<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, 2003

                                       OR

     [ ]      TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                      THE SECURITIES EXCHANGE ACT OF 1934

       FOR THE TRANSITION PERIOD FROM                TO                .

                         COMMISSION FILE NUMBER 1-2700

                          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 15, 2004:
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...   10
Item 7A.  Quantitative and Qualitative Disclosures About Market
            Risk......................................................   15
Item 8.   Financial Statements and Supplementary Data.................   16
Item 9.   Changes in and Disagreements with Accountants on Accounting
            and Financial Disclosure..................................   42
Item 9A.  Controls and Procedures.....................................   42

                                    PART III
Item 10.  Directors and Executive Officers of the Registrant..........    *
Item 11.  Executive Compensation......................................    *
Item 12.  Security Ownership of Certain Beneficial Owners and
            Management and Related Stockholder Matters................    *
Item 13.  Certain Relationships and Related Transactions..............    *
Item 14.  Principal Accountant Fees and Services......................   43

                                    PART IV
Item 15.  Exhibits, Financial Statement Schedules, and Reports on Form
            8-K.......................................................   43
          Signatures..................................................   46
</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                                   MMcf    = million cubic feet
BBtu     = billion British thermal units             MMDth   = million dekatherm
Bcf      = billion cubic feet                        Tcfe    = trillion cubic feet equivalent
</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 an indirect 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 4,650
MMcf/d (including 120 MMcf/d related to our Phase I Line 2000 Power-up expansion
which went into service on February 27, 2004) and approximately 800 MMcf/d of
east-end deliverability. EPNG is currently expanding its Line 2000 system which
extends from West Texas to the Arizona and California border and is expected to
increase capacity by an additional 200 MMcf/d by mid-2004. During 2003, 2002 and
2001, average throughput on the EPNG system was 3,874 BBtu/d, 3,799 BBtu/d and
4,253 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
2003, 2002 and 2001, average throughput on the Mojave system was 192 BBtu/d, 266
BBtu/d and 283 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, 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 energy 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 93 percent of our transportation services
revenue is attributable to a capacity reservation (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 7 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 10, and is
incorporated herein by reference.

                            MARKETS AND COMPETITION

     We serve major markets in the southwestern United States and California as
well as northern Mexico. These have recently been among the fastest growing
regions in the U.S. and Mexico; therefore the market demand for natural gas
distribution as well as gas-fired electric generation capacity has experienced
considerable growth. While this demand growth has slowed somewhat from the
levels in 2000-2002, we expect it to continue at a slower rate. Our markets
consist of distribution and industrial companies, electric generation companies,
natural gas producers, other interstate and intrastate 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 serviced by these pipelines.

<Table>
<Caption>
  PIPELINE
   SYSTEM         CUSTOMER INFORMATION            CONTRACT INFORMATION                      COMPETITION
------------  ----------------------------   -------------------------------   -------------------------------------
<S>           <C>                            <C>                               <C>
EPNG          Approximately 215 firm and     Approximately 215 firm            EPNG faces competition in the West
                interruptible                transportation contracts          and Southwest from other existing
              transportation                 Contracted capacity: 97%          pipelines, California storage
                customers                    Weighted average remaining        facilities and newly proposed
                                             contract term:                    pipeline and LNG projects as well as
                                               approximately 5 years           alternative energy sources that
                                                                               generate electricity such as
                                                                               hydroelectric power, nuclear, coal
              Major Customer:                                                  and fuel oil.
                Southern California Gas
                  Company                    Contract term expires in 2006.
              (1,215 BBtu/d)                 Contract terms expiring
              (93 BBtu/d)                    2004-2007.

Mojave        Approximately 35 firm and      Eight firm contracts              Mojave faces competition from other
                interruptible                Contracted capacity: 96%          existing pipelines and newly proposed
              transportation   customers     Weighted average remaining        pipeline and LNG projects as well as
                                             contract term:                    alternative energy sources that
                                               approximately 3 years           generate electricity such as
                                                                               hydroelectric power, nuclear, coal
              Major Customers:                                                 and fuel oil.
                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>

     The combined capacity of all pipeline companies serving the California
market is approximately 8.5 Bcf/d and we provide approximately 39 percent of
this capacity. In 2003, the demand for interstate pipeline capacity to
California averaged 4.9 Bcf/d, equivalent to approximately 57 percent of the
total interstate pipeline capacity serving that state. Natural gas shipped to
California across our system represented approximately 28 percent of the natural
gas consumed in the state in 2003.

     A number of large natural gas consumers are electric utility companies who
use natural gas to fuel electric power generation facilities. Electric power
generation is the fastest growing demand sector 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 potentially benefit the natural gas

                                        2
<PAGE>

industry by creating more demand for natural gas turbine generated electric
power, but this effect is offset, in varying degrees, by increased efficiency in
generation and the use of surplus electric capacity as a result of open market
access.

     Our existing contracts mature at various times and in varying amounts of
throughput capacity. 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 10, and is incorporated
herein by reference.

                                   EMPLOYEES

     As of March 9, 2004, we had approximately 740 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

     The fifteen California cases discussed in Part II, Item 8, Financial
Statements and Supplementary Data, Note 10, include 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***); 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 six 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**; The City of Culver City v.
Southern California Gas, et al., filed April 11, 2002); The State of Nevada et
al v. El Paso Corporation, El Paso Natural Gas Company, et. al. filed November
2002 in the District Court for Clark County, Nevada**; Gus N. Bustamante v. The
McGraw-Hill Companies filed in the Superior Court of California, County of Los
Angeles in November 2002**.
---------------
*   We have been dismissed from these cases and judgment has been entered. An
    appeal of that judgment is pending.
**  Cases to be dismissed in conjunction with final approval of the Western
    Energy Settlement.
*** We have been dismissed from this case in a settlement separate from the
    Western Energy Settlement.

     More details on the above cases, and a description of our other legal
proceedings is included in Part II, Item 8, Financial Statements and
Supplementary Data, Note 10, 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 a subsidiary
of El Paso and, accordingly, our stock is not publicly traded.

     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 2003.

                                        4
<PAGE>

     During late 2003 and early 2004, El Paso issued a total of 26.4 million
shares of common stock pursuant to the Western Energy Settlement (WES). A
discussion of the WES is included in Item 8, Financial Statements and
Supplementary Data, Notes 3 and 10. El Paso contributed to us gross proceeds of
approximately $195 million from the sales of its common stock, which we in turn
funded to an escrow account for the benefit of the settling parties in the WES.

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.

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, including a reasonable 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.

                                        5
<PAGE>

                             RESULTS OF OPERATIONS

     Our management, as well as El Paso's management, uses earnings before
interest and income taxes (EBIT) to assess the operating results and
effectiveness of our business. We define EBIT as net income adjusted for (i)
items that do not impact our income from continuing operations, such as the
impact of accounting changes, (ii) income taxes, (iii) interest and debt expense
and (iv) affiliated interest income. We exclude interest and debt expense from
this measure so that our management can evaluate our operating results without
regard to our financing methods. We believe the discussion of our results of
operations based on EBIT is useful to our investors because it allows them to
more effectively evaluate the operating performance of our business using the
same performance measure analyzed internally by our management. EBIT may not be
comparable to measurements used by other companies. Additionally, EBIT should be
considered in conjunction with net income and other performance measures such as
operating income or operating cash flow. The following is a reconciliation of
our operating income to our EBIT and our EBIT to our net income for the years
ended December 31:

<Table>
<Caption>
                                                               2003         2002
                                                              -------      -------
                                                              (IN MILLIONS, EXCEPT
                                                                VOLUME AMOUNTS)
<S>                                                           <C>          <C>
Operating revenues..........................................  $  526       $  564
Operating expenses..........................................    (385)        (668)
                                                              ------       ------
  Operating income (loss)...................................     141         (104)
Other income................................................       7           --
                                                              ------       ------
  EBIT......................................................     148         (104)
Interest and debt expense...................................     (90)         (72)
Affiliated interest income..................................      20           22
Income taxes................................................     (31)          55
                                                              ------       ------
  Net income (loss).........................................  $   47       $  (99)
                                                              ======       ======
Total throughput (BBtu/d)...................................   4,066        4,065
                                                              ======       ======
</Table>

OPERATING RESULTS (EBIT)

     Our EBIT for the year ended December 31, 2003 was $252 million higher than
in 2002. The increase in EBIT was primarily the result of a decrease in
operating expenses due to a net decrease of $272 million in Western Energy
Settlement charges incurred in 2003 as compared to 2002. For a further
discussion of the Western Energy Settlement, see Item 8, Financial Statements
and Supplementary Data, Notes 3 and 10. In addition, our EBIT in 2003 was higher
due to bad debt expense in 2002 of $12 million related to the bankruptcy of
Enron Corp. and reduced corporate and legal charges of $8 million in 2003. Our
EBIT results were negatively impacted by a decrease of $35 million in operating
revenues in 2003 related to the expiration of capacity contracts which we were
prohibited from remarketing due to various FERC orders and obligations to make
capacity available to our former full requirement customers until our Line 2000
Power-up project is phased-in during 2004. Each of the capacity related items
discussed below had no impact on our operating expenses in 2003. Property
additions in 2003 resulted in higher depreciation expense and ad valorem taxes
of $8 million and higher other income from allowances for equity funds used
during construction in 2003 of $7 million. We also had higher expenses related
to natural gas used in operations in excess of amounts recovered from customers
of $11 million resulting in a negative impact on our 2003 EBIT.

     As discussed above and in Item 8, Financial Statements and Supplementary
Data, Note 10, the FERC issued various orders related to the allocation of
capacity on our EPNG system. These orders impacted our 2003 revenues and will
continue to impact our future results. Based on these orders:

     - Reservation charges will be credited to our firm shippers if we fail to
       schedule the shipper's confirmed volumes (except in the case of force
       majeure, in which case partial credits will be given);

                                        6
<PAGE>

     - We must refrain from entering into any new contracts unless we can
       demonstrate that we have capacity available to provide the new service;

     - We refrained from remarketing turned-back capacity under contracts
       terminating or expiring between May 31, 2002 and May 1, 2003, because
       that capacity was allocated to our full requirement (FR) shippers; and

     - We are adding 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.

     As a result, we were unable to remarket approximately 471 MMDth/d of
turned-back capacity, of which approximately 200 MMDth/d relates to capacity
rejected by Enron Corp. in May 2002 in its bankruptcy proceeding and the
remaining 271 MMDth/d relates to contracts that expired within the time frame
specified under these orders. By order, this 471 MMDth/d of capacity was made
available to converting full requirement shippers without an increase in their
reservation charge obligation until January 1, 2006. At that time, we will seek
to recover these costs by adjusting our rates. Prior to the rejection and
expiration of this capacity, we were earning revenues on this capacity (net of
revenue credits) of approximately $3.5 million per month.

     In July 2003, the FERC (i) reaffirmed its decision that our full
requirements contracts must be converted to contract demand contracts effective
September 1, 2003, (ii) supported our position relative to the maximum amount of
capacity we can make available to our shippers and (iii) confirmed that we have
honored our obligations under our existing rate settlement, our contracts, the
FERC's regulations and our certificates. We were required to establish a pool of
110 MMcf/d for use by our full requirement shippers until our Line 2000
expansion project is phased into service which is expected to occur by the end
of the first quarter of 2004. Effective September 1, 2003, we acquired this
capacity, primarily on a permanent basis, and will be at risk for remarketing
this capacity. We estimate this will reduce our revenues for the first six
months of 2004 by approximately $3.9 million as compared to the first six months
of 2003.

     In addition, we had risk sharing mechanisms under our most recent rate case
settlement. This risk sharing period expired on December 31, 2003. Under these
risk sharing mechanisms, we collected cash from our customers, refunded a
portion of the cash received as required by the mechanisms and then recognized
the difference as revenues over the risk sharing period. We estimate that the
expiration of the risk sharing mechanisms will decrease our annual revenues by
approximately $22 million. See Item 8, Financial Statements and Supplementary
Data, Note 10, for a further discussion of our risk sharing mechanisms.

INTEREST AND DEBT EXPENSE

<Table>
<Caption>
                                                               YEAR ENDED
                                                              DECEMBER 31,
                                                              -------------
                                                              2003     2002
                                                              ----     ----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
Long term debt..............................................  $91      $69
Short term borrowings.......................................   --        8
Other.......................................................    2        1
Less: Capitalized interest..................................   (3)      (6)
                                                              ---      ---
  Total interest and debt expense...........................  $90      $72
                                                              ===      ===
</Table>

     Interest and debt expense for the year ended December 31, 2003, was $18
million higher than in 2002. The increase in interest expense resulted from the
issuances of $300 million of long-term 8.375% notes in June 2002 and $355
million of long-term 7.625% notes in July 2003, and decreases in interest
capitalized on construction projects due to a lower capitalization base in 2003.
These increases were partially offset by decreases in commercial paper interest
expense due to the discontinuation of commercial paper borrowings in the fourth
quarter of 2002.

                                        7
<PAGE>

AFFILIATED INTEREST INCOME

     Affiliated interest income for the year ended December 31, 2003, was $2
million lower than in 2002 due to lower average advances to El Paso under the
cash management program in 2003 offset by higher short-term rates in 2003 on
which we earned interest. The average advance balance due from El Paso of $1.2
billion in 2002 decreased to $996 million in 2003. The average short-term
interest rates increased from 1.9% in 2002 to 2% in 2003.

INCOME TAXES

<Table>
<Caption>
                                                                  YEAR ENDED
                                                                 DECEMBER 31,
                                                              ------------------
                                                               2003        2002
                                                              ------      ------
                                                                (IN MILLIONS,
                                                              EXCEPT FOR RATES)
<S>                                                           <C>         <C>
Income taxes................................................    $31        $(55)
Effective tax rate..........................................     40%         36%
</Table>

     Our effective tax rates were different than the statutory rate of 35
percent in all 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 6.

     Included in our deferred tax assets as of December 31, 2003 was $200
million related to the Western Energy Settlement. Proposed tax legislation has
been introduced in the U.S. Senate which would disallow deductions for certain
settlements made to or on behalf of governmental entities. If enacted, this tax
legislation could impact the deductibility of the Western Energy Settlement and
could result in a write-off of some or all of the associated deferred tax
assets. In such event, our tax expense would increase.

                        LIQUIDITY AND CAPITAL RESOURCES

LIQUIDITY

     Our liquidity needs have been 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, 2003, we had receivables from El Paso of $779 million
as a result of this program. These receivables are due upon demand; however, we
do not anticipate settlement within twelve months. As of December 31, 2003 these
receivables were classified as non-current notes receivable from affiliates in
our balance sheet. We believe that cash flows from operating activities will be
adequate to meet our short-term capital and debt servicing requirements for
existing operations. However, as a result of recent announcements by El Paso
related to a revision of its estimates of its natural gas and oil reserves, our
ability to borrow or recover the amounts advanced under El Paso's cash
management program could be impacted. See Item 8, Financial Statements and
Supplementary Data, Note 2 for a discussion of these matters. Our cash flows for
the years ended December 31 were as follows:

<Table>
<Caption>
                                                              2003    2002
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Cash flows from operating activities........................  $ 157   $ 269
Cash flows from investing activities........................   (409)    120
Cash flows from financing activities........................    275    (386)
</Table>

     In a series of credit rating agency actions beginning in 2002, 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 (with a negative outlook and under review
for a

                                        8
<PAGE>

possible downgrade) and B- by Standard & Poor's (with a negative outlook). These
downgrades will increase our cost of capital and collateral requirements and
could impede our access to capital markets in the future.

CAPITAL EXPENDITURES

     Our capital expenditures during the periods indicated are listed below:

<Table>
<Caption>
                                                               YEAR ENDED
                                                              DECEMBER 31,
                                                              -------------
                                                              2003    2002
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Maintenance.................................................  $103    $123
Expansion/Other.............................................   122      70
                                                              ----    ----
     Total..................................................  $225    $193
                                                              ====    ====
</Table>

     Under our current plan, we expect to spend between approximately $120
million and $175 million in each of the next three years for capital
expenditures to maintain the integrity of our pipelines and ensure the reliable
delivery of natural gas to our customers. In addition, we have budgeted to spend
between approximately $10 million and $70 million in each of the next three
years to expand the capacity of our pipeline systems contingent upon customer
commitments to the projects. We expect to fund our maintenance and expansion
capital expenditures using a combination of internally generated funds and
external financing.

DEBT

     As of December 31, 2003, we had long-term debt outstanding of $1,109
million, net of a $6 million discount, none of which matures within the next
five years. For a discussion of our debt and other credit facilities, see Item
8, Financial Statements and Supplementary Data, Note 9, 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 10, which is incorporated
herein by reference.

            NEW ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

     As of December 31, 2003, there were a number of accounting standards and
interpretations that had been issued, but not yet adopted by us. Based on our
assessment of those standards, we do not believe there are any that could have a
material impact on us.

                                        9
<PAGE>

    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 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 such as hydroelectric power;

     - price competition;

     - drilling activity and supply availability of natural gas;

     - expiration and/or turn back of significant contracts;

     - service area competition;

     - changes in regulation and actions of regulatory bodies;

     - credit risk of our customer base;

     - increased cost of capital;

     - opposition to energy infrastructure development, especially in
       environmentally sensitive areas;

     - adverse general economic conditions;

     - expiration and/or renewal of existing interests in real property
       associated with our pipeline; and

     - unfavorable movements in natural gas and liquids prices.

                                        10
<PAGE>

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 example, Southern California Gas Company, our largest customer,
filed a proposal in January 2004 with the California Public Utilities Commission
asking for permission to give notice to terminate certain of its transportation
agreements with us by February 25, 2005, with the intent of negotiating to
reduce their capacity holdings on our pipeline system as part of an effort to
diversify their capacity holdings. The outcome of this proceeding is uncertain
at this time. 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:

     - competition by other pipelines, including the proposed construction by
       other companies of additional pipeline capacity or LNG terminals 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 in the areas we serve;

     - 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.

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 a reduction of the volumes transported by our customers, such as
power companies who, depending on the price of fuel, may not dispatch gas fired
power plants. Increased prices could also result from industrial plant shutdowns
or load losses to competitive fuels as well as local distribution companies'
loss of customer base. 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. If natural gas prices in the supply
basins connected to our pipeline systems are higher on a delivered basis to our
off-system markets than delivered prices from other natural gas producing
regions, our ability to compete with other transporters may be negatively
impacted. 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

                                        11
<PAGE>

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 and local governments 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.

     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, and these amounts
could be material. For additional information, see Item 8, Financial Statements
and Supplementary Data, Note 10.

WE FACE UNCERTAINTY RELATED TO EXPIRING REAL PROPERTY INTERESTS RELATED TO OUR
PIPELINE.

     Nearly 900 miles of the north mainline of our pipeline system are currently
located on property inside the Navajo Nation. We currently pay approximately
$2.3 million per year for the real property interests, such as easements, leases
and rights-of-way, located on Navajo Nation trust lands. These real property
interests are scheduled to expire in October 2005. We are beginning negotiations
with the Navajo Nation to renew these interests. The outcome of this process is
uncertain but we may incur future costs arising from potential litigation or
increased right-of-way fees.

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 to the extent and
in amounts that we believe are reasonable, 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 2003, contracts with Southern California Gas Company were substantial.
For additional information on our contracts with Southern California Gas
Company, see Part I, Item 1, Business -- Markets and

                                        12
<PAGE>

Competition and Part II, Item 8, Financial Statements and Supplementary Data,
Note 14. The loss of this customer or a decline in its credit-worthiness could
adversely affect our results of operations, financial position and cash flow.

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

     A listing of legal proceedings is included in Part I, Item 3, Legal
Proceedings. A description of our legal proceedings and investigations is
included in Part II, Item 8, Financial Statements and Supplementary Data, Note
10.

                 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 senior unsecured indebtedness of
El Paso has been downgraded to below investment grade, currently rated Caa1 by
Moody's (with a negative outlook and under review for a possible downgrade) and
CCC+ by Standard & Poor's (with a negative outlook). Our senior unsecured
indebtedness is rated B1 by Moody's (with a negative outlook and under review
for a possible downgrade) and B- by Standard & Poor's (with a negative outlook).
These downgrades will increase our cost of capital and collateral requirements,
and could impede our access to capital markets. As a result of these downgrades,
El Paso has realized substantial demands on its liquidity. 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.

     El Paso has embarked on its 2003 Long-Range Plan that, among other things,
defines, El Paso's future businesses, targets significant debt reduction and
establishes financial goals. An inability to meet these objectives could
adversely affect El Paso's liquidity position, and in turn 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,
2003, we have net receivables of approximately $770 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 these matters, see
Item 8, Financial Statements and Supplementary Data, Note 13.

     Furthermore, in February 2004, El Paso announced that it had completed a
review of its estimates of natural gas and oil reserves. As a result of this
review, El Paso announced that it was reducing its proved natural gas and oil
reserves by approximately 1.8 Tcfe. El Paso also announced that this reserve
revision would result in a 2003 charge of approximately $1 billion if the full
impact of the revision was taken in that period. In March 2004, El Paso provided
an update and stated that the revisions would likely result in a restatement of
its historical financial statements, the timing and magnitude of which are still
being determined. El Paso has retained a law firm to conduct an internal
investigation, which is ongoing. Also, as a result of the reduction in reserve
estimates, several class action suits have been filed against El Paso and
several of its subsidiaries, but not against us. The reduction in reserve
estimates may also become the subject of an SEC investigation or

                                        13
<PAGE>

separate inquiries by other governmental regulatory agencies. These
investigations and lawsuits may further negatively impact El Paso's credit
ratings and place further demands on its liquidity. See Item 8, Financial
Statements and Supplementary Data, Note 2 for a further discussion of the
possible impacts of this announcement.

WE MAY BE SUBJECT TO A CHANGE OF CONTROL UNDER CERTAIN CIRCUMSTANCES.

     One of our subsidiaries is one of many subsidiary guarantors of El Paso's
$3 billion revolving credit facility. In connection with its guarantee of the $3
billion revolving credit facility, the subsidiary pledged as collateral its
ownership of Mojave Pipeline, its sole asset. In addition, in connection with
its guarantee of El Paso's $3 billion revolving credit facility, our direct
parent, El Paso EPNG Investments, L.L.C. pledged as collateral its equity
interests in us. As a result, our ownership is subject to change if El Paso's
lenders under the $3 billion revolving credit facility exercise rights over
their collateral. El Paso EPNG Investments' equity in us and our ownership of
the above-referenced subsidiary also collateralizes approximately $1 billion of
other financing arrangements, including leases, letters of credit and other
facilities.

A DEFAULT UNDER EL PASO'S $3 BILLION REVOLVING CREDIT FACILITY BY ANY PARTY
COULD ACCELERATE OUR FUTURE BORROWINGS, IF ANY, UNDER THE FACILITY AND OUR
LONG-TERM DEBT, WHICH COULD ADVERSELY AFFECT OUR LIQUIDITY POSITION.

     We are a party to El Paso's $3 billion revolving credit facility. We are
only liable, however, for our borrowings under the facility, which were zero as
of December 31, 2003. Under the facility, a default by El Paso, or any other
party, could result in the acceleration of all outstanding borrowings under the
facility, including the borrowings of any non-defaulting party. El Paso's
revisions to its reserve estimates would likely result in a restatement of its
historical financial statements. Any such material restatement would result in
an event of default under El Paso's revolving credit facility, which could
result in the acceleration of any outstanding borrowings by El Paso, and would
preclude us from borrowing under the facility in the future. The acceleration of
our future borrowings, if any, under the credit facility, or the inability to
borrow under the credit facility, could adversely affect our liquidity position
and, in turn, our financial condition.

     Furthermore, the indentures governing our long-term debt include
cross-acceleration provisions. Therefore, if we borrow $25 million or more under
the credit facility and such borrowings are accelerated for any reason,
including the default of another party, our long-term debt could also be
accelerated. The acceleration of our long-term debt could also adversely affect
our liquidity position and, in turn, our financial condition.

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.

                                        14
<PAGE>

WE ARE A WHOLLY OWNED DIRECT SUBSIDIARY OF EL PASO EPNG INVESTMENTS, L.L.C., A
DIRECT SUBSIDIARY OF EL PASO.

     As we are an indirect 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.

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 effective 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, 2003                    DECEMBER 31, 2002
                                       -----------------------------------------------   ---------------------
                                        EXPECTED FISCAL YEAR OF MATURITY OF CARRYING
                                                           AMOUNTS
                                       -----------------------------------------------   CARRYING
                                        2004     THEREAFTER     TOTAL      FAIR VALUE    AMOUNTS    FAIR VALUE
                                       ------   ------------   --------   ------------   --------   ----------
                                                                (DOLLARS IN MILLIONS)
<S>                                    <C>      <C>            <C>        <C>            <C>        <C>
LIABILITIES:
  Short-term debt -- fixed rate......   $  7       $   --       $    7       $    7        $ --        $ --
       Average interest rate.........    7.3%          --
       Long-term debt, including
          current portion -- fixed
          rate.......................   $ --       $1,109       $1,109       $1,132        $958        $739
       Average interest rate.........     --          7.9%
</Table>

                                        15
<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,
                                           -----------------------
                                           2003     2002     2001
                                           -----    -----    -----
<S>                                        <C>      <C>      <C>
Operating revenues......................   $526     $564     $572
                                           ----     ----     ----
Operating expenses
  Operation and maintenance.............    163      173      190
  Merger-related costs..................     --       --       98
  Depreciation, depletion and
     amortization.......................     66       63       70
  Western Energy Settlement.............    127      412       --
  Gain on long lived assets.............     --       (1)      --
  Taxes, other than income taxes........     29       21       28
                                           ----     ----     ----
                                            385      668      386
                                           ----     ----     ----
Operating income (loss).................    141     (104)     186
Other income (expense)..................      7       --       (2)
Interest and debt expense...............    (90)     (72)     (87)
Affiliated interest income..............     20       22       58
                                           ----     ----     ----
Income (loss) before income taxes.......     78     (154)     155
Income taxes............................     31      (55)      60
                                           ----     ----     ----
Net income (loss).......................   $ 47     $(99)    $ 95
                                           ====     ====     ====
</Table>

                            See accompanying notes.

                                        16
<PAGE>

                          EL PASO NATURAL GAS COMPANY

                          CONSOLIDATED BALANCE SHEETS
                      (IN MILLIONS, EXCEPT SHARE AMOUNTS)

<Table>
<Caption>
                                            DECEMBER 31,
                                          ----------------
                                           2003      2002
                                          ------    ------
<S>                                       <C>       <C>
                          ASSETS
Current assets
  Cash and cash equivalents.............  $   26    $    3
  Accounts and notes receivable
    Customer, net of allowance of $18 in
      2003 and 2002.....................      71        79
    Affiliates..........................       4       432
    Other...............................       6        13
  Materials and supplies................      42        43
  Deferred income taxes.................     206        36
  Restricted cash.......................     443        --
  Other.................................      20        27
                                          ------    ------
         Total current assets...........     818       633
                                          ------    ------
Property, plant and equipment, at
  cost..................................   3,228     3,060
  Less accumulated depreciation,
    depletion and amortization..........   1,187     1,152
                                          ------    ------
         Total property, plant and
          equipment, net................   2,041     1,908
Other assets
  Note receivable from affiliate........     779       565
  Other.................................      86        83
                                          ------    ------
                                             865       648
                                          ------    ------
         Total assets...................  $3,724    $3,189
                                          ======    ======
           LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities
  Accounts payable
    Trade...............................  $   35    $   43
    Affiliates..........................      13        33
    Other...............................       5        11
  Short-term borrowings, including
    current maturities of long-term
    debt................................       7       200
  Accrued interest......................      25        15
  Taxes payable.........................     122       133
  Contractual deposits..................      29        35
  Western Energy Settlement.............     538       100
  Other.................................      20        53
                                          ------    ------
         Total current liabilities......     794       623
                                          ------    ------
Long-term debt, less current
  maturities............................   1,109       758
                                          ------    ------
Other liabilities
  Deferred income taxes.................     386       221
  Western Energy Settlement.............      --       312
  Other.................................     113       122
                                          ------    ------
                                             499       655
                                          ------    ------
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 at
    December 31, 2002...................      --       350
  Common stock, par value $1 per share;
    authorized and issued 1,000
    shares..............................      --        --
  Additional paid-in capital............   1,194       715
  Retained earnings.....................     128        88
                                          ------    ------
         Total stockholder's equity.....   1,322     1,153
                                          ------    ------
         Total liabilities and
          stockholder's equity..........  $3,724    $3,189
                                          ======    ======
</Table>

                            See accompanying notes.

                                        17
<PAGE>

                          EL PASO NATURAL GAS COMPANY

                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (IN MILLIONS)

<Table>
<Caption>
                                           YEAR ENDED DECEMBER 31,
                                          -------------------------
                                          2003     2002      2001
                                          -----    -----    -------
<S>                                       <C>      <C>      <C>
Cash flows from operating activities
Net income (loss).......................  $  47    $ (99)   $    95
  Adjustments to reconcile net income
    (loss) to net cash from operating
    activities
    Depreciation, depletion and
      amortization......................     66       63         70
    Western Energy Settlement...........    117      412         --
    Deferred income tax expense
      (benefit).........................    (12)    (113)        29
    Net gain on the sale of assets......     --       (1)        --
    Risk-sharing revenue................    (32)     (32)       (32)
    Non-cash portion of merger-related
      costs.............................     --       --         92
    Bad debt expense....................     --       12          6
    Other non-cash income items.........     (4)       2          2
    Working capital changes, net of
      non-cash transactions
       Accounts receivable..............     18       (4)        25
       Accounts payable.................    (33)      (4)        (5)
       Taxes payable....................     (9)      24         17
       Other working capital changes
         Assets.........................     (5)       4         (6)
         Liabilities....................    (30)      14         12
    Non-working capital changes
       Assets...........................      1       (1)        28
       Liabilities......................     33       (8)        (9)
                                          -----    -----    -------
         Net cash provided by operating
           activities...................    157      269        324
                                          -----    -----    -------
Cash flows from investing activities
  Additions to property, plant and
    equipment...........................   (225)    (193)      (157)
  Net proceeds from the sale of
    assets..............................     38        9         --
  Additions to restricted cash..........   (443)      --         --
  Net change in affiliated advances
    receivable..........................    221      304       (298)
                                          -----    -----    -------
         Net cash provided by (used in)
           investing activities.........   (409)     120       (455)
                                          -----    -----    -------
Cash flows from financing activities
  Net borrowings (repayments) of
    commercial paper and other current
    debt................................      7     (439)       159
  Payments to retire long-term debt.....   (200)    (215)        --
  Capital contribution from parent......    121       --         --
  Net proceeds from the issuance of
    long-term debt......................    347      296         --
  Dividends paid........................     --      (28)       (28)
                                          -----    -----    -------
         Net cash provided by (used in)
           financing activities.........    275     (386)       131
                                          -----    -----    -------
Increase in cash and cash equivalents...     23        3         --
Cash and cash equivalents
  Beginning of period...................      3       --         --
                                          -----    -----    -------
  End of period.........................  $  26    $   3    $    --
                                          =====    =====    =======
</Table>

                            See accompanying notes.

                                        18
<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, 2001.....................    $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
  Net income........................                                                 47            47
  Preferred stock dividends.........                                                 (7)           (7)
  Redemption of preferred stock.....    (350)                            359                        9
  Western Energy Settlement
     contribution...................                                     121                      121
  Allocated tax expense of El Paso
     equity plans...................                                      (1)                      (1)
                                        ----      -----     ----      ------       ----        ------
December 31, 2003...................    $ --      1,000     $ --      $1,194       $128        $1,322
                                        ====      =====     ====      ======       ====        ======
</Table>

                            See accompanying notes.

                                        19
<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 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.

  Regulated Operations

     Our natural gas systems are subject to the jurisdiction of the FERC in
accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of
1978, and we currently apply the provisions of Statements of Financial
Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Type
of Regulation. We perform an annual study to assess the ongoing applicability of
SFAS No. 71. The accounting required by SFAS No. 71 differs from the accounting
required for businesses that do not apply its provisions. Transactions that are
generally recorded differently as a result of applying regulatory accounting
requirements include capitalizing an equity return component on regulated
capital projects, post retirement employee benefit plans, and other costs
included in, or expected to be included in, future rates.

  Cash and Cash Equivalents

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

  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 an outstanding receivable 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.

                                        20
<PAGE>

     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 method 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, 2003, we had unamortized additional acquisition
costs of $69 million net of accumulated amortization of $82 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 one to 40 years.

     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 the proceeds received, if any, when the asset is sold or
retired.

     At December 31, 2003 and 2002, we had approximately $218 million and $146
million of construction work in progress included in our property, plant and
equipment.

     As a FERC-regulated company, we capitalize a carrying cost (an allowance
for funds used during construction, or AFUDC) on funds invested in our
construction of long-lived assets. This carrying cost consists of a return on
the investment financed by debt and a return on the investment financed by
equity. The debt portion is calculated based on our average cost of debt. Debt
amounts capitalized during the years ended December 31, 2003, 2002 and 2001,
were $3 million, $6 million and $9 million. These amounts are included as an
offset to interest expense in our income statement. The equity portion is
calculated using the most recent FERC approved equity rate of return. The equity
amount capitalized for the year ended December 31, 2003, was $4 million
(exclusive of any tax related impacts). Equity amounts capitalized for the year
ended December 31, 2002 and 2001 were immaterial. These amounts are included as
other non-operating income on our income statement. Capitalized carrying costs
for debt and equity financed construction are reflected as an increase in the
cost of the asset on our balance sheet.

  Asset Impairments

     We evaluate our assets 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.
                                        21
<PAGE>

  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
physical deliveries of natural gas are made at 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.

     Through 2003, we also recorded 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
10 for a further discussion of our rate settlement and these risk sharing
provisions.

  Environmental Costs and Other Contingencies

     We record environmental 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 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 and
state income tax returns. The policy provides, among other things, that (i) each
company in a taxable income position will accrue a current expense equivalent to
its federal and state income taxes, 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 returns. El Paso pays all
consolidated U.S. federal and state income taxes directly to the appropriate
taxing jurisdictions and, under a separate tax billing agreement, El Paso may
bill or refund its subsidiaries for their portion of these income tax payments.
                                        22
<PAGE>

2. LIQUIDITY

     In February 2004, El Paso announced that it had completed a review of its
estimates of natural gas and oil reserves. As a result of this review, El Paso
announced that it was reducing its proved natural gas and oil reserves by
approximately 1.8 Tcfe. El Paso also announced that this reserve revision would
result in a 2003 charge of approximately $1 billion if the full impact of the
revision was taken in that period. In March 2004, El Paso provided an update and
stated that the revision would likely result in a restatement of its historical
financial statements, the timing and magnitude of which are still being
determined.

     A material restatement of El Paso's prior period financial statements may
result in an "event of default" under El Paso's revolving credit facility and
various other financing transactions; specifically under the provisions of the
facility related to representations and warranties on the accuracy of its
historical financial statements and its debt to total capitalization ratio. El
Paso has received waivers on its revolving credit facility and two other
transactions. These waivers have a condition that provides for the expiration of
the waiver in thirty days, unless El Paso successfully receives waivers on other
specified transactions within that time period. El Paso is pursuing these
additional waivers and expects to receive them. However, if El Paso is unable to
obtain these additional waivers, and there is an existing event of default, El
Paso could be required to immediately repay the amounts outstanding under the
revolving credit facility, and El Paso and we would be precluded from borrowing
under this facility. We currently have no outstanding borrowings under the
facility, have never borrowed under the facility and do not believe we will need
to borrow from the facility in the future. In addition, based upon a review of
the covenants and indentures of our other outstanding indebtedness, we do not
believe that a default on the revolving credit facility would constitute an
event of default on our other debt securities.

     El Paso is a significant potential source of liquidity to us. We
participate in El Paso's cash management program. Under this 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 to El Paso under this program, and as of December 31, 2003, we had a cash
advance receivable from El Paso of $779 million, classified as a non-current
asset in our balance sheet. If El Paso were unable to meet its liquidity needs,
we would not have access to this source of liquidity and there is no assurance
that El Paso could repay the entire amounts owed to us. In that event, we could
be required to write-off some amount of these advances, which could have a
material impact on our stockholder's equity. Furthermore, we would still be
required to repay affiliated company payables. Non-cash write-downs that cause
our debt to EBITDA (as defined in our agreements) ratio to fall below 5 to 1
could prohibit us from incurring additional debt. However, this non-cash equity
reduction would not result in an event of default under our existing debt
securities. In addition, based on our current estimates of cash flows, we do not
believe we will need to seek repayment of all or part of these advances in the
next year.

     El Paso's ownership in us and our ownership in Mojave Pipeline Company
serve as collateral under El Paso's revolving credit facility and other of El
Paso's borrowings. If El Paso's lenders under this facility or those borrowings
were to exercise their rights to this collateral, our ownership could change and
our ownership interests in Mojave could be liquidated. However, this change of
control and liquidation would not constitute an event of default under our
existing debt securities.

     If, as a result of the events described above, El Paso were subject to
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. We believe that claims to
substantively consolidate us with El Paso and/or its other subsidiaries would be
without merit. However, there is no assurance that El Paso and/or its other
subsidiaries or their creditors would not advance such a claim in a bankruptcy
proceeding. If we were to be substantively consolidated in a bankruptcy
proceeding with El Paso and/or its other subsidiaries, there could be a material
adverse effect on our financial condition and our liquidity.

     Finally, we have cross-acceleration provisions in our long-term debt that
state that should we incur an event of default under which borrowings in excess
of $25 million are accelerated, our long-term debt

                                        23
<PAGE>

could also be accelerated. The acceleration of our long-term debt would
adversely affect our liquidity position and, in turn, our financial condition.

3. WESTERN ENERGY SETTLEMENT

     As a result of the Western Energy Settlement discussed in Note 10, we
recorded an initial pretax charge and obligation of $412 million in 2002. Upon
entering the definitive agreements and during the remainder of 2003, we recorded
an additional obligation and a net pretax charge in 2003 of approximately $127
million. The additional charge was primarily a result of changes in the value of
the common stock to be issued in connection with the definitive settlement
agreements and changes in the timing of settlement payments. During 2003, we
also recorded accretion expense on the discounted Western Energy Settlement
obligation of $9 million and paid other charges of $4 million both of which are
included as part of operation and maintenance expense in our income statement.
As of December 31, 2003, our total Western Energy settlement obligation was $538
million, all of which is reflected as a current liability since we estimate the
finalization of the settlement in the next twelve months. As of December 31,
2003, $10 million of the total obligation had been paid to certain settling
parties.

     El Paso established an escrow account for amounts funded by us and its
affiliates until final approval of the settlement agreements. As of December 31,
2003, total amounts in this account were $443 million, which is reflected as
restricted cash in our balance sheet and as an investing activity in our
statement of cash flows. We funded $322 million of this account by using the
majority of the net proceeds from the issuance of $355 million in senior notes
in July 2003. Additionally, during the fourth quarter of 2003, El Paso issued a
total of 17.6 million shares of its common stock on our behalf for $121 million,
the proceeds from which were placed in the escrow account. In January 2004, El
Paso issued the remaining 8.8 million shares for approximately $74 million,
which was also placed in the escrow account. Future payments from this account,
upon final approval of the settlement agreements, will be reflected as a
reduction of our cash flow from operations.

4. ACQUISITIONS AND DIVESTITURES

     In August 2003, we announced the purchase of Copper Eagle Gas Storage,
L.L.C., which is developing a natural gas storage project located outside of
Phoenix, Arizona. We purchased Copper Eagle from Arizona Gas Storage, L.L.C. and
APACS Holding L.L.C. Arizona Gas Storage is owned by our affiliate, GulfTerra
Energy Partners, L.P. The purchase price was $12 million, and under the current
terms of the purchase agreement, we paid $2.5 million in cash at the closing. In
the fourth quarter of 2003, we made a payment of $2.3 million. The remaining
balance at December 31, 2003 of $7 million is scheduled to be paid in three
quarterly installments ending September 2004. We also acquired land for
approximately $9 million that will allow for further development of that
project.

     During 2003, we sold a non-pipeline asset with a net book value of
approximately $38 million. Net proceeds from the sale were approximately $38
million, including approximately $8 million from our parent, and no gain or loss
was recognized on the sale.

5. MERGER-RELATED COSTS

     During the year ended December 31, 2001, we incurred merger-related costs
of $98 million associated with El Paso's 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, 2003, we have paid $40
million of the accrual leaving a remaining balance of $52 million. The amounts
accrued will be paid over the term of the applicable

                                        24
<PAGE>

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.

6. 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>
                                                           2003      2002      2001
                                                           -----     -----     -----
                                                                 (IN MILLIONS)
<S>                                                        <C>       <C>       <C>
Current
  Federal................................................  $  37     $  52     $  25
  State..................................................      6         6         6
                                                           -----     -----     -----
                                                              43        58        31
                                                           -----     -----     -----
Deferred
  Federal................................................    (11)     (105)       27
  State..................................................     (1)       (8)        2
                                                           -----     -----     -----
                                                             (12)     (113)       29
                                                           -----     -----     -----
          Total income taxes.............................  $  31     $ (55)    $  60
                                                           =====     =====     =====
</Table>

     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>
                                                              2003     2002     2001
                                                              ----     ----     ----
                                                                  (IN MILLIONS)
<S>                                                           <C>      <C>      <C>
Income taxes at the statutory federal rate of 35%...........  $ 27     $(54)    $54
Items creating rate differences:
  State income tax, net of federal income tax effect........     3       (1)      5
  Other.....................................................     1       --       1
                                                              ----     ----     ---
Income taxes................................................  $ 31     $(55)    $60
                                                              ====     ====     ===
Effective tax rate..........................................    40%      36%     38%
                                                              ====     ====     ===
</Table>

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

<Table>
<Caption>
                                                              2003     2002
                                                              -----    -----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
Deferred tax liabilities
  Property, plant and equipment.............................  $332     $337
  Employee benefits and deferred compensation obligations...    25       21
  Regulatory and other assets...............................    89       91
                                                              ----     ----
          Total deferred tax liability......................   446      449
                                                              ----     ----
Deferred tax assets
  Western Energy Settlement.................................   200      150
  U.S. net operating loss and tax credit carryovers.........    17       17
  Other liabilities.........................................    49       97
                                                              ----     ----
          Total deferred tax asset..........................   266      264
                                                              ----     ----
Net deferred tax liability..................................  $180     $185
                                                              ====     ====
</Table>

     Included in deferred tax assets are amounts related to the Western Energy
Settlement. Proposed tax legislation has been introduced in the U.S. Senate
which would disallow deductions for certain settlements made to or on behalf of
governmental entities. If enacted, this tax legislation could impact the
deductibility of the expenses related to the Western Energy Settlement and could
result in a write-off of some or all of the associated deferred tax assets.

                                        25
<PAGE>

     Under El Paso's tax accrual policy, we are allocated the tax effects
associated with our employees' non-qualified dispositions of employee stock
purchase plan stock, the exercise of non-qualified stock options and the vesting
of restricted stock as well as restricted stock dividends. This allocation
increased taxes payable by $1 million in 2003 and reduced taxes payable by $1
million in 2002 and $4 million in 2001. These tax effects are included in
additional paid-in capital in our balance sheet.

     As of December 31, 2003, 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.

7. FINANCIAL INSTRUMENTS

     The carrying amounts and estimated fair values of our financial instruments
are as follows at December 31:

<Table>
<Caption>
                                                               2003                     2002
                                                       ---------------------    ---------------------
                                                       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)..............................   $1,109      $1,132        $958        $739
</Table>

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

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

     As of December 31, 2003 and 2002, 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.

8. REGULATORY ASSETS AND LIABILITIES

     Our regulatory assets and regulatory liabilities as of December 31, 2003
and 2002 are presented below.

<Table>
<Caption>
                                                                        REMAINING AVERAGE
                  DESCRIPTION                       2003      2002       RECOVERY PERIOD
                  -----------                       ----      ----      -----------------
                                                    (IN MILLIONS)
<S>                                                 <C>       <C>       <C>
Non-current regulatory assets
  Unamortized loss on reacquired debt...........    $23       $25           18 years
  Grossed-up deferred taxes on capitalized funds
     used during construction...................     15        14            Various
  Postretirement benefits(1)....................     11         9              N/A
  Under-collected state income taxes............      4         5            2 years
                                                    ---       ---
          Total non-current regulatory
            assets(2)...........................    $53       $53
                                                    ===       ===
Non-current regulatory liabilities
  Property and plant depreciation...............    $28       $22            Various
  Excess deferred federal income taxes..........      4         5            2 years
                                                    ---       ---
          Total non-current regulatory
            liabilities(2)......................    $32       $27
                                                    ===       ===
</Table>

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

(1) This amount is not included in our rate base on which we earn a current
    return.

(2) Amounts are included as other non-current assets and liabilities in our
    balance sheet.

                                        26
<PAGE>

9. DEBT AND OTHER CREDIT FACILITIES

  Debt

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

<Table>
<Caption>
                                                               2003      2002
                                                              ------     ----
                                                               (IN MILLIONS)
<S>                                                           <C>        <C>
     6.75% Notes due 2003...................................  $   --     $200
     7.625% Notes due 2010..................................     355       --
     8.625% Debentures due 2022.............................     260      260
     7.50% Debentures due 2026..............................     200      200
     8.375% Notes due 2032..................................     300      300
                                                              ------     ----
                                                               1,115      960
  Less: Unamortized discount................................       6        2
       Current maturities...................................      --      200
                                                              ------     ----
          Total long-term debt, less current maturities.....  $1,109     $758
                                                              ======     ====
</Table>

     In June 2002, we issued $300 million aggregate principal amount 8.375%
notes due 2032. Proceeds were approximately $296 million, net of issuance costs.

     In July 2003, we issued $355 million of senior unsecured notes with an
annual interest rate of 7.625% due 2010. Net proceeds were approximately $347
million. In November 2003, we retired $200 million of 6.75% notes due 2003.

     None of the principal amounts of our long-term debt matures in the next 5
years.

     Our long-term debt contains cross-acceleration provisions, the most
restrictive of which is a $25 million cross-acceleration clause. If triggered,
repayment of our long-term debt, could be accelerated.

  Letters of Credit

     In 2001, we issued $3 million of letters of credit for an unconsolidated
affiliate, $2 million of which matures in April 2005. We cancelled $1 million of
these letters of credit in January 2004, undrawn.

  Other Financing Arrangements

     In April 2003, El Paso entered into a new $3 billion revolving credit
facility, with a $1.5 billion letter of credit sublimit, which matures on June
30, 2005. The credit facility has a borrowing cost of LIBOR plus 350 basis
points, letter of credit fees of 350 basis points and a commitment fee of 75
basis points on the unused portion of the facility. This facility replaced El
Paso's previous $3 billion revolving credit facility. El Paso's $1 billion
revolving credit facility which matured in August 2003, and approximately $1
billion of other El Paso financing arrangements (including leases, letters of
credit and other facilities) were also amended to conform El Paso's obligations
under those arrangements to the new credit facility. We, along with El Paso and
our affiliates, ANR Pipeline Company, Tennessee Gas Pipeline Company (TGP) and
Colorado Interstate Gas Company (CIG), are borrowers under El Paso's $3 billion
revolving credit facility, and El Paso's equity in several of its subsidiaries,
including its equity in us and our equity in Mojave Pipeline Company,
collateralize the credit facility and the other financing arrangements. We are
only liable for amounts we directly borrow. As of December 31, 2003, $850
million was outstanding and $1.2 billion in letters of credit were issued under
the $3 billion revolving credit facility, none of which were borrowed by or
issued on behalf of us. See Note 2 for a discussion regarding El Paso's possible
default on the $3 billion revolving credit facility.

     We were jointly and severally liable for any outstanding amounts under El
Paso's $1 billion revolving credit facility through its maturity in August 2003,
and under El Paso's $3 billion revolving credit facility through August 2003.

                                        27
<PAGE>

     Under the new $3 billion revolving credit facility and other indentures, we
are subject to a number of restrictions and covenants. The most restrictive of
these include (i) limitations on the incurrence of additional debt, based on a
ratio of debt to EBITDA (as defined in the agreements); (ii) limitations on the
use of proceeds from borrowings; (iii) limitations, in some cases, on
transactions with our affiliates; (iv) limitations on the incurrence of liens;
(v) potential limitations on our ability to declare and pay dividends; and (vi)
potential limitations on our ability to participate in the El Paso cash
management program discussed in Note 13. For the year ended December 31, 2003,
we were in compliance with these covenants.

10. COMMITMENTS AND CONTINGENCIES

  Legal Proceedings

     Western Energy Settlement.  On June 26, 2003, El Paso announced that it had
executed a Master Settlement Agreement, or MSA, to resolve the principal
litigation relating to the sale or delivery of natural gas and/or electricity to
or in the Western United States. The MSA settles California lawsuits in state
court, the California Public Utilities Commission (CPUC) proceeding at the FERC,
and the California Attorney General investigation discussed herein. Parties to
the settlement agreements include private class action litigants in California;
the governor and lieutenant governor of California; the attorneys general of
California, Washington, Oregon and Nevada; the CPUC; the California Electricity
Oversight Board; the California Department of Water Resources; Pacific Gas and
Electric Company (PG&E), Southern California Edison Company, five California
municipalities and six non-class private plaintiffs. We are a party to the MSA
and, as such, will bear a portion of the costs and obligations of the
settlements, as discussed more fully below. For a discussion of the charges
taken in connection with the Western Energy Settlement, see Note 3.

     The MSA is in addition to the Joint Settlement Agreement, or JSA, announced
earlier in June 2003 where we agreed to provide structural relief to the
settling parties. In the JSA, we agreed to do the following:

     - Subject to the conditions in the settlement, provide 3.29 Bcf/d of
       primary firm pipeline capacity on our system to California delivery
       points during a five year period from the date of settlement, and not add
       any firm incremental load to our system that would prevent us from
       satisfying our obligation to provide this capacity;

     - Construct a new $173 million, 320 MMcf/d, Line 2000 Power-up expansion
       project, and forgo recovery of the cost of service of this expansion
       until our next rate case before the FERC;

     - Clarify the rights of Northern California shippers to recall some of our
       system capacity (Block II capacity) to serve markets in PG&E's service
       area; and

     - With limited exceptions, bar any of our affiliated companies from
       obtaining additional firm capacity on our pipeline system during a five
       year period from the effective date of the settlement.

     In connection with the JSA, a Stipulated Judgment will be filed with the
United States District Court for the Central District of California. This
Stipulated Judgment provides for the enforcement of some of the obligations
contained in the JSA.

     In the MSA, we agreed to the following terms:

     - We admitted to no wrongdoing;

     - We would make cash payments totaling $93.5 million for the benefit of the
       parties to the definitive settlement agreements subsequent to the signing
       of these agreements. This amount represents the originally announced $100
       million cash payment less credits for amounts that have been paid to
       other settling parties;

     - We agreed to pay amounts equal to the proceeds from the issuance of
       approximately 26.4 million shares by El Paso of El Paso common stock on
       behalf of the settling parties. In this transaction, El Paso sold its
       common stock and provided the proceeds from the issuance to us through an
       equity contribution to satisfy this obligation; and

                                        28
<PAGE>

     - We would eliminate the originally announced 20-year obligation to pay $22
       million per year in cash by depositing $250 million in escrow for the
       benefit of the settling parties within 180 days of the signing of the
       definitive settlement agreements. This prepayment eliminates any
       collateral that might have been required on the $22 million per year
       payment over the next 20 years.

     As of December 31, 2003, $443 million had been deposited into an escrow
account for the benefit of the settling parties related to the items discussed
above. In January 2004, we deposited an additional $74 million in the escrow
account (see Note 3).

     El Paso Merchant Energy L.P. (EPME), our affiliate, was also a party to the
settlement agreements and, along with El Paso, is obligated to provide a total
of $1,027 million (on an undiscounted basis) under these agreements. Of this
amount, $2 million will be paid by El Paso upon final approval of the definitive
settlement agreements, $125 million represents a contractual price discount that
will be realized over the remaining 30-month life of an existing power contract
between EPME and one of the settling parties, and $900 million will be paid by
EPME or El Paso in installments over the next 20 years. The long-term payment
obligation is a direct obligation of El Paso and EPME and will be supported by
collateral posted by El Paso's affiliates in amounts specified by the settlement
agreements. We have guaranteed the payment of these obligations in the event El
Paso and EPME fail to pay these amounts.

     In June 2003, in anticipation of the execution of the MSA, El Paso, the
CPUC, PG&E, Southern California Edison Company, and the City of Los Angeles
filed the JSA described above with the FERC in resolution of specific
proceedings before that agency. In November 2003, the FERC approved the JSA with
minor modifications. Our east of California shippers have filed a request for
rehearing and the matter is currently pending before the FERC.

     We were 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. In December 2003, the California State Court in San
Diego dismissed us from seven of the fifteen class action suits and entered
judgment approving the MSA. The judgment was appealed. This appeal will delay
the effective date of the settlement. Seven other cases will be dismissed after
the MSA becomes effective. The fifteenth lawsuit was settled in May 2003.

     In November 2002, a lawsuit was filed in the Superior Court of California,
County of Los Angeles against us, as well as numerous other unrelated entities,
alleging the creation of artificially high natural gas index prices via the
reporting of false price and volume information. This purported class action on
behalf of California consumers alleges various unfair business practices and
seeks restitution, disgorgement of profits, compensatory and punitive damages,
and civil fines. This lawsuit will be resolved upon approval of the Western
Energy Settlement.

     In September 2001, we received a civil document subpoena from the
California Attorney General, seeking information said to be relevant to the
Attorney General's ongoing investigation into the high electricity prices in
California. This proceeding will be resolved upon approval of the Western Energy
Settlement.

     In February 2003, the state of Nevada and two individuals filed a class
action lawsuit in Nevada state court naming us and a number of our affiliates as
defendants. The allegations are similar to those in the California cases. The
suit seeks monetary damages and other relief under Nevada antitrust and consumer
protection laws. This proceeding will be resolved upon approval of the Western
Energy Settlement.

     Proposed tax legislation has been introduced in the U.S. Senate which could
impact the deductibility of the expenses related to the Western Energy
Settlement. More details on its impact may be found in Note 6.

     Other Energy Market Lawsuits.  In April 2003, Sierra Pacific Resources and
Nevada Power Company filed a suit against us. The allegations were similar to
those in the California cases. On January 27, 2004, the Court dismissed the
lawsuit. An appeal is likely. Our costs and legal exposure related to this
lawsuit are not currently determinable.

                                        29
<PAGE>

     In January 2003, a lawsuit titled IMC Chemicals v. EPME, et al. was filed
in California state court against us and our affiliates. The suit arose out of a
gas supply contract between IMC Chemicals (IMCC) and EPME and sought to void the
Gas Purchase Agreement between IMCC and EPME for gas purchases until December
2003. IMCC contended that EPME and its affiliates manipulated market prices for
natural gas and, as part of that manipulation, induced IMCC to enter into the
contract. In furtherance of its attempt to void the contract, IMCC repeated the
allegations and claims of the California lawsuits described above. EPME intends
to enforce the terms of the contract and counterclaim for contract damages. EPME
has filed a counterclaim for contract damages in excess of $5 million. IMCC's
claim is undeterminable but appears to be in excess of $20 million. Our costs
and legal exposure related to this lawsuit are not currently determinable.

     Henry W. Perlman et. al. v. El Paso Corporation, El Paso Natural Gas
Company, El Paso Merchant Energy, L.P., et al.  A purported class action suit
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. This lawsuit has been voluntarily dismissed.

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

     Phelps Dodge vs. EPNG.  On February 3, 2004, one of our customers, Phelps
Dodge, and a number of its affiliates filed a lawsuit against us in the State
Court of Arizona. Plaintiffs claim we violated Arizona anti-trust statutes and
allege that during 2000-2001, we unlawfully manipulated and inflated gas prices.
Our costs and legal exposure related to this lawsuit are not currently
determinable.

     Shareholder Class Action Suit.  In November 2002, we were named as a
defendant in a shareholder derivative suit titled Marilyn Clark v. Byron
Allumbaugh, David A. Arledge, John M. Bissell, Juan Carlos Braniff, James F.
Gibbons, Anthony W. Hall, Ronald L. Kuehn, J. Carleton MacNeil, Thomas McDade,
Malcolm Wallop, William Wise, Joe B. Wyatt, El Paso Natural Gas Company and El
Paso Merchant Energy Company filed in state court in Houston. This shareholder
derivative suit generally alleges that manipulation of California gas supply and
gas prices exposed our parent, El Paso, to claims of antitrust conspiracy, FERC
penalties and erosion of share value. The plaintiffs have not asked for any
relief with regard 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. As a result, the U.S. Department
of Transportation's Office of Pipeline Safety issued a Notice of Probable
Violation and Proposed Civil Penalty to us proposing a fine of $2.5 million. We
have fully accrued for these fines. In October 2001, we filed a response with
the Office of Pipeline Safety disputing each of the alleged violations. In
December 2003, the matter was referred to the Department of Justice.

     In addition, after a public hearing conducted by the National
Transportation Safety Board (NTSB) on its investigation of the Carlsbad rupture,
the NTSB published its final report in April 2003. The NTSB stated that it had
determined that the probable cause of the August 19, 2000 rupture was a
significant reduction in pipe wall thickness due to severe internal corrosion,
which occurred because our corrosion control program "failed to prevent, detect,
or control internal corrosion" in the pipeline. The NTSB also determined that
ineffective federal preaccident inspections contributed to the accident by not
identifying deficiencies in our internal corrosion control program.

     On November 1, 2002, we received a federal grand jury subpoena for
documents relating to the rupture and we cooperated fully in responding to the
subpoena. That subpoena has since expired. In December 2003 and January 2004,
eight current and former employees were served with testimonial subpoenas issued
by the grand jury. Testimony by six of these individuals occurred in March 2004.
Additional testimonial and documentary subpoenas may be issued by the grand
jury.

                                        30
<PAGE>

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

     Parties to four of the settled lawsuits have since filed an additional
lawsuit titled Diane Heady et al. v. EPEC and EPNG in Harris County, Texas, on
November 20, 2002, seeking additional sums based upon their interpretation of
earlier agreements. In addition, a lawsuit entitled Baldonado et al. vs. EPNG
was filed on June 30, 2003, in state court in Eddy County, New Mexico, on behalf
of firemen and EMS personnel who responded to the fire and who allegedly have
suffered psychological trauma. The Baldonado lawsuit was dismissed by the court.
We expect it will be appealed. Our costs and legal exposure related to the Heady
and Baldonado lawsuits are currently not determinable, however, we believe these
matters will be fully covered by insurance.

     Grynberg.  In 1997, we and a number of our affiliates were named defendants
in actions brought by Jack Grynberg on behalf of the U.S. Government under the
False Claims Act. Generally, these complaints allege an industry-wide conspiracy
to underreport the heating value as well as the volumes of the natural gas
produced from federal and Native American lands, which deprived the U.S.
Government of royalties. The plaintiff in this case seeks royalties that he
contends the government should have received had the volume and heating value
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). Discovery is proceeding. Our costs and legal exposure related to these
lawsuits and claims are not currently determinable.

     Will Price (formerly Quinque).  We and a number of our affiliates are named
defendants in Will Price et al. v. Gas Pipelines and Their Predecessors, et al.,
filed in 1999 in the District Court of Stevens County, Kansas. Plaintiffs allege
that the defendants mismeasured natural gas volumes and heating content of
natural gas on non-federal and non-Native American lands and seek certification
of a nationwide class of natural gas working interest owners and natural gas
royalty owners to recover royalties that they contend these owners should have
received had the volume and heating value of natural gas produced from their
properties been differently measured, analyzed, calculated and reported,
together with prejudgment and postjudgment interest, punitive damages, treble
damages, attorneys' fees, costs and expenses, and future injunctive relief to
require the defendants to adopt allegedly appropriate gas measurement practices.
No monetary relief has been specified in this case. Plaintiffs motion for class
certification of a nationwide class of natural gas working interest owners and
natural gas royalty owners was denied on April 10, 2003. Plaintiffs were granted
leave to file a Fourth Amended Petition, which narrows the proposed class to
royalty owners in wells in Kansas, Wyoming and Colorado, and removes claims as
to heating content. A second class action has since been filed as to the heating
content claims. Our costs and legal exposure related to these lawsuits and
claims are not currently determinable.

     Bank of America.  We are a named defendant, with Burlington Resources,
Inc., in two class action lawsuits styled Bank of America, et al. v. El Paso
Natural Gas Company, et al., and Deane W. Moore, et al. v. Burlington Northern,
Inc., et. al., each filed in 1997 in the District Court of Washita County, State
of Oklahoma and subsequently consolidated by the court. Plaintiffs contend that
defendants underpaid royalties from 1983 to the present on natural gas produced
from specified wells in Oklahoma through the use of below-market prices,
improper deductions and transactions with affiliated companies and in other
instances failed to pay or delayed in the payment of royalties on certain gas
sold from these wells. The plaintiffs seek an accounting and damages for alleged
royalty underpayments, plus interest from the time such amounts were allegedly
due, as well as punitive damages. The plaintiffs have filed expert reports
alleging damages in excess of $1 billion. While Burlington accepted our tender
of defense in 1997, and had been defending the matter since that time, it has
recently asserted contractual claims for indemnity against us. We believe we
have substantial defenses to the plaintiffs' claims as well as to the claims for
indemnity. The court has certified the plaintiff classes of royalty and
overriding royalty interest owners, and the parties are proceeding with
discovery.
                                        31
<PAGE>

It is anticipated that this matter will be scheduled for trial during 2004. A
third action, styled Bank of America, et al v. El Paso Natural Gas and
Burlington Resources Oil & Gas Company, was filed in October 2003 in the
District Court of Kiowa County, Oklahoma asserting similar claims as to
specified shallow wells in Oklahoma, Texas and New Mexico. A class has not been
certified. We believe we have substantial defenses to the plaintiffs' claims as
well as to the claims for indemnity. Our costs and legal exposure related to
these lawsuits and claims are not currently determinable.

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

     For each of our outstanding legal matters, we evaluate the merits of the
case, our exposure in the matter, possible legal or settlement strategies and
the likelihood of an unfavorable outcome. If we determine that an unfavorable
outcome is probable and can be estimated, we establish the necessary accruals.
As this information becomes available, or other relevant developments occur, we
will adjust our accrual amounts accordingly. While there are still uncertainties
related to the ultimate costs we may incur, based upon our evaluation and
experience to date, we believe our current reserves are adequate. As of December
31, 2003, we had accrued approximately $541 million for all outstanding legal
matters, which is reflected in the Western Energy Settlement liability and other
current liabilities on our balance sheet.

  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, 2003, we had accrued approximately $28 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. Our accrual at December 31, 2003, was based on the
probability of the most likely outcome that can be reasonably estimated;
however, our exposure could be as high as $54 million. Below is a reconciliation
of our accrued liability as of December 31, 2003 (in millions).

<Table>
<S>                                                           <C>
Balance as of January 1, 2003...............................       $29
Additions/adjustments for remediation activities............         1
Payments for remediation activities.........................        (2)
                                                                   ---
Balance as of December 31, 2003.............................       $28
                                                                   ===
</Table>

     For 2004, we estimate that our total remediation expenditures will be
approximately $4 million, which primarily will be expended under government
directed clean-up plans. In addition, we expect to make capital expenditures for
environmental matters of approximately $2 million in the aggregate for the years
2004 through 2008. These expenditures primarily relate to compliance with clean
air regulations.

     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, 2003, we have estimated our share of the remediation costs at these sites to
be between $12 million and $17 million. Since the clean-up costs are estimates
and are subject to revision as more information becomes available about the
extent of remediation required, and because in some cases we have asserted a
defense to any liability, our estimates could change. Moreover, liability under
the federal CERCLA statute is joint and several, meaning that we could be
required to pay in excess of our pro rata share of remediation costs. Our
understanding of the financial strength of other PRPs has been considered, where
appropriate, in estimating our liabilities. Reserves for these matters are
included in the environmental reserve discussed above.

                                        32
<PAGE>

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

  Rates and Regulatory Matters

     CPUC Complaint Proceeding.  This matter will be settled by the Western
Energy Settlement. In April 2000, the CPUC filed a complaint under Section 5 of
the Natural Gas Act (NGA) with the FERC alleging that our sale of approximately
1.2 Bcf/d of capacity to our affiliate, EPME, raised issues of market power and
violation of the FERC's marketing affiliate regulations and asked that the
contracts be voided. In the spring and summer of 2001, two hearings were held
before an ALJ to address the market power issue and the affiliate issue. On
November 19, 2003, in approving the JSA, FERC also vacated both of the ALJ's
Initial Decisions. As discussed under the Western Energy Settlement, a request
for rehearing of this order is pending.

     Systemwide Capacity Allocation Proceeding.  In July 2001, several of our
customers filed complaints against us at the FERC claiming that we had failed to
provide appropriate service on our pipeline. As a result of the FERC's many
orders in these proceedings; (i) FR shippers were required to convert from full
requirements to contract demand service on September 1, 2003; (ii) firm
customers were assigned specific receipt point rights in lieu of systemwide
receipt point rights; (iii) reservation charges will be credited to all firm
customers if we fail to schedule confirmed volumes except in cases of force
majeure; in such force majeure cases, the reservation charge credits will be
limited to the return and associated tax portion of our reservation rate; (iv)
no new firm contract can be executed unless we can demonstrate there is adequate
capacity on the system available to provide the service; (v) capacity
turned-back to us from contracts that terminated or expired from May 31, 2002
and May 1, 2003, could not be remarketed because it was included in the volumes
allocated to the FR shippers; and (vi) a backhaul service was established from
our California delivery points for existing and new shippers. We also received
certificate authority to add compression to our Line 2000 to increase our system
by 320 MMcf/d without receiving cost coverage for the expansion until our next
rate case (in January 2006).

     On July 9, 2003, the FERC found that we had not violated our certificates,
our contractual obligations, including our obligations under the 1996 Rate
Settlement (discussed below), or our tariff provisions as a result of the
capacity allocations that have occurred on the system since the 1996 Rate
Settlement. In addition, the FERC found we had correctly stated the capacity
that is available on a firm basis for allocation among our shippers and that we
had properly allocated that capacity. On a prospective basis, the FERC ordered
us to set aside a pool of 110 MMcf/d of capacity for use by the converting FR
shippers until the first phase of the Line 2000 Power-up expansion (discussed
below) went into service (as of February 27, 2004, after which the pool of
capacity has been reduced to 50 MMcf/d until the second phase of the Power-up is
placed in service in mid-2004).

     On July 18, 2003, the FR shippers filed an appeal of the July 9 order with
the D.C. Circuit (Arizona Corporation Comm'n, et al. v. FERC, No. 03-1206) and
subsequently sought a stay of the FERC's orders. The stay was denied by the
court. Other parties have filed appeals of the FERC's orders and all such
appeals have been consolidated. The final outcome of these appeals cannot be
predicted with certainty.

     Rate Settlement.  Our current rate settlement establishes our base rates
through December 31, 2005. The settlement has certain requirements applicable to
the Post-Settlement Period. These requirements include a provision which limits
the rates to be charged to a portion of our contracted portfolio to a level
equal to the inflation-escalated rate from the 1996 rate settlement. We are
currently reviewing the definition and applicability of this future capped-rate
requirement given, among other things, the customer and contract changes
required by the capacity allocation proceeding discussed above. We have the
right to increase or

                                        33
<PAGE>

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 participated in risk sharing provisions. Under these
provisions, we received 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 was
recognized in revenues ratably over the risk sharing period which ended December
31, 2003. As of December 31, 2003 all risk sharing revenues had been collected
from customers under this provision. Amounts received for relinquished capacity
sold to customers, above certain dollar levels specified in our rate settlement,
obligated us to refund a portion of the excess to customers. Under this
provision, we refunded a total of $46 million of 2002 revenues to customers
during 2002 and the first quarter of 2003. During 2003, we established an
additional refund obligation of $40 million of which $28 million has been
refunded to customers as of December 31, 2003. Both the risk and revenue sharing
provisions of the rate settlement expired at the end of 2003.

     Line 2000 Project.  In July 2000, we applied with the FERC for a
certificate of public convenience and necessity for our Line 2000 project, which
was designed to replace old compression on the system with a converted oil
pipeline, resulting in no increase in system capacity. In response to demand
conditions on our system, however, we filed in March 2001 to amend our
application to convert the project to an expansion project of 230 MMcf/d. In May
2001, the FERC authorized the amended Line 2000 project. We placed the line in
service in November 2002 at a capital cost of $189 million. The cost of the Line
2000 conversion will not be included in our rates until our next rate case,
which will be effective on January 1, 2006.

     In October 2002, pursuant to the FERC's orders in the systemwide capacity
allocation proceeding, we filed with the FERC for a certificate of public
convenience and necessity to add compression to our Line 2000 project to
increase the capacity of that line by an additional 320 MMcf/d at an estimated
capital cost of approximately $173 million for all phases of the Power-up. On
June 4, 2003, the FERC issued an order approving our certificate application. On
November 14, 2003, FERC denied pending requests for rehearing on its June 4
order approving the power-up. The project is currently under construction and
Phase I was placed in service on February 27, 2004, adding 120 MMcf/d of
compression to our system.

     There are other regulatory rules and orders in various stages of adoption,
review and/or implementation, none of which we believe will have a material
impact on us.

     While the outcome of our outstanding 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 and accruals related to these
matters.

 Other Matters

     Enron Bankruptcy.  In December 2001, Enron Corp. and a number of its
subsidiaries, including Enron North America Corp. and Enron Power Marketing,
Inc., filed for Chapter 11 bankruptcy protection in the United States Bankruptcy
Court for the Southern District of New York. Enron North America had
transportation contracts on our system. The transportation contracts have now
been rejected and we have filed a proof of claim in the amount of approximately
$128 million, which included $18 million for amounts due for services provided
through the date the contracts were rejected and $110 million for damage claims
arising from the rejection of its transportation contracts. We anticipate that
Enron will vigorously oppose these claims. Given the uncertainties of Bankruptcy
Court, 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 this matter cannot be predicted with certainty, based
on current information and our existing accrual, we do not expect the ultimate
resolution 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 this matter, and adjust our accrual accordingly.
                                        34
<PAGE>

The impact of these changes may have a material effect on our results of
operations, our financial position, and our cash flows in the periods these
events occur.

  Capital Commitments

     At December 31, 2003, we had capital and investment commitments of $43
million 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.

  Operating Leases

     We lease property, facilities and equipment under various operating leases.
Minimum annual rental commitments on operating leases as of December 31, 2003,
were as follows:

<Table>
<Caption>
                        YEAR ENDING
                        DECEMBER 31,                          OPERATING LEASES
------------------------------------------------------------  ----------------
                                                              (IN MILLIONS)
<S>                                                           <C>
   2004.....................................................        $13
   2005.....................................................         14
   2006.....................................................         14
   2007.....................................................          6
                                                                    ---
          Total.............................................        $47
                                                                    ===
</Table>

     Aggregate minimum commitments have not been reduced by minimum sublease
rentals of approximately $6 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, 2003, 2002 and 2001 was $3 million.

11. 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. In March 2003, El Paso suspended the matching contribution.
Effective July 1, 2003, El Paso began making matching contributions again at a
rate of 50 percent of participant basic contributions up to 6 percent. El Paso
is responsible for benefits accrued under its plans and allocates the related
costs to its affiliates. See Note 13 for a summary of transactions with
affiliates.

                                        35
<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. We expect to contribute $11 million to our other postretirement
benefit plan in 2004.

     On December 8, 2003, the Medicare Prescription Drug, Improvement and
Modernization Act of 2003 was signed into law. The benefit obligations and costs
reported below, which include prescription drug coverage, do not reflect the
impact of this legislation. Current accounting standards that are not yet
effective may require changes to previously reported benefit information once
they are finalized.

     The following table presents 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 (the plan reporting date):

<Table>
<Caption>
                                                              2003     2002
                                                              -----    ----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
Change in benefit obligation
  Benefit obligation at beginning of period.................  $ 100    $ 95
  Interest cost.............................................      7       7
  Actuarial loss............................................      9       5
  Benefits paid.............................................     (9)     (7)
                                                              -----    ----
  Benefit obligation at end of period.......................  $ 107    $100
                                                              =====    ====
Change in plan assets
  Fair value of plan assets at beginning period.............  $  60    $ 61
  Actual return on plan assets..............................      8      (5)
  Employer contributions....................................     11      11
  Benefits paid.............................................     (9)     (7)
                                                              -----    ----
  Fair value of plan assets at end of period................  $  70    $ 60
                                                              =====    ====
Reconciliation of funded status
  Under funded status as of September 30....................  $ (37)   $(40)
  Fourth quarter contributions..............................      3       3
  Unrecognized net actuarial gain...........................     32      28
  Unrecognized net transition obligation....................     15      23
                                                              -----    ----
  Prepaid benefit cost at December 31.......................  $  13    $ 14
                                                              =====    ====
</Table>

     Benefit costs include the following components for the year ended December
31,:

<Table>
<Caption>
                                                              2003    2002    2001
                                                              ----    ----    ----
                                                                 (IN MILLIONS)
<S>                                                           <C>     <C>     <C>
  Interest cost.............................................  $ 7     $ 7     $ 6
  Expected return on plan assets............................   (4)     (4)     (5)
  Amortization of net actuarial gain........................    1      --      (1)
  Amortization of transition obligation.....................    8       8       8
                                                              ---     ---     ---
  Net postretirement benefit cost...........................  $12     $11     $ 8
                                                              ===     ===     ===
</Table>

                                        36
<PAGE>

     Benefit obligations are based on actuarial estimates and assumptions. The
following table details the weighted average assumptions we used for our other
postretirement plan for 2003, 2002 and 2001:

<Table>
<Caption>
                                                               2003    2002    2001
                                                              ------   -----   -----
<S>                                                           <C>      <C>     <C>
Assumptions related to benefit obligations at September 30:
  Discount rate............................................    6.00%   6.75%
Assumptions related to benefit costs at December 31:
  Discount rate............................................    6.75%   7.25%   7.75%
  Long-term rate of return on plan assets(1)...............    7.50%   7.50%   7.50%
</Table>

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

(1) The expected return on plan assets is a pre-tax rate (before a tax rate
    ranging from 15% to 17% on postretirement benefits) that is primarily based
    on an expected risk-free investment return, adjusted for historical risk
    premiums and specific risk adjustments associated with our debt and equity
    securities. These expected returns were then weighted based on the target
    asset allocations of our investment portfolio.

     Actuarial estimates for our postretirement benefits plan assumed a weighted
average annual rate of increase in the per capita costs of covered health care
benefits of 10.0 percent in 2003, gradually decreasing to 5.5 percent by the
year 2008. Assumed health care cost trends can have a significant effect on the
amounts reported for our postretirement benefit plan. A one-percentage point
change in assumed health care cost trends would have the following effects:

<Table>
<Caption>
                                                              2003     2002
                                                              -----    -----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
One percentage point increase
  Aggregate of service cost and interest cost...............  $ --     $  1
  Accumulated postretirement benefit obligation.............  $  8     $  8
One percentage point decrease
  Aggregate of service cost and interest cost...............  $ --     $ (1)
  Accumulated postretirement benefit obligation.............  $ (7)    $ (8)
</Table>

     Other Postretirement Plan Assets.  The following table provides the actual
asset allocations in our postretirement plan as of September 30:

<Table>
<Caption>
                                                              ACTUAL    ACTUAL
                                                               2003      2002
                                                              ------    ------
<S>                                                           <C>       <C>
Equity securities...........................................     32%       37%
Debt securities.............................................     67        31
Other.......................................................      1        32
                                                                ---       ---
Total.......................................................    100%      100%
</Table>

     The target allocation for the invested assets is 65% equity/35% fixed
income. In late 2003, we modified our target asset allocations for our
postretirement plan to increase our equity allocation to 65 percent of total
plan assets. As of September 30, 2003, we had not yet adjusted our portfolio's
investments to reflect this change in strategy. Other assets are held in cash
for payment of benefits upon presentment. Any El Paso stock held by the plan is
held indirectly through investments in mutual funds.

     The primary investment objective of our plan is to ensure, that over the
long-term life of the plan, an adequate pool of sufficiently liquid assets
exists to support the benefit obligation to participants, retirees and
beneficiaries. In meeting this objective, the plan seeks to achieve a high level
of investment return consistent with a prudent level of portfolio risk.
Investment objectives are long-term in nature covering typical market cycles of
three to five years. Any shortfall in investment performance compared to
investment objectives is the result of general economic and capital market
conditions.

12. PREFERRED STOCK

     On April 3, 2003, El Paso contributed its 500,000 shares of our 8%
preferred stock to us, including accrued dividends of $9 million. The total
contribution was approximately $359 million and is reflected as

                                        37
<PAGE>

additional paid in capital in our stockholder's equity. During each of the years
ended December 31, 2002 and 2001, we paid $28 million in dividends on our
preferred stock.

13. TRANSACTIONS WITH AFFILIATES

     We participate in El Paso's cash management program which matches
short-term cash surpluses and need requirements of its participating affiliates,
thus minimizing total borrowing from outside sources. As of December 31, 2003
and 2002, we had advanced to El Paso $779 million and $990 million. The rate of
interest at December 31, 2003 and 2002, was 2.8% and 1.5%. These receivables are
due upon demand; however, we do not anticipate settlement within the next twelve
months. As of December 31, 2003 and 2002, we have classified $779 million and
$565 million as non-current note receivables from affiliates. See Note 2 for a
discussion of issues regarding our ongoing participation in and the
collectibility of these receivables.

     At December 31, 2003 and 2002, we had other accounts receivable from
affiliates of $4 million and $7 million. In addition, we had accounts payable to
affiliates of $13 million at December 31, 2003, and $33 million at December 31,
2002. These balances arose in the normal course of business. As a result of El
Paso's credit rating downgrades, we maintained $6 million and $5 million as of
December 31, 2003 and 2002 in contractual deposits related to an affiliate's
transportation contract on our EPNG system.

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

     We provided El Paso Merchant Energy L.P. transportation services for the
years ended 2003, 2002 and 2001. We recognized revenues of $18 million, $46
million and $72 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.

     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, 2003, 2002 and 2001, the annual charges were $52
million, $49 million and $43 million. TGP allocates 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 2003, 2002 and 2001, the annual charges were $8
million, $7 million and $6 million. El Paso Field Services allocated payroll and
other expenses to us. During 2003, 2002 and 2001 those amounts were $9 million,
$8 million and $7 million. In addition, we performed operational, financial,
accounting and administrative services for, an affiliate, CIG. The amounts
received for these services are recorded as reimbursement of operating expenses
and for 2003, 2002 and 2001 were $13 million, $12 million and $7 million. We
believe all the allocation methods are reasonable.

     The following table shows revenues and charges from our affiliates:

<Table>
<Caption>
                                                                  YEARS ENDED
                                                                  DECEMBER 31,
                                                              --------------------
                                                              2003    2002    2001
                                                              ----    ----    ----
                                                                 (IN MILLIONS)
<S>                                                           <C>     <C>     <C>
Revenues from affiliates....................................  $18     $46     $72
Operation and maintenance costs from affiliates.............   69      64      56
Reimbursement of operating expenses.........................   13      12       7
</Table>

                                        38
<PAGE>

14. TRANSACTIONS WITH MAJOR CUSTOMER

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

<Table>
<Caption>
                                                            2003      2002      2001
                                                            ----      ----      ----
                                                                 (IN MILLIONS)
<S>                                                         <C>       <C>       <C>
Southern California Gas Company...........................  $154      $139      $135
</Table>

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

(1) Our contracts with Southern California Gas Company include 1,215 BBtu/d
    which expires in 2006 and 93 BBtu/d which expires 2004 through 2007.

15. SUPPLEMENTAL CASH FLOW INFORMATION

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

<Table>
<Caption>
                                                              2003      2002      2001
                                                              ----      ----      ----
                                                                   (IN MILLIONS)
<S>                                                           <C>       <C>       <C>
Interest paid, net of capitalized interest..................  $74       $75       $82
Income tax payments.........................................   51        33        14
</Table>

16. SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

     Financial information by quarter is summarized below:

<Table>
<Caption>
                                                        QUARTERS ENDED
                                    -------------------------------------------------------
                                    MARCH 31   JUNE 30   SEPTEMBER 30   DECEMBER 31   TOTAL
                                    --------   -------   ------------   -----------   -----
                                                         (IN MILLIONS)
<S>                                 <C>        <C>       <C>            <C>           <C>
2003
  Operating revenues..............    $132      $134         $132          $ 128      $ 526
  Operating income (loss).........      73       (87)          91             64        141
  Net income (loss)...............      35       (63)          44             31         47
2002
  Operating revenues..............    $152      $144         $139          $ 129      $ 564
  Operating income (loss).........      82        82           75           (343)      (104)
  Net income (loss)...............      44        44           38           (225)       (99)
</Table>

                                        39
<PAGE>

                         REPORT OF INDEPENDENT AUDITORS

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, 2003 and 2002, and the consolidated
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2003 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 the 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.

     As discussed in Note 2 to the consolidated financial statements, the
Company's indirect parent, El Paso Corporation, may be in default of covenants
contained in its revolving credit facility and other financing transactions.
Such an event of default could have a material impact on the Company's
liquidity. Certain waivers have been obtained by El Paso Corporation, however,
additional waivers must be obtained and certain conditions must be satisfied to
continue the effectiveness of the waivers.

/s/ PricewaterhouseCoopers LLP

Houston, Texas
March 15, 2004

                                        40
<PAGE>

                                  SCHEDULE II

                          EL PASO NATURAL GAS COMPANY
                       VALUATION AND QUALIFYING ACCOUNTS

                  YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
                                 (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>
2003
  Allowance for doubtful accounts.......     $ 18          $ --         $ --          $ --        $ 18
  Legal reserves........................      415           136(1)        --           (10)(3)     541
  Environmental reserves................       29             1           --            (2)         28
  Provision for refunds.................       13            40(4)                     (41)(4)      12
2002
  Allowance for doubtful accounts.......     $  6          $ 12         $ --          $ --        $ 18
  Legal reserves........................        2           423(2)        --           (10)(3)     415
  Environmental reserves................       29            --           --            --          29
  Provision for refunds.................       19            46(4)        --           (52)(4)      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
</Table>

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

(1) Reflects charges for the Western Energy Settlement.

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

(3) Relates to payments made pursuant to the Western Energy Settlement.

(4) Relates to amounts collected and paid for our risk sharing provisions with
    customers.

                                        41
<PAGE>

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

     None.

ITEM 9A. CONTROLS AND PROCEDURES

     Evaluation of Controls and Procedures.  Under the supervision and with the
participation of management, including our principal executive officer and
principal financial officer, we have evaluated the effectiveness of the design
and operation of our disclosure controls and procedures (Disclosure Controls)
and internal controls over financial reporting (Internal Controls) as of the end
of the period covered by this 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. 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. Therefore, a control system, no matter how well conceived and
operated, can provide only reasonable, not absolute, assurance that the
objectives of the control system are met. Our Disclosure Controls and Internal
Controls are designed to provide such reasonable assurances of achieving our
desired control objectives, and our principal executive officer and principal
financial officer have concluded that our Disclosure Controls and Internal
Controls are effective in achieving that level of reasonable assurance.

     No Significant Changes in Internal Controls.  We have sought to determine
whether there were any "significant deficiencies" or "material weaknesses" in El
Paso Natural Gas Company's Internal Controls, or whether the company had
identified any acts of fraud involving personnel who have a significant role in
El Paso Natural Gas Company's Internal Controls. This information was important
both for the controls evaluation generally and because the principal executive
officer and principal financial officer are required to disclose that
information to our Board's Audit Committee and our independent auditors and to
report on related matters in this section of the Annual Report. The principal
executive officer and principal financial officer note that there has not been
any change in Internal Controls that occurred during the most recent fiscal
quarter that has materially affected, or is reasonably likely to materially
affect, Internal Controls.

     Effectiveness of Disclosure Controls.  Based on the controls evaluation,
our principal executive officer and principal financial officer have concluded
that the Disclosure Controls are effective to ensure that material information
relating to El Paso Natural Gas Company and its consolidated subsidiaries is
made known to management, including the principal executive officer and
principal financial officer, on a timely basis.

                                        42
<PAGE>

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

                                    PART III

     Item 10, "Directors and Executive Officers of the Registrant;" Item 11,
"Executive Compensation;" Item 12, "Security Ownership of Certain Beneficial
Owners and Management and Related Stockholder Matters;" 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. PRINCIPAL ACCOUNTANT FEES AND SERVICES

     The Audit Fees for the years ended December 31, 2003 and 2002 of $588,500
and $490,000 were for professional services rendered by PricewaterhouseCoopers
LLP for the audits of the consolidated financial statements of El Paso Natural
Gas Company, the review of documents filed with the Securities and Exchange
Commission, consents, and the issuance of comfort letters. No other
audit-related, tax or other services were provided by our auditors for the years
ended December 31, 2003 and 2002.

     We are an indirect wholly owned subsidiary of El Paso and do not have a
separate audit committee. El Paso's Audit Committee has adopted a pre-approval
policy for audit and non-audit services. For a description of El Paso's
pre-approval policies for audit and non-audit related services, see El Paso
Corporation's proxy statement.

                                    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......................   16
     Consolidated Balance Sheets............................   17
     Consolidated Statements of Cash Flows..................   18
     Consolidated Statements of Stockholder's Equity........   19
     Notes to Consolidated Financial Statements.............   20
     Report of Independent Auditors.........................   40

2. Financial statement schedules.

     Schedule II -- Valuation and Qualifying Accounts.......   41

     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.............................................   44
</Table>

     (b) REPORTS ON FORM 8-K:

     None.

                                        43
<PAGE>

                          EL PASO NATURAL GAS COMPANY

                                  EXHIBIT LIST
                               DECEMBER 31, 2003

     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 April 8, 2003
                            (Exhibit 3.A to our 2003 Second Quarter Form 10-Q).
          3.B            -- By-laws dated June 24, 2002 (Exhibit 3.B to our 2002 Form
                            10-K).
          4.A            -- Indenture dated as of January 1, 1992, between El Paso
                            Natural Gas Company 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 El Paso
                            Natural Gas Company 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).
          4.C            -- Indenture dated as of July 21, 2003, between El Paso
                            Natural Gas Company and Wilmington Trust Company, as
                            Trustee, (Exhibit 4.1 to our Form 8-K filed July 23,
                            2003).
         10.A            -- $3,000,000,000 Revolving Credit Agreement dated as of
                            April 16, 2003 among El Paso Corporation, El Paso Natural
                            Gas Company, Tennessee Gas Pipeline Company and ANR
                            Pipeline Company, as Borrowers, the Lenders Party
                            thereto, and JPMorgan Chase Bank, as Administrative
                            Agent, ABN Amro Bank N.V. and Citicorp North America,
                            Inc., as Co-Document Agents, Bank of America, N.A. and
                            Credit Suisse First Boston, as Co-Syndication Agents,
                            J.P. Morgan Securities Inc. and Citigroup Global Markets
                            Inc., as Joint Bookrunners and Co-Lead Arrangers.
                            (Exhibit 99.1 to El Paso Corporation's Form 8-K filed
                            April 18, 2003).
         10.B            -- $1,000,000,000 Amended and Restated 3-Year Revolving
                            Credit Agreement dated as of April 16, 2003 among El Paso
                            Corporation, El Paso Natural Gas Company and Tennessee
                            Gas Pipeline Company, as Borrowers, The Lenders Party
                            thereto, and JPMorgan Chase Bank, as Administrative
                            Agent, ABN Amro Bank N.V. and Citicorp North America,
                            Inc., as Co-Document Agents, Bank of America, N.A., as
                            Syndication Agent, J.P. Morgan Securities Inc. and
                            Citigroup Global Markets Inc., as Joint Bookrunners and
                            Co-Lead Arrangers. (Exhibit 99.2 to El Paso Corporation's
                            Form 8-K filed April 18, 2003).
         10.C            -- Security and Intercreditor Agreement dated as of April
                            16, 2003 among El Paso Corporation, the persons referred
                            to therein as Pipeline Company Borrowers, the persons
                            referred to therein as Grantors, each of the
                            Representative Agents, JPMorgan Chase Bank, as Credit
                            Agreement Administrative Agent and JPMorgan Chase Bank,
                            as Collateral Agent, Intercreditor Agent, and Depository
                            Bank. (Exhibit 99.3 to El Paso Corporation's Form 8-K
                            filed April 18, 2003).
</Table>

                                        44
<PAGE>

<Table>
<Caption>
        EXHIBIT
         NUMBER                                  DESCRIPTION
        -------                                  -----------
<C>                      <S>
         10.D            -- Master Settlement Agreement dated as of June 24, 2003, by
                            and between, on the one hand, El Paso Corporation, El
                            Paso Natural Gas Company, and El Paso Merchant Energy,
                            L.P.; and, on the other hand, the Attorney General of the
                            State of California, the Governor of the State of
                            California, the California Public Utilities Commission,
                            the California Department of Water Resources, the
                            California Energy Oversight Board, the Attorney General
                            of the State of Washington, the Attorney General of the
                            State of Oregon, the Attorney General of the State of
                            Nevada, Pacific Gas & Electric Company, Southern
                            California Edison Company, the City of Los Angeles, the
                            City of Long Beach, and classes consisting of all
                            individuals and entities in California that purchased
                            natural gas and/or electricity for use and not for resale
                            or generation of electricity for the purpose of resale,
                            between September 1, 1996 and March 20, 2003, inclusive,
                            represented by class representatives Continental Forge
                            Company, Andrew Berg, Andrea Berg, Gerald J. Marcil,
                            United Church Retirement Homes of Long Beach, Inc., doing
                            business as Plymouth West, Long Beach Brethren Manor,
                            Robert Lamond, Douglas Welch, Valerie Welch, William
                            Patrick Bower, Thomas L. French, Frank Stella, Kathleen
                            Stella, John Clement Molony, SierraPine, Ltd., John
                            Frazee and Jennifer Frazee, John W.H.K. Phillip, and Cruz
                            Bustamante (Exhibit 10.HH to our second quarter 2003 Form
                            10-Q).
         10.E            -- Joint Settlement Agreement submitted and entered into by
                            El Paso Natural Gas Company, El Paso Merchant Energy
                            Company, El Paso Merchant Energy-Gas, L.P., the Public
                            Utilities Commission of the State of California, Pacific
                            Gas & Electric Company, Southern California Edison
                            Company and the City of Los Angeles (Exhibit 10.II to our
                            second quarter 2003 Form 10-Q).
         21              -- Omitted pursuant to the reduced disclosure format
                            permitted by General Instruction I to Form 10-K.
        *31.A            -- Certification of Chief Executive Officer pursuant to sec.
                            302 of the Sarbanes-Oxley Act of 2002.
        *31.B            -- Certification of Chief Financial Officer pursuant to sec.
                            302 of the Sarbanes-Oxley Act of 2002.
        *32.A            -- Certification of Chief Executive Officer pursuant to 18
                            U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the
                            Sarbanes-Oxley Act of 2002.
        *32.B            -- Certification of Chief Financial Officer pursuant to 18
                            U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the
                            Sarbanes-Oxley Act of 2002.
</Table>

UNDERTAKING

     We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph
(4)(iii), to furnish to the U.S. Securities and Exchange Commission upon request
all constituent instruments defining the rights of holders of our long-term debt
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.

                                        45
<PAGE>

                                   SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized on the 15th day of
March 2004.

                                            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, this
report has been signed below by the following persons on behalf of the
registrant 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 15, 2004
-----------------------------------------------------    Executive Officer and Director
              (John W. Somerhalder II)                   (Principal Executive Officer)

                 /s/ JAMES J. CLEARY                   President and Director            March 15, 2004
-----------------------------------------------------
                  (James J. Cleary)

                 /s/ GREG G. GRUBER                    Senior Vice President, Chief      March 15, 2004
-----------------------------------------------------    Financial Officer, Treasurer
                  (Greg G. Gruber)                       and Director (Principal
                                                         Financial and Accounting
                                                         Officer)
</Table>

                                        46
<PAGE>

                          EL PASO NATURAL GAS COMPANY

                                 EXHIBIT INDEX
                               DECEMBER 31, 2003

     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 April 8, 2003
                            (Exhibit 3.A to our 2003 Second Quarter Form 10-Q).
          3.B            -- By-laws dated June 24, 2002 (Exhibit 3.B to our 2002 Form
                            10-K).
          4.A            -- Indenture dated as of January 1, 1992, between El Paso
                            Natural Gas Company 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 El Paso
                            Natural Gas Company 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).
          4.C            -- Indenture dated as of July 21, 2003, between El Paso
                            Natural Gas Company and Wilmington Trust Company, as
                            Trustee, (Exhibit 4.1 to our Form 8-K filed July 23,
                            2003).
         10.A            -- $3,000,000,000 Revolving Credit Agreement dated as of
                            April 16, 2003 among El Paso Corporation, El Paso Natural
                            Gas Company, Tennessee Gas Pipeline Company and ANR
                            Pipeline Company, as Borrowers, the Lenders Party
                            thereto, and JPMorgan Chase Bank, as Administrative
                            Agent, ABN Amro Bank N.V. and Citicorp North America,
                            Inc., as Co-Document Agents, Bank of America, N.A. and
                            Credit Suisse First Boston, as Co-Syndication Agents,
                            J.P. Morgan Securities Inc. and Citigroup Global Markets
                            Inc., as Joint Bookrunners and Co-Lead Arrangers.
                            (Exhibit 99.1 to El Paso Corporation's Form 8-K filed
                            April 18, 2003).
         10.B            -- $1,000,000,000 Amended and Restated 3-Year Revolving
                            Credit Agreement dated as of April 16, 2003 among El Paso
                            Corporation, El Paso Natural Gas Company and Tennessee
                            Gas Pipeline Company, as Borrowers, The Lenders Party
                            thereto, and JPMorgan Chase Bank, as Administrative
                            Agent, ABN Amro Bank N.V. and Citicorp North America,
                            Inc., as Co-Document Agents, Bank of America, N.A., as
                            Syndication Agent, J.P. Morgan Securities Inc. and
                            Citigroup Global Markets Inc., as Joint Bookrunners and
                            Co-Lead Arrangers. (Exhibit 99.2 to El Paso Corporation's
                            Form 8-K filed April 18, 2003).
         10.C            -- Security and Intercreditor Agreement dated as of April
                            16, 2003 among El Paso Corporation, the persons referred
                            to therein as Pipeline Company Borrowers, the persons
                            referred to therein as Grantors, each of the
                            Representative Agents, JPMorgan Chase Bank, as Credit
                            Agreement Administrative Agent and JPMorgan Chase Bank,
                            as Collateral Agent, Intercreditor Agent, and Depository
                            Bank. (Exhibit 99.3 to El Paso Corporation's Form 8-K
                            filed April 18, 2003).
</Table>
<PAGE>

<Table>
<Caption>
        EXHIBIT
         NUMBER                                  DESCRIPTION
        -------                                  -----------
<C>                      <S>
         10.D            -- Master Settlement Agreement dated as of June 24, 2003, by
                            and between, on the one hand, El Paso Corporation, El
                            Paso Natural Gas Company, and El Paso Merchant Energy,
                            L.P.; and, on the other hand, the Attorney General of the
                            State of California, the Governor of the State of
                            California, the California Public Utilities Commission,
                            the California Department of Water Resources, the
                            California Energy Oversight Board, the Attorney General
                            of the State of Washington, the Attorney General of the
                            State of Oregon, the Attorney General of the State of
                            Nevada, Pacific Gas & Electric Company, Southern
                            California Edison Company, the City of Los Angeles, the
                            City of Long Beach, and classes consisting of all
                            individuals and entities in California that purchased
                            natural gas and/or electricity for use and not for resale
                            or generation of electricity for the purpose of resale,
                            between September 1, 1996 and March 20, 2003, inclusive,
                            represented by class representatives Continental Forge
                            Company, Andrew Berg, Andrea Berg, Gerald J. Marcil,
                            United Church Retirement Homes of Long Beach, Inc., doing
                            business as Plymouth West, Long Beach Brethren Manor,
                            Robert Lamond, Douglas Welch, Valerie Welch, William
                            Patrick Bower, Thomas L. French, Frank Stella, Kathleen
                            Stella, John Clement Molony, SierraPine, Ltd., John
                            Frazee and Jennifer Frazee, John W.H.K. Phillip, and Cruz
                            Bustamante (Exhibit 10.HH to our second quarter 2003 Form
                            10-Q).
         10.E            -- Joint Settlement Agreement submitted and entered into by
                            El Paso Natural Gas Company, El Paso Merchant Energy
                            Company, El Paso Merchant Energy-Gas, L.P., the Public
                            Utilities Commission of the State of California, Pacific
                            Gas & Electric Company, Southern California Edison
                            Company and the City of Los Angeles (Exhibit 10.II to our
                            second quarter 2003 Form 10-Q).
         21              -- Omitted pursuant to the reduced disclosure format
                            permitted by General Instruction I to Form 10-K.
        *31.A            -- Certification of Chief Executive Officer pursuant to sec.
                            302 of the Sarbanes-Oxley Act of 2002.
        *31.B            -- Certification of Chief Financial Officer pursuant to sec.
                            302 of the Sarbanes-Oxley Act of 2002.
        *32.A            -- Certification of Chief Executive Officer pursuant to 18
                            U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the
                            Sarbanes-Oxley Act of 2002.
        *32.B            -- Certification of Chief Financial Officer pursuant to 18
                            U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the
                            Sarbanes-Oxley Act of 2002.
</Table>