<PAGE>

--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
                                 UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549
                             ---------------------

                                   FORM 10-K
(MARK ONE)
     [X]        ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                      THE SECURITIES EXCHANGE ACT OF 1934

                  FOR THE FISCAL YEAR ENDED DECEMBER 31, 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

                          EL PASO NATURAL GAS COMPANY
             (Exact Name of Registrant as Specified in Its Charter)

<Table>
<S>                                            <C>
                  DELAWARE                                      74-0608280
       (State or Other Jurisdiction of                       (I.R.S. Employer
       Incorporation or Organization)                       Identification No.)

              EL PASO BUILDING
            1001 LOUISIANA STREET
               HOUSTON, TEXAS                                      77002
  (Address of Principal Executive Offices)                      (Zip Code)
</Table>

                        TELEPHONE NUMBER: (713) 420-2600

        SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE

        SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE

     Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes  [X]  No  [ ].

     Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.  [X]

     Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act).  Yes [ ]  No [X]

     STATE THE AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY NON-AFFILIATES
OF THE REGISTRANT...........................................................NONE

     INDICATE THE NUMBER OF SHARES OUTSTANDING OF EACH OF THE REGISTRANT'S
CLASSES OF COMMON STOCK, AS OF THE LATEST PRACTICABLE DATE.

     Common Stock, par value $1 per share. Shares outstanding on March 27, 2003:
1,000

     EL PASO NATURAL GAS COMPANY MEETS THE CONDITIONS OF GENERAL INSTRUCTION
I(1)(a) AND (b) TO FORM 10-K AND IS THEREFORE FILING THIS REPORT WITH A REDUCED
DISCLOSURE FORMAT AS PERMITTED BY SUCH INSTRUCTION.

                   DOCUMENTS INCORPORATED BY REFERENCE: NONE

--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
<PAGE>

                          EL PASO NATURAL GAS COMPANY

                               TABLE OF CONTENTS

<Table>
<Caption>
                                    CAPTION                             PAGE
                                    -------                             ----
<S>       <C>                                                           <C>
                                     PART I
Item 1.   Business....................................................    1
Item 2.   Properties..................................................    4
Item 3.   Legal Proceedings...........................................    4
Item 4.   Submission of Matters to a Vote of Security Holders.........    *

                                    PART II
Item 5.   Market for Registrant's Common Equity and Related
            Stockholder Matters.......................................    4
Item 6.   Selected Financial Data.....................................    *
Item 7.   Management's Discussion and Analysis of Financial Condition
            and Results
            of Operations.............................................    5
          Risk Factors and Cautionary Statement for Purposes of the
            "Safe Harbor" Provisions
            of the Private Securities Litigation Reform Act of 1995...    9
Item 7A.  Quantitative and Qualitative Disclosures About Market
            Risk......................................................   16
Item 8.   Financial Statements and Supplementary Data.................   17
Item 9.   Changes in and Disagreements with Accountants on Accounting
            and Financial Disclosure..................................   43

                                    PART III
Item 10.  Directors and Executive Officers of the Registrant..........    *
Item 11.  Executive Compensation......................................    *
Item 12.  Security Ownership of Management............................    *
Item 13.  Certain Relationships and Related Transactions..............    *
Item 14.  Controls and Procedures.....................................   43

                                    PART IV
Item 15.  Exhibits, Financial Statement Schedules, and Reports on Form
            8-K.......................................................   44
          Signatures..................................................   47
          Certifications..............................................   48
</Table>

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

* We have not included a response to this item in this document since no
  response is required pursuant to the reduced disclosure format permitted by
  General Instruction I to Form 10-K.

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

<Table>
<S>      <C>                                         <C>    <C>
/d       = per day                                   Mcf    = thousand cubic feet
BBtu     = billion British thermal units             MMcf   = million cubic feet
Bcf      = billion cubic feet
</Table>

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

     When we refer to "us", "we", "our" or "ours", we are describing El Paso
Natural Gas Company and/or our subsidiaries.

                                        i
<PAGE>

                                     PART I

ITEM 1. BUSINESS

                                    GENERAL

     We are a Delaware corporation incorporated in 1928, and a wholly owned
subsidiary of El Paso Corporation (El Paso). Our primary business is the
interstate transportation of natural gas. We conduct our business activities
through two pipeline systems, each of which is discussed below.

     The EPNG system.  The El Paso Natural Gas system consists of approximately
10,600 miles of pipeline with a winter sustainable west-flow capacity of 4,530
MMcf/d and approximately 800 MMcf/d of east-end deliverability. The west-flow
capacity includes approximately 230 MMcf/d of capacity added in November 2002
related to the completion of our Line 2000 project which converted a pipeline
from oil transmission to natural gas transmission. This pipeline extends from
West Texas to the Arizona and California border. During 2002, 2001 and 2000,
average throughput on the EPNG system was 3,799 BBtu/d, 4,253 BBtu/d and 3,937
BBtu/d. This system delivers natural gas from the San Juan, Permian and Anadarko
Basins to California, which is our single largest market, as well as markets in
Arizona, Nevada, New Mexico, Oklahoma, Texas and northern Mexico.

     The Mojave system.  The Mojave Pipeline system consists of approximately
400 miles of pipeline with a design capacity of approximately 400 MMcf/d. During
2002, 2001 and 2000, average throughput on the Mojave system was 266 BBtu/d, 283
BBtu/d and 407 BBtu/d. This system connects with the EPNG and Transwestern
transmission systems at Topock, Arizona, the Kern River Gas Transmission Company
transmission system in California and extends to customers in the vicinity of
Bakersfield, California.

                             REGULATORY ENVIRONMENT

     Our interstate natural gas transmission systems are regulated by the
Federal Energy Regulatory Commission (FERC) under the Natural Gas Act of 1938
and the Natural Gas Policy Act of 1978. Our systems operate under FERC-approved
tariffs that establish rates and terms and conditions for service to our
customers. Generally, the FERC's authority extends to:

     - rates and charges for natural gas transportation;

     - certification and construction of new facilities;

     - extension or abandonment of facilities;

     - maintenance of accounts and records;

     - relationships between pipeline and marketing affiliates;

     - terms and conditions of services;

     - depreciation and amortization policies;

     - acquisition and disposition of facilities; and

     - initiation and discontinuation of services.

     The fees or rates established under our tariffs are a function of our costs
of providing service to our customers, including a reasonable return on our
invested capital. Approximately 94 percent of our transportation services
revenue is attributable to a capacity reservation, or demand charge, paid by
firm customers. These firm shippers are obligated to pay a monthly demand
charge, regardless of the amount of natural gas they transport, for the term of
their contracts. The remaining 6 percent of our transportation services revenue
is attributable to charges based solely on the volumes of gas actually
transported on our pipeline systems. Consequently, our financial results have
historically been relatively stable; however, they can

                                        1
<PAGE>

be subject to volatility due to factors such as weather, changes in natural gas
prices and market conditions, regulatory actions, competition and the
credit-worthiness of our customers.

     Our interstate pipeline systems are also subject to federal, state and
local pipeline safety and environmental statutes and regulations. We have
continuing programs designed to keep all of our facilities in compliance with
pipeline safety and environmental requirements. We believe that our systems are
in material compliance with the applicable requirements.

     A discussion of significant rate and regulatory matters is included in Part
II, Item 8, Financial Statements and Supplementary Data, Note 8.

                            MARKETS AND COMPETITION

     We have firm and interruptible customers, including distribution and
industrial companies, electric generation companies, natural gas producers,
other natural gas pipelines and natural gas marketing and trading companies. We
provide transportation services in both our natural gas supply and market areas.
Our pipeline systems connect with multiple pipelines that provide our shippers
with access to diverse sources of supply and various natural gas markets served
by these pipelines. The following table details our markets and competition on
each of our interstate pipeline systems.

<Table>
<Caption>
  PIPELINE
   SYSTEM         CUSTOMER INFORMATION            CONTRACT INFORMATION                      COMPETITION
------------  ----------------------------   -------------------------------   -------------------------------------
<S>           <C>                            <C>                               <C>
EPNG          Approximately 230 firm and     Approximately 180 firm            EPNG faces competition from other
                interruptible                transportation contracts          pipelines as well as alternative
              transportation                 Contracted capacity:(1)           energy sources that generate
                customers                    Weighted average remaining        electricity such as hydroelectric
                                             contract term:                    power, nuclear, coal and fuel oil.
                                               approximately 5 years
              Major Customer:
                Southern California Gas
                  Company                    Contract term expires in 2006.
              (1,235 BBtu/d)                 Contract terms expiring
              (95 BBtu/d)                    2004-2007.

Mojave        Approximately 35 firm and      Eight firm contracts              Mojave faces competition from other
                interruptible                Contracted capacity: 98%          pipelines as well as alternative
              transportation   customers     Weighted average remaining        energy sources that generate
                                             contract term:                    electricity such as hydroelectric
                                               approximately 4 years           power, nuclear, coal and fuel oil.
              Major Customers:
                Texaco Natural Gas Inc.
                  (185 BBtu/d)               Contract term expires in 2007.
                Burlington Resources
                  Trading Inc.
                  (76 BBtu/d)                Contract term expires in 2007.
                Los Angeles Department of
                  Water and Power
                  (50 BBtu/d)                Contract term expires in 2007.
</Table>

---------------
(1) A discussion of significant rate and regulatory matters regarding our
    capacity is included in Part II, Item 8, Financial Statements and
    Supplementary Data, Note 8.

     The combined capacity of all pipeline companies serving the California
market is approximately 7.4 Bcf/d and we provide approximately 44 percent of
this capacity. In 2002, the demand for interstate pipeline capacity to
California averaged 5.0 Bcf/d, equivalent to approximately 68 percent of the
total interstate pipeline capacity serving that state. Natural gas shipped to
California across our system represented approximately 34 percent of the natural
gas consumed in the state in 2002.

     Electric power generation is one of the fastest growing demand sectors of
the natural gas market. The potential consequences of proposed and ongoing
restructuring and deregulation of the electric power industry are currently
unclear. Restructuring and deregulation benefit the natural gas industry by
creating more demand for natural gas turbine generated electric power, but this
effect is offset, in varying degrees, by

                                        2
<PAGE>

increased generation efficiency and more effective use of surplus electric
capacity as a result of open market access.

     Our ability to extend our existing contracts or re-market expiring capacity
at maximum rates is dependent on competitive alternatives, the regulatory
environment at the federal, state and local levels and market supply and demand
factors at the relevant dates these contracts are extended or expire. The
duration of new or re-negotiated contracts will be affected by current prices,
competitive conditions and judgments concerning future trends and volatility.

                                 ENVIRONMENTAL

     A description of our environmental activities is included in Part II, Item
8, Financial Statements and Supplementary Data, Note 8, and is incorporated
herein by reference.

                                   EMPLOYEES

     As of March 26, 2003, we had approximately 710 full-time employees, none of
whom are subject to collective bargaining arrangements.

                                        3
<PAGE>

ITEM 2. PROPERTIES

     A description of our properties is included in Item 1, Business, and is
incorporated herein by reference.

     We believe that we have satisfactory title to the properties owned and used
in our businesses, subject to liens for taxes not yet payable, liens incident to
minor encumbrances, liens for credit arrangements and easements and restrictions
that do not materially detract from the value of these properties, our interests
in these properties, or the use of these properties in our businesses. We
believe that our properties are adequate and suitable for the conduct of our
business in the future.

ITEM 3. LEGAL PROCEEDINGS

     A description of our legal proceedings is included in Part II, Item 8,
Financial Statements and Supplementary Data, Note 8, and is incorporated herein
by reference.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     Item 4, Submission of Matters to a Vote of Security Holders, has been
omitted from this report pursuant to the reduced disclosure format permitted by
General Instruction I to Form 10-K.

                                    PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

     All of our common stock, par value $1 per share, is owned by El Paso and,
accordingly, there is no public trading market for our stock.

     We pay dividends on our common stock from time to time from legally
available funds that have been approved for payment by our Board of Directors.
In 2002, we declared and paid to El Paso a non-cash dividend of non-regulated
assets in the amount of $19 million. There were no common stock dividends
declared during 2001.

ITEM 6. SELECTED FINANCIAL DATA

     Item 6, Selected Financial Data, has been omitted from this report pursuant
to the reduced disclosure format permitted by General Instruction I to Form
10-K.

                                        4
<PAGE>

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
        OF OPERATIONS

     The information required by this Item is presented in a reduced disclosure
format pursuant to General Instruction I to Form 10-K. The notes to our
consolidated financial statements contain information that is pertinent to the
following analysis, including a discussion of our significant accounting
policies.

                                    GENERAL

     Our business is the interstate transportation of natural gas. Our
interstate natural gas transportation systems face varying degrees of
competition from other pipelines, as well as from alternative energy sources
used to generate electricity, such as hydroelectric power, nuclear, coal and
fuel oil. We are regulated by the FERC which regulates the rates we can charge
our customers. These rates are a function of our costs of providing services to
our customers, and include a return on our invested capital. As a result, our
financial results have historically been relatively stable; however, they can be
subject to volatility due to factors such as weather, changes in natural gas
prices and market conditions, regulatory actions, competition and the credit-
worthiness of our customers. In addition, our ability to extend our existing
customer contracts or re-market expiring contracted capacity at maximum rates is
dependent on competitive alternatives, the regulatory environment and supply and
demand factors at the relevant dates these contracts are extended or expire.

                             RESULTS OF OPERATIONS

     We use earnings before interest and income taxes (EBIT) to assess the
operating results and effectiveness of our business. We define EBIT as operating
income, adjusted for gains and losses on sales of assets, capitalized returns on
equity and other miscellaneous non-operating items. Items that are not included
in this measure are financing costs, including interest and debt expense,
affiliated interest income and income taxes. The following is a reconciliation
of our operating results to EBIT and net income for the years ended December 31:

<Table>
<Caption>
                                                               2002         2001
                                                              -------      -------
                                                              (IN MILLIONS, EXCEPT
                                                                VOLUME AMOUNTS)
<S>                                                           <C>          <C>
Operating revenues..........................................  $  564       $  572
Operating expenses..........................................    (669)        (386)
                                                              ------       ------
  Operating income (loss)...................................    (105)         186
Other income and expense....................................       1           (2)
                                                              ------       ------
  EBIT......................................................    (104)         184
Interest and debt expense...................................     (72)         (87)
Affiliated interest income..................................      22           58
Income taxes................................................      55          (60)
                                                              ------       ------
  Net income (loss).........................................  $  (99)      $   95
                                                              ======       ======
Total throughput (BBtu/d)(1)................................   4,065        4,535
                                                              ======       ======
</Table>

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

(1) Excludes Mojave throughput on behalf of EPNG.

     We believe EBIT is a useful measurement for our investors because it
provides information that can be used to evaluate the effectiveness of our
businesses and 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.

                                        5
<PAGE>

OPERATING RESULTS (EBIT)

     Operating revenues for the year ended December 31, 2002, were $8 million
lower than in 2001. The decrease was due to $13 million from lower fuel
efficiencies and lower natural gas prices, $8 million from lower throughput to
California and other southwestern states due to lower electric generation demand
and milder weather in 2002 and $4 million from lower rates on the Mojave
Pipeline system as a result of a rate case settlement effective October 2001.
The decreases were partially offset by $13 million in higher revenues associated
with a larger portion of our available system capacity earning maximum tariff
rates and $3 million related to higher demand revenues in 2002 resulting from
annual inflation increases as provided in the EPNG tariff.

     Operating expenses for the year ended December 31, 2002, were $283 million
higher than in 2001 primarily as a result of a $412 million accrual for our
Western Energy Settlement in December 2002. Also contributing to the increase
were a $10 million contribution to a charitable foundation, a $6 million
increase in corporate allocations, a $6 million increase in bad debt expense
related to the bankruptcy of Enron Corporation and a $3 million increase in
payroll and other costs. These increases were partially offset by the merger
related costs of $98 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. For
a further discussion of these charges, see Item 8, Financial Statements and
Supplementary Data, Note 3. Also offsetting the increase was a $22 million
reduction associated with the periodic revaluation of natural gas imbalances as
a result of changes in imbalance volumes and gas prices, $10 million of lower
compressor operating costs resulting from lower electric usage and prices in
2002, $8 million of lower property and other taxes due to a change in an
estimated business activity tax settlement and property and franchise tax
refunds received in 2002, $7 million of lower legal fees, $7 million of
depreciation adjustments due to the finalization of regulatory issues in 2002
and $6 million in decreased environmental costs.

     Other income for the year ended December 31, 2002, was $3 million higher
than the same period in 2001 due to gains on sales of non-pipeline assets of $1
million in 2002 and a 2001 accrual of $3 million for proposed fines from the
Department of Transportation related to the August 2000 pipeline rupture.

REVENUE OUTLOOK

     As discussed in Item 8, Financial Statements and Supplementary Data, Note
8, on September 20, 2002, the FERC issued an order related to the allocation of
capacity on our EPNG system. This order 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 contracts terminating or expiring after May 31, 2002; and

     - add additional compression to our Line 2000 project increasing the
       capacity by 320 MMcf/d without the opportunity to recover these costs in
       our rates until our next rate case which will be effective January 1,
       2006.

     Our future results of operations will be impacted as a result of this FERC
order. Based on the order, we are unable to remarket approximately 471 MMDth/d
of capacity, of which approximately 200 MMDth/d was rejected by Enron
Corporation in May 2002 in its bankruptcy proceeding. The remaining 271 MMDth/d
relates to contracts that expired within the time frame specified under the
order. Prior to the rejection and expiration of the 471 MMDth/d contracts, we
were earning approximately $3.5 million per month, net of revenue credits,
related to this capacity. 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.

                                        6
<PAGE>

INTEREST AND DEBT EXPENSE

     Interest and debt expense for the year ended December 31, 2002, was $15
million lower than the same period in 2001. Below is the analysis of our
interest expense for the years ended December 31:

<Table>
<Caption>
                                                              2002     2001
                                                              ----     ----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
Long term debt, including current maturities................  $69      $73
Short term borrowings.......................................    8       23
Other.......................................................    1       --
Less: Capitalized interest..................................   (6)      (9)
                                                              ---      ---
  Total interest and debt expense...........................  $72      $87
                                                              ===      ===
</Table>

     The decrease in interest expense was primarily due to a decrease in average
commercial paper balances outstanding of $480 million in 2001 compared with $296
million in 2002 with the weighted average interest rate decreasing from 4.61% in
2001 to 2.67% in 2002. Also contributing to the decrease was a lower weighted
average outstanding long-term debt principal balance in 2002 compared with 2001.
In January 2002, we retired $215 million aggregate principal amount of 7.75%
notes and in June 2002, we issued $300 million aggregate principal amount 8.375%
notes. Offsetting the decrease was lower capitalized interest in 2002 compared
to 2001 due to lower interest capitalization rates partially offset by a larger
average construction work in progress balance in 2002.

AFFILIATED INTEREST INCOME

     Affiliated interest income for the year ended December 31, 2002, was $36
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 the cash management
program. The average short-term interest rates decreased from 4.3% in 2001 to
1.8% in 2002, and average advances to El Paso under its cash management program,
were $1,227 million in 2002 versus $1,352 million in 2001.

INCOME TAXES

     Income tax benefit for the year ended December 31, 2002, was $55 million
and the income tax expense for the year ended December 31, 2001, was $60
million, resulting in effective tax rates of 36 percent and 38 percent. Our
effective tax rates were different from the statutory rate of 35 percent in both
periods primarily due to state income taxes. For a reconciliation of the
statutory rate to the effective rates, see Item 8, Financial Statements and
Supplementary Data, Note 4.

                        LIQUIDITY AND CAPITAL RESOURCES

LIQUIDITY

     Our liquidity needs are provided by cash flow from operating activities and
the use of El Paso's cash management program. Under El Paso's cash management
program, depending on whether we have short-term cash surpluses or requirements,
we either provide cash to El Paso or El Paso provides cash to us. We have
historically provided cash advances to El Paso, and we reflect these net
advances to our parent as investing activities in our statement of cash flows.
As of December 31, 2002, we had net receivables from El Paso and its
subsidiaries of $990 million as a result of this program. These receivables are
due upon demand. However, as of December 31, 2002, we have classified $565
million as non-current because we do not anticipate settlement within twelve
months. We believe that cash flow from operating activities and cash provided by
El Paso's cash management program will be adequate to meet our short-term
capital and debt

                                        7
<PAGE>

servicing requirements for existing operations. Our cash flows for the years
ended December 31 were as follows:

<Table>
<Caption>
                                                              2002    2001
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Cash flows from operating activities........................  $ 269   $ 324
Cash flows from investing activities........................    120    (455)
Cash flows from financing activities........................   (386)    131
</Table>

     In a series of credit rating agency actions in late 2002 and early 2003,
and contemporaneously with the downgrades of the senior unsecured indebtedness
of El Paso, our senior unsecured indebtedness was downgraded to below investment
grade and is currently rated B1 by Moody's and B+ by Standard & Poor's with a
negative outlook from both agencies. These downgrades will increase our cost of
capital and collateral requirements and could impede our access to capital
markets in the future.

     As a result of El Paso's credit ratings being downgraded to below
investment grade status, cash generated by Mojave, our indirect wholly owned
subsidiary, can be used only for Mojave's operating and maintenance needs and
for purposes of redeeming the preferred interests of Trinity River, an El Paso
financing arrangement that Mojave and other El Paso affiliates collateralize.
Until the preferred interests were redeemed in full, Mojave was required to
distribute a portion of its cash-based earnings each quarter to its parent
Sabine River Investors V, L.L.C. and was no longer able to provide excess cash
to El Paso's cash management program. On January 8, 2003, Mojave, through its
parent paid approximately $3 million under this provision to the preferred
interest members of Trinity River. In March 2003, El Paso entered into a $1.2
billion two-year term loan and the proceeds were used to retire the outstanding
balance under the Trinity River financing agreement. As of December 31, 2002,
the total amount outstanding under this agreement was approximately $980
million. See Part II, Item 8, Financial Statements and Supplementary Date, Note
7, which is incorporated herein by reference.

     In August 2002, the FERC issued a notice of proposed rulemaking requiring,
among other things, that FERC regulated entities participating in cash
management arrangements with non-FERC regulated parents maintain a minimum
proprietary capital balance of 30 percent, and that the FERC regulated entity
and its parent maintain investment grade credit ratings, as a condition to
participating in the cash management program. If this proposal is adopted, our
participation in El Paso's cash management program would terminate, which could
affect our liquidity. We cannot predict the outcome of this proposal at this
time.

     On March 20, 2003, we and our affiliates entered into an agreement in
principle (the Western Energy Settlement) with various public and private
claimants, including the states of California, Washington, Oregon and Nevada, to
resolve the principal litigation, claims and regulatory proceedings against us
and our affiliates relating to the sale or delivery of natural gas and
electricity from September 1996 to the date of the Western Energy Settlement.
See Item 8, Financial Statements and Supplementary Data, and Notes 2 and 8 for a
further discussion of this settlement and its impact to our liquidity.

CAPITAL EXPENDITURES

     Our capital expenditures during the periods indicated are listed below:

<Table>
<Caption>
                                                               YEAR ENDED
                                                              DECEMBER 31,
                                                              -------------
                                                              2002    2001
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Maintenance.................................................  $123    $105
Expansion/Other.............................................    70      52
                                                              ----    ----
     Total..................................................  $193    $157
                                                              ====    ====
</Table>

     Under our current plan, we expect to spend between approximately $100
million and $150 million in each of the next three years for capital
expenditures to maintain the integrity of our pipelines and ensure the

                                        8
<PAGE>

reliable delivery of natural gas to our customers. In addition, we have budgeted
to spend between approximately $70 million and $ 195 million in each of the next
three years to expand the capacity of our pipeline systems. We expect to fund
our maintenance and expansion capital expenditures using a combination of
internally generated funds and external financing.

DEBT

     For a discussion of our debt obligations, see Item 8, Financial Statements
and Supplementary Data, Note 7, which is incorporated herein by reference.

                         COMMITMENTS AND CONTINGENCIES

     For a discussion of our commitments and contingencies, see Item 8,
Financial Statements and Supplementary Data, Note 8, which is incorporated
herein by reference.

            NEW ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

     As of December 31, 2002, there were a number of accounting standards and
interpretations that had been issued, but not yet adopted by us. Below is a
discussion of the more significant standards that could impact us.

ACCOUNTING FOR COSTS ASSOCIATED WITH EXIT OR DISPOSAL ACTIVITIES

     In July 2002, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standard (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.

ACCOUNTING FOR GUARANTEES

     In November 2002, the FASB issued FASB Interpretation (FIN) No. 45,
Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others. This interpretation requires that
companies record a liability for all guarantees issued after January 31, 2003,
including financial, performance, and fair value guarantees. This liability is
recorded at its fair value upon issuance, and does not affect any existing
guarantees issued before January 31, 2003. This standard also requires expanded
disclosures on all existing guarantees at December 31, 2002. See Item 8,
Financial Statements and Supplementary Data, Notes 7 and 8 for related
disclosures.

    RISK FACTORS AND CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR"
       PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

     This report contains or incorporates by reference forward-looking
statements within the meaning of the Private Securities Litigation Reform Act of
1995. Where any forward-looking statement includes a statement of the
assumptions or bases underlying the forward-looking statement, we caution that,
while we believe these assumptions or bases to be reasonable and in good faith,
assumed facts or bases almost always vary from the actual results, and the
differences between assumed facts or bases and actual results can be material,
depending upon the circumstances. Where, in any forward-looking statement, we or
our management express an expectation or belief as to future results, that
expectation or belief is expressed in good faith and is believed to have a
reasonable basis. We cannot assure you, however, that the statement of
expectation or belief will result or be achieved or accomplished. The words
"believe," "expect," "estimate," "anticipate," "plan," "budget" and similar
expressions will generally identify forward-looking statements. Our
forward-looking statements, whether written or oral, are expressly qualified by
these cautionary statements and any other

                                        9
<PAGE>

cautionary statements that may accompany those statements. In addition, we
disclaim any obligation to update any forward-looking statements to reflect
events or circumstances after the date of this report.

     With this in mind, you should consider the risks discussed elsewhere in
this report and other documents we file with the Securities and Exchange
Commission (SEC) from time to time and the following important factors that
could cause actual results to differ materially from those expressed in any
forward-looking statement made by us or on our behalf.

                         RISKS RELATED TO OUR BUSINESS

OUR SUCCESS DEPENDS ON FACTORS BEYOND OUR CONTROL.

     Our business is the transportation of natural gas for third parties. As a
result, the volume of natural gas involved in these activities depends on the
actions of those third parties, and is beyond our control. Further, the
following factors, most of which are beyond our control, may unfavorably impact
our ability to maintain or increase current transmission volumes and rates, to
renegotiate existing contracts as they expire, or to remarket unsubscribed
capacity:

     - future weather conditions, including those that favor alternative energy
       sources;

     - price competition;

     - drilling activity and supply availability;

     - expiration and/or turn back of significant contracts;

     - service area competition;

     - changes in regulation and actions of regulatory bodies;

     - credit risk of customer base;

     - increased cost of capital; and

     - natural gas and liquids prices.

THE REVENUES OF OUR PIPELINE BUSINESSES ARE GENERATED UNDER CONTRACTS THAT MUST
BE RENEGOTIATED PERIODICALLY.

     Our revenues are generated under transportation contracts which expire
periodically and must be renegotiated and extended or replaced. We cannot assure
that we will be able to extend or replace our contracts when they expire or that
the terms of any renegotiated contracts will be as favorable as the existing
contracts. For a further discussion of these matters, see Part I, Item 1,
Business -- Markets and Competition.

     In particular, our ability to extend and/or replace transportation
contracts could be adversely affected by factors we cannot control, including:

     - the proposed construction by other companies of additional pipeline
       capacity in markets served by us;

     - changes in state regulation of local distribution companies, which may
       cause them to negotiate short-term contracts or turn back their capacity
       when their contracts expire;

     - reduced demand and market conditions;

     - the availability of alternative energy sources or gas supply points; and

     - regulatory actions.

     If we are unable to renew, extend or replace these contracts or if we renew
them on less favorable terms, we may suffer a material reduction in our revenues
and earnings.

                                        10
<PAGE>

WE FACE COMPETITION THAT COULD ADVERSELY AFFECT OUR OPERATING RESULTS.

     Our competitors include other pipeline companies, as well as participants
in other industries supplying and transporting alternative fuels. If we are
unable to compete effectively, our future profitability may be negatively
impacted.

FLUCTUATIONS IN ENERGY COMMODITY PRICES COULD ADVERSELY AFFECT OUR BUSINESS.

     Revenues generated by our contracts depend on volumes and rates, both of
which can be affected by the prices of natural gas. Increased natural gas prices
could result in loss of load from our customers, such as power companies not
dispatching gas fired power plants, industrial plant shutdown or load loss to
competitive fuels and local distribution companies' loss of customer base due to
conversion from natural gas. The success of our operations is subject to
continued development of additional oil and natural gas reserves in the vicinity
of our facilities and our ability to access additional suppliers from
interconnecting pipelines to offset the natural decline from existing wells
connected to our systems. A decline in energy prices could precipitate a
decrease in these development activities and could cause a decrease in the
volume of reserves available for transmission on our system. Fluctuations in
energy prices are caused by a number of factors, including:

     - regional, domestic and international supply and demand;

     - availability and adequacy of transportation facilities;

     - energy legislation;

     - federal and state taxes, if any, on the transportation of natural gas;

     - abundance of supplies of alternative energy sources; and

     - political unrest among oil-producing countries.

THE AGENCIES THAT REGULATE US AND OUR CUSTOMERS AFFECT OUR PROFITABILITY.

     Our pipeline businesses are regulated by the FERC, the U.S. Department of
Transportation, and various state and local regulatory agencies. Regulatory
actions taken by those agencies have the potential to adversely affect our
profitability. In particular, the FERC regulates the rates we are permitted to
charge our customers for our services. If our tariff rates were reduced in a
future rate proceeding, if our volume of business under our currently permitted
rates was decreased significantly or if we were required to substantially
discount the rates for our services because of competition, our profitability
and liquidity could be reduced.

     Further, state agencies that regulate our local distribution company
customers could impose requirements that could impact demand for our services.

COSTS OF ENVIRONMENTAL LIABILITIES, REGULATIONS AND LITIGATION COULD EXCEED OUR
ESTIMATES.

     Our operations are subject to various environmental laws and regulations.
These laws and regulations obligate us to install and maintain pollution
controls and to clean up various sites at which regulated materials may have
been disposed of or released. We are also party to legal proceedings involving
environmental matters pending in various courts and agencies.

     It is not possible for us to estimate reliably the amount and timing of all
future expenditures related to environmental matters because of:

     - the uncertainties in estimating clean up costs;

     - the discovery of new sites or information;

     - the uncertainty in quantifying liability under environmental laws that
       impose joint and several liability on all potentially responsible
       parties;

     - the nature of environmental laws and regulations; and

     - the possible introduction of future environmental laws and regulations.

                                        11
<PAGE>

     Although we believe we have established appropriate reserves for
liabilities, including clean up costs, we could be required to set aside
additional reserves in the future due to these uncertainties. For additional
information, see Part II, Item 8, Financial Statements and Supplementary Data,
Note 8.

OUR OPERATIONS ARE SUBJECT TO OPERATIONAL HAZARDS AND UNINSURED RISKS.

     Our operations are subject to the inherent risks normally associated with
those operations, including pipeline ruptures, explosions, pollution, release of
toxic substances, fires and adverse weather conditions, and other hazards, each
of which could result in damage to or destruction of our facilities or damages
to persons and property. In addition, our operations face possible risks
associated with acts of aggression on our assets. If any of these events were to
occur, we could suffer substantial losses.

     While we maintain insurance against many of these risks, our financial
condition and operations could be adversely affected if a significant event
occurs that is not fully covered by insurance.

ONE CUSTOMER CONTRACTS FOR A SUBSTANTIAL PORTION OF OUR FIRM TRANSPORTATION
CAPACITY.

     For 2002, contracts with Southern California Gas Company were substantial.
For additional information on our relationship with Southern California Gas
Company, see Part I, Item 1, Business -- Markets and Competition and Part II,
Item 8, Financial Statements and Supplementary Data, Note 12. The loss of this
customer or a decline in its credit-worthiness could adversely affect our
results of operations, financial position and cash flow.

TERRORIST ATTACKS AIMED AT OUR FACILITIES COULD ADVERSELY AFFECT OUR BUSINESS.

     On September 11, 2001, the U.S. was the target of terrorist attacks of
unprecedented scale. Since the September 11th attacks, the U.S. government has
issued warnings that energy assets, including our nation's pipeline
infrastructure, may be a future target of terrorist organizations. These
developments have subjected our operations to increased risks. Any future
terrorist attack on our facilities, those of our customers and, in some cases,
those of other pipelines, could have a material adverse effect on our business.

                 RISKS RELATED TO OUR AFFILIATION WITH EL PASO

     El Paso files reports, proxy statements and other information with the SEC
under the Securities Exchange Act of 1934, as amended. Each prospective investor
should consider this information and the matters disclosed therein in addition
to the matters described in this report. Such information is not incorporated by
reference herein.

OUR RELATIONSHIP WITH EL PASO AND ITS FINANCIAL CONDITION SUBJECTS US TO
POTENTIAL RISKS THAT ARE BEYOND OUR CONTROL.

     Due to our relationship with El Paso, adverse developments or announcements
concerning El Paso could adversely affect our financial condition, even if we
have not suffered any similar development. The outstanding senior unsecured
indebtedness of El Paso has been downgraded to below investment grade, currently
rated Caa1 by Moody's and B by Standard & Poor's (with a negative outlook at
both agencies), which in turn resulted in a similar downgrading of our
outstanding senior unsecured indebtedness to B1 by Moody's and B+ by Standard &
Poor's (with a negative outlook at both agencies). These downgrades will
increase our cost of capital and collateral requirements, and could impede our
access to capital markets. As a result of these recent downgrades, El Paso has
realized substantial demands on its liquidity, which demands have included:

     - application of cash required to be withheld from El Paso's cash
       management program in order to redeem preferred membership interests at
       one of El Paso's minority interest financing structures; and

     - cash collateral or margin requirements associated with contractual
       commitments of El Paso subsidiaries.

These downgrades may subject El Paso to additional liquidity demands in the
future. These downgrades are a result, at least in part, of the outlook
generally for the consolidated businesses of El Paso and its needs for
liquidity.
                                        12
<PAGE>

     In order to meet its short term liquidity needs, El Paso has embarked on
its 2003 Operational and Financial Plan that contemplates drawing all or part of
its availability under its existing bank facilities and consummating significant
asset sales. In addition, El Paso may take additional steps, such as entering
into other financing activities, renegotiating its credit facilities and further
reducing capital expenditures, which should provide additional liquidity. There
can be no assurance that these actions will be consummated on favorable terms,
if at all, or even if consummated, that such actions will be successful in
satisfying El Paso's liquidity needs. In the event that El Paso's liquidity
needs are not satisfied, El Paso could be forced to seek protection from its
creditors in bankruptcy. Such a development could materially adversely affect
our financial condition.

     Pursuant to El Paso's cash management program, surplus cash is made
available to El Paso in exchange for an affiliated receivable. In addition, we
conduct commercial transactions with some of our affiliates. As of December 31,
2002, we have net receivables of approximately $964 million from El Paso and its
affiliates. El Paso provides cash management and other corporate services for
us. If El Paso is unable to meet its liquidity needs, there can be no assurance
that we will be able to access cash under the cash management program, or that
our affiliates would pay their obligations to us. However, we might still be
required to satisfy affiliated company payables. Our inability to recover any
intercompany receivables owed to us could adversely affect our ability to repay
our outstanding indebtedness. For a further discussion of our related party
transactions, see Part II, Item 8, Financial Statements and Supplementary Data,
Note 11.

WE ARE JOINTLY AND SEVERALLY LIABLE FOR ALL OUTSTANDING AMOUNTS UNDER EL PASO'S
CREDIT FACILITIES.

     We are a designated borrower under El Paso's $3 billion, 364-day revolving
credit and competitive advance facility and El Paso's $1 billion, 3-year
revolving credit and competitive advance facility. As such, we are jointly and
severally liable for any amounts outstanding under these facilities. As of March
1, 2003, $1.5 billion was outstanding under the $3 billion facility and $956
million (including $456 million in letters of credit) was outstanding under the
$1 billion facility. If, for any reason, El Paso does not repay any of the
outstanding amounts under these facilities, and we are required to repay any
such amounts, our financial condition and liquidity could be materially
adversely affected.

WE COULD BE SUBSTANTIVELY CONSOLIDATED WITH EL PASO IF EL PASO WERE FORCED TO
SEEK PROTECTION FROM ITS CREDITORS IN BANKRUPTCY.

     If El Paso were the subject of voluntary or involuntary bankruptcy
proceedings, El Paso and its other subsidiaries and their creditors could
attempt to make claims against us, including claims to substantively consolidate
our assets and liabilities with those of El Paso and its other subsidiaries. The
equitable doctrine of substantive consolidation permits a bankruptcy court to
disregard the separateness of related entities and to consolidate and pool the
entities' assets and liabilities and treat them as though held and incurred by
one entity where the interrelationship between the entities warrants such
consolidation. We believe that any effort to substantively consolidate us with
El Paso and/or its other subsidiaries would be without merit. However, we cannot
assure you that El Paso and/or its other subsidiaries or their respective
creditors would not attempt to advance such claims in a bankruptcy proceeding
or, if advanced, how a bankruptcy court would resolve the issue. If a bankruptcy
court were to substantively consolidate us with El Paso and/or its other
subsidiaries, there could be a material adverse effect on our financial
condition and liquidity.

ONGOING LITIGATION AND INVESTIGATIONS REGARDING US AND EL PASO COULD
SIGNIFICANTLY ADVERSELY AFFECT OUR BUSINESS.

     On March 20, 2003, we and our affiliates entered into an agreement in
principle (the Western Energy Settlement) with various public and private
claimants, including the states of California, Washington, Oregon, and Nevada,
to resolve the principal litigation, claims, and regulatory proceedings against
us and our affiliates relating to the sale or delivery of natural gas and
electricity from September 1996 to the date of the Western Energy Settlement.
For further information on these matters, see Part II, Item 8, Financial
Statements and Supplementary Data, Notes 2 and 8. If we and our affiliates are
unable to negotiate definitive settlement

                                        13
<PAGE>

agreements, or if the settlement is not approved by the courts or the FERC, the
proceedings and litigation will continue.

     Since July 2002, twelve purported shareholder class action suits alleging
violations of federal securities laws have been filed against El Paso and
several of its officers. Eleven of these suits are now consolidated in federal
court in Houston before a single judge. The suits generally challenge the
accuracy or completeness of press releases and other public statements made
during 2001 and 2002. The twelfth shareholder class action lawsuit was filed in
federal court in New York City in October 2002 challenging the accuracy or
completeness of El Paso's February 27, 2002 prospectus for an equity offering
that was completed on June 21, 2002. It has since been dismissed, in light of
similar claims being asserted in the consolidated suits in Houston. Four
shareholder derivative actions have also been filed. One shareholder derivative
lawsuit was filed in federal court in Houston in August 2002. This derivative
action generally alleges the same claims as those made in the shareholder class
action, has been consolidated with the shareholder class actions pending in
Houston and has been stayed. A second shareholder derivative lawsuit was filed
in Delaware State Court in October 2002 and generally alleges the same claims as
those made in the consolidated shareholder class action lawsuit. A third
shareholder derivative suit was filed in state court in Houston in March 2002,
and a fourth shareholder derivative suit was filed in state court in Houston in
November 2002. The third and fourth shareholder derivative suits both generally
allege that manipulation of California gas supply and gas prices exposed El Paso
to claims of antitrust conspiracy, FERC penalties and erosion of share value. At
this time, El Paso's legal exposure related to these lawsuits and claims is not
determinable.

     Another action was filed against El Paso in December 2002, on behalf of
participants in El Paso's 401(k) plan.

     If we and El Paso do not prevail in these cases (or any of the other
litigation, administrative or regulatory matters disclosed in El Paso's 2002
Form 10-K to which El Paso, is or may be, a party), and if the remedy adopted in
these cases substantially impairs our and El Paso's financial posture, the
long-term adverse impact on our and El Paso's credit rating, liquidity and our
ability to raise capital to meet ongoing and future investing and financing
needs could be substantial.

THE PROXY CONTEST INITIATED BY SELIM ZILKHA TO REPLACE EL PASO'S BOARD OF
DIRECTORS COULD HAVE A MATERIAL ADVERSE EFFECT ON US.

     On February 18, 2003, Selim Zilkha, a stockholder of El Paso, announced his
intention to initiate a proxy solicitation to replace El Paso's entire board of
directors with his own nominees, and on March 11, 2003, Mr. Zilkha filed his
preliminary proxy statement to that effect with the SEC. This proxy contest may
be highly disruptive and may negatively impact El Paso's ability to achieve the
stated objectives of its 2003 Operational and Financial Plan. In addition, El
Paso may have difficulty attracting and retaining key personnel until such proxy
contest is resolved. Therefore, this proxy contest, whether or not successful,
could have a material adverse effect on El Paso's liquidity and financial
condition, which, in turn, could adversely affect our liquidity and financial
position.

WE ARE A WHOLLY OWNED SUBSIDIARY OF EL PASO.

     El Paso has substantial control over:

     - our payment of dividends;

     - decisions on our financings and our capital raising activities;

     - mergers or other business combinations;

     - our acquisitions or dispositions of assets; and

     - our participation in El Paso's cash management program.

     El Paso may exercise such control in its interests and not necessarily in
the interests of us or the holders of our long-term debt.

                                        14
<PAGE>

                      RISKS RELATED TO OUR LONG-TERM DEBT

OUR SUBSTANTIAL LONG-TERM DEBT COULD IMPAIR OUR FINANCIAL CONDITION AND OUR
ABILITY TO FULFILL OUR DEBT OBLIGATIONS.

     We have substantial long-term debt. As of December 31, 2002, we had total
long-term debt of approximately $960 million, all of which was senior unsecured
long-term indebtedness.

     Our substantial long-term debt could have important consequences. For
example, it could:

     - make it more difficult for us to satisfy our obligations with respect to
       our long-term debt, which could in turn result in an event of default on
       any or all of such long-term debt;

     - impair our ability to obtain additional financing in the future for
       working capital, capital expenditures, acquisitions, general corporate
       purposes or other purposes;

     - diminish our ability to withstand a downturn in our business or the
       economy generally;

     - require us to dedicate a substantial portion of our cash flow from
       operations to debt service payments, thereby reducing the availability of
       cash for working capital, capital expenditures, acquisitions, general
       corporate purposes or other purposes;

     - limit our flexibility in planning for, or reacting to, changes in our
       business and the industry in which we operate; and

     - place us at a competitive disadvantage compared to our competitors that
       have proportionately less debt.

     If we are unable to meet our debt service obligations, we could be forced
to restructure or refinance our long-term debt, seek additional equity capital
or sell assets. We may be unable to obtain financing or sell assets on
satisfactory terms, or at all.

     Covenants applicable to our long-term debt allow us to incur significant
amounts of additional indebtedness. Our incurrence of significant additional
indebtedness would exacerbate the negative consequences mentioned above, and
could adversely affect our ability to repay our long-term debt.

SOME OF OUR LONG-TERM DEBT IS SUBJECT TO CROSS-ACCELERATION PROVISIONS.

     It is an event of default in the indenture governing one issue of our
long-term debt if we default in compliance with the terms of any of our other
indebtedness with an outstanding principal amount that exceeds $25 million, and
the default results in the acceleration of such indebtedness. If this were to
occur, this issue of long-term debt would be subject to possible acceleration,
and we may not be able to repay such long-term debt upon such acceleration.

                                        15
<PAGE>

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     Our primary market risk is exposure to changing interest rates. The table
below shows the carrying value and related weighted average interest rates of
our interest bearing securities, by expected maturity dates, and the fair value
of those securities. The carrying amounts of short-term borrowings are
representative of fair values because of the short-term maturity of these
instruments. The fair values of our fixed rate long-term debt securities have
been estimated based on quoted market prices for the same or similar issues.

<Table>
<Caption>
                                               DECEMBER 31, 2002                      DECEMBER 31, 2001
                               --------------------------------------------------   ---------------------
                                        EXPECTED FISCAL YEAR OF MATURITY
                                              OF CARRYING AMOUNTS
                               --------------------------------------------------   CARRYING
                               2003   2004-2007   THEREAFTER   TOTAL   FAIR VALUE   AMOUNTS    FAIR VALUE
                               ----   ---------   ----------   -----   ----------   --------   ----------
                                                         (DOLLARS IN MILLIONS)
<S>                            <C>    <C>         <C>          <C>     <C>          <C>        <C>
LIABILITIES:
  Short-term debt -- variable
     rate....................                                                         $439        $439
       Average interest
          rate...............
  Long-term debt, including
     current portion -- fixed
     rate....................  $200       --         $758      $958       $739        $874        $891
       Average interest
          rate...............   6.8%      --          7.9%
</Table>

                                        16
<PAGE>

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                          EL PASO NATURAL GAS COMPANY

                       CONSOLIDATED STATEMENTS OF INCOME
                                 (IN MILLIONS)

<Table>
<Caption>
                                           YEAR ENDED DECEMBER 31,
                                           -----------------------
                                           2002     2001     2000
                                           -----    -----    -----
<S>                                        <C>      <C>      <C>
Operating revenues......................   $564     $572     $508
                                           ----     ----     ----
Operating expenses
  Operation and maintenance.............    173      190      189
  Merger-related costs..................     --       98       --
  Depreciation, depletion and
     amortization.......................     63       70       66
  Western Energy Settlement.............    412       --       --
  Taxes, other than income taxes........     21       28       30
                                           ----     ----     ----
                                            669      386      285
                                           ----     ----     ----
Operating income (loss).................   (105)     186      223
Other income (expense)..................      1       (2)       4
Interest and debt expense...............    (72)     (87)     (96)
Affiliated interest income..............     22       58       75
                                           ----     ----     ----
Income (loss) before income taxes.......   (154)     155      206
Income taxes............................    (55)      60       78
                                           ----     ----     ----
Net income (loss).......................   $(99)    $ 95     $128
                                           ====     ====     ====
</Table>

                            See accompanying notes.

                                        17
<PAGE>

                          EL PASO NATURAL GAS COMPANY

                          CONSOLIDATED BALANCE SHEETS
                      (IN MILLIONS, EXCEPT SHARE AMOUNTS)

<Table>
<Caption>
                                            DECEMBER 31,
                                          ----------------
                                           2002      2001
                                          ------    ------
<S>                                       <C>       <C>
                          ASSETS
Current assets
  Cash and cash equivalents.............  $    3    $   --
  Accounts and notes receivable
     Customer, net of allowance of $18
      in 2002 and $6 in 2001............      79        97
     Affiliates.........................     432     1,298
     Other..............................      13         6
  Materials and supplies................      43        39
  Deferred income taxes.................      36        --
  Other.................................      27        16
                                          ------    ------
          Total current assets..........     633     1,456
                                          ------    ------
Property, plant and equipment, at
  cost..................................   3,060     2,940
  Less accumulated depreciation,
     depletion and amortization.........   1,152     1,142
                                          ------    ------
          Total property, plant and
           equipment, net...............   1,908     1,798
                                          ------    ------
Note receivable from affiliate..........     565        --
                                          ------    ------
Other...................................      83        90
                                          ------    ------
          Total assets..................  $3,189    $3,344
                                          ======    ======

           LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities
  Accounts payable
     Trade..............................  $   43    $   54
     Affiliates.........................      33         9
     Other..............................      11         9
  Short-term borrowings (including
     current maturities of long-term
     debt)..............................     200       654
  Accrued interest......................      15        22
  Taxes payable.........................     133       117
  Contractual deposits..................      35         1
  Western Energy Settlement payable.....     100        --
  Other.................................      53        70
                                          ------    ------
          Total current liabilities.....     623       936
                                          ------    ------
Long-term debt, less current
  maturities............................     758       659
                                          ------    ------
Other liabilities
  Deferred income taxes.................     221       282
  Western Energy Settlement
     obligation.........................     312        --
  Other.................................     122       169
                                          ------    ------
                                             655       451
                                          ------    ------
Commitments and contingencies
Stockholder's equity
  Preferred stock, 8%, par value $0.01
     per share; authorized 1,000,000
     shares; issued 500,000 shares;
     stated at liquidation value........     350       350
  Common stock, par value $1 per share;
     authorized and issued 1,000
     shares.............................      --        --
  Additional paid-in capital............     715       714
  Retained earnings.....................      88       234
                                          ------    ------
          Total stockholder's equity....   1,153     1,298
                                          ------    ------
          Total liabilities and
           stockholder's equity.........  $3,189    $3,344
                                          ======    ======
</Table>

                            See accompanying notes.

                                        18
<PAGE>

                          EL PASO NATURAL GAS COMPANY

                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (IN MILLIONS)

<Table>
<Caption>
                                            YEAR ENDED DECEMBER 31,
                                          ---------------------------
                                           2002      2001      2000
                                          -------    -----    -------
<S>                                       <C>        <C>      <C>
Cash flows from operating activities
Net income (loss).......................  $   (99)   $  95    $   128
  Adjustments to reconcile net income
    (loss) to net cash from operating
    activities
    Depreciation, depletion and
       amortization.....................       63       70         66
    Western Energy Settlement...........      412       --         --
    Deferred income tax expense
       (benefit)........................     (113)      29         34
    Net gain on the sale of assets......       (1)      --         (3)
    Risk-sharing revenue................      (32)     (32)       (32)
    Non-cash portion of merger-related
       costs............................       --       92         --
    Bad debt expense....................       12        6         --
    Other non-cash income items.........        2        2          3
    Working capital changes, net of
       non-cash transactions
       Accounts receivable..............       (4)      25        (64)
       Accounts payable.................       (4)      (5)        12
       Taxes payable....................       24       17         16
       Other working capital changes
         Assets.........................        4       (6)        (7)
         Liabilities....................       14       12         (2)
    Non-working capital changes
       Assets...........................       (1)      28         18
       Liabilities......................       (8)      (9)        (9)
                                          -------    -----    -------
         Net cash provided by operating
           activities...................      269      324        160
                                          -------    -----    -------
Cash flows from investing activities
  Additions to property, plant and
    equipment...........................     (193)    (157)      (228)
  Net proceeds from the sale of
    assets..............................        9       --         36
  Net change in affiliated advances
    receivable..........................      304     (298)       344
  Other.................................       --       --          3
                                          -------    -----    -------
         Net cash provided by (used in)
           investing activities.........      120     (455)       155
                                          -------    -----    -------
Cash flows from financing activities
  Net borrowings (repayments) of
    commercial paper....................     (439)     159       (287)
  Payments to retire long-term debt.....     (215)      --         --
  Net proceeds from the issuance of
    long-term debt......................      296       --         --
  Dividends paid........................      (28)     (28)       (28)
                                          -------    -----    -------
         Net cash provided by (used in)
           financing activities.........     (386)     131       (315)
                                          -------    -----    -------
Increase in cash and cash equivalents...        3       --         --
Cash and cash equivalents
  Beginning of period...................       --       --         --
                                          -------    -----    -------
  End of period.........................  $     3    $  --    $    --
                                          =======    =====    =======
</Table>

                            See accompanying notes.

                                        19
<PAGE>

                          EL PASO NATURAL GAS COMPANY

                CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
                      (IN MILLIONS, EXCEPT SHARE AMOUNTS)

<Table>
<Caption>
                                        8%        COMMON STOCK     ADDITIONAL                  TOTAL
                                     PREFERRED   ---------------    PAID-IN     RETAINED   STOCKHOLDER'S
                                       STOCK     SHARES   AMOUNT    CAPITAL     EARNINGS      EQUITY
                                     ---------   ------   ------   ----------   --------   -------------
<S>                                  <C>         <C>      <C>      <C>          <C>        <C>
January 1, 2000....................    $350      1,000     $ --       $700        $ 76        $1,126
  Net income.......................                                                128           128
  Preferred stock dividends........                                                (28)          (28)
  Allocated tax benefit of El Paso
     equity plans..................                                      5                         5
  Non-cash capital contributions
     from El Paso..................                                      5                         5
  Dividends........................                                                 (9)           (9)
                                       ----      -----     ----       ----        ----        ------
December 31, 2000..................     350      1,000       --        710         167         1,227
  Net income.......................                                                 95            95
  Preferred stock dividends........                                                (28)          (28)
  Allocated tax benefit of El Paso
     equity plans..................                                      4                         4
                                       ----      -----     ----       ----        ----        ------
December 31, 2001..................     350      1,000       --        714         234         1,298
  Net loss.........................                                                (99)          (99)
  Preferred stock dividends........                                                (28)          (28)
  Allocated tax benefit of El Paso
     equity plans..................                                      1                         1
  Dividends........................                                                (19)          (19)
                                       ----      -----     ----       ----        ----        ------
December 31, 2002..................    $350      1,000     $ --       $715        $ 88        $1,153
                                       ====      =====     ====       ====        ====        ======
</Table>

                            See accompanying notes.

                                        20
<PAGE>

                          EL PASO NATURAL GAS COMPANY

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

  Basis of Presentation and Principles of Consolidation

     Our consolidated financial statements include the accounts of all
majority-owned, controlled subsidiaries after the elimination of all significant
intercompany accounts and transactions. We consolidate entities when we have the
ability to control the operating and financial decisions and policies of that
entity. Our financial statements for prior periods include reclassifications
that were made to conform to the current year presentation. Those
reclassifications had no impact on reported net income or stockholder's equity.

  Use of Estimates

     The preparation of financial statements in conformity with U.S. generally
accepted accounting principles (GAAP) requires the use of estimates and
assumptions that affect the amounts we report as assets, liabilities, revenues
and expenses and our disclosures in these financial statements. Actual results
can, and often do, differ from those estimates.

  Accounting for Regulated Operations

     Our natural gas systems are subject to the jurisdiction of FERC in
accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of
1978, and we apply the provisions of SFAS No. 71, Accounting for the Effects of
Certain Types of Regulation. Accounting requirements for regulated businesses
can differ from the accounting requirements for non-regulated businesses.
Transactions that have been recorded differently as a result of regulatory
accounting requirements include the capitalization of an equity return component
on regulated capital projects, employee related benefits and other costs and
taxes included in, or expected to be included in, future rates.

     Our application of SFAS No. 71 is based on the current regulatory
environment, our current tariff rates and our ability to collect those rates.
Future regulatory developments and rate cases could impact this accounting.
Although discounting of our maximum tariff rates does occur, we believe the
standards required by SFAS No. 71 for its application are met and the continued
use of regulatory accounting under SFAS No. 71 best reflects the results of
operations in the economic environment in which we currently operate. Regulatory
accounting requires us to record assets and liabilities that result from the
rate-making process that would not be recorded under GAAP for non-regulated
entities. We will continue to evaluate the application of regulatory accounting
principles based on on-going changes in the regulatory and economic environment.
Items that may influence our assessment are:

     - inability to recover cost increases due to rate caps and rate case
       moratoriums;

     - inability to recover capitalized costs, including an adequate return on
       those costs through the rate-making process and FERC proceedings;

     - excess capacity;

     - increased competition and discounting in the markets we serve; and

     - impacts of ongoing regulatory initiatives in the natural gas industry.

  Cash and Cash Equivalents

     We consider short-term investments with an original maturity of less than
three months to be cash equivalents.

                                        21
<PAGE>

  Allowance for Doubtful Accounts

     We establish provisions for losses on accounts receivable and for natural
gas imbalances due from shippers and operators if we determine that we will not
collect all or part of the outstanding balance. We regularly review
collectibility and establish or adjust our allowance as necessary using the
specific identification method.

  Materials and Supplies

     We value materials and supplies at the lower of cost or market value with
cost determined using the average cost method.

  Natural Gas Imbalances

     Natural gas imbalances occur when the actual amount of natural gas
delivered from or received by a pipeline system differs from the contractual
amount scheduled to be delivered or received. We value these imbalances due to
or from shippers and operators at the end of year actual or appropriate market
index price. Imbalances are settled in cash or made up in kind, subject to the
contractual terms of settlement.

     Imbalances due from others are reported in our balance sheet as either
accounts receivable from customers or accounts receivable from affiliates.
Imbalances owed to others are reported on the balance sheet as either trade
accounts payable or accounts payable to affiliates. In addition, all imbalances
are classified as current.

  Property, Plant and Equipment

     Our property, plant and equipment is recorded at its original cost of
construction or, upon acquisition, at either the fair value of the assets
acquired or the cost to the entity that first placed the asset in service. We
capitalize direct costs, such as labor and materials, and indirect costs, such
as overhead and an allowance for funds used during construction for our
regulated business as allowed by FERC. We capitalize the major units of property
replacements or improvements and expense minor items. Included in our pipeline
property balances are additional acquisition costs which represent the excess
purchase costs associated with purchase business combinations allocated to our
regulated interstate systems. These costs are amortized on a straight-line basis
over 36 years, and we do not recover these excess costs in our rates. As of
December 31, 2002, we had unamortized additional acquisition costs of $71
million net of accumulated amortization of $80 million.

     We use the composite (group) method to depreciate regulated property, plant
and equipment. Under this method, assets with similar lives and other
characteristics are grouped and depreciated as one asset. For aircraft, we apply
the depreciation rates to the total cost of the group until its net book value
equals its salvage value. For all other property, plant and equipment we
depreciate the asset to zero. Currently, our depreciation rates vary from 2 to
33 percent. Using these rates, the average remaining depreciable lives of these
assets range from 2 to 39 years. We re-evaluate depreciation rates each time we
redevelop our transportation rates when we file with the FERC for an increase or
decrease in rates.

     When we retire regulated property, plant and equipment, we charge
accumulated depreciation and amortization for the original cost, plus the cost
to remove, sell or dispose, less its salvage value. We do not recognize a gain
or loss unless we sell an entire operating unit. We include gains or losses on
dispositions of operating units in income. On non-regulated property, plant and
equipment, we record a gain or loss in income for the difference between the net
book value relative to proceeds received, if any, when the asset is sold or
retired.

     At December 31, 2002 and 2001, we had approximately $146 million and $262
million of construction work in progress included in our property, plant and
equipment. In addition, during 2002, 2001 and 2000, we had capitalized an
allowance for funds used during construction of $6 million, $9 million and $8
million.

                                        22
<PAGE>

  Asset Impairments

     We apply the provisions of SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets to account for asset impairments. Under this
standard, we evaluate an asset for impairment when events or circumstances
indicate that a long-lived asset's carrying value may not be recovered. These
events include market declines, changes in the manner in which we intend to use
an asset or decisions to sell an asset and adverse changes in the legal or
business environment such as adverse actions by regulators. At the time we
decide to exit an activity or sell a long-lived asset or group of assets, we
adjust the carrying value of those assets downward, if necessary, to the
estimated sales price, less costs to sell. We also classify these asset or
assets as either held for sale or as discontinued operations, depending on
whether the asset or assets have independently determinable cash flows.

  Revenue Recognition

     Our revenues consist primarily of demand and throughput-based
transportation services. We recognize demand revenues on firm contracted
capacity monthly over the contract period regardless of the amount of capacity
that is actually used. For throughput-based services, we record revenues when we
complete the delivery of natural gas to the agreed upon delivery point. Revenues
are generally based on the thermal quantity of gas delivered or subscribed at a
price specified in the contract or tariff. We are subject to FERC regulations
and, as a result, revenues we collect may be refunded in a final order of a
pending rate proceeding or as a result of a rate settlement. We establish
reserves for these potential refunds.

     We also record risk sharing revenues related to our most recent rate
settlement. The majority of the risk sharing amounts were collected in advance
from our customers. These collections were initially deferred and are then
amortized over the risk sharing period as specified in our tariff. See Note 8
for a further discussion of our rate settlement and these risk sharing
provisions.

  Environmental Costs and Other Contingencies

     We record liabilities when our environmental assessments indicate that
remediation efforts are probable, and the costs can be reasonably estimated. We
recognize a current period expense when clean-up efforts do not benefit future
periods. We capitalize costs that benefit more than one accounting period,
except in instances where separate agreements or legal and regulatory guidelines
dictate otherwise. Estimates of our liabilities are based on currently available
facts, existing technology and presently enacted laws and regulations taking
into account the likely effects of inflation and other societal and economic
factors, and include estimates of associated legal costs. These amounts also
consider prior experience in remediating contaminated sites, other companies'
clean-up experience and data released by the Environmental Protection Agency
(EPA) or other organizations. These estimates are subject to revision in future
periods based on actual costs or new circumstances and are included in our
balance sheet in other current and long-term liabilities at their undiscounted
amounts. We evaluate recoveries from insurance coverage, rate recovery,
government sponsored and other programs separately from our liability and, when
recovery is assured, we record and report an asset separately from the
associated liability in our financial statements.

     We recognize liabilities for other contingencies when we have an exposure
that, when fully analyzed, indicates it is both probable that an asset has been
impaired or that a liability has been incurred and the amount of impairment or
loss can be reasonably estimated. Funds spent to remedy these contingencies are
charged against a reserve, if one exists, or expensed. When a range of probable
loss can be estimated, we accrue the most likely amount, or at least the minimum
of the range of probable loss.

  Income Taxes

     We report current income taxes based on our taxable income and we provide
for deferred income taxes to reflect estimated future tax payments or receipts.
Deferred taxes represent the tax impacts of differences between the financial
statement and tax bases of assets and liabilities and carryovers at each year
end. We account for tax credits under the flow-through method, which reduces the
provision for income taxes in the year the tax credits first become available.
We reduce deferred tax assets by a valuation allowance when, based
                                        23
<PAGE>

on our estimates, it is more likely than not that a portion of those assets will
not be realized in a future period. The estimates utilized in the recognition of
deferred tax assets are subject to revision, either up or down, in future
periods based on new facts or circumstances.

     El Paso maintains a tax accrual policy to record both regular and
alternative minimum taxes for companies included in its consolidated federal
income tax return. The policy provides, among other things, that (i) each
company in a taxable income position will accrue a current expense equivalent to
its federal income tax, and (ii) each company in a tax loss position will accrue
a benefit to the extent its deductions, including general business credits, can
be utilized in the consolidated return. El Paso pays all federal income taxes
directly to the IRS and, under a separate tax billing agreement, El Paso may
bill or refund its subsidiaries for their portion of these income tax payments.

  New Accounting Pronouncements Issued Not Yet Adopted

     As of December 31, 2002, there were a number of accounting standards and
interpretations that had been issued, but not yet adopted by us. Below is a
discussion of the more significant standards that could impact us.

     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.

     Accounting for Guarantees. In November 2002, the FASB issued FIN No. 45,
Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others. This interpretation requires that
companies record a liability for all guarantees issued after January 31, 2003,
including financial, performance, and fair value guarantees. This liability is
recorded at its fair value upon issuance, and does not affect any existing
guarantees issued before January 31, 2003. This standard also requires expanded
disclosures on all existing guarantees at December 31, 2002. We have included
these required disclosures in Notes 7 and 8.

2. WESTERN ENERGY SETTLEMENT

     On March 20, 2003, we and our affiliates entered into an agreement in
principle (the Western Energy Settlement) with various public and private
claimants, including the states of California, Washington, Oregon and Nevada, to
resolve the principal litigation, claims and regulatory proceedings against us
and our affiliates relating to the sale or delivery of natural gas and
electricity from September 1996 to the date of the Western Energy Settlement.
See Note 8 for a discussion of this matter.

     The portion of the Western Energy Settlement allocated to us by El Paso
resulted in a one-time charge in the fourth quarter of 2002 of $412 million
before tax and approximately $262 million after tax. These amounts represent the
present value of the components of the settlement discounted at 10 percent. The
settlement will become payable beginning with the execution of a definitive
settlement agreement. Components of the settlement were allocated to us, our
parent and our affiliate, El Paso Merchant Energy, based on the nature of the
component and our individual ability to perform under the agreement. The
components that were allocated to us are as follows:

     - a cash payment of $100 million;

     - the delivery of approximately 26.4 million shares of El Paso's common
       stock valued at $125 million;

     - payments of $22 million per year for 20 years.

     - for a period of five years, our EPNG system will make available at its
       California delivery points, 3,290 MMcf/d of capacity on a primary
       delivery point basis; and

                                        24
<PAGE>

     - no admission of wrong doing.

     The settlement is subject to review and approval by state courts and the
FERC.

     Our obligation for the settlement is reflected in our balance sheet at $412
million, which represents the notional amount of approximately $665 million,
less a discount (at a rate of 10 percent) of approximately $253 million. The
components of the obligation for the settlement are as follows (in millions):

<Table>
<S>                                                           <C>
Our portion of the Western Energy Settlement................     $  665
Discount at 10 percent......................................       (253)
                                                                 ------
Net present value of settlement.............................        412
Less: Current portion of obligation.........................        100
                                                                 ------
Non-current obligation for Western Energy Settlement........     $  312
                                                                 ======
</Table>

     The discount will be amortized to interest expense annually at an amount
based on a constant rate of interest (10 percent) applied to the declining
obligation balance. This amortization is expected to be approximately $12
million for 2003, after income taxes.

3. MERGER-RELATED COSTS

     During the year ended December 31, 2001, we incurred merger-related costs
of $98 million associated with El Paso Corporation's (El Paso) 2001 merger with
The Coastal Corporation and the relocation of our headquarters from El Paso,
Texas to Colorado Springs, Colorado. Our merger-related costs include employee
severance, retention and transition costs for severed employees totaling $6
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 December 31, 2002, we have paid
$29 million of the accrual leaving a balance of $63 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.

4. INCOME TAXES

     The following table reflects the components of income taxes included in net
income for each of the three years ended December 31:

<Table>
<Caption>
                                                              2002      2001     2000
                                                              -----     ----     ----
                                                                   (IN MILLIONS)
<S>                                                           <C>       <C>      <C>
Current
  Federal...................................................  $  52     $25      $37
  State.....................................................      6       6        7
                                                              -----     ---      ---
                                                                 58      31       44
                                                              -----     ---      ---
Deferred
  Federal...................................................   (105)     27       36
  State.....................................................     (8)      2       (2)
                                                              -----     ---      ---
                                                               (113)     29       34
                                                              -----     ---      ---
          Total income taxes................................  $ (55)    $60      $78
                                                              =====     ===      ===
</Table>

                                        25
<PAGE>

     Our income taxes included in net income differ from the amount computed by
applying the statutory federal income tax rate of 35 percent for the following
reasons for each of the three years ended December 31:

<Table>
<Caption>
                                                              2002     2001     2000
                                                              ----     ----     ----
                                                                  (IN MILLIONS)
<S>                                                           <C>      <C>      <C>
Income taxes at the statutory federal rate of 35%...........  $(54)    $54      $72
Items creating rate differences:
  State income tax, net of federal income tax benefit.......    (1)      5        3
  Other.....................................................    --       1        3
                                                              ----     ---      ---
Income taxes................................................  $(55)    $60      $78
                                                              ====     ===      ===
Effective tax rate..........................................    36%     38%      38%
                                                              ====     ===      ===
</Table>

     The following are the components of our net deferred tax liability as of
December 31:

<Table>
<Caption>
                                                              2002     2001
                                                              -----    -----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
Deferred tax liabilities
  Property, plant and equipment.............................  $337     $284
  Employee benefits and deferred compensation obligations...    21       27
  Regulatory and other assets...............................    91       86
                                                              ----     ----
          Total deferred tax liability......................   449      397
                                                              ----     ----
Deferred tax assets
  Western Energy Settlement.................................   150       --
  U.S. net operating loss and tax credit carryovers.........    17       20
  Other liabilities.........................................    97       79
                                                              ----     ----
          Total deferred tax asset..........................   264       99
                                                              ----     ----
Net deferred tax liability..................................  $185     $298
                                                              ====     ====
</Table>

     Under El Paso's tax accrual policy, we are allocated the tax benefit
associated with our employees' exercise of non-qualified stock options and the
vesting of restricted stock as well as restricted stock dividends. This
allocation reduced taxes payable by $1 million in 2002, $4 million in 2001 and
$5 million in 2000. These benefits are included in additional paid-in capital in
our balance sheet.

     As of December 31, 2002, we had approximately $17 million of alternative
minimum tax credits and $1 million of net operating loss carryovers available to
offset future regular tax liabilities. The alternative minimum tax credits
carryover indefinitely. The net operating loss carryover period ends in 2021.
Usage of these carryovers is subject to the limitations provided under Sections
382 and 383 of the Internal Revenue Code as well as the separate return
limitation year rules of IRS regulations.

5. FINANCIAL INSTRUMENTS

  Fair Value of Financial Instruments

     As of December 31, 2002 and 2001, the carrying amounts of cash and cash
equivalents, short-term borrowings, and trade receivables and payables are
representative of fair value because of the short-term maturity of these
instruments. The carrying amounts and estimated fair values of our financial
instruments are as follows at December 31:

<Table>
<Caption>
                                                               2002                     2001
                                                       ---------------------    ---------------------
                                                       CARRYING                 CARRYING
                                                        AMOUNT    FAIR VALUE     AMOUNT    FAIR VALUE
                                                       --------   ----------    --------   ----------
                                                                       (IN MILLIONS)
<S>                                                    <C>        <C>           <C>        <C>
     Balance sheet financial instruments:
       Long-term debt, including current
          maturities(1)..............................    $958        $739         $874        $891
</Table>

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

(1) We estimated the fair value of debt with fixed interest rates based on
    quoted market prices for the same or similar issues.
                                        26
<PAGE>

6. REGULATORY ASSETS AND LIABILITIES

     Our non-current regulatory assets and liabilities are included in other
non-current assets and liabilities in our balance sheet. Below are the details
of our regulatory assets and liabilities at December 31:

<Table>
<Caption>
                                                                        REMAINING AVERAGE
                  DESCRIPTION                       2002      2001       RECOVERY PERIOD
                  -----------                       ----      ----      -----------------
                                                    (IN MILLIONS)
<S>                                                 <C>       <C>       <C>
Non-Current Regulatory Assets
  Unamortized loss on reacquired debt...........    $25        27           19 years
  Grossed-up deferred taxes on capitalized
     funds......................................     14        15           11 years
  Retiree medical...............................      9         9            N/A(1)
  Under-collected state income taxes............      5         6            3 years
  Other.........................................     --         1              N/A
                                                    ---       ---
          Total regulatory assets...............    $53       $58
                                                    ===       ===
Non-Current Regulatory Liabilities
  Property and plant depreciation...............    $22       $24            various
  Excess deferred federal income taxes..........      5         5            3 years
                                                    ---       ---
          Total regulatory liabilities..........    $27       $29
                                                    ===       ===
</Table>

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

(1) Amount to be recovered in future rate proceedings.

7. DEBT AND OTHER CREDIT FACILITIES

     We had the following short-term borrowings including current maturities of
long-term debt at December 31:

<Table>
<Caption>
                                                              2002     2001
                                                              -----    -----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
Commercial paper(1).........................................  $ --     $439
Current maturities of long-term debt........................   200      215
                                                              ----     ----
                                                              $200     $654
                                                              ====     ====
</Table>

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

(1) At December 31, 2001, our weighted average interest rate on our commercial
    paper was 3.3%.

     Our long-term debt outstanding consisted of the following at December 31:

<Table>
<Caption>
                                                              2002     2001
                                                              ----     ----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
     7.75% Notes due 2002...................................  $ --     $215
     6.75% Notes due 2003...................................   200      200
     8.625% Debentures due 2022.............................   260      260
     7.50% Debentures due 2026..............................   200      200
     8.375% Notes due 2032..................................   300       --
                                                              ----     ----
                                                               960      875
  Less: Unamortized discount................................     2        1
       Current maturities...................................   200      215
                                                              ----     ----
          Total long-term debt, less current maturities.....  $758     $659
                                                              ====     ====
</Table>

     In January 2002, we retired $215 million aggregate principal amount of
7.75% notes due 2002. In June 2002, we issued $300 million aggregate principal
amount 8.375% notes due 2032 in a private placement. Proceeds were approximately
$296 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

                                        27
<PAGE>

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.

     Aggregate maturities of the principal amounts of long-term debt for the
next 5 years and in total thereafter are as follows:

<Table>
<Caption>
YEAR                                                          (IN MILLIONS)
----                                                          -------------
<S>                                                           <C>
2003........................................................      $200
2004........................................................        --
2005........................................................        --
2006........................................................        --
2007........................................................        --
Thereafter..................................................       760
                                                                  ----
          Total long-term debt, including current
           maturities.......................................      $960
                                                                  ====
</Table>

     We have indentures with cross-acceleration provisions that, if triggered,
could result in the acceleration of our long-term debt.

  Other Financing Arrangements

     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 jointly and severally liable for any amounts outstanding under
this facility. This facility matures in May 2003 and provides that amounts
outstanding on that date are not due until May 2004. In June 2002, El Paso
amended its existing $1 billion, 3-year revolving credit and competitive advance
facility to permit it 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 jointly and severally
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 December 31, 2002, an initial draw would have had a rate of LIBOR plus
1.0%, and a 0.25% utilization fee for drawn amounts above 25% of the committed
amounts. As of December 31, 2002, $1.5 billion was outstanding under the $3
billion facility, and $456 million in letters of credit were issued under the $1
billion facility. In February 2003, an additional draw of $500 million was made
under the revolver.

     As a result of El Paso's credit ratings being downgraded to below
investment grade status, cash generated by Mojave, our indirect wholly owned
subsidiary, can be used only for Mojave's operating and maintenance needs and
for purposes of redeeming the preferred interests of Trinity River, an El Paso
financing arrangement that Mojave and other El Paso affiliates collateralize.
Until the preferred interests were redeemed in full, Mojave was required to
distribute a portion of its cash-based earnings to its parent Sabine River
Investors V, L.L.C. and was no longer able to provide excess cash to El Paso's
cash management program. On January 8, 2003, Mojave, through its parent, paid
approximately $3 million under this provision to the preferred interest members
of Trinity River. In March 2003, El Paso entered into a $1.2 billion 2-year term
loan and the proceeds were used to retire the outstanding balance under the
Trinity River financing agreement.

8. COMMITMENTS AND CONTINGENCIES

  Legal Proceedings

     Western Energy Settlement.  On March 20, 2003, we and our affiliates
entered into an agreement in principle (the Western Energy Settlement) with
various public and private claimants, including the states of California,
Washington, Oregon, and Nevada, to resolve the principal litigation, claims, and
regulatory proceedings, which are more fully described below, against us and our
affiliates relating to the sale or delivery

                                        28
<PAGE>

of natural gas and electricity from September 1996 to the date of the Western
Energy Settlement. Among other things, the components of the settlement include:

     - a cash payment of $100 million;

     - a $2 million cash payment from El Paso's officer bonus pool;

     - the issuance of approximately 26.4 million shares of El Paso common
       stock;

     - delivery to the California border by our affiliate of $45 million worth
       of natural gas annually for 20 years beginning in 2004;

     - a reduction of the pricing of our affiliate's long-term power supply
       contracts with the California Department of Water Resources of $125
       million over the remaining term of those contracts, which run through the
       end of 2005;

     - payments of $22 million per year for 20 years;

     - for a period of five years, EPNG will make available at its California
       delivery points 3,290 MMcf per day of capacity on a primary delivery
       point basis;

     - for a period of five years, our affiliates will be subject to
       restrictions in subscribing for new capacity on the EPNG system; and

     - no admission of wrongdoing.

The Western Energy Settlement will result in an after-tax charge to us of
approximately $262 million in the fourth quarter of 2002 for the component of
the settlement allocated to us.

     The agreement in principle is subject to the negotiation of a formal
settlement agreement, portions of which will then be filed with the courts and
the FERC for approval. Upon approval, the parties will release us from covered
claims that they may have against us and our affiliates for the period covered
by the Western Energy Settlement, and the litigation, claims, and regulatory
proceedings against us and our affiliates will be dismissed with prejudice.

     California Lawsuits.  We have been named as a defendant in fifteen
purported class action, municipal or individual lawsuits, filed in California
state courts. These suits contend that we acted improperly to limit the
construction of new pipeline capacity to California and/or to manipulate the
price of natural gas sold into the California marketplace. Specifically, the
plaintiffs argue that our conduct violates California's antitrust statute
(Cartwright Act), constitutes unfair and unlawful business practices prohibited
by California statutes, and amounts to a violation of California's common law
restrictions against monopolization. In general, the plaintiffs are seeking (i)
declaratory and injunctive relief regarding allegedly anticompetitive actions,
(ii) restitution, including treble damages, (iii) disgorgement of profits, (iv)
prejudgment and postjudgment interest, (v) costs of prosecuting the actions and
(vi) attorney's fees. All fifteen cases have been consolidated before a single
judge, under two omnibus complaints, one of which has been set for trial in
September 2003. All of the class action lawsuits and all but one of the
individual lawsuits will be resolved upon finalization and approval of the
Western Energy Settlement.

     The California cases discussed above are five filed in the Superior Court
of Los Angeles County (Continental Forge Company, et al v. Southern California
Gas Company, et al, filed September 25, 2000*; Berg v. Southern California Gas
Company, et al, filed December 18, 2000*; County of Los Angeles v. Southern
California Gas Company, et al, filed January 8, 2002*; The City of Los Angeles,
et al v. Southern California Gas Company, et al and The City of Long Beach, et
al v. Southern California Gas Company, et al, both filed March 20, 2001*); two
filed in the Superior Court of San Diego County (John W.H.K. Phillip v. El Paso
Merchant Energy; and John Phillip v. El Paso Merchant Energy, both filed
December 13, 2000*); and two filed in the Superior Court of San Francisco County
(Sweetie's et al v. El Paso Corporation, et al, filed March 22, 2001*; and
California Dairies, Inc., et al v. El Paso Corporation, et al, filed May 21,
2001);

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

* Cases to be dismissed upon finalization and approval of the Western Energy
  Settlement.
                                        29
<PAGE>

and one filed in the Superior Court of the State of California, County of
Alameda (Dry Creek Corporation v. El Paso Natural Gas Company, et al filed
December 10, 2001*); and five filed in the Superior Court of Los Angeles County
(The City of San Bernardino v. Southern California Gas Company, et al; The City
of Vernon v. Southern California Gas Company; The City of Upland v. Southern
California Gas Company, et al; Edgington Oil Company v. Southern California Gas
Company, et al; World Oil Corp. v. Southern California Gas Company, et al, filed
December 27, 2002*).

     In November 2002, a lawsuit titled Gus M. Bustamante v. The McGraw-Hill
Companies was filed in the Superior Court of California, County of Los Angeles
by several individuals, including Lt. Governor Bustamante acting as a private
citizen, against numerous defendants, including us, alleging the creation of
artificially high natural gas index prices via the reporting of false price and
volume information. This purported class action on behalf of California
consumers alleges various unfair business practices and seeks restitution,
disgorgement of profits, compensatory and punitive damages, and civil fines.
This lawsuit will be resolved upon finalization and approval of the Western
Energy Settlement.

     In January 2003, a lawsuit titled IMC Chemicals v. EPME, et al. was filed
in California state court against us, El Paso and EPME. The suit arises out of a
gas supply contract between IMC Chemicals (IMCC) and EPME and seeks to void the
Gas Purchase Agreement between IMCC and EPME for gas purchases until December
2003. IMCC contends that EPME and its affiliates manipulated market prices for
natural gas and, as part of that manipulation, induced IMCC to enter into the
contract. In furtherance of its attempt to void the contract, IMCC repeats the
allegations and claims of the California lawsuits described above. EPME intends
to enforce the terms of the contract and counterclaim for contract damages. Our
costs and legal exposure related to these lawsuits and claims are not currently
determinable.

     In September 2001, we received a civil document subpoena from the
California Attorney General, seeking information said to be relevant to the
Department's ongoing investigation into the high electricity prices in
California. We are continuing to cooperate in responding to their discovery
requests. This proceeding will be resolved upon finalization and approval of the
Western Energy Settlement.

     Other Energy Market Lawsuits.  The state of Nevada and two individuals
filed a class action lawsuit in Nevada state court naming us and a number of our
affiliates as defendants. The allegations are similar to those in the California
cases. The suit seeks monetary damages and other relief under Nevada antitrust
and consumer protection laws. This proceeding will be resolved upon finalization
and approval of the Western Energy Settlement.

     A purported class action suit titled Henry W. Perlman et. al. v. Southern
California Gas Company, San Diego Gas & Electric; Sempra Energy, El Paso
Corporation, El Paso Natural Gas Company and El Paso Merchant Energy, L.P. was
filed in federal court in New York City in December 2002 alleging that the
defendants manipulated California's natural gas market by manipulating the spot
market of gas traded on the NYMEX. We have not yet been served with the
complaint. Our costs and legal exposure related to this lawsuit are not
currently determinable.

     In March 2003, the State of Arizona sued us, our affiliates and other
unrelated entities on behalf of Arizona consumers. The suit alleges that the
defendants conspired to artificially inflate prices of natural gas and
electricity during 2000 and 2001. Making factual allegations similar to those
alleged in the California cases, the suit seeks relief similar to the California
cases as well, but under Arizona antitrust and consumer fraud statutes. Our
costs and legal exposure related to these lawsuits and claims are not currently
determinable.

     Shareholder Class Action Suit.  In November 2002, we were named as a
defendant in a shareholder derivative suit titled Marilyn Clark v. Byron
Allumbaugh, David A. Arledge, John M. Bissell, Juan Carlos Braniff, James F.
Gibbons, Anthony W. Hall, Ronald L. Kuehn, J. Carleton MacNeil, Thomas McDade,
Malcolm Wallop, William Wise, Joe B. Wyatt, El Paso Natural Gas Company and El
Paso Merchant Energy Company filed in state court in Houston. This shareholder
derivative suit generally alleges that manipulation of California gas supply and
gas prices exposed our parent, El Paso, to claims of antitrust conspiracy, FERC

                                        30
<PAGE>

penalties and erosion of share value. The plaintiffs have not asked for any
relief with regards to us. Our costs and legal exposure related to this
proceeding are not currently determinable.

     Carlsbad.  In August 2000, a main transmission line owned and operated by
us ruptured at the crossing of the Pecos River near Carlsbad, New Mexico. Twelve
individuals at the site were fatally injured. On June 20, 2001, the U.S.
Department of Transportation's Office of Pipeline Safety issued a Notice of
Probable Violation and Proposed Civil Penalty to us. The Notice alleged five
violations of DOT regulations, proposed fines totaling $2.5 million and proposed
corrective actions. We have fully accrued for these fines. The alleged five
probable violations of the regulations of the Department of Transportation's
Office of Pipeline Safety are: (1) failure to develop an adequate internal
corrosion control program, with an associated proposed fine of $500,000; (2)
failure to investigate and minimize internal corrosion, with an associated
proposed fine of $1,000,000; (3) failure to conduct continuing surveillance on
our pipeline and consider, and respond appropriately to, unusual operating and
maintenance conditions, with an associated proposed fine of $500,000; (4)
failure to follow company procedures relating to investigating pipeline failures
and thereby to minimize the chance of recurrence, with an associated proposed
fine of $500,000; and (5) failure to maintain elevation profile drawings, with
an associated proposed fine of $25,000. On October 2001, we filed a response
with the Office of Pipeline Safety disputing each of the alleged violations. If
we are required to pay the proposed fines, it will not have a material adverse
effect on our financial position, operations results or cash flows.

     On February 11, 2003, the National Transportation Safety Board conducted a
public meeting on its investigation of the Carlsbad rupture at which the NTSB
adopted Findings, Conclusions and Recommendation based upon its investigation.
In a synopsis of the Safety Board's report, the NTSB stated that it had
determined that the probable cause of the August 19, 2000 rupture was a
significant reduction in pipe wall thickness due to severe internal corrosion,
which occurred because our corrosion control program "failed to prevent, detect,
or control internal corrosion" in the pipeline. The NTSB also determined that
ineffective federal preaccident inspections contributed to the accident by not
identifying deficiencies in our internal corrosion control program. The NTSB's
final report is pending.

     On November 1, 2002, we received a federal grand jury subpoena for
documents relating to the rupture and we are cooperating fully with the grand
jury.

     A number of personal injury and wrongful death lawsuits were filed against
us in connection with the rupture. All but one of these suits have been settled,
with settlement payments 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 contributed $10
million to a charitable foundation as a memorial to the families involved. The
contribution was not covered by insurance.

     Parties to five settled lawsuits have since filed an additional lawsuit
titled Diane Heady et al. v. EPEC and EPNG in Harris County, Texas on November
20, 2002 seeking an additional $180 million based upon their interpretation of
earlier agreements. In addition, plaintiffs' counsel for the settled New Mexico
state court cases have notified us that they intend to file suit on behalf of
about twenty-three firemen and EMS personnel who responded to the fire and who
allegedly have suffered psychological trauma. We have not been served with such
a lawsuit. Our costs and legal exposure related to these lawsuits and claims are
currently not determinable. However, we believe these matters will be fully
covered by insurance.

     Grynberg.  In 1997, we and a number of our affiliates were named defendants
in actions brought by Jack Grynberg on behalf of the U.S. Government under the
False Claims Act. Generally, these complaints allege an industry-wide conspiracy
to underreport the heating value as well as the volumes of the natural gas
produced from federal and Native American lands, which deprived the U.S.
Government of royalties. The plaintiff in this case seeks royalties that he
contends the government should have received had the volume and heating value of
natural gas produced from royalty properties been differently measured,
analyzed, calculated and reported, together with interest, treble damages, civil
penalties, expenses and future injunctive relief to require the defendants to
adopt allegedly appropriate gas measurement practices. No monetary relief has
been specified in this case. These matters have been consolidated for pretrial
purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court
for the District of Wyoming, filed June 1997). In May

                                        31
<PAGE>

2001, the court denied the defendants' motions to dismiss. Discovery is
proceeding. Our costs and legal exposure related to these lawsuits and claims
are currently not determinable.

     Will Price (formerly Quinque).  We and a number of our affiliates were
named defendants in Quinque Operating Company et al v. Gas Pipelines and Their
Predecessors, et al, filed in 1999 in the District Court of Stevens County,
Kansas. Quinque has been dropped as a plaintiff and Will Price has been added.
This class action complaint alleges that the defendants mismeasured natural gas
volumes and heating content of natural gas on non-federal and non-Native
American lands. The plaintiff in this case seeks certification of a nationwide
class of natural gas working interest owners and natural gas royalty owners to
recover royalties that the plaintiff contends these owners should have received
had the volume and heating value of natural gas produced from their properties
been differently measured, analyzed, calculated and reported, together with
prejudgment and postjudgment interest, punitive damages, treble damages,
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. Plaintiff's motion for class
certification has been argued and we are awaiting a ruling. Our costs and legal
exposure related to these lawsuits and claims are currently not determinable.

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

     For each of our outstanding legal matters, we evaluate the merits of the
case, our exposure in the matter, possible legal or settlement strategies and
the likelihood of an unfavorable outcome. If we determine that an unfavorable
outcome is probable and can be estimated, we establish the necessary accruals.
As of December 31, 2002, we had accrued approximately $415 million for all
outstanding legal matters.

  Environmental Matters

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

     In addition, we expect to make capital expenditures for environmental
matters of approximately $4 million in the aggregate for the years 2003 through
2007. These expenditures primarily relate to compliance with clean air
regulations. For 2003, we estimate that our total remediation expenditures will
be approximately $7 million, which primarily will be expended under government
directed clean-up plans.

     CERCLA Matters.  We have received notice that we could be designated, or
have been asked for information to determine whether we could be designated, as
a Potentially Responsible Party (PRP) with respect to four active sites under
the Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA) or state equivalents. We have sought to resolve our liability as a PRP
at these sites through indemnification by third parties and settlements which
provide for payment of our allocable share of remediation costs. As of December
31, 2002, we have estimated our share of the remediation costs at these sites to
be between $14 million and $18 million. Since the clean-up costs are estimates
and are subject to revision as more information becomes available about the
extent of remediation required, and because in some cases we have asserted a
defense to any liability, our estimates could change. Moreover, liability under
the federal CERCLA statute is joint and several, meaning that we could be
required to pay in excess of our pro rata share of remediation costs. Our
understanding of the financial strength of other PRPs has been considered, where
appropriate, in determining our estimated liabilities.

     It is possible that new information or future developments could require us
to reassess our potential exposure related to environmental matters. We may
incur significant costs and liabilities in order to comply with existing
environmental laws and regulations. It is also possible that other developments,
such as increasingly strict environmental laws and regulations and claims for
damages to property, employees, other

                                        32
<PAGE>

persons and the environment resulting from our current or past operations, could
result in substantial costs and liabilities in the future. As this information
becomes available, or other relevant developments occur, we will adjust our
accrual amounts accordingly. While there are still uncertainties relating to the
ultimate costs we may incur, based upon our evaluation and experience to date,
we believe the reserves are adequate.

  Rates and Regulatory Matters

     CPUC Complaint Proceeding.  In April 2000, the CPUC filed a complaint under
Section 5 of the Natural Gas Act (NGA) with the FERC alleging that our sale of
approximately 1.2 billion cubic feet per day of capacity to our affiliate, El
Paso Merchant Energy Company (EPME), raised issues of market power and 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 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 FERC's
marketing affiliate rule. 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, the ALJ issued his
initial decision, again finding that there was no evidence that EPME had
exercised market power during the period at issue to drive up California gas
prices and therefore recommending that the complaint against EPME be dismissed.
However, the ALJ found that we had withheld at least 345 MMcf/d of capacity (and
perhaps as much as 696 MMcf/d) from the California market during the period from
November 1, 2000 through March 31, 2001. The ALJ found that this alleged
withholding violated our 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; briefs
opposing exceptions were filed on November 12, 2002. This proceeding will be
resolved upon finalization and approval of the Western Energy Settlement.

     Systemwide Capacity Allocation Proceeding.  In July 2001, several of our
contract demand or CD customers filed a complaint against us at the FERC
claiming, among other things, that our full requirements contracts or FR
contracts (contracts with no volumetric limitations) should be converted to CD
contracts, and that we should be required to expand our system and give demand
charge credits to CD customers when we are unable to meet their full contract
demands. In July 2001, several of our FR customers filed a complaint alleging
that we had violated the Natural Gas Act and our contractual obligations to them
by not expanding our system, at our cost, to meet their increased requirements.

     On May 31, 2002, the FERC issued an order on the complaints in which it
required that (i) FR service, for all FR customers except small volume
customers, be converted to CD service; (ii) firm customers be assigned specific
receipt point rights in lieu of their existing systemwide receipt point rights;
(iii) reservation charge credits be given to all firm customers for failure to
schedule confirmed volumes except in cases of force majeure; (iv) no new firm
contracts be executed until we have demonstrated there is adequate capacity on
the system; and (v) a process be implemented to allow existing CD customers to
turn back capacity for acquisition by FR customers in which process we would
remain revenue neutral. These changes were to be made effective November 1,
2002. The order also stated that the FERC expected us to file for certificate
authority to add compression to Line 2000 to increase our system capacity by 320
MMcf/d without cost coverage until our next rate case (i.e. January 1, 2006). We
had previously informed the FERC that we were willing to add compression to Line
2000 provided we were assured of rate coverage in the next rate case. On July 1,
2002, we and other parties filed for clarification and/or rehearing of the May
31 order.

                                        33
<PAGE>

     On September 20, 2002, at the urging of the FR shippers, the FERC issued an
order postponing until May 1, 2003 the effective date of the FR conversions.
That order also required us to allocate among our FR customers (i) the 320
MMcf/d of capacity that will be available from the addition of compression to
Line 2000, and (ii) any firm capacity that expires under existing contracts
between May 31, 2002, and May 1, 2003, thereby precluding us from reselling that
capacity. In total, the September 20 order requires that our FR customers pay
only their current aggregate reservation charges for existing unsubscribed
capacity, for the 230 MMcf/d of capacity made available in November 2002 by our
Line 2000 project, for the 320 MMcf/d of capacity from the addition of
compression to Line 2000, and for all capacity subject to contracts expiring
before May 1, 2003. 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. Until May 1, 2003, we are required to pay
partial reservation charge credits to CD customers when we are unable to
schedule 95 percent of their monthly confirmed volumes except for reasons of
force majeure and provided that there is no capacity available from other supply
basins on our system.

     Several pleadings have been filed in response to the September 20 order,
including rehearing requests and requests by several customers to modify the
order based on the ALJ's decision in the CPUC Complaint Proceeding discussed
above. All such pleadings remain pending before the FERC. In the interim, we are
proceeding with the directives contained in the September 20 order.

     On October 7, 2002, we filed tariff sheets in compliance with the September
20 order to implement a partial demand charge credit for the period November 1,
2002 to May 31, 2003, and to allow California delivery points to be used as
secondary receipt points to the extent of our backhaul displacement
capabilities. We proposed both a reservation and a usage charge for this
service. On December 26, 2002, the FERC issued an order (i) denying our request
to charge existing CD customers a reservation rate for California receipt
service for the remaining term of the settlement, i.e., through December 31,
2005; (ii) allowing us to charge our maximum IT rate for the service; (iii)
approving our proposed usage rate for the service until our next rate case; and
(iv) requiring us to make a showing that capacity is available for any new
shippers utilizing this service. We made a revised tariff filing on January 10,
2003, in compliance with the December 26 order. On January 27, 2003, we filed a
request for rehearing on certain aspects of the December 26 order. That request
is pending.

     Rate Settlement.  Our current rate settlement establishes our base rates
through December 31, 2005. Under the settlement, our base rates began escalating
annually in 1998 for inflation. We have the right to increase or decrease our
base rates if changes in laws or regulations result in increased or decreased
costs in excess of $10 million a year. In addition, all of our settling
customers participate in risk sharing provisions. Under these provisions, we
will receive cash payments in total of $295 million for a portion of the risk we
assumed from capacity relinquishments by our customers (primarily capacity
turned back to us by Southern California Gas Company and Pacific Gas & Electric
Company which represented approximately one-third of the capacity of our system)
during 1996 and 1997. The cash we received was deferred, and we recognize this
amount in revenues ratably over the risk sharing period. As of December 31,
2002, we had unearned risk sharing revenues of approximately $32 million and had
$13 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 $46 million, of which $32 million was refunded
in 2002. The remainder will be refunded in 2003. 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 placed the line
in service in November 2002 at an approximate capital cost of $185 million. The
cost of the Line 2000 conversion will not be included in our rates until our
next rate case, which will be effective on January 1, 2006.
                                        34
<PAGE>

     On October 3, 2002, pursuant to the FERC's May 31 and September 20 orders
in the systemwide capacity allocation proceeding, we filed with the FERC for a
certificate of public convenience and necessity to add compression to our Line
2000 project to increase the capacity of that line by an additional 320 MMcf/d
at an estimated capital cost of approximately $173 million for all phases. That
application has been protested, and remains pending. 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. That request remains pending.

     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 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 and 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, which was effective immediately. The Accounting Release provides
guidance on how companies should account for money pool arrangements and the
types of documentation that should be maintained for these arrangements.
However, it 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.

     Emergency Reconstruction of Interstate Natural Gas Facilities NOPR.  On
January 17, 2003, FERC issued a NOPR proposing to (1) expand the scope of
construction activities authorized under a pipeline's blanket certificate to
allow replacement of mainline facilities; (2) authorize a pipeline to commence
reconstruction of the affected system without a waiting period; and (3)
authorize automatic approval of construction that would be above the normal cost
ceiling. Comments on the NOPR were filed on February 27, 2003. At this time, we
cannot predict the outcome of this rulemaking.

                                        35
<PAGE>

     Pipeline Safety Notice of Proposed Rulemaking.  On January 28, 2003, the
U.S. Department of Transportation issued a NOPR proposing to establish a rule
requiring pipeline operators to develop integrity management programs to
comprehensively evaluate their pipelines, and take measures to protect pipeline
segments located in what the notice refers to as "high consequence areas." The
proposed rule resulted from the enactment of the Pipeline Safety Improvement Act
of 2002, a new bill signed into law in December 2002. We intend to submit
comments on the NOPR, which are due on or before April 30, 2003. At this time,
we cannot predict the outcome of this rulemaking.

 Other Matters

     Enron Bankruptcy.  In December 2001, Enron Corp. and a number of its
subsidiaries, including Enron North America Corp. and Enron Power Marketing,
Inc., filed for Chapter 11 bankruptcy protection in the United States Bankruptcy
Court for the Southern District of New York. Enron North America had
transportation contracts on our system. The transportation contracts have now
been rejected and we have filed a proof of claim in the amount of approximately
$128 million, which included $18 million for amounts due for services provided
through the date the contracts were rejected and $110 million for damage claims
arising from the rejection of its transportation contracts. 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, and we have not recognized any amounts under these contracts
since the rejection date.

     While the outcome of our outstanding legal matters, environmental matters,
and rates and regulatory matters cannot be predicted with certainty, based on
current information and our existing accruals, we do not expect the ultimate
resolution of these matters to have a material adverse effect on our financial
position, operating results or cash flows. However, it is possible that new
information or future developments could require us to reassess our potential
exposure related to these matters. It is also possible that these matters could
impact our debt rating and the credit rating of our parent. Further, for
environmental matters, it is also possible that other developments, such as
increasingly strict environmental laws and regulations and claims for damages to
property, employees, other persons and the environment resulting from our
current or past operations, could result in substantial costs and liabilities in
the future. As new information for our outstanding legal matters, environmental
matters and rates and regulatory matters becomes available, or relevant
developments occur, we will review our accruals and make any appropriate
adjustments. The impact of these changes may have a material effect on our
results of operations, our financial position, and on our cash flows in the
period the event occurs.

  Capital Commitments

     At December 31, 2002, we had capital and investment commitments of $30
million for 2003 primarily relating to ongoing capital projects. Our other
planned capital and investment projects are discretionary in nature, with no
substantial capital commitments made in advance of the actual expenditures.

                                        36
<PAGE>

  Operating Leases

     We lease property, facilities and equipment under various operating leases.
Minimum annual rental commitments at December 31, 2002, were as follows:

<Table>
<Caption>
                        YEAR ENDING
                        DECEMBER 31,                          OPERATING LEASES
------------------------------------------------------------  ----------------
                                                              (IN MILLIONS)
<S>                                                           <C>
   2003.....................................................        $13
   2004.....................................................         13
   2005.....................................................         14
   2006.....................................................         14
   2007.....................................................          6
   Thereafter...............................................         --
                                                                    ---
          Total.............................................        $60
                                                                    ===
</Table>

     Aggregate minimum commitments have not been reduced by minimum sublease
rentals of approximately $7 million due in the future under noncancelable
subleases. In addition, as part of our relocation from El Paso to Colorado
Springs, we accrued these minimum lease commitments as merger-related charges.
These accruals were reduced by our estimated minimum sublease rentals.

     Rental expense for operating leases for each of the years ended December
31, 2002, 2001 and 2000 was $3 million, $3 million and $10 million.

  Guarantees

     As of December 31, 2002, we had the following guarantees:

     Pipeline Joint Venture -- In 1997, we entered into a joint venture to
construct a pipeline that extends from Bolivia to Brazil. In connection with the
joint venture, we issued a financial guarantee with a maximum potential exposure
of approximately $11 million to cover the need to increase our equity in the
project. Our guarantee expires in July 2018. As of December 31, 2002, we do not
have a liability recorded for this guarantee.

     Lease -- In 1996, we entered into a lease with Oxford Properties for office
space located in Calgary, Canada. In connection with this lease, we issued a
financial guarantee with a maximum potential exposure of approximately $500
thousand to cover any non-payments of rental fees on this property. Our
guarantee expires in March 2003. As of December 31, 2002, we do not have a
liability recorded for this guarantee.

     See Note 7 for a discussion of our obligations related to El Paso's
revolving credit facilities.

9. RETIREMENT BENEFITS

  Pension and Retirement Benefits

     Prior to January 1, 1997, El Paso maintained a defined benefit pension plan
covering substantially all of our employees. Pension benefits were based on
years of credited service and final five year average compensation, subject to
maximum limitations as defined in the pension plan. Effective January 1, 1997,
the plan was amended to provide benefits determined by a cash balance formula.
Employees who were pension plan participants on December 31, 1996, receive the
greater of cash balance benefits or prior plan benefits accrued through December
31, 2001. In addition, El Paso maintains a defined contribution plan covering
its U.S. employees, including our employees. Prior to May 1, 2002, El Paso
matched 75 percent of participant basic contributions up to 6 percent, with the
matching contributions being made to the plan's stock fund, which participants
could diversify at any time. After May 1, 2002, the plan was amended to allow
for matching contributions to be invested in the same manner as that of
participant contributions. Effective March 1, 2003, El Paso suspended the
matching contribution. El Paso is responsible for benefits accrued under its
plans and allocates the related costs to its affiliates. See Note 11 for a
summary of transactions with affiliates.

                                        37
<PAGE>

  Other Postretirement Benefits

     We provide postretirement medical benefits for a closed group of employees
who retired on or before March 1, 1986, and limited postretirement life
insurance for employees who retired after January 1, 1985. As such, our
obligation to accrue for other postretirement employee benefits (OPEB) is
primarily limited to the fixed population of retirees who retired on or before
March 1, 1986. The medical plan is pre-funded to the extent employer
contributions are recoverable through rates. To the extent actual OPEB costs
differ from amounts recovered in rates, a regulatory asset or liability is
recorded.

     The following table sets forth the change in benefit obligation, change in
plan assets, reconciliation of funded status, and components of net periodic
benefit cost for other postretirement benefits as of and for the twelve months
ended September 30:

<Table>
<Caption>
                                                              2002     2001
                                                              -----    -----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
Change in benefit obligation
  Benefit obligation at beginning of period.................  $ 95     $ 83
  Interest cost.............................................     7        6
  Actuarial loss............................................     5       13
  Benefits paid.............................................    (7)      (7)
                                                              ----     ----
  Benefit obligation at end of period.......................  $100     $ 95
                                                              ====     ====
Change in plan assets
  Fair value of plan assets at beginning period.............  $ 61     $ 77
  Actual return on plan assets..............................    (5)     (20)
  Employer contributions....................................    11       11
  Benefits paid.............................................    (7)      (7)
                                                              ----     ----
  Fair value of plan assets at end of period................  $ 60     $ 61
                                                              ====     ====
Reconciliation of funded status
  Funded status as of September 30..........................  $(40)    $(34)
  Fourth quarter contributions..............................     3        3
  Unrecognized net actuarial gain...........................    28       14
  Unrecognized net transition obligation....................    23       31
                                                              ----     ----
  Prepaid benefit cost at December 31.......................  $ 14     $ 14
                                                              ====     ====
</Table>

<Table>
<Caption>
                                                                   YEAR ENDED
                                                                  DECEMBER 31,
                                                              --------------------
                                                              2002    2001    2000
                                                              ----    ----    ----
                                                                 (IN MILLIONS)
<S>                                                           <C>     <C>     <C>
Postretirement benefit costs for the plans includes the
  following components
  Interest cost.............................................  $ 7     $ 6     $ 7
  Expected return on plan assets............................   (4)     (5)     (4)
  Amortization of net actuarial gain........................   --      (1)     (1)
  Amortization of transition obligation.....................    8       8       7
                                                              ---     ---     ---
  Net postretirement benefit cost...........................  $11     $ 8     $ 9
                                                              ===     ===     ===
</Table>

Postretirement benefit obligations are based upon actuarial estimates as
described below.

<Table>
<Caption>
                                                              2002    2001
                                                              -----   -----
<S>                                                           <C>     <C>
Weighted average assumptions
  Discount rate.............................................  6.75%   7.25%
  Expected return on plan assets............................  7.50%   7.50%
</Table>

                                        38
<PAGE>

     Actuarial estimates for our postretirement benefits plans assume a weighted
average annual rate of increase in the per capita costs of covered health care
benefits of 11.0 percent in 2002, gradually decreasing to 5.5 percent by the
year 2008. Assumed health care cost trends have a significant effect on the
amounts reported for other postretirement benefit plans. A one-percentage point
change in assumed health care cost trends would have the following effects:

<Table>
<Caption>
                                                              2002     2001
                                                              -----    -----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
One Percentage Point Increase
  Aggregate of Service Cost and Interest Cost...............  $  1     $  1
  Accumulated Postretirement Benefit Obligation.............  $  8     $  8
One Percentage Point Decrease
  Aggregate of Service Cost and Interest Cost...............  $ (1)    $ (1)
  Accumulated Postretirement Benefit Obligation.............  $ (8)    $ (7)
</Table>

10. PREFERRED STOCK

     In December 1998, we issued 500,000 shares of 8% Cumulative Preferred Stock
to El Paso. We used the proceeds of $350 million to reduce our outstanding debt.
El Paso is entitled to receive dividends at the rate of 8% on a liquidation
value of $700 per share annually. On or after January 1, 2003, these shares are
redeemable at our option, in whole or in part, upon not less than 30 days'
notice at a redemption price of $700 per share, plus unpaid dividends. For each
of the years ended December 31, 2002, 2001 and 2000 we paid $28 million in
dividends on our preferred stock. At December 31, 2002, we had accrued $2
million in dividends payable on our 8% preferred stock.

11. TRANSACTIONS WITH AFFILIATES

     Subject to the limitation on Mojave as described in Note 7, 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. Our continued participation in the program may be
dependent on any final rule issued by the FERC in connection with its cash
management notice of proposed rulemaking discussed under Note 8. As of December
31, 2002 and December 31, 2001, we had a cumulative net receivable from El Paso
of $990 million and $1,294 million. The rate of interest at December 31, 2002
and 2001, was 1.5% and 2.1%. These receivables are due upon demand; however, as
of December 31, 2002, we have classified $565 million as non-current because we
do not anticipate settlement within the next twelve months.

     At December 31, 2002 and 2001, we had other accounts receivable from
related parties of $7 million and $4 million. In addition, we had accounts
payable to affiliates of $33 million at December 31, 2002, versus $9 million at
December 31, 2001. These balances arose in the normal course of business. As a
result of El Paso's credit rating downgrades, we maintained $5 million as of
December 31, 2002 in contractual deposits related to an affiliate's
transportation contract on our EPNG system.

     During 2002 and 2000, we distributed assets to our parent through a
dividend with net book values of $19 million and $9 million.

     El Paso allocated a portion of its general and administrative expenses to
us. The allocation is based on the estimated level of effort devoted to our
operations and the relative size of our EBIT, gross property and payroll. For
the years ended December 31, 2002, 2001 and 2000, the annual charges were $49
million, $43 million and $58 million. During 2002 and 2001, Tennessee Gas
Pipeline allocated payroll to us and other expenses associated with our shared
pipeline services. The allocated expenses are based on the estimated level of
staff and their expenses to provide the services. For the years ended 2002 and
2001, the annual charges were $6 million. El Paso Field Services allocated
payroll and other expenses to us. During 2002, 2001 and 2000 those amounts were
$9 million, $7 million and $6 million. In addition, during 2002 and 2001 we
performed operational, financial, accounting and administrative services for, an
affiliate, Colorado Interstate Gas

                                        39
<PAGE>

Company. These services are recorded as reimbursement of operating expenses and
for 2002 and 2001 were $12 million and $7 million. We believe all the allocation
methods are reasonable.

     We provided El Paso Merchant Energy L.P. transportation services for the
years ended 2002, 2001 and 2000. We recognized revenues of $46 million, $72
million and $35 million for these periods. We entered into these transactions in
the ordinary course of business and the services were based on the same terms as
non-affiliates.

     The following table shows revenues and charges from our affiliates:

<Table>
<Caption>
                                                                  YEARS ENDED
                                                                  DECEMBER 31,
                                                              --------------------
                                                              2002    2001    2000
                                                              ----    ----    ----
                                                                 (IN MILLIONS)
<S>                                                           <C>     <C>     <C>
Revenues from affiliates....................................  $46     $72     $35
Operation and maintenance costs from affiliates.............   64      56      64
Reimbursement of operating expenses.........................   12       7      --
</Table>

12. TRANSACTIONS WITH MAJOR CUSTOMER

     The following table shows revenues from our major customer for the years
ended December 31:

<Table>
<Caption>
                                                            2002      2001      2000
                                                            ----      ----      ----
                                                                 (IN MILLIONS)
<S>                                                         <C>       <C>       <C>
Southern California Gas Company...........................  $139      $135      $132
</Table>

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

(1) Our contracts with Southern California Gas Company include 1,235 BBtu/d
    which expires in 2006 and 95 BBtu/d which expires 2004 through 2007.

13. SUPPLEMENTAL CASH FLOW INFORMATION

     The following table contains supplemental cash flow information for the
years ended December 31:

<Table>
<Caption>
                                                              2002      2001      2000
                                                              ----      ----      ----
                                                                   (IN MILLIONS)
<S>                                                           <C>       <C>       <C>
Interest paid...............................................  $78       $84       $99
Income tax payments.........................................   33        14        23
</Table>

14. SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

     Financial information by quarter is summarized below:

<Table>
<Caption>
                                                        QUARTERS ENDED
                                    -------------------------------------------------------
                                    DECEMBER 31   SEPTEMBER 30   JUNE 30   MARCH 31   TOTAL
                                    -----------   ------------   -------   --------   -----
                                                         (IN MILLIONS)
<S>                                 <C>           <C>            <C>       <C>        <C>
2002
  Operating revenues..............     $ 129          $139        $144       $152     $ 564
  Operating (loss) income.........      (342)           77          79         81      (105)
  Income (loss) from continuing
     operations...................      (225)           38          44         44       (99)
  Net income (loss)...............      (225)           38          44         44       (99)
2001
  Operating revenues..............     $ 145          $148        $138       $141     $ 572
  Merger-related costs............         1            (5)         94          8        98
  Operating income (loss).........        69            75         (25)        67       186
  Income (loss) from continuing
     operations...................        36            40         (21)        40        95
  Net income (loss)...............        36            40         (21)        40        95
</Table>

                                        40
<PAGE>

                       REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Stockholder of
El Paso Natural Gas Company:

     In our opinion, the consolidated financial statements listed in the Index
appearing under Item 15(a)(1) present fairly, in all material respects, the
consolidated financial position of El Paso Natural Gas Company and its
subsidiaries, (the "Company") at December 31, 2002 and 2001, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 2002 in conformity with accounting
principles generally accepted in the United States of America. In addition, in
our opinion, the financial statement schedule listed in the Index appearing
under Item 15(a)(2) presents fairly, in all material respects, the information
set forth therein when read in conjunction with the related consolidated
financial statements. These financial statements and financial statement
schedule are the responsibility of the Company's management; our responsibility
is to express an opinion on these financial statements and financial statement
schedule based on our audits. We conducted our audits of these statements in
accordance with auditing standards generally accepted in the United States of
America, which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas
March 25, 2003

                                        41
<PAGE>

                                  SCHEDULE II

                          EL PASO NATURAL GAS COMPANY
                       VALUATION AND QUALIFYING ACCOUNTS

                  YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
                                 (IN MILLIONS)

<Table>
<Caption>
                                          BALANCE AT    CHARGED TO   CHARGED TO                  BALANCE
                                          BEGINNING     COSTS AND      OTHER                     AT END
              DESCRIPTION                 OF PERIOD      EXPENSES     ACCOUNTS     DEDUCTIONS   OF PERIOD
              -----------                 ----------    ----------   ----------    ----------   ---------
<S>                                       <C>           <C>          <C>           <C>          <C>
2002
  Allowance for doubtful accounts.......     $ 6           $ 12         $ --          $ --        $ 18
  Legal reserves........................       2            423(1)        --           (10)(2)     415
  Environmental reserves................      29             --           --            --          29
  Provision for refunds.................      19             46           --           (52)(3)      13
2001
  Allowance for doubtful accounts.......     $ 2           $  6         $ --          $ (2)       $  6
  Legal reserves........................      --              2           --            --           2
  Environmental reserves................      25              4           --            --          29
  Provision for refunds.................      15              6           --            (2)         19
2000
  Allowance for doubtful accounts.......     $ 1           $  1         $ --          $ --        $  2
  Legal reserves........................       3             --           --            (3)         --
  Environmental reserves................      22              3           --            --          25
  Provision for refunds.................      49              1           --           (35)(4)      15
</Table>

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

(1) Includes a $412 million charge for the Western Energy Settlement.

(2) Relates to settlements paid.

(3) Relates to amounts paid for our risk sharing provisions with customers.

(4) Relates to the resolution of a contested rate matter.

                                        42
<PAGE>

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
        FINANCIAL DISCLOSURE

     None.

                                    PART III

     Item 10, "Directors and Executive Officers of the Registrant;" Item 11,
"Executive Compensation;" Item 12, "Security Ownership of Management;" and Item
13, "Certain Relationships and Related Transactions," have been omitted from
this report pursuant to the reduced disclosure format permitted by General
Instruction I to Form 10-K.

ITEM 14. CONTROLS AND PROCEDURES

     Evaluation of Controls and Procedures.  Under the supervision and with the
participation of management, including our principal executive officer and
principal financial officer, we have evaluated the effectiveness of the design
and operation of our disclosure controls and procedures (Disclosure Controls)
and internal controls (Internal Controls) within 90 days of the filing date of
this annual report pursuant to Rules 13a-15 and 15d-15 under the Securities
Exchange Act of 1934 (Exchange Act).

     Definition of Disclosure Controls and Internal Controls.  Disclosure
Controls are our controls and other procedures that are designed to ensure that
information required to be disclosed by us in the reports that we file or submit
under the Exchange Act is recorded, processed, summarized and reported, within
the time periods specified under the Exchange Act. Disclosure Controls include,
without limitation, controls and procedures designed to ensure that information
required to be disclosed by us in the reports that we file under the Exchange
Act is accumulated and communicated to our management, including our principal
executive officer and principal financial officer, as appropriate to allow
timely decisions regarding required disclosure. Internal Controls are procedures
which are designed with the objective of providing reasonable assurance that (1)
our transactions are properly authorized; (2) our assets are safeguarded against
unauthorized or improper use; and (3) our transactions are properly recorded and
reported, all to permit the preparation of our financial statements in
conformity with generally accepted accounting principles.

     Limitations on the Effectiveness of Controls.  El Paso Natural Gas
Company's management, including the principal executive officer and principal
financial officer, does not expect that our Disclosure Controls and Internal
Controls will prevent all errors and all fraud. A control system, no matter how
well conceived and operated, can provide only reasonable, not absolute,
assurance that the objectives of the control system are met. Further, the design
of a control system must reflect the fact that there are resource constraints,
and the benefits of controls must be considered relative to their costs. Because
of the inherent limitations in all control systems, no evaluation of controls
can provide absolute assurance that all control issues and instances of fraud,
if any, within the company have been detected. These inherent limitations
include the realities that judgments in decision-making can be faulty, and that
breakdowns can occur because of simple errors or mistakes. Additionally,
controls can be circumvented by the individual acts of some persons, by
collusion of two or more people, or by management override of the controls. The
design of any system of controls also is based in part upon certain assumptions
about the likelihood of future events, and there can be no assurance that any
design will succeed in achieving its stated goals under all potential future
conditions. Over time, controls may become inadequate because of changes in
conditions, or the degree of compliance with the policies or procedures may
deteriorate. Because of the inherent limitations in a cost-effective control
system, misstatements due to error or fraud may occur and not be detected.

     No Significant Changes in Internal Controls.  We have sought to determine
whether there were any "significant deficiencies" or "material weaknesses" in El
Paso Natural Gas Company's Internal Controls, or whether the company had
identified any acts of fraud involving personnel who have a significant role in
El Paso Natural Gas Company's Internal Controls. This information was important
both for the controls evaluation generally and because the principal executive
officer and principal financial officer are required to disclose that
information to our Board and our independent auditors and to report on related
matters in this

                                        43
<PAGE>

section of the Annual Report. The principal executive officer and principal
financial officer note that, from the date of the controls evaluation to the
date of this Annual Report, there have been no significant changes in Internal
Controls or in other factors that could significantly affect Internal Controls,
including any corrective actions with regard to significant deficiencies and
material weaknesses.

     Effectiveness of Disclosure Controls.  Based on the controls evaluation,
our principal executive officer and principal financial officer have concluded
that, subject to the limitations discussed above, the Disclosure Controls are
effective to ensure that material information relating to El Paso Natural Gas
Company and its consolidated subsidiaries is made known to management, including
the principal executive officer and principal financial officer, particularly
during the period when our periodic reports are being prepared.

     Officer Certifications.  The certifications from the principal executive
officer and principal financial officer required under Sections 302 and 906 of
the Sarbanes-Oxley Act of 2002 have been included herein, or as Exhibits to this
Annual Report, as appropriate.

                                    PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

     (a) THE FOLLOWING DOCUMENTS ARE FILED AS A PART OF THIS REPORT:

     1. Financial statements.

     The following consolidated financial statements are included in Part II,
Item 8 of this report:

<Table>
<Caption>
                                                              PAGE
                                                              ----
<S>                                                           <C>
     Consolidated Statements of Income......................   17
     Consolidated Balance Sheets............................   18
     Consolidated Statements of Cash Flows..................   19
     Consolidated Statements of Stockholder's Equity........   20
     Notes to Consolidated Financial Statements.............   21
     Report of Independent Accountants......................   41

2. Financial statement schedules.

     Schedule II -- Valuation and Qualifying Accounts.......   42

     All other schedules are omitted because they are not
      applicable, or the required information is disclosed
      in the financial statements or accompanying notes.

3. Exhibit list.............................................   45
</Table>

     (b) REPORTS ON FORM 8-K:

     We filed a current report on Form 8-K dated March 21, 2003 regarding the
Western Energy Settlement.

                                        44
<PAGE>

                          EL PASO NATURAL GAS COMPANY

                                  EXHIBIT LIST
                               DECEMBER 31, 2002

     Exhibits not incorporated by reference to a prior filing are designated by
an asterisk. All exhibits not so designated are incorporated herein by reference
to a prior filing as indicated.

<Table>
<Caption>
        EXHIBIT
         NUMBER                                  DESCRIPTION
        -------                                  -----------
<C>                      <S>
          3.A            -- Restated Certificate of Incorporation dated May 11, 1999
                            (Exhibit 3.A to our 1999 First Quarter Form 10-Q).
         *3.B            -- By-Laws dated June 24, 2002.
          4.A            -- Indenture dated as of January 1, 1992, between EPNG and
                            Wilmington Trust Company (as successor to Citibank,
                            N.A.), as Trustee (Exhibit 4.A to our 1998 Form 10-K).
          4.B            -- Indenture dated as of November 13, 1996, between EPNG and
                            Wilmington Trust Company (as successor to JPMorgan Chase
                            Bank, formerly known as The Chase Manhattan Bank), as
                            Trustee (Exhibit 4.1 to our Form 8-K, filed November 13,
                            1996); First Supplemental Indenture dated as of June 10,
                            2002, by and between EPNG and the Trustee (Exhibit 4.2 to
                            our Registration Statement on Form S-4 filed July 24,
                            2002, File No. 333-97017).
          4.C            -- Registration Rights Agreement dated as of June 10, 2002,
                            between EPNG and Credit Suisse First Boston Corporation
                            (Exhibit 4.3 to our Registration Statement on Form S-4
                            filed July 24, 2002, File No. 333-97017).
         10.A            -- $3,000,000,000 364-Day Revolving Credit and Competitive
                            Advance Facility Agreement, dated May 15, 2002, by and
                            among El Paso Corporation, EPNG, TGP, the several banks
                            and other financial institutions from time to time
                            parties thereto, JPMorgan Chase Bank, as Administrative
                            Agent and CAF Advance Agent, ABN Amro Bank N.V. and
                            Citibank, N.A., as Co-Documentation Agents, and Bank of
                            America, N.A. and Credit Suisse First Boston, as
                            Co-Syndication Agents (Exhibit 10.A to our 2002 Second
                            Quarter Form 10-Q).
         10.B            -- Amended and Restated $1,000,000,000 3-Year Revolving
                            Credit and Competitive Advance Facility Agreement dated
                            June 27, 2002, by and among El Paso EPNG, TGP, El Paso
                            CGP, the several banks and other financial institutions
                            from time to time parties thereto, and JPMorgan Chase
                            Bank, as Administrative Agent, CAF Advance Agent and
                            Issuing Bank, Citibank, N.A. and ABN Amro Bank N.V., as
                            Co-Documentation Agents, and Bank of America, N.A., as
                            Syndication Agent (Exhibit 10.B to our 2002 Second
                            Quarter Form 10-Q).
         21              -- Omitted pursuant to the reduced disclosure format
                            permitted by General Instruction I to Form 10-K.
        *99.A            -- Certification of Principal Executive Officer pursuant to
                            18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of
                            the Sarbanes-Oxley Act of 2002. A signed original of this
                            written statement required by sec. 906 has been provided
                            to El Paso Natural Gas Company and will be retained by El
                            Paso Natural Gas Company and furnished to the Securities
                            and Exchange Commission or its staff upon request.
        *99.B            -- Certification of Principal Financial Officer pursuant to
                            18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of
                            the Sarbanes-Oxley Act of 2002. A signed original of this
                            written statement required by sec. 906 has been provided
                            to El Paso Natural Gas Company and will be retained by El
                            Paso Natural Gas Company and furnished to the Securities
                            and Exchange Commission or its staff upon request.
</Table>

                                        45
<PAGE>

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
and our consolidated subsidiaries not filed herewith for the reason that the
total amount of securities authorized under any of such instruments does not
exceed 10 percent of our total consolidated assets.

                                        46
<PAGE>

                                   SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934 as amended, El Paso Natural Gas Company has duly caused
this report to be signed on its behalf by the undersigned, thereunto duly
authorized on the 27th day of March 2003.

                                           EL PASO NATURAL GAS COMPANY

                                           By
                                            /s/ JOHN W. SOMERHALDER II
                                            -----------------------------
                                               John W. Somerhalder II
                                                Chairman of the Board

     Pursuant to the requirements of the Securities Exchange Act of 1934 as
amended, this report has been signed below by the following persons on behalf of
El Paso Natural Gas Company and in the capacities and on the dates indicated:

<Table>
<Caption>
                      SIGNATURE                                    TITLE                     DATE
                      ---------                                    -----                     ----
<C>                                                    <S>                             <C>

             /s/ JOHN W. SOMERHALDER II                Chairman of the Board, Chief     March 27, 2003
-----------------------------------------------------    Executive Officer and
              (John W. Somerhalder II)                   Director (Principal
                                                         Executive Officer)

               /s/ PATRICIA A. SHELTON                 President and Director           March 27, 2003
-----------------------------------------------------
                (Patricia A. Shelton)

                 /s/ GREG G. GRUBER                    Chief Financial Officer and      March 27, 2003
-----------------------------------------------------    Treasurer (Principal
                  (Greg G. Gruber)                       Financial and Accounting
                                                         Officer)
</Table>

                                        47
<PAGE>

                                 CERTIFICATION

I, John W. Somerhalder II, certify that:

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

     2. Based on my knowledge, this annual 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 annual
report;

     3. Based on my knowledge, the financial statements, and other financial
information included in this annual 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 annual 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 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 annual
             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 annual report (the "Evaluation Date"); and

          c) presented in this annual 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 functions):

          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
annual report whether 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.

                                              /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
Date: March 27, 2003

                                        48
<PAGE>

                                 CERTIFICATION

I, Greg G. Gruber, certify that:

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

     2. Based on my knowledge, this annual 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 annual
report;

     3. Based on my knowledge, the financial statements, and other financial
information included in this annual 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 annual 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 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 annual
             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 annual report (the "Evaluation Date"); and

          c) presented in this annual 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 functions):

          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
annual report whether 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.

                                                  /s/ GREG G. GRUBER
                                          --------------------------------------
                                                      Greg G. Gruber
                                                  Senior Vice President,
                                          Chief Financial Officer and Treasurer
                                              (Principal Financial Officer)
                                               El Paso Natural Gas Company
Date: March 27, 2003

                                        49
<PAGE>

                                 EXHIBIT INDEX

     Exhibits not incorporated by reference to a prior filing are designated by
an asterisk. All exhibits not so designated are incorporated herein by reference
to a prior filing as indicated.

<Table>
<Caption>
        EXHIBIT
         NUMBER                                  DESCRIPTION
        -------                                  -----------
<C>                      <S>
          3.A            -- Restated Certificate of Incorporation dated May 11, 1999
                            (Exhibit 3.A to our 1999 First Quarter Form 10-Q).
         *3.B            -- By-Laws dated June 24, 2002.
          4.A            -- Indenture dated as of January 1, 1992, between EPNG and
                            Wilmington Trust Company (as successor to Citibank,
                            N.A.), as Trustee (Exhibit 4.A to our 1998 Form 10-K).
          4.B            -- Indenture dated as of November 13, 1996, between EPNG and
                            Wilmington Trust Company (as successor to JPMorgan Chase
                            Bank, formerly known as The Chase Manhattan Bank), as
                            Trustee (Exhibit 4.1 to our Form 8-K, filed November 13,
                            1996); First Supplemental Indenture dated as of June 10,
                            2002, by and between EPNG and the Trustee (Exhibit 4.2 to
                            our Registration Statement on Form S-4 filed July 24,
                            2002, File No. 333-97017).
          4.C            -- Registration Rights Agreement dated as of June 10, 2002,
                            between EPNG and Credit Suisse First Boston Corporation
                            (Exhibit 4.3 to our Registration Statement on Form S-4
                            filed July 24, 2002, File No. 333-97017).
         10.A            -- $3,000,000,000 364-Day Revolving Credit and Competitive
                            Advance Facility Agreement, dated May 15, 2002, by and
                            among El Paso Corporation, EPNG, TGP, the several banks
                            and other financial institutions from time to time
                            parties thereto, JPMorgan Chase Bank, as Administrative
                            Agent and CAF Advance Agent, ABN Amro Bank N.V. and
                            Citibank, N.A., as Co-Documentation Agents, and Bank of
                            America, N.A. and Credit Suisse First Boston, as
                            Co-Syndication Agents (Exhibit 10.A to our 2002 Second
                            Quarter Form 10-Q).
         10.B            -- Amended and Restated $1,000,000,000 3-Year Revolving
                            Credit and Competitive Advance Facility Agreement dated
                            June 27, 2002, by and among El Paso EPNG, TGP, El Paso
                            CGP, the several banks and other financial institutions
                            from time to time parties thereto, and JPMorgan Chase
                            Bank, as Administrative Agent, CAF Advance Agent and
                            Issuing Bank, Citibank, N.A. and ABN Amro Bank N.V., as
                            Co-Documentation Agents, and Bank of America, N.A., as
                            Syndication Agent (Exhibit 10.B to our 2002 Second
                            Quarter Form 10-Q).
         21              -- Omitted pursuant to the reduced disclosure format
                            permitted by General Instruction I to Form 10-K.
        *99.A            -- Certification of Principal Executive Officer pursuant to
                            18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of
                            the Sarbanes-Oxley Act of 2002. A signed original of this
                            written statement required by sec. 906 has been provided
                            to El Paso Natural Gas Company and will be retained by El
                            Paso Natural Gas Company and furnished to the Securities
                            and Exchange Commission or its staff upon request.
        *99.B            -- Certification of Principal Financial Officer pursuant to
                            18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of
                            the Sarbanes-Oxley Act of 2002. A signed original of this
                            written statement required by sec. 906 has been provided
                            to El Paso Natural Gas Company and will be retained by El
                            Paso Natural Gas Company and furnished to the Securities
                            and Exchange Commission or its staff upon request.
</Table>