EL PASO NATURAL GAS CO - 10-Q Quarterly Report

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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 SEPTEMBER 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)

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)

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 November 10,
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

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Below is a list of terms that are common to our industry and used
throughout this document:

/d = per day
BBtu = billion British thermal units
Bcf = billion cubic feet
MMcf = million cubic feet
MMDth = million dekatherm

When we refer to cubic feet measurements, all measurements are at a pressure
of 14.73 pounds per square inch.

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PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EL PASO NATURAL GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(IN MILLIONS)
(UNAUDITED)

See accompanying notes.

1

EL PASO NATURAL GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS
(IN MILLIONS, EXCEPT SHARE AMOUNTS)
(UNAUDITED)

See accompanying notes.

2

EL PASO NATURAL GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN MILLIONS)
(UNAUDITED)

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 September 30, 2003, and for the
quarters and nine months ended September 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 be indicative of our 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 had 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 systems are subject
to the jurisdiction of the Federal Energy Regulatory Commission (FERC) in
accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of
1978, and we currently apply the provisions of SFAS No. 71, Accounting for the
Effects of Certain Types of Regulation. The accounting required by SFAS No. 71
differs from the accounting required for businesses that do not apply its
provisions. Transactions that are generally recorded differently as a result of
applying regulatory accounting requirements include the capitalization of an
equity return component on regulated capital projects, post retirement employee
benefit plans, and other costs included in, or expected to be included in,
future rates. As a result of recent changes in our competitive environment and
operating cost structure, we continue to assess the applicability of the
provisions of SFAS No. 71 to our financial statements.

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 it 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 the obligations of El Paso and El Paso Merchant Energy L.P. (EPME),
a subsidiary of El Paso, 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.

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The definitive settlement agreements modified an 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 in 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. During the third quarter of 2003, we recorded
a benefit of $20 million due to changes in El Paso's stock price resulting in a
charge for the nine months ended September 30, 2003, of approximately $126
million. This charge was 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 during 2003. For the nine
months ended September 30, 2003, these accretion and other charges were
approximately $12 million. As of September 30, 2003, our total Western Energy
Settlement obligation was $536 million, all of which is reflected as a current
liability since we estimate the finalization of the settlement to occur in the
next twelve months. As of September 30, 2003, $10 million had been satisfied.
The stock portion of the settlement obligation is approximately $192 million and
will continue to impact our income statement, either positively or negatively,
based upon future changes in El Paso's stock price until the settling parties
elect to have the shares issued on their behalf.

3. ACQUISITIONS AND DIVESTITURES

In August 2003, we announced the purchase of Copper Eagle Gas Storage,
L.L.C., which is developing a natural gas storage project located outside of
Phoenix, Arizona. We purchased Copper Eagle from Arizona Gas Storage, L.L.C. and
APACS Holding L.L.C. Arizona Gas Storage is owned by our affiliate, GulfTerra
Energy Partners, L.P. The purchase price was $12 million, and we paid $2.5
million in cash at the closing. The remaining amount will be paid over twelve
months beginning January 2004. We also acquired land for approximately $9
million that will allow for further development of that project.

During 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

Debt

In July 2003, we issued $355 million of senior unsecured notes with an
annual interest rate of 7.625% due 2010. Net proceeds were approximately $347
million.

Trinity River

In March 2003, El Paso retired amounts outstanding under its Trinity River
financing arrangement. Prior to this retirement, our ownership in Mojave, along
with various assets of El Paso, collateralized that arrangement.

Credit Facilities

In April 2003, El Paso entered into a new $3 billion revolving credit
facility, with a $1.5 billion letter of credit sublimit, which matures on June
30, 2005. The $3 billion revolving credit facility has a borrowing cost of LIBOR
plus 350 basis points, letter of credit fees of 350 basis points and a
commitment fee of 75 basis points on the unused portion of the facility. This
facility replaced El Paso's previous $3 billion revolving credit facility.
Approximately $1 billion of other El Paso financing arrangements (including
leases, letters of credit and other facilities) were also amended to conform El
Paso's obligations 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 its
equity in us and our equity in Mojave Pipeline Company, collateralize the
revolving credit facility and these other financing arrangements. We were
jointly and severally liable under the $3 billion revolving credit facility
through August 19, 2003, after which time we are only liable for amounts we
directly borrow. As of September 30, 2003, $1.3 billion was outstanding and $1
billion in letters of credit

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were issued under the $3 billion revolving credit facility, none of which were
borrowed by or issued on behalf of us.

We were also a borrower under El Paso's $1 billion revolving credit
facility, which expired on August 4, 2003.

Under the $3 billion revolving credit facilities and other indentures, we
are subject to a number of restrictions and covenants. The most restrictive of
these include (i) limitations on the incurrence of additional debt, based on a
ratio of debt to EBITDA (as defined in the agreements); (ii) limitations on the
use of 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 nine months ended September 30,
2003, we were in compliance with these covenants.

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
(CPUC); the California Electricity Oversight Board; the California Department of
Water Resources; Pacific Gas and Electric Company (PG&E), 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 earlier in June 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'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 will
be 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;

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- 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 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 in escrow 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 CPUC, PG&E,
Southern California Edison Company, and the City of Los Angeles filed the
structural settlement described above with the FERC in resolution of specific
proceedings before that agency. The structural settlement was protested by our
east of California shippers and 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 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 in these cases
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. All of the
class action and municipal lawsuits and all but one of the individual lawsuits
will be resolved upon 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

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* Cases to be dismissed upon finalization and approval of the Western Energy
Settlement.

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v. El Paso Merchant Energy; and John Phillip v. El Paso Merchant Energy, both
filed December 13, 2000*); and two filed in the Superior Court of San Francisco
County (Sweetie's et al. v. El Paso Corporation, et al., filed March 22, 2001*;
and California Dairies, Inc., et al. v. El Paso Corporation, et al., filed May
21, 2001); 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 approval of the Western Energy Settlement.

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 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 arose out of a
gas supply contract between IMC Chemicals (IMCC) and EPME and sought to void the
Gas Purchase Agreement between IMCC and EPME for gas purchases until December
2003. IMCC contended 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 repeated the
allegations and claims of the California lawsuits described above. EPME intends
to enforce the terms of the contract and counterclaim for contract damages. El
Paso was dismissed from the case for lack of personal jurisdiction on September
9, 2003.

Other Energy Market Lawsuits. In February 2003, 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 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 allegations similar to those alleged in
the California cases, the suit seeks relief similar to the California cases, but
under Arizona antitrust and consumer fraud statutes. Our costs and legal
exposure related to these lawsuits and claims are not currently determinable.

In April 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. The complaint 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

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they entered into contracts at inappropriately high prices and hedging
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. In 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.

After a public hearing conducted by the National Transportation Safety
Board (NTSB) on its investigation of the Carlsbad rupture, the NTSB published
its final report in April 2003. 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 this
investigation.

A number of personal injury and wrongful death lawsuits were filed against
us in connection with the rupture. All of these lawsuits 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 of the 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 an additional lawsuit titled In the Matter of the Appointments 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

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behalf of firemen and EMS personnel who 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. We filed a motion
to dismiss the Baldonado lawsuit which is pending before the court. 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 plaintiff in this case seeks certification of a nationwide
class of natural gas working interest owners and natural gas royalty owners to
recover royalties that the plaintiff contends 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,
attorneys' fees, costs and expenses, and future injunctive relief to require the
defendants to adopt allegedly appropriate gas measurement practices. No monetary
relief has been specified in this case. Plaintiffs' motion for class
certification 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 September 30, 2003, we had accrued approximately $539 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 September
30, 2003, we had accrued approximately $29 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
September 30, 2003 was based on the

10

probability of the range of reasonably possible outcomes. Below is a
reconciliation of our accrued liability as of September 30, 2003 (in millions).

Balance as of January 1, 2003............................... $29
Additions/adjustments for remediation activities............ 2
Payments for remediation activities......................... (2)
---
Balance as of September 30, 2003............................ $29
===

In addition, we expect to make capital expenditures for environmental
matters of approximately $2 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 $1 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 September
30, 2003, we have estimated our share of the remediation costs at these sites to
be between $13 million and $17 million. Since the clean-up costs are estimates
and are subject to revision as more information becomes available about the
extent of remediation required, and because in some cases we have asserted a
defense to any liability, our estimates could change. Moreover, liability under
the federal CERCLA statute is joint and several, meaning that we could be
required to pay in excess of our pro rata share of remediation costs. Our
understanding of the financial strength of other PRPs has been considered, where
appropriate, in estimating our liabilities. Reserves for these matters are
included in the environmental reserve discussed above.

It is possible that new information or future developments could require us
to reassess our potential exposure related to environmental matters. We may
incur significant costs and liabilities in order to comply with existing
environmental laws and regulations. It is also possible that other developments,
such as increasingly strict environmental laws and regulations and claims for
damages to property, employees, other persons and the environment resulting from
our current or past operations, could result in substantial costs and
liabilities in the future. As this information becomes available, or other
relevant developments occur, we will adjust our accrual amounts accordingly.
While there are still uncertainties relating to the ultimate costs we may incur,
based upon our evaluation and experience to date, we believe our reserves are
adequate.

Rates and Regulatory Matters

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 the 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 the 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

11

November 1, 2000 through March 31, 2001. The ALJ found that this alleged
withholding violated our 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 based on the ALJ's finding. This proceeding
will be resolved upon 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 our full contract demands.
Also, in July 2001, several of our FR customers filed a complaint alleging that
we had violated the NGA and its contractual obligations by not expanding our
system, at our cost, to meet their increased requirements. Earlier, KN
Marketing, L.P. filed a complaint at the FERC alleging that we had
oversubscribed our firm mainline capacity from the San Juan Basin to the East
End of our system. In the May 31, 2002 order discussed below, the FERC addressed
these complaints. As a result of the FERC's orders in these proceedings, FR
shippers were required to convert to CD service on September 1, 2003.

On May 31, 2002, the FERC issued an order that required (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 system-wide
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 CD
customers to turn back capacity for acquisition by FR customers, in which
process we would remain revenue neutral. The order also stated that the FERC
expected us to file for certificate authority to add compression to our 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. On July 1, 2002, we and other parties filed for
clarification and/or rehearing of the May 31 order.

Following the May 31 order, the FERC issued several additional orders in
this proceeding that, among other things, required us to allocate substantial
volumes of existing and proposed pipeline capacity to our converting FR shippers
at their current aggregate reservation charges, and set the rates that we could
charge for backhaul service from our California delivery points for existing and
new shippers.

On July 9, 2003, the FERC issued a rehearing order in this case. In that
order, the FERC found that we had not violated our certificates, our contractual
obligations, including our obligations under the 1996 Rate Settlement (discussed
below), or our tariff provisions as a result of the capacity allocations that
have occurred on the system since the 1996 Rate Settlement. In addition, the
FERC found that we had correctly stated the capacity that is available on a firm
basis for allocation among our shippers and that we had properly allocated that
capacity. On a prospective basis, the FERC ordered us 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 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 case of force majeure events,
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
established in the May 31 order 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 an appeal of the July 9 order with
the D.C. Circuit (Arizona Corporation Comm'n, et al. v. FERC, No. 03-1206) and
subsequently sought a stay of the FERC's orders. The stay was denied by the
Court. Other parties have filed appeals of the FERC's orders and all such
appeals have been consolidated. The final outcome of these appeals cannot be
predicted with certainty.

On August 29, 2003, the FERC issued a further order in this matter that,
among other things, authorized our converted FR shippers to relocate delivery
points associated with the California turn back capacity they

12

would receive under the May 31 order from California to their traditional east
of California delivery points. We sought rehearing of that order because we do
not have adequate transfer capacity between our Northern and Southern mainlines
to allow us to comply with the order unless we allocate our limited North/South
capacity among our shippers. Our converted FR shippers requested that the FERC
initiate an enforcement investigation based on our position. We have opposed the
request. In the August 29 order, the FERC also directed that a technical
conference be held to address the concerns expressed by our shippers. That
conference was held on September 24, 2003 and we filed our comments regarding
that conference with the FERC. On October 20, 2003, we and the converted FR
Shippers filed an uncontested settlement that, if approved by the FERC, will
resolve all issues regarding the administration of the 110 MMcf/d capacity pool.

On October 29, 2003 our east of California shippers filed a complaint
against us with the FERC claiming that we had not properly implemented the
FERC's orders in the Capacity Allocation Case with respect to our provision of
backhaul transportation service from the California border and requesting that
the FERC issue an order requiring us to properly implement such service. We will
respond to the compliant.

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 September 30,
2003, we had unearned risk sharing revenues of approximately $8 million and had
$3 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 $30 million of
which $14 million has been refunded to customers as of September 30, 2003. 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.

In October 2002, pursuant to the FERC's 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. On June 4, 2003, the
FERC issued an order approving our certificate application. Requests for
rehearing of the June 4 order are pending at the FERC. The project is currently
under construction and Phase I should be placed in service during the first
quarter of 2004.

Marketing Affiliate NOPR. In September 2001, the FERC issued a Notice of
Proposed Rulemaking (NOPR) proposing 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 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.

13

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 an order that prospectively prohibits
pipelines from negotiating rates based upon natural gas commodity price indices
and imposes certain new filing requirements to ensure the transparency of
negotiated rate transactions. Requests for rehearing were filed on August 25,
2003 and remain pending. We do not expect the order on rehearing will have a
material effect on us.

Cash Management Rule. On October 23, 2003, the FERC approved a rule that
requires a FERC regulated entity to file its cash management agreement with the
FERC, maintain records of transactions involving its participation in the cash
management program, compute its proprietary capital ratio quarterly based on
criteria established by the FERC, and notify the FERC 45 days after the end of a
calendar quarter whether its proprietary capital ratio falls below 30 percent
and subsequently when its proprietary capital ratio returns to or exceeds 30
percent. In the rule, the FERC stated that the requirements imposed by the rule
are not in the nature of a regulation governing participation in cash management
programs and that the rule does not dictate the content or terms for
participating in a cash management program. Although the rule is subject to
rehearing, we do not believe an order on rehearing will have a material effect
on us.

On September 10, 2003, the Office of Executive Director of Regulatory
Audits completed an industry-wide audit of the FERC Form 2 related to cash
management. The audit included us and our subsidiary, Mojave Pipeline Company.
The audit did not identify any instances of non-compliance with the FERC's
reporting and recording requirements but recommended that both we and Mojave
revise and update our existing cash management agreements with El Paso. We are
in the process of reviewing and revising our cash management agreements pursuant
to this recommendation.

Emergency Reconstruction of Interstate Natural Gas Facilities Rule. On May
19, 2003, the FERC issued a 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 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. It also 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. Although we cannot predict the outcome of this
rulemaking, we do not expect this order to have a material effect on us.

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

14

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 possible that the outcome of these
matters could impact our credit rating and that of our parent. Further, for
environmental matters, it is 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. As of September 30, 2003 and December 31,
2002, we had advanced to El Paso $1,050 million and $990 million. The market
rate of interest at September 30, 2003 was 3.5% and at December 31, 2002 was
1.5%. As of September 30, 2003 and December 31, 2002, we have classified $622
million and $565 million of these advances as non-current notes receivable from
affiliates. These receivables are due upon demand; however, we do not anticipate
settlement within the next twelve months.

At September 30, 2003 and December 31, 2002, we had other accounts
receivable from related parties of $4 million and $7 million. Accounts payable
to affiliates was $63 million and $33 million at September 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 stockholder's equity.

The following table shows revenues and charges from our affiliates for the
quarters and nine months ended September 30, 2003 and 2002:

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 and the
financial statements and notes presented in Item 1 of this Form 10-Q.

REVENUE OUTLOOK

Our total revenues were $132 million during the third quarter of 2003 and
$398 million for the nine month period ended September 30, 2003. This compares
to revenues of $139 million and $435 million for the same periods in 2002, a
decrease of 5 percent for the third quarter and 9 percent year to date. As
discussed in Item 1, Note 5, the FERC issued various orders related to the
allocation of capacity on our EPNG system. These orders impacted our 2003
revenues and will continue to impact our future results.

Based on these orders, we are unable to remarket approximately 471 MMDth/d
of capacity, of which approximately 200 MMDth/d relates to capacity rejected by
Enron Corp. in May 2002 in its bankruptcy proceeding and the remaining 271
MMDth/d relates to contracts that expired within the time frame specified under
these orders. Prior to the rejection and expiration of this 471 MMDth/d of
capacity, we were earning approximately $3.5 million per month, net of revenue
credits, on this capacity.

In July 2003, the FERC issued a rehearing order related to our capacity
allocation proceedings discussed more fully in Item 1, 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 were required to
establish a pool of 110 MMcf/d for use by our full requirement shippers until
our Line 2000 expansion project is phased into service, which is expected in
early 2004. Effective September 1, 2003, we acquired this capacity, primarily on
a permanent basis, and will be at risk for remarketing this capacity which
previously generated approximately $1 million of revenue per month.

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. We estimate that 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, such as the impact of accounting changes, (ii) income taxes, (iii)
interest and debt expense and (iv) affiliated interest income. 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 measurement
used by El Paso to evaluate the operating performance of its business segments.
We exclude interest and debt expense from this measure so that investors may
evaluate our operating results without regard to our financing methods. EBIT 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

16

operating cash flow. The following is a reconciliation of our operating income
to our EBIT and our EBIT to our net income for the periods ended September 30:

- ---------------

(1) Excludes Mojave throughput on behalf of EPNG.

Third Quarter 2003 Compared to Third Quarter 2002

Operating revenues for the quarter ended September 30, 2003, were $7
million lower than the same period in 2002. A decrease of $6 million was due to
capacity contracts that have expired which we are prohibited from remarketing
due to various FERC orders. For further discussion of these orders, see our
revenue outlook above, as well as Item 1, Note 5.

Operating expenses for the quarter ended September 30, 2003, were $23
million lower than the same period in 2002. A decrease of $20 million was due to
the revaluation of the stock portion of El Paso's Western Energy Settlement
discussed in Item 1, Notes 2 and 5. Also contributing to the decrease was a $5
million change in an estimated settlement in 2002 related to the Carlsbad
incident and a $2 million loss recognized in 2002 on the sale of non-pipeline
assets. These decreases were partially offset by an increase of $4 million due
to the periodic revaluation of natural gas imbalances due to a change in natural
gas prices and volumes and $2 million of taxes, other than income taxes, due to
a change in an estimated business activity tax settlement and franchise tax
refunds in 2002.

Nine Months Ended 2003 Compared to Nine Months Ended 2002

Operating revenues for the nine months ended September 30, 2003, were $37
million lower than the same period in 2002. A decrease of $34 million was due to
capacity contracts that have expired which we are prohibited from remarketing
due to various FERC orders. 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. 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 and $3 million of higher throughput based revenues from
transportation to interconnecting pipelines. For further discussion of the
revenue sharing provisions, see Item 1, Note 5.

Operating expenses for the nine months ended September 30, 2003, were $125
million higher than the same period in 2002. An increase of $138 million
resulted from El Paso's Western Energy Settlement discussed in Item 1, Notes 2
and 5. Also contributing to the increase was $6 million of natural gas used in
operations in excess of amounts recovered in 2003, $3 million of higher
depreciation expense resulting from facilities placed in service after the
second quarter of 2002 and $5 million of higher taxes, other than income taxes,
due to a change in an estimated business activity tax settlement and franchise
tax refunds in 2002. These increases were partially offset by a decrease of $12
million due to bad debt expense recorded in 2002

17

related to the bankruptcy of Enron Corp., a $10 million change in an estimated
settlement in 2002 related to the Carlsbad incident and $7 million due to the
decrease in our estimated purchase power costs in 2003 and the conversion of
certain compressors to gas from electric.

Other income for the nine months ended September 30, 2003 was $3 million
higher than the same period in 2002 due to a higher allowance for equity funds
used during construction in 2003.

INTEREST AND DEBT EXPENSE

Below is the analysis of our interest expense for the quarter and nine
months ended September 30, 2003 and 2002 (in millions):

Third Quarter 2003 Compared to Third Quarter 2002

Interest and debt expense for the quarter ended September 30, 2003, was $6
million higher than the same period in 2002 primarily due to the increase in
interest expense resulting from the issuance of $355 million of long-term debt
in July 2003.

Nine Months Ended 2003 Compared to Nine Months Ended 2002

Interest and debt expense for the nine months ended September 30, 2003, was
$12 million higher than the same period in 2002 primarily due to an increase in
interest expense resulting from the issuances of $300 million of long-term debt
in June 2002 and $355 million of long-term debt issued in July 2003, and
decreases in interest capitalized on construction projects due to a lower
capitalization base in 2003. These increases were partially offset by decreases
in commercial paper interest expense due to the discontinuation of commercial
paper activity in the fourth quarter of 2002.

AFFILIATED INTEREST INCOME, NET

Third Quarter 2003 Compared to Third Quarter 2002

Affiliated interest income, net for the quarter ended September 30, 2003,
was $1 million lower than the same period in 2002 due to lower average advances
to El Paso under its cash management program offset by higher interest rates.
The average short-term interest rates for the third quarter increased from 1.8%
in 2002 to 1.9% during the same period in 2003. The average advance balance for
the third quarter of $1.2 billion in 2002 decreased to $992 million during the
same period in 2003.

Nine Months Ended 2003 Compared to Nine Months Ended 2002

Affiliated interest income, net for nine months ended September 30, 2003,
was $6 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 its cash
management program. The average short-term interest rates for nine months ended
decreased from 1.9% in 2002 to 1.6% during the same period in 2003. The average
advance balance for the nine months ended September 30, 2002 of $1.2 billion
decreased to $996 million during the same period in 2003.

18

INCOME TAXES

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 have
been 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.

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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.

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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.

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

September 8, 2003........................ Filed our Computation of Ratio of
Earnings to Fixed Charges for the five
years ended December 31, 2002 and for the
six months ended June 30, 2003 and 2002.

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.

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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: November 10, 2003 /s/ JOHN W. SOMERHALDER II
------------------------------------
John W. Somerhalder II
Chairman of the Board,
Chief Executive Officer and Director
(Principal Executive Officer)

Date: November 10, 2003 /s/ GREG G. GRUBER
------------------------------------
Greg G. Gruber
Senior Vice President,
Chief Financial Officer, Treasurer
and Director
(Principal Financial and Accounting
Officer)

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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.