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, 2002

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 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 14,
2002: 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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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

We prepared this Quarterly Report on Form 10-Q under the rules and
regulations of the United States Securities and Exchange Commission (SEC).
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 2001 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, 2002, and for
the quarters and nine months ended September 30, 2002 and 2001, are unaudited.
We derived the balance sheet as of December 31, 2001, from the audited balance
sheet filed in our Form 10-K. In our opinion, we have made all adjustments, all
of which are of a normal, recurring nature (except for merger-related costs
discussed in Note 2 below), 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 Form
10-K, except as discussed below:

Asset Impairments

On January 1, 2002, we adopted Statement of Financial Accounting Standards
(SFAS) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets.
SFAS No. 144 changed the accounting requirements related to when an asset
qualifies as held for sale or as a discontinued operation and the way in which
we evaluate assets for impairment. It also changed accounting for discontinued
operations such that we can no longer accrue future operating losses in these
operations. There was no initial financial statement impact of adopting this
statement.

2. MERGER-RELATED COSTS

During the nine months ended September 30, 2001, we incurred merger-related
costs of $97 million associated with El Paso Corporation's (El Paso) 2001 merger
with The Coastal Corporation and the relocation of our headquarters from El
Paso, Texas to Colorado Springs, Colorado. This amount reflects that we have
reduced our estimated severance charges from $10 million to $5 million in the
third quarter of 2001. Our merger-related costs include employee severance,
retention and transition costs for severed employees totaling $5 million that
occurred as a result of El Paso's merger-related workforce reduction and
consolidation. All employee severance, retention and transition costs have been
paid. Merger-related costs also include estimated net lease payments on a
non-cancelable lease for office space and facility-related costs of $92 million
to close our offices in El Paso and relocate our headquarters to Colorado
Springs. These charges were accrued in 2001 at the time we completed our
relocations and closed these offices. As of September 30, 2002, we have paid $26
million of the accrual leaving a balance of $66 million. The amounts accrued
will be paid over the term of the applicable non-cancelable lease agreements.
Future developments, such as our ability to terminate the lease or to recover
lease costs through sub-leases, could impact the accrued amounts.

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3. DEBT AND OTHER CREDIT FACILITIES

At December 31, 2001, our weighted average interest rate on our commercial
paper was 3.3%. We had the following short-term borrowings including current
maturities of long-term debt:

In January 2002, we retired $215 million aggregate principal amount of
7.75% notes due 2002.

In May 2002, El Paso renewed its $3 billion, 364-day revolving credit and
competitive advance facility. We are a designated borrower under this facility
and, as such, are liable for any amounts outstanding under this facility. This
facility matures in May 2003. In June 2002, El Paso amended its existing $1
billion, 3-year revolving credit and competitive advance facility to permit El
Paso to issue up to $500 million in letters of credit and to adjust pricing
terms. This facility matures in August 2003, and we are also a designated
borrower under this facility and, as such, are liable for any amounts
outstanding under this facility. The interest rate under both of these
facilities varies based on El Paso's senior unsecured debt rating, and as of
September 30, 2002, an initial draw would have had a rate of LIBOR plus 0.625%,
and a 0.25% utilization fee for drawn amounts above 25% of the committed
amounts. As of September 30, 2002, there were no borrowings outstanding, and
$492 million in letters of credit were issued under the $1 billion facility.

In September 2002, Moody's lowered El Paso's senior unsecured debt rating
from Baa2 to Baa3, and in November 2002, Standard and Poor's lowered El Paso's
senior unsecured debt rating from BBB to BBB-. As a result of these events, the
current interest rate on an initial draw under both of these facilities would be
at a rate of LIBOR plus 0.80%, plus a 0.25% utilization fee for drawn amounts
above 25% of the committed amounts.

In June 2002, we issued $300 million aggregate principal amount 8.375%
notes due 2032 in a private placement. Proceeds were approximately $297 million,
net of issuance costs. We have committed to exchange these notes for new notes
that will be registered with the SEC. The form and terms of the new notes will
be identical in all material respects to the form and terms of the old notes
except that the new notes (1) will be registered with the SEC, (2) will not be
subject to transfer restrictions and (3) will not be subject, under certain
circumstances, to an increase in the stated interest rate.

4. COMMITMENTS AND CONTINGENCIES

Legal Proceedings

California Lawsuits. We have been named as a defendant in eleven purported
class action, municipal or individual lawsuits, filed in California state courts
(a list of the California cases is included in Part II, Item 1, Legal
Proceedings). 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 post-judgment interest, (v) costs of prosecuting the actions and
(vi) attorney's fees. The lawsuits have been consolidated before a single judge
and are at the preliminary pleading stages with trial scheduled for September
2003 on several of the cases. At this time, our legal exposure related to these
lawsuits and claims is not determinable.

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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.

Nevada Lawsuit. The state of Nevada and four individuals have purportedly
filed a lawsuit in District Court for Clark County, Nevada on November 1, 2002
naming us, El Paso and several other El Paso subsidiaries and affiliates as
defendants. While the complaint has not yet been served on us, we believe that
its allegations are similar to those in the California cases. The suit
purportedly seeks unquantified monetary damages, to be trebled, general and
special damages and attorney fees and costs.

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
Proposed Violation against us. The Notice alleged five violations of its
regulations (a list of the alleged five violations is included in Part II, Item
1, Legal Proceedings), proposed fines totaling $2.5 million and proposed
corrective actions. We have fully accrued for these fines. 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, operating results or
cash flows. We are cooperating with the National Transportation Safety Board in
an investigation into the facts and circumstances concerning the possible causes
of the rupture. On November 1, 2002, we received a federal grand jury subpoena
for documents relating to the rupture and we will cooperate fully with the
subpoena. In addition, a number of personal injury and wrongful death lawsuits
were filed against us in connection with the rupture. All but one of these suits
have been settled. The settlement payments have been fully covered by insurance.
The remaining case is Geneva Smith, et al, vs. EPEC and EPNG filed October 23,
2000 in Harris County, Texas. In connection with the settlement of the cases, we
have agreed to contribute $10 million to a charitable foundation as a memorial
to the families involved. This contribution will not be 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.

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 gas working interest owners and 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, 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 has been
filed and we have filed our response.

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.

6

For each of our outstanding legal matters, we evaluate the merits of the
case, our exposure to the matter, possible legal or settlement strategies and
the likelihood of an unfavorable outcome. If we determine that an unfavorable
outcome is probable and can be estimated, we establish the necessary accruals.
As of September 30, 2002, we had approximately $13 million accrued for all
outstanding legal matters, including the $10 million for our contribution to a
charitable foundation.

Environmental Matters

We are subject to extensive federal, state and local laws and regulations
governing environmental quality and pollution control. These laws and
regulations require us to remove or remedy the effect on the environment of the
disposal or release of specified substances at current and former operating
sites. As of September 30, 2002 and December 31, 2001, we had approximately $29
million accrued for expected remediation costs and associated onsite, offsite
and groundwater technical studies and for related environmental legal costs,
which we anticipate incurring through 2027.

In addition, we expect to make capital expenditures for environmental
matters of approximately $4 million in the aggregate for the years 2002 through
2007. These expenditures primarily relate to compliance with clean air
regulations. For the fourth quarter 2002, we estimate that our total
expenditures will be approximately $1 million, which primarily will be expended
under government directed clean-up plans.

CERCLA Matters. We have been designated and 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, 2002, we have estimated our share of the remediation
costs at these sites to be between $14 million and $19 million which are
included in the environmental reserve discussed above. We believe our reserves
are adequate for such costs. Since the clean-up costs are estimates and are
subject to revision as more information becomes available about the extent of
remediation required, and because in some cases we have asserted a defense to
any liability, our estimates could change. Moreover, liability under the federal
CERCLA statute is joint and several, meaning that we could be required to pay in
excess of our pro rata share of remediation costs. Our understanding of the
financial strength of other PRPs has been considered, where appropriate, in
determining our estimated liabilities.

Rates and Regulatory Matters

CPUC Complaint Proceeding. In April 2000, the Public Utilities Commission
of the State of California (CPUC) filed a complaint under Section 5 of the
Natural Gas Act (NGA) with the Federal Energy Regulatory Commission (FERC)
alleging that our sale of approximately 1.2 billion cubic feet per day of
capacity to our affiliate, El Paso Merchant Energy Company (EPME), raised issues
of market power, violation of FERC's marketing affiliate regulations and asked
that the contracts be voided. Although the FERC held that we did not violate its
marketing affiliate requirements, it established a hearing before an
administrative law judge (ALJ) to address the market power issue. In the spring
and summer of 2001, two hearings were held before the ALJ to address the market
power issue and, at the request of the ALJ, 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 and that accordingly the market power claims against us should be
dismissed. The ALJ found, however, that we had violated the marketing affiliate
rules. We and other parties filed briefs on exceptions and briefs opposing
exceptions to the October initial decision.

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,

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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 recommended 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 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. We and others
filed briefs on exceptions to the initial decision on October 23, 2002. In
support of our request, we informed the FERC that the initial decision is
inconsistent with the facts, the law, and FERC policy and urged the FERC to
reverse it. Briefs opposing exceptions were filed on November 12, 2002. Oral
argument, currently set for December 2, 2002, will be heard by the FERC
commissioners prior to the issuance of an order on the initial decisions.

Systemwide Capacity Allocation Proceeding. In July 2001, several of our
customers who hold contracts with volumetric ceilings (Contract Demand or CD
customers) filed a complaint against us at the FERC under Section 5 of the NGA
claiming, among other things, that our full requirements contracts (contracts
with no volumetric limitations) with customers located east of California (EOC)
should be converted to CD contracts, that we should be required to expand our
system to serve all of our customers' growing requirements instead of relying on
the pro rata allocation provisions of our FERC approved tariff to allocate our
available capacity among our EOC and CD customers, and that we should be
required to give demand charge credits to our CD customers when we are unable to
meet their full contract demands. Likewise, in July 2001, several of our EOC
customers filed a complaint under Section 5 of the NGA alleging that we had
violated the NGA and our contractual obligations to them by not expanding our
system, at our own cost, to meet their increased requirements.

On May 31, 2002, the FERC issued an order on the complaints in which it
required that (i) full requirements service, for all EOC customers other than
small volume customers, be converted to service with specified volumetric rights
(i.e., contract demand service); (ii) firm customers be assigned specific
receipt point rights in lieu of their existing systemwide receipt point rights;
(iii) we prospectively give reservation charge credits to all firm customers for
any failure to schedule confirmed volumes except in cases of force majeure; (iv)
we refrain from entering into new firm contracts until we have demonstrated that
we have adequate capacity on the system; and (v) we conduct a process to allow
existing CD customers to turn back capacity for acquisition by full requirements
customers. The FERC indicated in the May 31 order that we were to remain revenue
neutral as a result of this turnback process. In addition, the order stated that
the FERC expected us to file for certificate authority to add compression to our
Line 2000 project, thereby increasing our system capacity by 320 MMcf/d, without
cost coverage until the next rate case (which will be January 1, 2006). We had
previously stated we were willing to add compression to the project at a public
conference held in April 2002, provided we were assured of rate coverage in the
next rate case. The May 31 order established dates by which the steps necessary
to implement the order's requirements would be completed. The changes required
by the order were to be made effective November 1, 2002.

On July 1, 2002, we and numerous other parties filed for clarification
and/or rehearing of the May 31 order. Although the order required the full
requirements customers to agree among themselves on an appropriate allocation of
unsubscribed westflow pipeline capacity by July 31, 2002, the customers failed
to reach such an agreement. On September 20, 2002, the FERC issued an order
postponing the effective date of the conversions required by their May 31 order
until May 1, 2003. The order instructed us to allocate among our full
requirements customers the 320 MMcf/d of capacity that will be available once
compression is added to Line 2000 (which the FERC estimated would be in the
summer of 2003; however, we anticipate the first and second phases of
compression will be in service by mid 2004, and have so advised the FERC). In
addition, the order prohibited us from reselling any firm capacity that expires
under existing contracts between May 31, 2002, and May 1, 2003, requiring
instead that we allocate this capacity to our full requirements customers. In
total, the September 20 order requires that our full requirements customers pay
only their current reservation charges for existing unsubscribed capacity, for
the 230 MMcf/d of capacity that was made available in November 2002 by the Line
2000 project, for the additional 320 MMcf/d of capacity to be
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available once the compression of Line 2000 is completed, and for all capacity
subject to contracts expiring before May 1, 2003. Beginning May 1, 2003, we will
be required to pay reservation charge credits when we are unable to schedule
confirmed volumes except in cases of force majeure. Between November 1, 2002,
and May 1, 2003, we are required to pay reservation charge credits to CD
customers when we are unable to schedule 95 percent of their confirmed volumes
except for reasons of force majeure and provided that there is no capacity
available to meet their needs from other supply basins on our system.

Several pleadings have been filed in response to the September 20 order,
including requests by several customers to modify the order based on the ALJ's
decision in the CPUC Complaint Proceeding discussed above, requests by customers
and others to vacate and/or stay the order and our responses to those pleadings,
and numerous applications for rehearing and/or clarification filed by us and
others. All such motions and requests remain pending before the FERC. On
November 1, 2002, the FERC issued a tolling order to allow it additional time to
act upon the requests for rehearing and indicated that it anticipates issuing an
order on rehearing by January 31, 2003. We anticipate that in the order the FERC
will address the various motions made as well as the requests for clarification
and rehearing. In the interim, we are proceeding with the directives contained
in the September 20 order.

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 and
Electric 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, 2002, we had unearned risk sharing revenues of approximately $40
million and had $17 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 $46
million of 2001 revenues to customers during 2001 and 2002. During 2002, we
established an additional refund obligation of $33 million, of which $17 million
has been refunded to date. Both the risk and revenue sharing provisions of the
rate settlement extend through 2003.

Line 2000 Project. On July 31, 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. On May
7, 2001, the FERC authorized the amended Line 2000 project. We have received
authorization to place the line in service, and anticipate having all segments
of Line 2000 in service by mid-November 2002 at a total estimated capital cost
of $185 million.

On October 3, 2002, pursuant to the FERC's May 31 and September 20 orders,
we applied 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. That application has been protested. 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.

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 FERC,
would dictate how we conduct business and interact with our energy affiliates.
In December 2001, we filed comments with the FERC addressing our concerns with
the proposed rules. A public hearing was held on May 21, 2002, providing an
opportunity to comment further on the NOPR. Following the conference, additional
comments were filed by El Paso's pipelines and others. At this time, we cannot
predict the outcome

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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 NOI. In July 2002, the FERC issued a Notice of Inquiry
(NOI) that seeks comments regarding its 1996 policy of permitting pipelines to
enter into negotiated rate transactions. We have entered into these 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, as well as
other issues related to negotiated rate programs. On September 25, 2002, El
Paso's pipelines and others filed comments. Reply comments were filed on October
25, 2002. At this time, we cannot predict the outcome of this NOI.

Cash Management NOPR. On August 1, 2002, the FERC issued a NOPR requiring
that all cash management or money pool arrangements between a FERC regulated
subsidiary (like us) and a non-FERC regulated parent must be in writing, and set
forth: the duties and responsibilities of cash management participants and
administrators; the methods of calculating interest and for allocating interest
income and expenses; and the restrictions on deposits or borrowings by money
pool members. The NOPR also requires specified documentation for all deposits
into, borrowings from, interest income from, and interest expenses related to,
these arrangements. Finally, the NOPR proposed that as a condition of
participating in a cash management or money pool arrangement, the FERC regulated
entity maintain a minimum proprietary capital balance of 30 percent, and the
FERC regulated entity and its parent maintain investment grade credit ratings.
On August 28, 2002, comments were filed. The FERC held a public conference on
September 25, 2002, to discuss the issues raised in the comments.
Representatives of companies from the gas and electric industries participated
on a panel and uniformly agreed that the proposed regulations should be revised
substantially and that the proposed capital balance and investment grade credit
rating requirements would be excessive. At this time, we cannot predict the
outcome of this NOPR.

Also on August 1, 2002, the FERC's Chief Accountant issued an Accounting
Release, to be effective immediately, providing guidance on how companies should
account for money pool arrangements and the types of documentation that should
be maintained for these arrangements. However, the Accounting Release did not
address the proposed requirements that the FERC regulated entity maintain a
minimum proprietary capital balance of 30 percent and that the entity and its
parent have investment grade credit ratings. Requests for rehearing were filed
on August 30, 2002. The FERC has not yet acted on the rehearing requests.

While the outcome of our outstanding legal matters, environmental matters,
and rates and regulatory matters cannot be predicted with certainty, based on
the information we know now 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. 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 these matters could
impact our debt rating and the credit rating of our parent. See Item 2, Recent
Developments. 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 and on our cash flows in the period the
event occurs.

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

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from the rejection of its transportation contracts. The September 20 order
capacity allocation proceeding discussed in Rates and Regulatory Matters above
prohibits us from remarketing Enron capacity that was not remarketed prior to
May 31, 2002. We have sought rehearing of the September 20 order. We have fully
reserved for all amounts due from Enron through the date the contracts were
rejected.

5. RELATED PARTY TRANSACTIONS

We participate in El Paso's cash management program which matches
short-term cash surpluses and need requirements of participating affiliates,
thus minimizing total borrowing from outside sources. As of September 30, 2002
and December 31, 2001, we had advanced $1,081 million and $1,294 million. The
market rate of interest at September 30, 2002 and December 31, 2001, was 1.8%
and 2.1%.

At September 30, 2002 and December 31, 2001, we had other accounts
receivable from related parties of $2 million and $4 million. Accounts payable
to affiliates was $40 million at September 30, 2002, versus $9 million at
December 31, 2001. These balances arose in the normal course of business.

In January 2002, we distributed assets to our parent through a dividend
with a net book value of $19 million. We also accrued $23 million in dividends
associated with our preferred stock as of September 30, 2002, and have consented
to pay $28 million on November 30, 2002.

In September of 2002, we sold approximately $42 million of our trade
accounts receivable at a discount to El Paso Energy Finance Company, an
unconsolidated affiliate, as part of an accounts receivable sales program. El
Paso Energy Finance Company, in turn, sold those receivables to a bank. The
program was initiated to accelerate the collection of funds for El Paso, and the
proceeds we received from the sale were advanced to our parent company through
our cash management program described above.

6. NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

Accounting for Asset Retirement Obligations

In August 2001, the Financial Accounting Standards Board (FASB) issued SFAS
No. 143, Accounting for Asset Retirement Obligations. This statement requires
companies to record a liability for the estimated retirement and removal costs
of assets used in their business. The liability is recorded at its fair value,
with a corresponding asset which is depreciated over the remaining useful life
of the long-lived asset to which the liability relates. An on-going expense will
also be recognized for changes in the value of the liability as a result of the
passage of time. The provisions of SFAS No. 143 are effective for fiscal years
beginning after June 15, 2002. We are currently assessing and quantifying the
asset retirement obligations associated with our long-lived assets. We expect to
complete our assessment of these asset retirement obligations and be able to
estimate their effect on our financial statements in the fourth quarter of 2002.

Accounting for Costs Associated with Exit or Disposal Activities

In July 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated
with Exit or Disposal Activities. This statement will require us to recognize
costs associated with exit or disposal activities when they are incurred rather
than when we commit to an exit or disposal plan. Examples of costs covered by
this guidance include lease termination costs, employee severance costs
associated with a restructuring, discontinued operations, plant closings or
other exit or disposal activities. This statement is effective for fiscal years
beginning after December 31, 2002, and will impact any exit or disposal
activities we initiate after January 1, 2003.

11

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

The information contained in Item 2 updates, and you should read it in
conjunction with, information disclosed in our Annual Report on Form 10-K filed
March 20, 2002, in addition to the financial statements and notes presented in
Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

RECENT DEVELOPMENTS

Since the fourth quarter of 2001, a number of recent developments in our
business and industry have impacted our pipelines' operations and liquidity.
These have included:

- The bankruptcy of Enron Corp. and related decline in the energy trading
industry; and

- The modification of credit standards by the rating agencies.

Credit rating agencies have recently re-evaluated the credit ratings of
companies involved in energy trading activities, which included our parent and
our affiliates. The recent developments referenced above, as well as the ALJ's
decision dated September 23, 2002 in the CPUC complaint, appear to have
influenced both Moody's and Standard & Poor's in downgrading our parent's credit
rating, and it remains on negative credit watch by both. Our senior unsecured
debt was downgraded from Baa1 to Baa2 by Moody's and from BBB+ to BBB by
Standard & Poor's and we remain on a negative credit watch by both rating
agencies.

Except as discussed in Results of Operations section below, these recent
developments, including the May 31, 2002 and September 20, 2002 orders in our
capacity allocation proceeding (see Note 4, Systemwide Capacity Allocation
Proceeding), do not have an immediate impact on our financial position or
results of operations; however, a further downgrade of our debt securities could
result in higher cash requirements to conduct our operations (through cash
collateral requirements). If this were to occur, we would have less cash
available to use for capital expenditures and other purposes, although we do
believe we would have sufficient operating resources to fund our ongoing
operating activities.

In addition, as a result of the rating agencies' downgrading the credit
rating of several of our customers and placing them on negative credit watch,
the credit-worthiness of these companies has been questioned. We have taken
actions to mitigate our exposure by requesting these companies to provide us
with a letter of credit or prepayment as permitted by our tariff. Our tariff
permits us to request additional credit assurance from our shippers equal to the
cost of performing transportation services for a three month period. If these
companies file for Chapter 11 bankruptcy protection and our contracts are not
assumed by other counterparties, or if the capacity is unavailable for resale,
it could have a material adverse effect on our financial position, operating
results or cash flows.

RESULTS OF OPERATIONS

Our pipeline includes our interstate transmission business. We face varying
degrees of competition from other pipelines, as well as alternate energy
sources, such as electricity, hydroelectric power, coal and fuel oil.

We are regulated by the Federal Energy Regulatory Commission. The FERC sets
the rates we can recover from our customers. These rates are generally a
function of our cost of providing service to our customers, as well as a
reasonable return on our invested capital. As a result, our results have
historically been relatively stable. However, they can be subject to volatility
due to factors such as weather, changes in natural gas prices, regulatory
actions and the creditworthiness of our customers.

As discussed in Item 1, Financial Statements, Note 4 under the subheading
Rates and Regulatory Matters, the September 20, 2002 FERC order related to the
allocation of capacity on our system required us to:

- Give reservation charge credits prospectively to our firm shippers if we
fail to schedule the shippers' confirmed volumes (except in the case of
force majeure);

- Refrain from entering into new firm contracts or remarketing turned back
capacity under terminated or expired contracts until May 1, 2003; and

12

- Add additional compression to our Line 2000 project (up to 320 MMcf/d)
without the recovery of these costs in our rates until our next rate case
which will be effective in January 1, 2006.

Our future results of operations will be impacted as a result of both the
September 20 FERC Order and the Enron bankruptcy. The September 20 order
prohibits us from remarketing approximately 471 MMDth/d of capacity. Of this
amount, approximately 195 MMdth/d is capacity which was rejected by Enron in May
2002 in its bankruptcy proceeding. Prior to the rejection of the contracts, we
were earning approximately $1.5 million (net of revenue sharing credits) per
month from Enron for this capacity. Because we cannot remarket this capacity, we
will experience a loss of revenue due to the relinquishment of this capacity in
the bankruptcy proceeding. The amount of such revenue loss cannot be determined
because it would depend on the rates we could obtain by remarketing the
capacity.

The remaining 276 MMDth/d of capacity that we are unable to remarket as a
result of the September 20 order will also cause a reduction in our
transportation revenues. This capacity relates to contracts that expire within
the time frame specified by the order. Under these contracts, we were earning $2
million (net of revenue sharing credits) per month in revenues prior to their
expiration. The amount of our revenue loss cannot be determined because, as with
the Enron capacity, it would depend on the rates we could obtain by remarketing
the capacity. We have requested rehearing of the September 20 FERC Order
relating to this and other aspects of the order. This request for rehearing is
pending before the FERC.

Another significant issue that may impact our future operating results is
the CPUC Complaint, which is discussed more fully in Item 1, Financial
Statements, Note 4, under the subheading Rates and Regulatory Matters. In
September 2002, we received an initial decision from an administrative law judge
(ALJ) related to whether we exercised market power with regard to our pipeline
capacity to the California border during the latter part of 2000 and the early
part of 2001. In that decision, the ALJ held that we withheld capacity from
California. We believe that holding is incorrect as a matter of fact, law, and
policy. We believe that we have consistently demonstrated that we operate our
system in a manner to maximize the flow of gas at all times consistent with
safety, reliability, and operational considerations, and that volume differences
during the period in question (November 1, 2000 to March 31, 2001) have been
fully explained on the record. However, despite our position, should the FERC
uphold the ALJ's decision, and should we not prevail in our appeal of that
decision, the long-term impact on us could be substantial depending on the
remedy the FERC may seek to impose on us and the impact such decision could have
on our pending state court litigation.

We use earnings before interest and income taxes (EBIT) to assess the
operating results and effectiveness of our business. We define EBIT as operating
income, adjusted for gains and losses on sales of assets and other miscellaneous
non-operating items. Items that are not included in this measure are financing
costs, including interest and debt expense and income taxes. We believe this
measurement is useful to our investors because it allows them to evaluate the
effectiveness of our businesses and operations and our investments from an
operational perspective, exclusive of the costs to finance those activities and
exclusive of income taxes, neither of which are directly relevant to the
efficiency of those operations. 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 cash flow. Results of
our operations were as follows for the periods ended September 30:

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

(1) BBtu/d means billion British thermal units per day.

13

Third Quarter 2002 Compared to Third Quarter 2001

Operating revenues for the quarter ended September 30, 2002, were $9
million lower than the same period in 2001. Included in this decrease was $7
million as a result of a FERC order which disallowed the remarketing of capacity
rejected by Enron in its bankruptcy proceeding. Also contributing to the
decrease was $2 million from lower rates on the Mojave Pipeline system as a
result of a rate case settlement effective October 2001.

Operating expenses for the quarter ended September 30, 2002, were $11
million lower than the same period in 2001. The decrease includes $15 million
due to the regular revaluation of natural gas imbalances as a result of changes
in imbalance volumes and gas prices. Also contributing to the decrease were
lower compressor operating costs of $3 million resulting from lower electric
usage and prices in 2002 and a $2 million franchise tax refund in the third
quarter of 2002. These decreases were partially offset by an increase in
estimated legal liabilities of $5 million in the third quarter of 2002 and a
reduction of merger-related costs of $5 million occurring in the third quarter
of 2001 due to changes in our estimates of costs related to our workforce
reduction. For a discussion of these costs, see Item 1, Financial Statements,
Note 2.

Other income for the quarter ended September 30, 2002, was $2 million lower
than the same period in 2001 primarily due to a loss on the sale of non-pipeline
assets in the third quarter of 2002.

Nine Months Ended 2002 Compared to Nine Months Ended 2001

Operating revenues for the nine months ended September 30, 2002, were $8
million higher than the same period in 2001. Included in this increase were
higher 2002 revenues of $25 million associated with a larger portion of our
available capacity earning maximum tariff rates as compared to the same period
in 2001 and $2 million related to higher demand rates resulting from annual
inflation increases. These increases were partially offset by $8 million from
lower prices on fuel recoveries from our customers, $7 million from lower
throughput to California and other southwestern states due to lower electric
generation demand and milder weather in 2002 and $6 million from lower rates on
the Mojave Pipeline system as a result of a rate case settlement effective
October 2001.

Operating expenses for the nine months ended September 30, 2002, were $112
million lower than the same period in 2001 primarily as a result of the
merger-related costs of $97 million incurred in 2001 related to the relocation
of our headquarters from El Paso, Texas to Colorado Springs, Colorado and costs
associated with severed employees as part of El Paso's merger with Coastal. Also
contributing to the decrease were the regular revaluation of natural gas
imbalances as a result of changes in imbalance volumes and gas prices of $19
million, lower compressor operating costs of $10 million resulting from lower
electric usage and prices in 2002, an adjustment to depreciation of $7 million
due primarily to finalization of regulatory issues in 2002 and lower other taxes
of $5 million due to a change in estimated business activity tax settlements and
franchise tax refunds in 2002. These decreases were partially offset by an
increase to our reserve for bad debts of $12 million related to the bankruptcy
of Enron Corp. and an increase in our estimated legal liabilities of $10 million
during 2002.

Other income for the nine months ended September 30, 2002, was $4 million
higher than the same period in 2001 due to a gain on the sale of non-pipeline
assets in 2002, and a 2001 accrual for proposed fines from the Department of
Transportation related to the August 2000 pipeline rupture.

INTEREST AND DEBT EXPENSE

Non-affiliated Interest and Debt Expense

Non-affiliated interest and debt expense for the quarter and nine months
ended September 30, 2002, was $19 million, and $53 million, or $3 million and
$14 million lower than the same periods in 2001. The decreases were primarily
due to a retirement of $215 million 7.75% long-term debt in January 2002 and
lower interest rates on decreased commercial paper borrowings in 2002. We had no
commercial paper outstanding at September 30, 2002. The decrease was partially
offset by an increase in long-term debt for the $300 million 8.375% debt issued
in June 2002.

14

Affiliated Interest Income

Affiliated interest income for the quarter ended September 30, 2002, was $6
million, or $7 million lower than the same period in 2001 due to lower
short-term interest rates in 2002 and lower average advances to El Paso under
our cash management program. The average short-term interest rates for the third
quarter decreased from 3.8% in 2001 to 1.8% in 2002.

Affiliated interest income for the nine months ended September 30, 2002,
was $18 million, or $30 million lower than the same period in 2001 due to lower
short-term interest rates in 2002 on advances to El Paso under our cash
management program. The average short-term interest rates for the nine months
decreased from 4.9% in 2001 to 1.9% in 2002.

INCOME TAXES

Income tax expense for the quarter and nine months ended September 30,
2002, was $24 million and $78 million, resulting in effective tax rates of 39
percent and 38 percent. Income tax expense for the quarter and nine months ended
September 30, 2001, was $26 million and $37 million, resulting in effective tax
rates of 39 percent for both periods. Our effective tax rates were different
than the statutory rate of 35 percent for all periods primarily due to state
income taxes.

COMMITMENTS AND CONTINGENCIES

See Item 1, Financial Statements, Note 4, which is incorporated herein by
reference.

NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

See Item 1, Financial Statements, Note 6, which is incorporated herein by
reference.

15

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, 2001, in addition to the information presented in
Items 1 and 2 of this Quarterly Report on Form 10-Q.

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, 2001.

ITEM 4. CONTROLS AND PROCEDURES

Under the supervision and with the participation of our 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 within 90 days of the filing date of this quarterly
report pursuant to Rules 13a-15 and 15d-15 under the Securities Exchange Act of
1934 (the "Exchange Act"). Based on that evaluation, our principal executive
officer and principal financial officer have concluded that these controls and
procedures are effective. There were no significant changes in our internal
controls or in other factors that could significantly affect these controls
subsequent to the date of their evaluation.

Disclosure controls and procedures 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 and procedures 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.

The principal executive officer and principal financial officer
certifications required under Sections 302 and 906 of the Sarbanes-Oxley Act of
2002 have been included herein, or as Exhibits to this Quarterly Report on Form
10-Q, as appropriate.

16

PART II -- OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Part I, Item 1, Financial Statements, Note 4, which is incorporated
herein by reference.

The California cases are: five filed in the Superior Court of Los Angeles
County (Continental Forge Company, et al v. Southern California Gas Company, et
al, filed on 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); three filed in the Superior Court of San Francisco County (Sweetie's, et
al v. El Paso Corporation, et al, filed March 22, 2001; Philip Hackett, et al v.
El Paso Corporation, et al, filed May 9, 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).

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 its pipelines 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.

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.

17

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

We filed a Current Report on Form 8-K dated September 25, 2002 filing our
communication regarding our opinion of a proposed ruling by a FERC
administrative law judge.

18

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 14, 2002 /s/ JOHN W. SOMERHALDER II
------------------------------------
John W. Somerhalder II
Chairman of the Board,
Chief Executive Officer and Director
(Principal Executive Officer)

Date: November 14, 2002 /s/ GREG G. GRUBER
------------------------------------
Greg G. Gruber
Senior Vice President,
Chief Financial Officer and
Treasurer
(Principal Financial and Accounting
Officer)

19

CERTIFICATION

I, John W. Somerhalder II, certify that:

1. I have reviewed this quarterly report on Form 10-Q of El Paso Natural
Gas Company;

2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this quarterly report is being
prepared;

b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and

c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):

a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.

Date: November 14, 2002 /s/ JOHN W. SOMERHALDER II
------------------------------------
John W. Somerhalder II
Chairman of the Board and
Chief Executive Officer
(Principal Executive Officer)
El Paso Natural Gas Company

20

CERTIFICATION

I, Greg G. Gruber, certify that:

1. I have reviewed this quarterly report on Form 10-Q of El Paso Natural
Gas Company;

2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrants and we have:

a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this quarterly report is being
prepared;

b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and

c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):

a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.

Date: November 14, 2002

/s/ GREG G. GRUBER
--------------------------------------
Greg G. Gruber
Senior Vice President,
Chief Financial Officer and Treasurer
(Principal Financial Officer)
El Paso Natural Gas Company

21

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.