these matters will be fully
covered by insurance.
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 of
natural gas produced from royalty properties 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). In May 2001, the court denied the
defendants' motions to dismiss. 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 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. Quinque has been dropped as a plaintiff and Will Price has been added.
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 plaintiffs in this case seek certification of a nationwide
class of natural gas working interest owners and natural gas royalty owners to
recover royalties that the plaintiffs contend these owners 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,
attorney's 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 was denied on April 10, 2003. Plaintiffs' motion to file another
amended petition to narrow the proposed class to royalty owners in wells in
Kansas, Wyoming and Colorado was granted on July 28, 2003. 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 in 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 of June 30, 2003, we had accrued approximately $559 million for all
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 June 30,
2003, we had accrued approximately $30 million for expected remediation costs at
current and former sites and associated onsite, offsite and groundwater
technical studies and for related environmental legal costs, which we anticipate
incurring through 2027. The high end of our reserve estimates was approximately
$54 million and the low end was approximately $28 million, and our accrual at
June 30, 2003 was based on the probability of
10
the range of reasonably possible outcomes. Below is a reconciliation of our
accrued liability as of June 30, 2003 (in millions).
<Table>
Balance as of January 1, 2003............................... $29
Additions/adjustments for remediation activities............ 1
---
Balance as of June 30, 2003................................. $30
===
</Table>
In addition, we expect to make capital expenditures for environmental
matters of approximately $3 million in the aggregate for the years 2003 through
2008. These expenditures primarily relate to compliance with clean air
regulations. For the remainder of 2003, we estimate that our total remediation
expenditures will be approximately $2 million, which primarily will be expended
under government directed clean-up plans.
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 four 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 sites through indemnification by third parties and settlements which
provide for payment of our allocable share of remediation costs. As of June 30,
2003, we have estimated our share of the remediation costs at these sites to be
between $13 million and $18 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 $30
million 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 the reserves are
adequate.
Rates and Regulatory Matters
CPUC Complaint Proceeding. In April 2000, the CPUC filed a complaint under
Section 5 of the Natural Gas Act (NGA) with the FERC alleging that our sale of
approximately 1.2 Bcf/d of capacity to our affiliate, EPME, raised issues of
market power and violation of FERC's marketing affiliate regulations and asked
that the contracts be voided. In the spring and summer of 2001, two hearings
were held before an ALJ to address the market power issue and the affiliate
issue. In October 2001, the ALJ issued an initial decision on the two issues,
finding that the record did not support a finding that either we or EPME had
exercised market power but finding that we had violated FERC's marketing
affiliate rule.
Also, in October 2001, the FERC's Office of Market Oversight and
Enforcement filed comments stating that the record at the hearings was
inadequate to conclude that we had complied with FERC regulations in the
transportation of gas to California. In December 2001, the FERC remanded the
proceeding to the ALJ for a supplemental hearing on the availability of capacity
at our California delivery points. On September 23, 2002, the ALJ issued his
initial decision, again finding that there was no evidence that EPME had
exercised market power during the period at issue to drive up California gas
prices and therefore recommending that the complaint against EPME be dismissed.
However, the ALJ found that we had withheld at least 345 MMcf/d of capacity (and
perhaps as much as 696 MMcf/d) from the California market during the period from
November 1, 2000 through March 31, 2001. The ALJ found that this alleged
withholding violated our
11
certificate obligations and was an exercise of market power that increased the
gas price to California markets. He therefore recommended that the FERC initiate
penalty procedures against us. The FERC has taken no actions in this proceeding
on the ALJ's finding. This proceeding will be resolved upon finalization and
approval of the Western Energy Settlement.
Systemwide Capacity Allocation Proceeding. In July 2001, several of our
contract demand (CD) customers filed a complaint against us at the FERC
claiming, among other things, that our full requirements (FR) contracts
(contracts with no volumetric limitations) should be converted to CD contracts,
and that we should be required to expand our system and give demand charge
credits to CD customers when we are unable to meet their full contract demands.
Also in July 2001, several of our FR customers filed a complaint alleging that
we had violated the Natural Gas Act and our contractual obligations to them by
not expanding our system, at our cost, to meet their increased requirements.
On May 31, 2002, the FERC issued an order on the complaints in which it
required that (i) FR service, for all FR customers except small volume
customers, be converted to CD service; (ii) firm customers be assigned specific
receipt point rights in lieu of their existing systemwide receipt point rights;
(iii) reservation charge credits be given to all firm customers for failure to
schedule confirmed volumes except in cases of force majeure; (iv) no new firm
contracts be executed until we have demonstrated there is adequate capacity on
the system; and (v) a process be implemented to allow existing CD customers to
turn back capacity for acquisition by FR customers in which process we would
remain revenue neutral. These changes were to be made effective November 1,
2002. The order also stated that the FERC expected us to file for certificate
authority to add compression to Line 2000 to increase our system capacity by 320
MMcf/d without cost coverage until our next rate case (i.e. January 1, 2006) as
we had previously informed the FERC we were willing to do. In July 2002, we and
other parties filed for clarification and/or rehearing of the May 31 order.
On September 20, 2002, the FERC issued an order postponing the effective
date of the FR conversions until May 1, 2003 and requiring us to allocate among
our FR customers (i) the 320 MMcf/d of capacity that will be available from the
addition of compression to Line 2000, and (ii) any firm capacity under existing
contracts that expired between May 31, 2002 and May 1, 2003. In total, our FR
customers will pay only their current aggregate reservation charges for existing
unsubscribed capacity, for the 230 MMcf/d of capacity made available in November
2002 by our Line 2000 project, for the 320 MMcf/d of capacity from the addition
of compression to Line 2000, and for all capacity subject to contracts expiring
before May 1, 2003. On April 14, 2003, the FERC issued an order resetting the
implementation date to September 1, 2003.
In October 2002, we filed tariff sheets in compliance with the September 20
order to implement a partial demand charge credit for the period November 1,
2002 to May 6, 2003, and to allow California delivery points to be used as
secondary receipt points to the extent of our backhaul displacement
capabilities. We proposed both a reservation and a usage charge for this
service. On December 26, 2002, the FERC issued an order (i) denying our request
to charge existing CD customers a reservation rate for California receipt
service for the remaining term of the settlement, i.e., through December 31,
2005; (ii) allowing us to charge our maximum IT rate for the service; (iii)
approving our proposed usage rate for the service until our next rate case; and
(iv) requiring us to make a showing that capacity is available for any new
shippers utilizing this service.
On July 9, 2003, the FERC issued a rehearing order in the proceeding. The
order denied rehearing of FERC's previous determination that FR contracts must
be converted to CD contracts. The order also declined to postpone the September
1, 2003 implementation date for the conversion of the FR contracts and for the
replacement of systemwide firm receipt rights with firm rights at specific
receipt locations. In ruling on these issues, the FERC found that we have not
violated our certificates, our contractual obligations, including our
obligations under the 1996 Settlement, or our tariff provisions as a result of
the capacity allocations that have occurred on the system since the 1996
Settlement. In addition, the FERC found that we have correctly stated the
capacity that is available on a firm basis for allocation among our shippers and
that we have allocated that capacity consistent with the requirements of the
previous orders in the proceeding. On a prospective basis, the FERC ordered us
to remove the pro rata allocation provisions from our tariff, to set aside a
pool of 110 MMcf/d of capacity for use by the converting FR shippers until the
first phase of the Line 2000
12
Power-Up (discussed below) goes into service (estimated to be February 2004,
after which the pool of capacity will be reduced to 50 MMcf/d until the second
phase of the Power-Up is in service in mid-2004), and to pay full reservation
charge credits when we are unable to schedule gas that has been nominated and
confirmed by our firm shippers. In cases of force majeure events and
maintenance, we will limit the amount of our reservation charge credits to the
return and associated tax portion of our rates. The rehearing order also lifted
the ban on the resale of firm capacity that comes back to us, subject only to
the 110/50 MMcf/d of capacity that must be maintained in a pool for the
converting FR shippers until the first two phases of the Line 2000 Power-Up are
in service.
On July 18, 2003, the FR shippers filed two appeals of the July 9 order
with the United States Court of Appeals for the D.C. Circuit (Arizona Corp.
Comm'n, et al. v. FERC, Nos. 03-1206, et al.) and subsequently moved the Court
for a stay of the September 1, 2003 conversion date. We have intervened in the
proceedings and will oppose the petitions. We opposed the stay motion. The Court
denied the stay motion on August 6, 2003. The final outcome of those appeals
cannot be predicted with certainty.
On August 8, 2003 a number of parties sought further clarification and/or
rehearing of the FERC's July 2003 rehearing order. We sought clarification of a
companion order that addressed tariff sheets implementing the conversions. We
cannot predict the final outcome of FERC's actions on those filings.
Rate Settlement. Our current rate settlement establishes our base rates
through December 31, 2005. Under the settlement, our base rates began escalating
annually in 1998 for inflation. 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 these provisions, we
will receive cash payments in total of $295 million for a portion of the risk we
assumed from capacity relinquishments by our customers (primarily capacity
turned back to us by Southern California Gas Company and Pacific Gas & Electric
Company which represented approximately one-third of the capacity of our system)
during 1996 and 1997. The cash we received was deferred, and we recognize this
amount in revenues ratably over the risk sharing period. As of June 30, 2003, we
had unearned risk sharing revenues of approximately $16 million and had $6
million remaining to be collected from customers under this provision. Amounts
received for relinquished capacity sold to customers, above certain dollar
levels specified in our rate settlement, obligate us to refund a portion of the
excess to customers. Under this provision, we refunded a total of $46 million of
2002 revenues to customers during 2002 and the first quarter of 2003. During
2003, we established an additional refund obligation of $19 million. Both the
risk and revenue sharing provisions of the rate settlement extend through 2003.
Line 2000 Project. In July 2000, we applied with the FERC for a
certificate of public convenience and necessity for our Line 2000 project, which
was designed to replace old compression on the system with a converted oil
pipeline, resulting in no increase in system capacity. In response to demand
conditions on our system, however, we filed in March 2001 to amend our
application to convert the project to an expansion project of 230 MMcf/d. In May
2001, the FERC authorized the amended Line 2000 project. We placed the line in
service in November 2002 at a capital cost of $189 million. The cost of the Line
2000 conversion will not be included in our rates until our next rate case,
which will be effective on January 1, 2006.
On October 3, 2002, pursuant to the FERC's May 31 and September 20 orders
in the systemwide capacity allocation proceeding, we filed with the FERC for a
certificate of public convenience and necessity to add compression to our Line
2000 project to increase the capacity of that line by an additional 320 MMcf/d
at an estimated capital cost of approximately $173 million for all phases. In
our request for clarification of the September 20 order, we have asked for
assurances from the FERC that we will be able to begin cost recovery for this
project at the time our next rate case becomes effective. On June 4, 2003, the
FERC approved our application to construct the Line 2000 Power-Up expansion. The
FERC did not address the rate cap issue raised in the application, although it
did find that rolled-in rate treatment for the costs of the Power-Up would be
appropriate in our next rate case.
Marketing Affiliate NOPR. In September 2001, the 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 the
13
FERC, would dictate how we conduct business and interact with our energy
affiliates. We have filed comments with the FERC addressing our concerns with
the proposed rules, participated in a public conference and filed additional
comments. At this time, we cannot predict the outcome of the NOPR, but adoption
of the regulations in their proposed form would, at a minimum, place additional
administrative and operational burdens on us.
Negotiated Rate Policy. In July 2002, the FERC issued a Notice of Inquiry
(NOI) that sought comments regarding its 1996 policy of permitting pipelines to
enter into negotiated rate transactions. We have entered into those transactions
over the years, and the FERC is now reviewing whether negotiated rates should be
capped, whether or not the "recourse rate" (a cost-of-service based rate)
continues to safeguard against a pipeline exercising market power and other
issues related to negotiated rate programs. El Paso's pipelines and others filed
comments on the NOI.
In July 2003, the FERC issued modifications to its negotiated rate policy
applicable to interstate natural gas pipelines. The new policy has two primary
changes. First, the FERC will no longer permit the pricing of negotiated rates
based on natural gas commodity price indices, although it will permit current
contracts negotiated on that basis to continue until the end of the applicable
contract period. Second, the FERC is imposing new filing requirements on
pipelines to ensure the transparency of negotiated rate transactions.
Interim Rule on Cash Management. In August 2002, the FERC issued a NOPR
proposing, inter alia, that all cash management or money pool arrangements
between a FERC-regulated subsidiary and its non-FERC regulated parent be in
writing and that, as a condition of participating in such an arrangement, the
FERC-regulated entity maintain a minimum proprietary capital balance of 30
percent and both it and its parent maintain investment grade credit ratings.
After receiving written comments and hearing industry participants' concerns at
a public conference in September 2002, the FERC issued an Interim Rule on Cash
Management on June 26, 2003, which did not adopt the proposed limitations on
entry into or participation in cash management programs. Instead, the Interim
Rule requires natural gas companies to maintain up-to-date documentation
authorizing the establishment of the cash management programs in which they
participate and supporting all deposits into, borrowings and interest from, and
interest expense paid to such programs.
The Interim Rule also seeks comments on a proposed reporting requirement
that a FERC-regulated entity file cash management agreements and any changes
thereto within ten days and that it notify the FERC within five days when its
proprietary capital ratio falls below 30 percent (i.e., its long-term
debt-to-equity ratio rises above 70 percent) and when it subsequently returns to
or exceeds 30 percent. We filed comments on the Interim Rule on August 7, 2003.
Emergency Reconstruction of Interstate Natural Gas Facilities Final
Rule. On May 19, 2003, the FERC issued a Final Rule that amends its regulations
to enable natural gas interstate pipeline companies, in emergency situations,
resulting in sudden, unanticipated loss of natural gas or capacity, to replace
facilities when immediate action is required to restore service, for the
protection of life or health or for the maintenance of physical property.
Specifically, the Final Rule permits a pipeline to replace mainline facilities
using a route other than an existing right-of-way, to commence construction
without being subject to a 45-day waiting period, and to undertake projects that
exceed the existing blanket cost constraints. Lastly, the Final Rule requires
that landowners be notified of potential construction but provides for a
possible waiver of the 30-day waiting period.
Pipeline Safety Notice of Proposed Rulemaking. In January 2003, the U.S.
Department of Transportation issued a NOPR proposing to establish a rule
requiring pipeline operators to develop integrity management programs to
comprehensively evaluate their pipelines and take measures to protect pipeline
segments located in what the notice refers to as "high consequence areas." The
proposed rule resulted from the enactment of the Pipeline Safety Improvement Act
of 2002, a new bill signed into law in December 2002. Comments on the NOPR were
filed on April 30, 2003. At this time, we cannot predict the outcome of this
rulemaking.
14
Other Matters
Enron Bankruptcy. 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. Enron North America had
transportation contracts on our system. The transportation contracts have now
been rejected and we have filed a proof of claim in the amount of approximately
$128 million, which included $18 million for amounts due for services provided
through the date the contracts were rejected and $110 million for damage claims
arising from the rejection of its transportation contracts. We have fully
reserved for all amounts due from Enron through the date the contracts were
rejected, and we have not recognized any amounts under these contracts since the
rejection date.
While the outcome of our outstanding legal matters, environmental matters,
and 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 related to these matters. It is also possible that the outcome of these
matters could impact our credit rating and that of our parent. Further, for
environmental matters, 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 new information for our outstanding legal matters, environmental
matters and rates and regulatory matters becomes available, or relevant
developments occur, we will review our accruals and make any appropriate
adjustments. 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.
6. RELATED PARTY TRANSACTIONS
We participate in El Paso's cash management program which matches
short-term cash surpluses and needs of participating affiliates, thus minimizing
total borrowings from outside sources. Our continued participation in the
program may be dependent on any final rule issued by the FERC in connection with
its Interim Rule on Cash Management as discussed in Note 5. As of June 30, 2003
and December 31, 2002, we had advanced to El Paso $1,046 million and $990
million. The market rate of interest at June 30, 2003 and December 31, 2002, was
1.3% and 1.5%. As of June 30, 2003 and December 31, 2002, we have classified
$845 million and $565 million of these advances as non-current notes receivable
from affiliates. These receivables were due upon demand; however, we do not
anticipate settlement within the next twelve months.
At June 30, 2003 and December 31, 2002, we had other accounts receivable
from related parties of $3 million and $7 million. Accounts payable to
affiliates was $20 million and $33 million at June 30, 2003 and December 31,
2002. These balances arose in the normal course of business.
On April 3, 2003, El Paso contributed its 500,000 shares of our 8%
preferred stock to us, including the accrued dividends. The total contribution
was approximately $359 million and is reflected as additional paid in capital in
our total stockholders equity.
The following table shows revenues and charges from our affiliates for the
quarters and six months ended June 30, 2003 and 2002:
<Table>
<Caption>
SIX MONTHS
QUARTER ENDED ENDED
JUNE 30, JUNE 30,
-------------- ------------
2003 2002 2003 2002
----- ----- ---- ----
(IN MILLIONS)
Revenues from affiliates.................................. $ 5 $13 $ 9 $26
Operations and maintenance from affiliates................ 16 13 34 30
Reimbursement for operating expenses from affiliates...... 3 3 6 4
</Table>
15
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The information contained in Item 2 updates, and should be read in
conjunction with, the information disclosed in our 2002 Form 10-K in addition to
the financial statements and notes presented in Item 1 of this Form 10-Q.
REVENUE OUTLOOK
Our total revenues were $134 million during the second quarter of 2003 and
$266 million for the six month period ended June 30, 2003. This compares to
revenues of $144 million and $296 million for the same periods of 2002, a
decrease of 7 percent for the second quarter and 10 percent year to date. As
discussed in Item 1, Note 5, on September 20, 2002, the FERC issued an order
related to the allocation of capacity on our EPNG system. This order impacted
our 2003 revenues and will continue to impact our future results.
Based on the order, we are unable to remarket approximately 471 MMDth/d of
capacity, of which approximately 200 MMDth/d was rejected by Enron Corp. in May
2002 in its bankruptcy proceeding with the remaining 271 MMDth/d related to
contracts that expired within the time frame specified under the order. Prior to
the rejection and expiration of the 471 MMDth/d contracts, we were earning
approximately $3.5 million per month, net of revenue credits, related to this
capacity.
In July 2003, the FERC issued a rehearing order related to our capacity
allocation proceedings discussed more fully in Note 5. In this ruling, the FERC
reaffirmed its decision that our full requirements contracts must be converted
to contract demand contracts effective September 1, 2003, supported our position
relative to the maximum amount of capacity we can make available to our shippers
and confirmed that we have honored our obligations under our existing rate
settlement, our contracts, the FERC's regulations and our certificates. Pursuant
to the July rehearing order, we are required to establish a pool of 110 MMcf/d
for use by our full requirement shippers until Line 2000 power up capacity is
phased into service, which is expected in 2004. See Item 1, Note 5 for a
discussion of this rehearing order. The full 110 MMcf/d will be turned back to
us on a permanent basis effective September 1, 2003, and we will be at risk for
remarketing this capacity.
In addition, we have risk sharing mechanisms under our most recent rate
case settlement. Under these risk sharing mechanisms, we collect cash from our
customers, refund a portion of the cash received as required by the mechanism
and then recognize the difference as revenues over the risk sharing period. This
risk sharing period will expire on December 31, 2003. The expiration of the risk
sharing mechanism will decrease our annual revenues by approximately $23
million. See Item 1, Note 5, for a further discussion of our risk sharing
mechanism.
RESULTS OF OPERATIONS
We use 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, (ii) income taxes, (iii) interest and debt expense and (iv)
affiliated interest income. We exclude interest and debt expense so that
investors may evaluate our operating results without regard to our financing
methods. As a result, we believe EBIT is useful to our investors because it
allows them to more effectively evaluate the operating performance of our
business. In addition, this is the measure used by El Paso to evaluate the
operating performance of its business segments. This measurement may not be
comparable to measurements used by other companies and should not be used as a
substitute for net income or other performance measures such as operating income
or operating cash flow. The following is a
16
reconciliation of our operating income to our EBIT and our EBIT to our net
income for the periods ended June 30:
<Table>
<Caption>
QUARTER ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
----------------- -------------------
2003 2002 2003 2002
------- ------- -------- --------
(IN MILLIONS, EXCEPT VOLUME AMOUNTS)
Operating revenues................................. $ 134 $ 144 $ 266 $ 296
Operating expenses................................. (221) (62) (280) (132)
------ ------ ------ ------
Operating income (loss).......................... (87) 82 (14) 164
Other income....................................... 1 -- 2 --
------ ------ ------ ------
EBIT............................................. (86) 82 (12) 164
Interest and debt expense.......................... (20) (18) (40) (34)
Affiliated interest income, net.................... 4 6 7 12
Income taxes....................................... 39 (26) 17 (54)
------ ------ ------ ------
Net income (loss)................................ $ (63) $ 44 $ (28) $ 88
====== ====== ====== ======
Throughput volumes (BBtu/d)(1)..................... 3,925 4,046 3,997 4,124
====== ====== ====== ======
</Table>
- ---------------
(1) Excludes Mojave throughput on behalf of EPNG.
Second Quarter 2003 Compared to Second Quarter 2002
Operating revenues for the quarter ended June 30, 2003, were $10 million
lower than the same period in 2002. A decrease of $12 million was due to
capacity contracts that have expired which we are prohibited from remarketing
due to our September 20, 2002 FERC order. For further discussion of this order,
see our revenue outlook above, as well as Item 1, Note 5. Also contributing to
the decrease was $3 million of higher natural gas recoveries from customers in
excess of amounts used in operations in 2002 versus 2003. These decreases were
partially offset by $3 million of tax reimbursements related to the construction
of facilities for our customers, and $2 million of lower revenue credits under
our risk sharing mechanism as a result of our inability to remarket the capacity
contracts discussed above. For further discussion of our revenue sharing
provisions and revenue credits see Item 1, Note 5.
Operating expenses for the quarter ended June 30, 2003, were $159 million
higher than the same period in 2002. An increase of $154 million was due to El
Paso's Western Energy Settlement discussed in Item 1, Notes 2 and 4, of which
$146 million related to the incremental obligations associated with reaching
definitive settlements of these matters and $8 million of accretion and other
operation and maintenance costs. Also contributing to the increase was $5
million of natural gas used in operations in excess of natural gas recovered
from our customers in 2003, $3 million of gains recognized in 2002 on the sale
of non-pipeline assets, $2 million of higher overhead allocations from El Paso
and $2 million of taxes, other than income taxes, due to a change in an
estimated business activity tax settlement in 2002. These increases were
partially offset by a $5 million change in an estimated settlement in 2002
related to the Carlsbad incident and $3 million due to bad debt expense recorded
in 2002 related to the bankruptcy of Enron Corp.
Six Months Ended 2003 Compared to Six Months Ended 2002
Operating revenues for the six months ended June 30, 2003, were $30 million
lower than the same period in 2002. A decrease of $28 million was due to
capacity contracts that have expired which we are prohibited from remarketing
due to our September 20, 2002 FERC order. Also contributing to the decrease was
a $6 million fuel settlement related to our Mojave Pipeline rate case settled in
the first quarter of 2002 and $4 million of higher natural gas recoveries from
our customers in excess of amounts used in operations in 2002 versus 2003. This
decrease was partially offset by $3 million of lower revenue credits under our
risk sharing mechanism as a result of our inability to remarket the capacity
contracts discussed above, $3 million of tax reimbursements related to the
construction of facilities for our customers, and $2 million of higher
throughput based revenues from transportation to interconnecting pipelines
serving markets in the Midwest and East.
17
Operating expenses for the six months ended June 30, 2003, were $148
million higher than the same period in 2002. An increase of $158 million is due
to El Paso's Western Energy Settlement discussed in Item 1, Notes 2 and 5. Also
contributing to the increase was $7 million of natural gas used in operations in
excess of amounts recovered in 2003, $4 million related to gains recognized in
2002 on the sale of non-pipeline assets, $4 million of higher depreciation
expense resulting from facilities placed in service after the second quarter of
2002, $3 million of higher overhead allocations from El Paso and $3 million of
taxes, other than income taxes, due to a change in an estimated business
activity tax settlement in 2002. These increases were partially offset by a
decrease of $12 million due to bad debt expense recorded in 2002 related to the
bankruptcy of Enron Corp., $6 million due to the decrease in our estimated
purchase power costs in 2003 and the conversion of certain compressors to gas
from electric, a $5 million change in an estimated settlement in 2002 related to
the Carlsbad incident and $2 million from the periodic revaluation of our gas
imbalances due to a change in natural gas prices.
INTEREST AND DEBT EXPENSE
Below is the analysis of our interest expense for the quarter and six
months ended June 30, 2003 and 2002 (in millions):
<Table>
<Caption>
QUARTER SIX MONTHS
ENDED ENDED
JUNE 30, JUNE 30,
----------- -----------
2003 2002 2003 2002
---- ---- ---- ----
Long term debt, including current maturities................ $20 $15 $40 $29
Commercial paper............................................ -- 4 -- 8
Other interest.............................................. -- -- 1 --
Less: capitalized interest.................................. -- (1) (1) (3)
--- --- --- ---
Total interest expense................................. $20 $18 $40 $34
=== === === ===
</Table>
Second Quarter 2003 Compared to Second Quarter 2002
Interest and debt expense for the quarter ended June 30, 2003, was $2
million higher than the same period in 2002 primarily due to a $5 million
increase in interest expense resulting from the issuance of $300 million
long-term debt in June 2002. This increase was offset by a $4 million decrease
in commercial paper interest expense due to the discontinuation of commercial
paper activity in the fourth quarter of 2002.
Six Months Ended 2003 Compared to Six Months Ended 2002
Interest and debt expense for the six months ended June 30, 2003, was $6
million higher than the same period in 2002 primarily due to an $11 million
increase in interest expense resulting from the issuance of $300 million
long-term debt in June 2002 and a $2 million decrease in interest capitalized on
construction projects due to a lower capitalization base in 2003. These
increases were partially offset by an $8 million decrease in commercial paper
interest expense due to the discontinuation of commercial paper activity in the
fourth quarter of 2002.
AFFILIATED INTEREST INCOME, NET
Second Quarter 2003 Compared to Second Quarter 2002
Affiliated interest income, net for the quarter ended June 30, 2003, was $2
million lower than the same period in 2002 due to lower short-term interest
rates in 2003 and lower average advances to El Paso under our cash management
program. The average short-term interest rates for the second quarter decreased
from 1.9% in 2002 to 1.3% in 2003. The average advance balance for the second
quarter of $1.2 billion in 2002 decreased to $1 billion in 2003.
18
Six Months Ended 2003 Compared to Six Months Ended 2002
Affiliated interest income, net for six months ended June 30, 2003, was $5
million lower than the same period in 2002 due to lower short-term interest
rates in 2003 and lower average advances to El Paso under our cash management
program. The average short-term interest rates for six months ended decreased
from 1.9% in 2002 to 1.3% in 2003. The average advance balance for the six
months ended June 30, 2002 of $1.3 billion decreased to $1 billion in 2003.
INCOME TAXES
<Table>
<Caption>
QUARTER ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
-------------- ----------------
2003 2002 2003 2002
---- ---- ---- ----
(IN MILLIONS, EXCEPT FOR RATES)
Income taxes......................................... $(39) $26 $(17) $54
Effective tax rate................................... 38% 37% 38% 38%
</Table>
Our effective tax rates were different than the statutory rate of 35
percent in all periods, primarily due to state income taxes.
COMMITMENTS AND CONTINGENCIES
See Item 1, Financial Statements, Note 5, which is incorporated herein by
reference.
19
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 to be made 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.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
This information updates, and you should read it in conjunction with,
information disclosed in Part II, Item 7A in our Annual Report on Form 10-K for
the year ended December 31, 2002, in addition to the information presented in
Items 1 and 2 of this Quarterly Report on Form 10-Q.
In July 2003, we issued $355 million of senior unsecured notes with an
annual interest rate of 7.625% due 2010. Other than this issuance, there are no
material changes in our quantitative and qualitative disclosures about market
risks from those reported in our Annual Report on Form 10-K for the year ended
December 31, 2002.
ITEM 4. 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 Quarterly 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. El Paso Natural Gas
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.
20
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 El
Paso Natural Gas Company's Internal Controls, or whether the company had
identified any acts of fraud involving personnel who have a significant role in
El Paso Natural Gas 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 Quarterly 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 El Paso Natural Gas Company and its consolidated subsidiaries is
made known to management, including the principal executive officer and
principal financial officer, on a timely basis.
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 Quarterly
Report.
21
PART II -- OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
See Part I, Item 1, Financial Statements, Note 5, which is incorporated
herein by reference.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS
None.
ITEM 5. OTHER INFORMATION
None.
22
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a. Exhibits
Each exhibit identified below is filed as a part of this report. Exhibits
not incorporated by reference to a prior filing are designated by an "*"; 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 April 8, 2003.
4.A Indenture dated as of July 21, 2003 between El Paso Natural
Gas Company and Wilmington Trust Company, as trustee
(Exhibit 4.1 to our Form 8-K filed July 23, 2003).
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 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. 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, Commission File
No. 1-2700).
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, Commission
File No. 1-2700).
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,
Commission File No. 1-2700).
*10.D Master Settlement Agreement dated as of June 24, 2003, by
and between, on the one hand, El Paso Corporation, El Paso
Natural Gas Company, and El Paso Merchant Energy, L.P.; and,
on the other hand, the Attorney General of the State of
California, the Governor of the State of California, the
California Public Utilities Commission, the California
Department of Water Resources, the California Energy
Oversight Board, the Attorney General of the State of
Washington, the Attorney General of the State of Oregon, the
Attorney General of the State of Nevada, Pacific Gas &
Electric Company, Southern California Edison Company, the
City of Los Angeles, the City of Long Beach, and classes
consisting of all individuals and entities in California
that purchased natural gas and/or electricity for use and
not for resale or generation of electricity for the purpose
of resale, between September 1, 1996 and March 20, 2003,
inclusive, represented by class representatives Continental
Forge Company, Andrew Berg, Andrea Berg, Gerald J. Marcil,
United Church Retirement Homes of Long Beach, Inc., doing
business as Plymouth West, Long Beach Brethren Manor, Robert
Lamond, Douglas Welch, Valerie Welch, William Patrick Bower,
Thomas L. French, Frank Stella, Kathleen Stella, John
Clement Molony, SierraPine, Ltd., John Frazee and Jennifer
Frazee, John W.H.K. Phillip, and Cruz Bustamante.
*10.E Joint Settlement Agreement submitted and entered into by El
Paso Natural Gas Company, El Paso Merchant Energy Company,
El Paso Merchant Energy-Gas, L.P., the Public Utilities
Commission of the State of California, Pacific Gas &
Electric Company, Southern California Edison Company and the
City of Los Angeles.
10.F Registration Rights Agreement dated as of July 21, 2003
between El Paso Natural Gas Company and the Initial
Purchasers (Exhibit 10.1 to our Form 8-K filed July 23,
2003).
*31.A Certification of Chief Executive Officer pursuant to
sec. 302 of the Sarbanes-Oxley Act of 2002.
</Table>
23
<Table>
<Caption>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
*31.B Certification of Chief Executive 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 Executive Officer pursuant to 18
U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the
Sarbanes-Oxley Act of 2002.
</Table>
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 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.
b. Reports on Form 8-K
<Table>
April 18, 2003........................... Announced the refinancing and
restructuring of our major bank
facilities.
April 23, 2003........................... Filed our Computation of Ratio of
Earnings to Fixed Charges for the five
years ended December 31, 2002.
June 6, 2003............................. Filed our Computation of Ratio of
Earnings to Fixed Charges for the five
years ended December 31, 2002 and three
months ended March 31, 2003 and 2002.
July 9, 2003............................. Announced the execution by El Paso
Corporation, our parent company, of two
definitive settlement agreements to
resolve the principal litigation in
connection with the western energy crisis
and the taking of the final procedural
step to ensure completion of these
agreements.
July 24, 2003............................ Announced the sale of our 7 5/8% Senior
Notes due 2010.
</Table>
We also furnished information to the SEC on Current Reports on Form 8-K
under Item 9. Current Reports on Form 8-K under Item 9 are not considered to be
"filed" for purposes of Section 18 of the Securities and Exchange Act of 1934
and are not subject to the liabilities of that section.
24
SIGNATURES
Pursuant to the requirements 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.
EL PASO NATURAL GAS COMPANY
Date: August 13, 2003 /s/ JOHN W. SOMERHALDER II
------------------------------------
John W. Somerhalder II
Chairman of the Board,
Chief Executive Officer and Director
(Principal Executive Officer)
Date: August 13, 2003 /s/ GREG G. GRUBER
------------------------------------
Greg G. Gruber
Senior Vice President,
Chief Financial Officer, Treasurer
and Director
(Principal Financial and Accounting
Officer)
25
EXHIBIT INDEX
Each exhibit identified below is filed as a part of this report. Exhibits
not incorporated by reference to a prior filing are designated by an "*"; 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 April 8, 2003.
4.A Indenture dated as of July 21, 2003 between El Paso Natural
Gas Company and Wilmington Trust Company, as trustee
(Exhibit 4.1 to our Form 8-K filed July 23, 2003).
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 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. 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, Commission File
No. 1-2700).
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, Commission
File No. 1-2700).
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,
Commission File No. 1-2700).
*10.D Master Settlement Agreement dated as of June 24, 2003, by
and between, on the one hand, El Paso Corporation, El Paso
Natural Gas Company, and El Paso Merchant Energy, L.P.; and,
on the other hand, the Attorney General of the State of
California, the Governor of the State of California, the
California Public Utilities Commission, the California
Department of Water Resources, the California Energy
Oversight Board, the Attorney General of the State of
Washington, the Attorney General of the State of Oregon, the
Attorney General of the State of Nevada, Pacific Gas &
Electric Company, Southern California Edison Company, the
City of Los Angeles, the City of Long Beach, and classes
consisting of all individuals and entities in California
that purchased natural gas and/or electricity for use and
not for resale or generation of electricity for the purpose
of resale, between September 1, 1996 and March 20, 2003,
inclusive, represented by class representatives Continental
Forge Company, Andrew Berg, Andrea Berg, Gerald J. Marcil,
United Church Retirement Homes of Long Beach, Inc., doing
business as Plymouth West, Long Beach Brethren Manor, Robert
Lamond, Douglas Welch, Valerie Welch, William Patrick Bower,
Thomas L. French, Frank Stella, Kathleen Stella, John
Clement Molony, SierraPine, Ltd., John Frazee and Jennifer
Frazee, John W.H.K. Phillip, and Cruz Bustamante.
*10.E Joint Settlement Agreement submitted and entered into by El
Paso Natural Gas Company, El Paso Merchant Energy Company,
El Paso Merchant Energy-Gas, L.P., the Public Utilities
Commission of the State of California, Pacific Gas &
Electric Company, Southern California Edison Company and the
City of Los Angeles.
10.F Registration Rights Agreement dated as of July 21, 2003
between El Paso Natural Gas Company and the Initial
Purchasers (Exhibit 10.1 to our Form 8-K filed July 23,
2003).
*31.A Certification of Chief Executive Officer pursuant to
sec. 302 of the Sarbanes-Oxley Act of 2002.
*31.B Certification of Chief Executive Officer pursuant to
sec. 302 of the Sarbanes-Oxley Act of 2002.
</Table>
<Table>
<Caption>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
*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 Executive Officer pursuant to 18
U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the
Sarbanes-Oxley Act of 2002.
</Table>