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 JUNE 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 $1.00 per share. Shares outstanding on August 13,
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. 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 June 30, 2002, and for the quarters
and six months ended June 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), 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.

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 impairments of assets. It also changes 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 quarter and six months ended June 30, 2001, we incurred
merger-related costs of $94 million and $102 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. These costs include employee severance, retention and transition costs
for severed employees that occurred as a result of El Paso's merger-related
workforce reduction and consolidation. These costs were expensed as incurred and
have been paid. Our merger-related costs also include actual severance payments
and costs for pension and post-retirement benefits settled and curtailed under
existing benefit plans. These costs were expensed as incurred and were paid in
the first and second quarters of 2001. Our 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 the
second quarter of 2001 at the time we completed our relocations and closed these
offices. The amounts accrued will be paid over the term of the applicable
non-cancelable lease agreements. Future developments, such as 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 June 30, 2002, our weighted average interest rate on our commercial
paper was 2.8%, and at December 31, 2001, it 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 remain 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 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
June 30, 2002, an initial draw would have had a rate of LIBOR plus 0.625%, plus
a 0.25% utilization fee for drawn amounts above 25% of the committed amounts. As
of June 30, 2002, there were no borrowings outstanding, and $450 million in
letters of credit were issued under the $1 billion facility.

In June 2002, we issued $300 million aggregate principal amount 8.375%
notes due 2032. Proceeds were approximately $297 million, net of issuance costs.

We have committed to exchange all of our outstanding 8.375% notes due 2032,
discussed above, for new registered 8.375% notes due 2032. 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
Securities and Exchange Commission, (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

El Paso and several of its subsidiaries were named defendants 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). We are a defendant in ten of these lawsuits. The eleven
suits contend that El Paso entities acted improperly to limit the construction
of new pipeline capacity to California and/or to manipulate the price of natural
gas sold into the California marketplace. The lawsuits have been consolidated
before a single judge and are at the preliminary pleading stages with trial not
anticipated until late 2003 at the earliest. Our costs and legal exposure
related to these lawsuits and claims are not currently determinable.

In September 2001, we received a civil document subpoena from the
California Department of Justice, seeking information said to be relevant to the
Department's ongoing investigation into the high electricity prices in
California. We have produced and expect to continue to produce materials under
this subpoena.

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
to us. The Notice alleged five probable violations of its regulations (a list of
the alleged five probable violations is included in Part II, Item 1, Legal
Proceedings), proposed fines totaling $2.5 million and proposed corrective
actions. In October 2001, we filed a detailed 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

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financial position, operation 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. In addition, a
number of personal injury and wrongful death lawsuits were filed against us in
connection with the rupture. Several of these suits have been settled, with
payments fully covered by insurance. Seven Carlsbad lawsuits remain, with one of
the seven having reached a contingent settlement within insurance coverage (a
list of the remaining Carlsbad lawsuits is included in Part II, Item 1, Legal
Proceedings).

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. These matters have been consolidated for pretrial purposes (In re:
Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District
of Wyoming, filed June 1997). In May 2001, the court denied the defendants'
motions to dismiss.

We and a number of our affiliates were named defendants in Quinque
Operating Company, et al v. Gas Pipelines and Their Predecessors, et al, filed
in 1999 in the District Court of Stevens County, Kansas. This class action
complaint alleges that the defendants mismeasured natural gas volumes and
heating content of natural gas on non-federal and non-Native American lands. The
Quinque complaint was transferred to the same court handling the Grynberg
complaint and has now been sent back to Kansas State Court for further
proceedings. A motion to dismiss this case is pending.

In addition to the above matters, we and our subsidiaries and affiliates
are named defendants in numerous lawsuits and governmental proceedings that
arise in the ordinary course of our business.

For each of our outstanding legal matters, we evaluate the merits of the
case, our exposure to the matter, possible legal or settlement strategies and
the likelihood of an unfavorable outcome. If we determine that an unfavorable
outcome is probable and can be estimated, we establish the necessary accruals.
As of June 30, 2002, we had reserves totaling $8 million for all outstanding
legal matters.

While the outcome of our outstanding legal matters cannot be predicted with
certainty, based on the information known to date 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. As
new information 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.

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 June 30, 2002, we had a reserve of approximately $29 million for
expected remediation costs (including related environmental litigation). 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.

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 4 active
sites under the Comprehensive Environmental Response, Compensation and Liability
Act (CERCLA) or state equivalents. We have sought to resolve our liability as a
PRP at these CERCLA sites, as appropriate, through indemnification by third
parties and settlements which provide for payment of our allocable share of
remediation costs. As of June 30, 2002, we have estimated our share of the
remediation costs at these sites to be between $14 million and $19 million and
have provided reserves that we believe are adequate for such costs. Since the
clean-up costs are estimates and are subject to revision as more information
becomes available about the extent of remediation required, and because in some
cases we have asserted a defense to any liability, our estimates could change.
Moreover, liability under the federal CERCLA statute is

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joint and several, meaning that we could be required to pay in excess of our pro
rata share of remediation costs. Our understanding of the financial strength of
other PRPs has been considered, where appropriate, in the determination of our
estimated liabilities.

While the outcome of our outstanding environmental matters cannot be
predicted with certainty, based on the information known to date 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 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 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.

Rates and Regulatory Matters

In April 2000, the California Public Utilities Commission (CPUC) filed a
complaint with the Federal Energy Regulatory Commission (FERC) alleging that our
sale of approximately 1.2 billion cubic feet per day of California capacity to
our affiliate, El Paso Merchant Energy Company, was anticompetitive and an abuse
of the affiliate relationship under the FERC's policies. Other parties in the
proceeding requested that Merchant Energy pay back any profits it earned under
the contract. In March 2001, the FERC established a hearing, before an
administrative law judge, to address the issue of whether we and/or Merchant
Energy had market power and, if so, had exercised it. In October 2001, a FERC
administrative law judge issued a proposed decision finding that El Paso did not
exercise market power and that the market power portion of the CPUC's complaint
should be dismissed. However, the decision did find that El Paso had violated
FERC's marketing affiliate regulations. In October 2001, the Market Oversight
and Enforcement section of the FERC's Office of the General Counsel filed
comments in this proceeding stating that record development at the trial was
inadequate to conclude that we complied with FERC's regulations. In December
2001, the FERC remanded the proceeding to the administrative law judge for a
supplemental hearing on the availability of capacity at our California delivery
points. The hearing commenced on March 21, 2002, and concluded on April 4, 2002.
Oral arguments were held on April 10, 2002. A post-hearing briefing was
completed on June 5, 2002, and an administrative law judge's ruling is expected
soon.

In late 1999, several of our customers filed complaints requesting that the
FERC order us to stop selling primary firm delivery point capacity at the
Southern California Gas Company Topock delivery point in excess of the
downstream capacity available at that point and to stop overselling firm
mainline capacity on the east-end of our mainline system. Several conferences
and meetings were held during the summer of 2000. They failed to produce a
settlement. In October 2000, the FERC ordered us to make a one time allocation
of capacity at the Southern California Gas Company Topock delivery point among
affected firm shippers, but deferred action on east-end and system-wide capacity
allocation issues. In February 2001, the FERC accepted our tariff filing
affirming the results of the Topock delivery point allocation process and
directing us to formulate a system-wide capacity allocation methodology to be
addressed in our Order No. 637 proceeding. In March 2001, we filed our proposed
system-wide allocation methodology with the FERC. In April 2001, the February
2001 order was appealed by a customer to the U.S. Court of Appeals for the 9th
Circuit, which dismissed the appeal in its entirety on July 22, 2002. In July
2001 and August 2001, technical conferences were conducted by the FERC on our
system-wide capacity allocation proposal, after which the parties have submitted
position papers to the FERC regarding the appropriate method for allocating
receipt point capacity on our system.

Two groups of our customers, those within California and those east of
California, have filed complaints against us with the FERC. In July 2001, twelve
parties composed of California customers, natural gas producers and natural gas
marketers, filed a complaint alleging that our full requirements contracts with
our east of California customers should be converted to contracts with specific
volumetric entitlements, that we should be required to expand our interstate
pipeline system and that firm shippers who experience reductions in their
nominated gas volumes should be awarded demand charge credits. Also, in July
2001, ten parties,
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most of which are east of California full requirements contract customers, filed
a complaint against us with the FERC, alleging that we violated the Natural Gas
Act of 1938 and breached our contractual obligations by failing to expand our
system in order to serve the needs of the full requirements contract shippers.
The complainants requested that the FERC require us to show cause why we should
not be required to augment our system capacity. On May 31, 2002, the FERC issued
an order in which it required, among other things that:

- our full requirements contracts, except those with our small volume
customers, be converted to contract demand (CD) contracts, i.e.,
contracts with maximum volumetric entitlements;

- CD customers be assigned specific receipt point rights, thereby replacing
system-wide receipt points on our system;

- we file an application to add compression to our Line 2000 project,
thereby adding up to 320 million cubic feet per day of additional
capacity to our system;

- we allow our California delivery points to be utilized as receipt points
on a secondary firm basis for the benefit of markets east of California;

- our 1996 rate settlement remain in effect for the remainder of its term,
except as necessary to effectuate the changes required by the order;

- we be required to give demand charge credits when we are unable, except
for reasons of force majeure, to schedule confirmed, firm nominations;
and

- we refrain from entering into new firm contracts until we have
demonstrated that we have adequate capacity on the system to do so.

The Order established November 1, 2002, as the date on which the new CD
contracts, demand charge credits, and receipt point entitlements will go into
effect. On July 1, 2002, a number of parties to the proceedings filed requests
for rehearing of various aspects of the order. Also on July 1, 2002, we filed a
request for clarification of the details involved in implementing the
requirements of the order. At its July 17, 2002 open meeting, the FERC
reaffirmed that the parties had until July 31, 2002, to establish capacity
allocation levels among themselves on a voluntary basis and, absent any such
voluntary agreement, the FERC itself will establish capacity levels by customer.
On July 30, 2002, at the request of several parties, the FERC extended the
deadline for the full requirements customers to bid for capacity turned back by
other shippers to August 9, 2002. On that date, we received several bids from
California shippers. The full requirements shippers, however, did not submit
bids, taking the position that the turnback process could not go forward until
the FERC had issued an order resolving disputes regarding the allocation to them
of unsubscribed capacity on the system. In our report to the FERC dated August
1, 2002, we advised the FERC that, in order to move the conversion process from
full requirements to CD service forward, it appears that the FERC will be
required to issue an order establishing entitlements for the full requirements
shippers to our unsubscribed, sustainable capacity. Our customers subsequently
filed responses disputing the basis upon which we believe capacity on its system
must be allocated. Although we and our customers have worked diligently to
achieve an allocation of unsubscribed capacity among the full requirements
shippers who are being required to convert to CD service, the full requirements
shippers and the pipeline continue to hold a different view as to how this
allocation should be accomplished. The needs of the full requirements shippers
can be met through a combination of unsubscribed capacity, California receipt
rights, turnback capacity from other shippers, and an appropriately sized
expansion.

As required by the FERC, we and our customers have held two meetings and
scheduled a third to discuss implementation issues involved in the full
requirement's conversion and the allocation of receipt rights. At the first
meeting, we identified the sustainable west-flow capacity on our system that is
available for allocation among the full requirements shippers under the rates
they are paying pursuant to the 1996 settlement. A group of full requirements
shippers subsequently filed a motion with the FERC requesting clarification of
our available capacity, claiming that we have understated the capacity on our
system that is available to be allocated among them. We filed an answer to that
motion on July 3, 2002, explaining that the capacity we

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identified as available each month for the full requirements shippers is the
amount of capacity that we can make available on a sustainable basis given the
impact of transient conditions beyond our control.

Our current rate settlement establishes, among other things, base rates
through December 31, 2005. According to the settlement, our base rates began
escalating annually in 1998 as a result of inflationary factors. We have the
right to increase or decrease our base rates if changes in laws or regulations
result in increased or decreased costs in excess of $10 million a year. In
addition, all of our settling customers participate in risk sharing provisions
under our rate case settlement. Under these provisions, we receive cash payments
totaling $295 million for a portion of the risk we assumed from capacity
relinquishments by our customers at the end of 1997. The cash received is
deferred, and we recognize this deferral in revenues ratably over the risk
sharing period. As of June 30, 2002, we had unearned risk sharing revenues of
approximately $48 million and had $20 million remaining to be collected from
customers under this provision. Amounts received for relinquished capacity to
customers above certain dollar levels specified in the rate settlement obligate
us to refund a portion of the excess to customers. Under this provision, we
refunded $46 million of 2001 revenues to customers during 2001 and through June
30, 2002. During 2002, we established an additional refund obligation of $22
million. Both the risk and revenue sharing provisions of the rate settlement
extend through 2003. Our unresolved matter in our current rate settlement
involves the application of one existing fuel recovery mechanism as it relates
to compression facilities that were abandoned. An appeal was filed in the Fifth
Circuit Court of Appeals and was transferred to the D.C. Circuit Court of
Appeals. On April 3, 2002, the court dismissed the appeal in its entirety.

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, at which interested parties were given an
opportunity to comment further on the NOPR. Following the conference, additional
comments were filed by El Paso's pipelines and others. We cannot predict the
outcome of the NOPR, but adoption of the regulations in substantially the form
proposed would, at a minimum, place additional administrative and operational
burdens on us.

On July 17, 2002, the FERC issued a Notice of Inquiry (NOI) that seeks
comments regarding its policy, established in 1996, of permitting pipelines to
enter into negotiated rates transactions. Our pipeline has entered into such
transactions over the years. Specifically, the FERC is now undertaking a review
of whether negotiated rates should be capped, whether or not a pipeline's
"recourse rate" (cost of service based rate) continues to serve as a viable
alternative and safeguard against the exercise of alleged pipeline market power,
as well as other issues related to its negotiated rate program. Comments are due
on September 25, 2002, with reply comments due on October 25, 2002. We cannot
predict the outcome of this NOI.

On August 1, 2002, the FERC issued a NOPR requiring that all arrangements
concerning the cash management or money pool arrangements between a FERC
regulated subsidiary 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 must maintain a minimum proprietary capital balance of 30 percent, and
the FERC regulated entity and its parent must maintain investment grade credit
ratings. Comments on the NOPR are due on August 22, 2002. We cannot predict the
outcome of this NOPR.

Also on August 1, 2002, the FERC's Chief Accountant issued, to be effective
immediately, an Accounting Release providing guidance on how jurisdictional
entities should account for money pool arrangements and the types of
documentation that should be maintained for these arrangements. The Accounting
Release sets forth the documentation requirements set forth in the NOPR for
money pool arrangements, but does not address the requirements in the NOPR that
as a condition for participating in

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money pool arrangements the FERC regulated entity must maintain a minimum
proprietary capital balance of 30 percent and that the entity and its parent
must have investment grade credit ratings. Requests for rehearing are due on
September 3, 2002.

In January 2002, we were selected for an industry-wide audit by the FERC's
Office of the Executive Director, Division of Regulatory Audits. The audit will
focus on FERC Form 2 and affiliated transactions for the period January 1, 2000
through December 31, 2001.

While the outcome of our rates and regulatory matters cannot be predicted
with certainty, based on the information known to date 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. As new information 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.

Other Matters

In December 2001, Enron Corp. and a number of its subsidiaries, including
Enron North America Corp. and Enron Power Marketing, Inc., filed for Chapter 11
bankruptcy protection in the United States Bankruptcy Court for the Southern
District of New York. Affiliates of Enron held both short-term and long-term
capacity on our pipeline system but Enron has now rejected most of these
contracts. Future revenue on these contracts will depend upon the outcome of
Enron's bankruptcy and our ability to re-market or otherwise maximize the value
of the rejected or released capacity. We do not presently know the precise
values that will be received by our pipelines as a result of their efforts.

As a result of current circumstances surrounding the energy sector, the
creditworthiness of several industry participants has been called into question.
We have taken actions to mitigate our exposure to these participants; however,
should several of these participants file for Chapter 11 bankruptcy protection
and our contracts are not assumed by other counterparties, it could have a
material adverse effect on our financial position, operating results or cash
flows.

5. RELATED PARTY TRANSACTIONS

We participate in El Paso's cash management program which matches
short-term cash surpluses and need requirements of its participating affiliates,
thus minimizing total borrowing from outside sources. We had advanced at June
30, 2002 and December 31, 2001, $1,412 million and $1,294 million. The market
rate of interest at June 30, 2002 and December 31, 2001, was 1.9% and 2.1%.

At June 30, 2002 and December 31, 2001, we had other accounts receivable
from related parties of $2 million and $4 million. Accounts payable to related
parties was $6 million at June 30, 2002, versus $9 million at December 31, 2001,
and other current liabilities include dividends payable to our parent of $16
million and $2 million at June 30, 2002 and 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 $14 million in dividends
associated with our preferred stock during the first and second quarters of
2002.

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 present
value, and the same amount is added to the recorded value of the asset and is
amortized over the asset's remaining useful life. The provisions of SFAS No. 143
are effective for fiscal years beginning after June 15, 2002. We are currently
evaluating the effects of this statement.

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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 that are
associated with a restructuring, discontinued operations, plant closings or
other exit or disposal activities. The provisions of this statement are
effective for fiscal years beginning after December 31, 2002 and will impact any
exit or disposal activities initiated after January 1, 2003.

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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

As a result of current circumstances surrounding the energy sector, the
creditworthiness of several industry participants has been called into question.
We have taken actions to mitigate our exposure to these participants; however,
should several of these participants file for Chapter 11 bankruptcy protection
and our contracts are not assumed by other counterparties, it could have a
material adverse effect on our financial position, operating results or cash
flows.

RESULTS OF OPERATIONS

Our results are relatively stable, but can be subject to variability from a
number of factors, such as weather conditions, including those conditions that
may impact the amount of power produced by natural gas fired turbines compared
to power generated by less costly hydro-electric methods, as well as gas supply
to market price differentials which can displace the pipeline's deliveries to
the markets they serve. Results can also be impacted by a pipeline's fuel
recovery level and the ability to operate the pipeline system efficiently.
Future revenues may also be impacted by expansion projects in our service areas,
competition by other pipelines for those expansion needs and regulatory impacts
on rates. Results of our operations were as follows for the periods ended June
30:

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

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

Second Quarter 2002 Compared to Second Quarter 2001

Operating revenues for the quarter ended June 30, 2002, were $6 million
higher than the same period in 2001 primarily due to a larger portion of our
capacity being sold at maximum tariff rates compared to the same period in 2001.
Partially offsetting the increase were lower throughput to California and other
western states due to lower electric generation demand and milder weather in
2002 and lower prices on fuel recoveries from customers. Also contributing to
the decrease were lower rates on the Mojave Pipeline system as a result of a
rate case settlement effective October 2001.

Operating expenses for the quarter ended June 30, 2002, were $98 million
lower than the same period in 2001. The decrease was primarily due to
merger-related costs of $94 million incurred in 2001 related to the relocation
of our headquarters from El Paso, Texas to Colorado Springs, Colorado as part of
El Paso's merger with Coastal, lower compressor operating costs resulting from
lower electric prices in 2002 and a change in estimated business activity tax
settlements in the second quarter of 2002. The decrease was partially offset by
an increase of accrued legal liabilities in the second quarter of 2002 and
increases to our reserve for bad debts related to the bankruptcy of Enron Corp.

12

Other income for the quarter ended June 30, 2002, was $5 million higher
than the same period in 2001 primarily due to a gain on the sale of non-pipeline
assets in the second quarter of 2002.

Six Months Ended 2002 Compared to Six Months Ended 2001

Operating revenues for the six months ended June 30, 2002, were $17 million
higher than the same period in 2001 primarily due to a larger portion of our
capacity being sold at maximum tariff rates compared to the same period in 2001.
Partially offsetting the increase were lower prices on fuel recoveries from
customers and lower throughput to California and other western states due to
lower electric generation demand and milder weather in 2002, as well as the
impact of lower rates on the Mojave Pipeline system as a result of a rate case
settlement effective October 2001.

Operating expenses for the six months ended June 30, 2002, were $101
million lower than the same period in 2001. The decrease was primarily due to
merger-related costs of $102 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 lower compressor operating costs resulting
from lower electric prices in 2002, an adjustment to depreciation as a result of
finalization of a regulatory issue in 2002, and a change in estimated business
activity tax settlements in the second quarter of 2002. The decrease was
partially offset by increases to our reserve for bad debts related to the
bankruptcy of Enron Corp. and an increase in accrued legal liabilities in the
second quarter of 2002.

Other income for the six months ended June 30, 2002, was $6 million higher
than the same period in 2001 primarily due to a gain on the sale of non-pipeline
assets in the second quarter of 2002.

INTEREST AND DEBT EXPENSE

Non-affiliated Interest and Debt Expense

Non-affiliated interest and debt expense for the quarter and six months
ended June 30, 2002, was $4 million and $11 million lower than the same period
in 2001 primarily due to a reduction of long-term debt in January 2002 and lower
interest rates on commercial paper borrowings in 2002. The decrease was
partially offset by an increase in long-term debt for the debt issued in June
2002.

Affiliated Interest Income

Affiliated interest income for the quarter and six months ended June 30,
2002, was $10 million and $23 million lower than the same period in 2001 due to
lower short-term interest rates in 2002 on advances partially offset by higher
average advances to El Paso under our cash management program.

INCOME TAXES

Income tax expense for the quarter and six months ended June 30, 2002, was
$26 million and $54 million, resulting in effective tax rates of 37 percent and
38 percent. Our effective tax rates were different than the statutory rate of 35
percent primarily due to state income taxes.

Income tax benefit for the quarter ended June 30, 2001, was $12 million,
resulting in an effective tax rate of 36 percent. The income tax expense for the
six months ended June 30, 2001, was $11 million, resulting in an effective tax
rate of 37 percent. Our effective tax rates were different than the statutory
rate of 35 percent for both 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.

13

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.

14

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 company
procedures relating to investigating pipeline failures and thereby minimize
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.

The six remaining Carlsbad lawsuits are as follows: one filed in district
court in Harris County, Texas (Geneva Smith, et al v. EPEC and EPNG, filed
October 23, 2000), and five filed in state district court in Carlsbad, New
Mexico (Chapman, as Personal Representative of the Estate of Amy Smith Heady, v.
EPEC, EPNG and John Cole, filed February 9, 2001; Chapman, as Personal
Representative of the Estate of Dustin Wayne Smith, v. EPEC, EPNG and John Cole;
Chapman, as Personal Representative of the Estate of Terry Wayne Smith, v. EPNG,
EPEC and John Cole; Rackley, as Personal Representative of the Estate of Glenda
Gail Sumler, v. EPEC, EPNG and John Cole; and Rackley, as Personal
Representative of the Estate of Amanda Sumler Smith, v. EPEC, EPNG and John
Cole, all filed March 16, 2001). We have reached a contingent settlement in an
additional case (Dawson, as Personal Representative of Kirsten Janay Sumler, v.
EPEC and EPNG, filed November 8, 2000).

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.

15

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

None.

16

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.

EL PASO NATURAL GAS COMPANY

Date: August 13, 2002 /s/ JOHN W. SOMERHALDER II
------------------------------------
John W. Somerhalder II
Chairman of the Board,
Chief Executive Officer and Director
(Principal Executive Officer)

Date: August 13, 2002 /s/ GREG G. GRUBER
------------------------------------
Greg G. Gruber
Senior Vice President,
Chief Financial Officer and
Treasurer
(Principal Financial and Accounting
Officer)

17

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.