EL PASO CORP/DE - 10-K Annual Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

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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 1-14365

EL PASO CORPORATION
(Exact Name of Registrant as Specified in Its Charter)

DELAWARE 76-0568816
(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)

TELEPHONE NUMBER: (713) 420-2600
INTERNET WEBSITE: WWW.ELPASO.COM

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

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 [ ] No [X].

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 [X] No [ ].

STATE THE AGGREGATE MARKET VALUE OF THE VOTING AND NON-VOTING COMMON EQUITY
HELD BY NON-AFFILIATES OF THE REGISTRANT.

Aggregate market value of the voting stock (which consists solely of shares
of common stock) held by non-affiliates of the registrant as of June 30, 2003
computed by reference to the closing sale price of the registrant's common stock
on the New York Stock Exchange on such date: $4,838,867,717.

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 $3 per share. Shares outstanding on September 24,
2004: 643,441,738

DOCUMENTS INCORPORATED BY REFERENCE

List hereunder the following documents if incorporated by reference and the
part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is
incorporated: None
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EL PASO CORPORATION

TABLE OF CONTENTS

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

/d = per day
Bbl = barrels
BBtu = billion British thermal units
BBtue = billion British thermal unit
equivalents
Bcf = billion cubic feet
Bcfe = billion cubic feet of natural gas
equivalents
MBbls = thousand barrels
Mcf = thousand cubic feet
Mcfe = thousand cubic feet of natural gas
equivalents
Mgal = thousand gallons
MMBbls = million barrels
MMBtu = million British thermal units
MMcf = million cubic feet
MMcfe = million cubic feet of natural gas
equivalents
MMWh = thousand megawatt hours
MTons = thousand tons
MW = megawatt
TBtu = trillion British thermal units
Tcfe = trillion cubic feet of natural gas
equivalents

When we refer to natural gas and oil in "equivalents," we are doing so to
compare quantities of oil with quantities of natural gas or to express these
different commodities in a common unit. In calculating equivalents, we use a
generally recognized standard in which one Bbl of oil is equal to six Mcf of
natural gas. Oil includes natural gas liquids unless otherwise specified. Also,
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", "ours", or "El Paso", we are describing
El Paso Corporation and/or our subsidiaries.

i

RESTATEMENT OF HISTORICAL FINANCIAL INFORMATION

In February 2004, we completed the December 31, 2003 reserve estimation
process for the proved natural gas and oil reserves in our Production segment.
The results of this process indicated that a significant downward revision to
our proved reserve estimates was needed. In August 2004, we also determined that
we had not properly accounted for certain derivatives, primarily those
associated with many of the historical hedges of our anticipated natural gas
production. After investigations into the factors that caused these issues, we
determined that a material portion of the downward reserve revisions should be
reflected in historical periods and that the historical accounting for our
production and certain other hedges should be corrected. Accordingly, we
restated our historical financial information for the years from 1999 to 2002
and for the first nine months of 2003.

In the restatement for our reserve revisions, an investigation determined
that certain personnel used aggressive, and at times, unsupportable methods to
book proved reserves. In some instances, certain personnel provided historical
proved reserve estimates that they knew or should have known were incorrect at
the time they were reported. The investigation also found that we did not, in
some cases, maintain adequate documentation and records to support historically
booked proved natural gas reserves.

In the restatement for certain hedges, we determined that we had not
properly applied generally accepted accounting principles for many of our
production hedges, certain other hedge transactions related to pipeline capacity
and hedges of the production owned by one of our pipeline subsidiaries. Most of
these hedging transactions were entered into from 1999 to 2002 under Master
International Swaps and Derivatives Association, or ISDA, swap agreements and
the restatement involved transactions where we entered into an identical,
offsetting trading position at the same time we entered into the hedge. In
reaching the conclusion to restate, we concluded that the business purpose for
the offsetting transactions was not alone sufficient to satisfy the standards
for separate accounting treatment from the hedge transaction. Generally accepted
accounting principles, or GAAP, requires that the objective of the two
transactions is not one that could have been accomplished through a single,
though less efficient, transaction. In addition, we considered two additional
factors in reaching this conclusion. First, we determined that some of the
offsetting transactions had not been completed at market prices. Second, we had
originally concluded that there was separate economic substance in the hedge and
the offsetting transactions, based on our view that there was credit risk
associated with the separate enforcement of the transactions. Upon further
review, we determined that there was insufficient credit risk associated with
enforcing these transactions to support that original conclusion.

As a result of these conclusions, we restated our historical proved natural
gas and oil reserve estimates, the financial information derived from those
estimates, and financial information related to our historical accounting for
certain hedges for the periods from 1999 through 2002, and for the first nine
months of 2003. The total cumulative impact of the restatement was a reduction
of our previously reported stockholders' equity as of September 30, 2003 of
approximately $2.4 billion. Of this amount, approximately $1.7 billion related
to the restatement of our historical reserve estimates and approximately $0.7
billion related to the restatement of our historical accounting for hedges.
These restated amounts have been reflected only in this Annual Report on Form
10-K, and we did not revise our historically filed reports for the impacts of
the restatements. Consequently, you should not rely on historical information
contained in those prior filings since this filing replaces and revises those
historically reported amounts.

For a further discussion of the impact of the restatements on our selected
financial information, see Part II, Item 6, Selected Financial Data; for a more
detailed discussion of the factors leading to the restatements, the restatement
methods used and the financial impacts of the restatements, see Item 8,
Financial Statements and Supplementary Data, Note 1; and for a discussion of
control weaknesses that contributed to these issues and changes we have made or
are in the process of making to our control procedures, see Item 9A, Controls
and Procedures.

1

PART I

ITEM 1. BUSINESS

We are an energy company originally founded in 1928 in El Paso, Texas. For
many years, we served as a regional pipeline company conducting business mainly
in the western United States. From 1996 through 2001, we expanded to become an
international energy company through a number of mergers and acquisitions as
well as internal growth initiatives. By 2001, our operations extended from
natural gas production to power generation, and included many new ventures and
businesses, in addition to our traditional natural gas businesses. During this
period, our total assets grew from approximately $7 billion at December 31, 1995
to over $44 billion following the completion of The Coastal Corporation merger
in January 2001. During this same time period, we incurred substantial amounts
of debt and other obligations.

In the latter part of 2001 and in 2002, our industry and business were
adversely impacted by a number of significant events, including (i) the
bankruptcy of a number of energy sector participants, (ii) the general decline
in the energy trading industry, (iii) performance in some areas of our business
that did not meet our expectations, (iv) credit rating downgrades of us and
other industry participants and (v) regulatory and political pressures arising
out of the western energy crisis of 2000 and 2001.

These events adversely affected our operating results, our financial
condition and our liquidity, requiring us to re-prioritize our businesses
throughout 2002 and 2003. Over this two year period, we refocused on our natural
gas assets, and divested or otherwise sold our interests in a significant number
of assets, generating proceeds in excess of $6 billion. As a result of these
sales activities and the performance of our businesses during this time period,
we have also experienced significant losses.

In 2003, we appointed a new chief executive officer. Following an
assessment period by our executive management team, we publicly announced our
2003 Long-Range Plan (Long-Range Plan) in December 2003. This Long-Range Plan
establishes the roadmap for the future direction and focus of our company. The
Long-Range Plan, among other things:

- defines our core businesses;

- establishes timetables for debt reduction; and

- sets a timeline for exiting from non-core businesses and assets.

BUSINESS SEGMENTS

For the years ended December 31, 2003, we operated through four business
segments -- Pipelines, Production, Field Services and Merchant Energy. Through
these segments, we provided the following energy related services:

CONTINUING OPERATIONS

Interstate Natural Gas Our interstate pipeline system is the largest in the
Transmission and Storage U.S., and owns or has interests in approximately
58,000 miles of pipeline and approximately 430 Bcf of
storage capacity. We provide customers with interstate
natural gas transmission and storage services from a
diverse group of supply regions to major markets
around the country, serving many of the largest market
areas.

Production Our production business holds interests in
approximately 8.1 million net developed and
undeveloped acres and had over 2.6 Tcfe of proved
natural gas and oil reserves worldwide at the end of
2003. During 2003, our production averaged
approximately 1.1 Bcfe/d. During the first eight
months of 2004, daily production averaged 855 MMcfe/d.

2

Midstream Services Our midstream business owns a 50 percent interest in
the general partner of a large publicly traded master
limited partnership, GulfTerra Energy Partners, L.P.
(GulfTerra), as well as a significant limited partner
interest in GulfTerra. GulfTerra provides onshore and
offshore midstream services to a diverse base of
customers. Our midstream businesses also provide
gathering and processing services, primarily in south
Texas and south Louisiana. We sold a substantial
portion of our limited and general partnership
interests in GulfTerra and our south Texas gathering
and processing assets in 2004.

Energy Marketing and Our energy marketing and trading business markets our
Trading natural gas and oil production and is managing and/or
liquidating our historical energy trading portfolio.

Power Generation and Supply Our power businesses own or manage almost 15,000 MW of
gross generating capacity in 16 countries. Our plants
serve customers under long-term and market-based
contracts or sell to the open market in spot market
transactions. This business also manages power supply
arrangements with electric utility customers to meet
their peak electricity requirements. We have sold or
expect to sell substantially all of our domestic power
business in 2004.

DISCONTINUED OPERATIONS

Petroleum Markets Our petroleum markets business owns and operates
refineries in the northeastern U.S. and in Aruba, with
a capacity to refine over 430,000 Bbls of oil per day.
We completed the sale of substantially all of this
business in early 2004.

Our Long-Range Plan did not impact our segment structure as of December 31,
2003, but will impact our reported segments going forward. Under our Long-Range
Plan, we will provide natural gas and related energy products and services
through two primary business lines: a regulated business line and an unregulated
business line. Below is a chart that outlines the composition of those business
lines:

(CHART)
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(1) In the long-term, we intend to dispose of substantially all of our assets
and investments in our international power business, except in Brazil.

3

Our long-term strategy will focus on:

Below is a description of each of our existing business segments. Our
current business segments of Pipelines, Production, Field Services and Merchant
Energy are strategic business units that provide a variety of energy products
and services. We managed each segment separately through the end of 2003 and
into early 2004, and each segment requires different technology and marketing
strategies. As we implement our Long-Range Plan, these segments will change to
reflect the way our operations will be managed in the future. For additional
discussion of our business segments, see Part II, Item 7, Management's
Discussion and Analysis of Financial Condition and Results of Operations. For
our segment operating results and identifiable assets, see Part II, Item 8,
Financial Statements and Supplementary Data, Note 26, which is incorporated
herein by reference.

REGULATED BUSINESS -- PIPELINES SEGMENT

Our Pipelines segment provides natural gas transmission, storage and
related services and owns or has interests in approximately 58,000 miles of
interstate natural gas pipelines in the U.S. and internationally. In the U.S.,
our systems connect the nation's principal natural gas supply regions to the six
largest consuming regions in the U.S.: the Gulf Coast, California, the
Northeast, the Midwest, the Southwest and the Southeast. These pipelines
represent the largest integrated coast-to-coast mainline natural gas
transmission system in the U.S. Our U.S. pipeline systems also own or have
interests in approximately 430 Bcf of storage capacity used to provide a variety
of flexible services to our customers and a liquefied natural gas (LNG) terminal
at Elba Island, Georgia. Our international pipeline operations include access to
systems in Canada and Mexico and until June 2004, interests in three operating
natural gas transmission systems in Australia, two of which were sold in June
2004. The remaining Australian investment was placed into receivership in the
second quarter of 2004.

Our Pipelines segment conducts its business activities primarily through
seven wholly owned and five partially owned interstate transmission systems
along with five underground natural gas storage entities and the entity that
owns the Elba Island LNG terminalling facility. The tables below detail our
wholly owned and partially owned interstate transmission systems:

Wholly Owned Interstate Transmission Systems

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(1) Includes throughput transported on behalf of affiliates.

(2) This capacity reflects winter-sustainable west-flow capacity (including 320
MMcf/d due to the completion of our Line 2000 compression added in 2004) and
800 MMcf/d of east-end delivery capacity.

5

We also have six pipeline expansion projects underway as of September 2004
that have been approved by the Federal Energy Regulatory Commission (FERC):

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(1) Looping is the installation of a pipeline, parallel to an existing pipeline,
with tie-ins at several points along the existing pipeline. Looping
increases the transmission system's capacity.
(2) Placed in service in August 2004.

Partially Owned Interstate Transmission Systems

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(1) These systems are accounted for as equity investments.
(2) Volumes represent the systems' total design capacity and average throughput
and are not adjusted for our ownership interest.
(3) We have an investment in Citrus Corporation, which owns this system.
(4) We sold our equity interest in the Portland Natural Gas Transmission System
in the fourth quarter of 2003.

6

(5) Our investment in this system was placed in receivership in the second
quarter of 2004.
(6) Our interests in these systems were sold in June 2004.

In addition to the storage capacity on our transmission systems, we own or
have interests in the following natural gas storage entities:

Underground Natural Gas Storage Entities

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(1) Includes a total of 133 Bcf contracted to affiliates. Storage capacity is
under long-term contracts and is not adjusted for our ownership interest.

(2) These systems were accounted for as equity investments as of December 31,
2003.

In addition to our pipeline systems and storage facilities, we own an LNG
receiving terminal located on Elba Island, near Savannah, Georgia. The facility
is capable of achieving a peak sendout of 675 MMcf/d and a base load sendout of
446 MMcf/d. The terminal was placed in service and began receiving deliveries in
December 2001. The capacity at the terminal was initially contracted with our
affiliate, El Paso Merchant Energy L.P. (EPME), under a contract that extends
through 2023. This contract was assigned by EPME to a subsidiary of British Gas,
BG LNG Services, LLC in December 2003. In 2003, the FERC approved our plan to
expand the peak sendout capacity of the Elba Island facility by 540 MMcf/d and
the base load sendout by 360 MMcf/d (for a total peak sendout capacity once
completed of 1,215 MMcf/d and a base load sendout of 806 MMcf/d). The expansion
is estimated to cost approximately $159 million and has a planned in-service
date of February 2006.

Regulatory Environment

Our interstate natural gas transmission systems and storage operations are
regulated by the FERC under the Natural Gas Act of 1938 and the Natural Gas
Policy Act of 1978. Each of our pipeline systems and storage facilities operates
under FERC-approved tariffs that establish rates, terms and conditions for
services to our customers. Generally, the FERC's authority extends to:

- rates and charges for natural gas transportation, storage, terminalling
and related services;

- 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 service;

- 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 services to our customers, including a reasonable return on our
invested capital. Our revenues from transportation, storage and related services
(transportation services revenues) consist of reservation revenues and usage
revenues.
7

Reservation revenues are from customers (referred to as firm customers) whose
contracts (which are for varying terms) reserve capacity on our pipeline systems
or storage facilities. These firm customers are obligated to pay a monthly
reservation or demand charge, regardless of the amount of natural gas they
transport or store, for the term of their contracts. Usage revenues are from
both firm customers and interruptible customers (those without reserved
capacity) who pay usage charges based on the volume of gas actually transported,
stored, injected or withdrawn. In 2003, approximately 84 percent of our
transportation services revenues were attributable to charges paid by firm
customers. The remaining 16 percent of our transportation services revenues were
attributable to usage charges paid by both firm and interruptible customers. Due
to our regulated nature, our financial results have historically been relatively
stable. However, these results can be subject to volatility due to factors such
as weather, changes in natural gas prices and market conditions, regulatory
actions, competition and the creditworthiness of our customers.

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

Markets and Competition

We provide natural gas services to a variety of customers including natural
gas producers, marketers, end-users and other natural gas transmission,
distribution and electric generation companies. In performing these services, we
compete with other pipeline service providers as well as alternative energy
sources such as coal, nuclear and hydroelectric power for power generation and
fuel oil for heating.

Other Matters Impacting Our Markets

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
industry by creating more demand for natural gas turbine generated electric
power, but this effect is offset, in varying degrees, by increased generation
efficiency and more effective use of surplus electric capacity as a result of
open market access. In addition, in several regions of the country, new capacity
additions have exceeded load growth and transmission capabilities out of those
regions. This may inhibit owners of new power generation facilities from signing
firm contracts with pipelines and may impair their creditworthiness.

Imported LNG is one of the fastest growing supply sectors of the natural
gas market. Terminals and other regasification facilities can serve as important
sources of supply for pipelines, enhancing the delivery capabilities and
operational flexibility and complementing traditional supply and market areas.
These LNG delivery systems also may compete with pipelines for transportation of
gas into market areas.

Our existing contracts mature at various times and in varying amounts of
throughput capacity. As our pipeline contracts expire, our ability to extend our
existing contracts or re-market expiring contracted capacity is dependent on the
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 market trends and volatility. Subject to regulatory
constraints, we attempt to re-contract or re-market our capacity at the maximum
rates allowed under our tariffs, although we, at times, discount these rates to
remain competitive. The level of discount varies for each of our pipeline
systems.

8

The following table details the markets we serve and the competition on
each of our wholly owned pipeline systems as of December 31, 2003:

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(1) Approximately 1,567 MMcf/d currently under contract is subject to early
termination in August 2006 provided shippers give timely notice of an intent
to terminate. If all of these rights were exercised, the weighted average on
the remaining contract terms would decrease to approximately three years.

9

UNREGULATED BUSINESSES -- PRODUCTION SEGMENT

Our Production segment is engaged in the exploration for, and the
acquisition, development and production of natural gas, oil and natural gas
liquids, primarily in North America. In the U.S., we controlled over 3 million
net acres of leasehold acreage through our onshore and coal seam operations in
20 states, including New Mexico, Louisiana, Texas, Oklahoma, Alabama and Utah,
and through our offshore operations in federal and state waters in the Gulf of
Mexico. As of December 31, 2003, we have international exploration and
production rights in Australia, Bolivia, Brazil, Canada, Hungary, Indonesia and
Turkey. During 2003, daily production averaged 1.1 Bcfe/d, and our proved
natural gas and oil reserves at December 31, 2003, were approximately 2.6 Tcfe.

Our December 31, 2003 proved reserve estimates reflect a 1.8 Tcfe downward
revision to our proved natural gas and oil reserves. Following an investigation
into the factors that caused this significant revision, we determined that a
material portion of these revisions should be reflected in prior years and, as a
result, we restated our historical proved reserve estimates and our historical
financial information derived from these proved reserve estimates. In August
2004, we also determined that we had not properly applied the accounting related
to many of our historical hedges, primarily those associated with hedges of our
anticipated natural gas production. Following an investigation into this matter,
we concluded that our historical financial statements should be further
restated. See Part II, Item 6, Selected Financial Data and Item 8, Financial
Statements and Supplementary Data, Note 1 for a further discussion of these
restatements.

As part of our Long-Range Plan, our strategy in this segment will focus on
developing production opportunities from our asset base in the U.S. and Brazil.
We will continue to divest our non-core assets, including international
properties in Canada, Hungary and Indonesia. As of September 2004, we have sold
substantially all of our production operations in Canada and Indonesia.

In June 2004, we announced a back-to-basics plan for our business. This
plan emphasizes strict capital discipline designed to improve capital efficiency
through the use of standardized risk analysis, a heightened focus on cost
control, and a rigorous process for booking proved natural gas and oil reserves.
This back-to-basics approach is designed to stabilize production by improving
the production mix across our operating areas, thereby generating more
predictable income and cash flows in this business.

Our U.S. operations are divided into the following areas: onshore, offshore
and coal seam. The onshore area includes operations in three regions: Texas
Onshore, Central and Rocky Mountains. The Texas Onshore region includes our
operations along the Texas Gulf Coast, the Central region includes primarily our
operations in north Louisiana and the Rocky Mountain region includes our
interests in Utah. The offshore area includes our interests in the Gulf of
Mexico primarily in state and federal waters along the coast of Texas and
Louisiana. Our coal seam area consists of operations in the Black Warrior Basin
in Alabama, the Arkoma Basin in Oklahoma and the Raton Basin in New Mexico. In
each of our domestic operating areas, we have extensive acreage and/or seismic
holdings, which allow us to be competitive.

11

In Brazil, our operations are concentrated in the Camamu, Santos, and
Potiguar Basins. We have been successful with our drilling programs in the
Santos and Camamu Basins and are seeking a strategic partner with a strong
interest in Brazil to contribute near-term development capital in these two
basins. Through our UnoPaso Ltda., or UnoPaso, investment, in which we owned a
50 percent interest at December 31, 2003, we continue to work with Petrobras,
the Brazilian national oil company, in growing our presence in the Potiguar
Basin with increased production and planned exploratory activity. In July 2004,
we acquired the remaining 50 percent interest in UnoPaso.

Natural Gas and Oil Reserves

The tables below provide information on our proved reserves at December 31,
2003. Reserve information in these tables is based on the reserve report dated
January 1, 2004, prepared internally by us. Ryder Scott Company and Huddleston &
Co., Inc., independent petroleum engineering firms, performed independent
reserve estimates for 90 percent and 10 percent of our properties, respectively.
The total estimate of proved reserves prepared independently by Ryder Scott
Company and Huddleston & Co., Inc. was within five percent of our internally
prepared estimates. This information is consistent with estimates of reserves
filed with other federal agencies, except for differences of less than five
percent resulting from actual production, acquisitions, property sales,
necessary reserve revisions and additions to reflect actual experience. The
tables below exclude reserve information related to our equity ownership
interests in UnoPaso; the Merchant Energy segment's interests in Sengkang in
Indonesia and Aguaytia in Peru; and the Field Services segment's interest in
GulfTerra. Combined proved reserve balances for these equity investment
interests were 255,278 MMcf of natural gas and 7,105 MBbls of oil or natural gas
equivalents of 297,909 MMcfe, all net to our ownership interests. Our estimated
proved reserves as of December 31, 2003, and our 2003 production, by area, are
as follows:

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(1) Net proved reserves exclude royalties and interests owned by others
(including net profits interests) and reflects contractual arrangements and
royalty obligations in effect at the time of the estimate.
(2) Includes oil, condensate and natural gas liquids.
(3) As of September 2004, we have sold our production operations in Canada and
substantially all of our operations in Indonesia.
(4) Includes international operations in Hungary and Indonesia.

There are considerable uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and the timing of
development expenditures, including many factors beyond our control,
particularly where such reserves are not currently producing or developed. The
reserve data represents only estimates. Reservoir engineering is a subjective
process of estimating underground accumulations of natural gas and oil that
cannot be measured in an exact manner. The accuracy of any reserve estimate is a
function of the quality of available data and of engineering and geological
interpretations and judgment. As a result, estimates of different engineers
often vary. Estimates are subject to revision based upon a number of factors,
including reservoir performance, prices, economic conditions and government
restrictions. In addition, results of drilling, testing and production
subsequent to the date of an estimate may justify revision of that estimate.
Reserve estimates are often different from the quantities of natural gas and oil
that are ultimately recovered. The meaningfulness of reserve estimates is highly
dependent on the accuracy of the assumptions on which they were based. In
general, the volume of production from the natural gas and oil properties we own
declines as reserves are depleted. Except to the extent we conduct successful
exploration and development drilling or acquire additional properties containing
proved reserves, or both, our proved reserves will decline as reserves are
produced.

13

In addition, during 2003, we sold reserves totaling over 500 Bcfe to
various third parties. The reserves sold were primarily located in Oklahoma, New
Mexico, Texas, Louisiana, the Gulf of Mexico and western Canada. See Part II,
Item 8, Financial Statements and Supplementary Data, Note 30, for a further
discussion of our reserves.

Acreage and Wells

The following table details our gross and net interest in developed and
undeveloped onshore, offshore, coal seam and international lease and mineral
acreage at December 31, 2003. Any acreage in which our interest is limited to
owned royalty, overriding royalty and other similar interests is excluded.

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(1) Gross interest reflects the total acreage we participated in, regardless of
our ownership interests in the acreage.
(2) Net interest is the aggregate of the fractional working interest that we
have in our gross acreage.
(3) In April 2004, we announced the sale of 174,679 gross and net acres
associated with our Brazilian offshore operations.
(4) As of September 2004, we have sold our production operations in Canadian and
substantially all of our operations in Indonesia.

The U.S. net developed acreage is concentrated primarily in the Gulf of
Mexico (47 percent), Utah (15 percent), Texas (9 percent), Louisiana (8
percent), and Oklahoma (8 percent). The domestic net undeveloped acreage is
concentrated primarily in the Gulf of Mexico (25 percent), New Mexico (21
percent), and Louisiana (11 percent). Approximately 20 percent, 14 percent and 7
percent of our total U.S. net undeveloped acreage is held under leases that have
minimum remaining primary terms expiring in 2004, 2005 and 2006, respectively.
During 2003, we sold approximately 956,513 net acres primarily located in
Oklahoma, New Mexico, Texas, Louisiana, the Gulf of Mexico and western Canada.

14

The following table details our gross and net interests in productive
onshore, offshore, coal seam and international natural gas and oil wells and the
number of wells being drilled at December 31, 2003:

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(1) Gross interest reflects the total number of wells we participated in,
regardless of our ownership interests in the wells.
(2) Net interest is the aggregate of the fractional working interest that we
have in our gross wells.
(3) As of September 2004, we have sold our production operations in Canada.

During 2003, we sold approximately 715 net productive wells located
primarily in Oklahoma, New Mexico, Texas, Louisiana, the Gulf of Mexico and
western Canada. At December 31, 2003, we operated 2,774 of the 2,900 net
productive wells.

The following table details our net exploratory and development wells
drilled for each of the three years ended December 31. As a result of the
restatement of our proved natural gas and oil reserves, some wells drilled that
were previously reported as development wells have been reclassified as
exploratory wells in 2002 and 2001. See Part II, Item 8, Financial Statement and
Supplementary Data, Note 1 for a further discussion of this restatement.

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

(1) Net interest is the aggregate of the fractional working interest that we
have in our gross wells drilled.
(2) As of September 2004, we have sold our production operations in Canada and
substantially all of our operations in Indonesia.
(3) Includes international operations in Australia, Hungary, Turkey and
Indonesia.

The information above should not be considered indicative of future
drilling performance, nor should it be assumed that there is any correlation
between the number of productive wells drilled and the amount of natural gas and
oil that may ultimately be recovered.

Net Production, Sales Prices, Transportation and Production Costs

The following table details our net production volumes, average sales
prices received, average transportation costs, average production costs and
average production taxes associated with the sale of natural gas and oil for
each of the three years ended December 31. See our Production segment in Part
II, Item 7, Management's Discussion and Analysis of Financial Condition and
Results of Operations for a further discussion of volumes, prices and production
costs.

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

(1) As of September 2004, we have sold our production operations in Canada.
(2) Prices are stated before transportation costs.
(3) These amounts have been restated as a result of our determination that a
number of our hedges in historical periods did not qualify as hedges for
consolidated reporting purposes.
(4) Production costs include lease operating costs and production related taxes
(including ad valorem and severance taxes).

17

Acquisition, Development and Exploration Expenditures

The following table details information regarding the costs incurred in our
acquisition, development and exploration activities for each of the three years
ended December 31. As a result of the restatement of our proved natural gas and
oil reserves, some costs that were previously reported as development costs have
been reclassified as exploratory drilling costs for the years 2002 and 2001. See
Part II, Item 8, Financial Statements and Supplementary Data, Notes 1 and 30,
for a further discussion of this restatement.

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

(1) As of September 2004, we have sold our production operations in Canada and
substantially all of our operations in Indonesia.
(2) Includes international operations in Australia, Hungary, Indonesia and
Turkey.

The following table details approximate amounts spent to develop proved
undeveloped reserves that were included in our reserve report for each of the
three years:

Regulatory and Operating Environment

Our natural gas and oil production activities are regulated at the federal,
state and local levels, as well as internationally by the countries around the
world where we do business. These regulations include, but are not limited to,
the drilling and spacing of wells, conservation, forced pooling and protection
of correlative rights among interest owners. We are also subject to governmental
safety regulations in the jurisdictions in which we operate.

Our domestic operations under federal natural gas and oil leases are
regulated by the statutes and regulations of the U.S. Department of the Interior
that currently impose liability upon lessees for the cost of environmental
impacts resulting from their operations. Royalty obligations on all federal
leases are regulated by the Minerals Management Service, which has promulgated
valuation guidelines for the payment of royalties by producers. Our
international operations are subject to environmental regulations administered
by foreign governments, which include political subdivisions and international
organizations. These domestic and international laws and regulations relating to
the protection of the environment affect our natural gas and oil operations
through their effect on the construction and operation of facilities, drilling
operations, production or the delay or prevention of future offshore lease
sales. We believe that our operations are in material compliance with the
applicable requirements. In addition, we maintain insurance on our production
business for sudden and accidental spills and oil pollution liability.

Our production business has operating risks normally associated with the
exploration for and production of natural gas and oil, including blowouts,
cratering, pollution and fires, each of which could result in damage to life or
property. In addition, offshore operations may encounter usual marine perils,
including hurricanes and other adverse weather conditions, damage from
collisions with vessels, governmental regulations and interruption or
termination by governmental authorities based on environmental and other
considerations. Customary with industry practices, we maintain insurance
coverage on behalf of our production activities with respect to potential losses
resulting from these operating hazards.

19

Markets and Competition

We primarily sell our natural gas and oil to third parties through our
Merchant Energy segment at spot market prices, subject to customary adjustments.
As part of our Long-Range Plan, we will continue to sell our natural gas and oil
production to this segment. We sell our natural gas liquids at market prices
under monthly or long-term contracts, subject to customary adjustments. We also
engage in hedging activities on a portion of our natural gas and oil production
to stabilize our cash flows and reduce the risk of downward commodity price
movements on sales of our production.

The natural gas and oil business is highly competitive in the search for
and acquisition of additional reserves and in the sale of natural gas, oil and
natural gas liquids. Our competitors include major and intermediate sized
natural gas and oil companies, independent natural gas and oil operators and
individual producers or operators with varying scopes of operations and
financial resources. Competitive factors include price and contract terms.
Ultimately, our future success in the production business will be dependent on
our ability to find or acquire additional reserves at costs that allow us to
remain competitive.

UNREGULATED BUSINESSES -- FIELD SERVICES SEGMENT

Our Field Services segment conducts our midstream activities which includes
gathering and processing of natural gas. Our Field Services assets principally
consist of our consolidated processing assets in south Texas and south
Louisiana, and our general and limited partner holdings of GulfTerra, a publicly
traded master limited partnership in which our subsidiary serves as the general
partner. GulfTerra provides services that include gathering, transportation,
separation, handling, processing, fractionation and storage of natural gas, oil
and natural gas liquids.

Until the fourth quarter of 2003, we owned 100 percent of the general
partner of GulfTerra. In December 2003, we sold 50 percent of this ownership
interest to Enterprise Products Partners, L.P. (Enterprise) as discussed below.
We will sell our remaining interest in the general partner to Enterprise upon
the completion of the merger described below for $370 million in cash and a 9.9
percent interest in the general partner of the combined entity.

Gathering and Processing Operations

Our gathering and processing operations provide gathering and processing
services to natural gas producers, primarily in the south Texas and south
Louisiana production areas. The following tables provide information regarding
operational capacity and volumes of these gathering and processing facilities:

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

(1) Substantially all of these assets will be sold in 2004 as part of the
Enterprise transaction discussed below.

20

During 2002 and 2003, we completed a number of sales of our midstream
assets, including the sale of our San Juan Basin gathering, treating and
processing assets and our Texas and New Mexico midstream assets, including the
intrastate natural gas pipeline system we acquired from Pacific Gas & Electric
Company in 2000, to GulfTerra. Under our Long-Range Plan, we intend to divest
the remaining processing assets or manage them as part of our unregulated
businesses.

Investment in GulfTerra

We currently serve as the managing member of GulfTerra's general partner.
As the managing member of the general partner, we manage the partnership's daily
operations and perform all of GulfTerra's administrative and operational
activities under a general and administrative services agreement or, in some
cases, separate operational agreements. The following table provides information
on the facilities of GulfTerra:

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

(1) All volumetric information reflects 100 percent of GulfTerra's interest.

As of December 31, 2003, we owned 17.8 percent, or 10,384,245, of
GulfTerra's voting common units and a 50 percent ownership interest in
GulfTerra's one percent general partner. We also owned all 10,937,500 of the
partnership's outstanding Series C units, which are non-voting but are
convertible into common units. Until October 2003, we owned all of the Series B
preference units of the partnership, which GulfTerra redeemed for $156 million
at that time. The remaining 82.2 percent of the partnership's common units are
owned by public unit holders (including small amounts owned by management and
employees of the general partner), none of which exceeds a 10 percent ownership
interest.

GulfTerra Merger with Enterprise

In December 2003, Enterprise and GulfTerra announced that they had executed
definitive merger agreements to form the second largest publicly traded energy
partnership in the United States. The general partner of the combined
partnership was to be jointly owned by us and affiliates of privately held
Enterprise Products Company, with each owning a 50 percent interest. In 2004, we
amended our agreement with Enterprise Products Company whereby we will sell our
remaining interest in the general partner of GulfTerra, in exchange for an
additional payment to us of $370 million and a 9.9 percent interest in the
general partner of the combined entity. In conjunction with the merger, we will
also sell to Enterprise a portion of our common units, all of our Series C units
in GulfTerra and substantially all of our south Texas gathering and processing
assets. Following the completion of these transactions, our Field Services
segment will own a 9.9 percent interest in the general partner of Enterprise,
approximately four percent of Enterprise's common units and processing plants
located primarily in south Louisiana.

The combined partnership, which will retain the name Enterprise Products
Partners L.P., will provide transportation, gathering, processing, and treating
services in the largest producing basins of natural gas, crude oil and natural
gas liquids (NGL) in the U.S., including the Gulf of Mexico, Rocky Mountains,
San Juan Basin, Permian Basin, south Texas, east Texas, Mid-Continent, Louisiana
Gulf Coast and, through connections with third-party pipelines, Canada's western
sedimentary basin. The partnership will also serve the largest consuming regions
for natural gas, crude oil and NGL on the U.S. Gulf Coast.

21

In July 2004, the unitholders of both Enterprise and GulfTerra approved the
merger and related transactions. The merger and related transactions are
discussed more fully in Part II, Item 8, Financial Statements and Supplementary
Data, Note 28.

Regulatory Environment

Some of our operations, owned directly or through equity investments, are
subject to regulation by the FERC in accordance with the Natural Gas Act of 1938
and the Natural Gas Policy Act of 1978. Each entity subject to the FERC's
regulation operates under separate FERC approved tariffs with established rates,
terms and conditions of service.

Some of our operations, owned directly or through equity investments, are
also subject to regulation by the Railroad Commission of Texas under the Texas
Utilities Code and the Common Purchaser Act of the Texas Natural Resources Code.
Field Services files the appropriate rate tariffs and operates under the
applicable rules and regulations of the Railroad Commission.

In addition, some of our operations, owned directly or through equity
investments, are subject to the Natural Gas Pipeline Safety Act of 1968, the
Hazardous Liquid Pipeline Safety Act of 1979 and various environmental statutes
and regulations. Each of our pipelines has continuing programs designed to keep
the facilities in compliance with pipeline safety and environmental
requirements, and we believe that these systems are in material compliance with
the applicable requirements.

Markets and Competition

We compete with major interstate and intrastate pipeline companies in
transporting natural gas and NGL's. We also compete with major integrated energy
companies, independent natural gas gathering and processing companies, natural
gas marketers and oil and natural gas producers in gathering and processing
natural gas and NGL's. Competition for throughput and natural gas supplies is
based on a number of factors, including price, efficiency of facilities,
gathering system line pressures, availability of facilities near drilling
activity, service and access to favorable downstream markets.

UNREGULATED BUSINESSES -- MERCHANT ENERGY SEGMENT

Our Merchant Energy segment consists of a Global Power division, an Energy
Marketing and Trading division and an LNG division.

Global Power

Our Global Power division includes the ownership and operation of domestic
and international power generation facilities as well as the management of
restructured power contracts. As of December 31, 2003, we owned or had interests
in 68 power facilities in 16 countries with a total generating capacity of
14,898 gross MW. Our commercial focus has historically been either to develop
projects in which new long-term power purchase agreements allow for an
acceptable return on capital, or to acquire projects with existing above-market
power purchase agreements. During 2003, we actively pursued the sale of most of
our domestic plants and in December 2003, our Board of Directors authorized a
plan that included the sale of substantially all of our domestic power
generation plants. As of September 2004, we have sold 23 domestic power plants
with a total generating capacity of 2,480 gross MW. Following these sales, we
anticipate that we will continue to own interests in several domestic plants and
own several power purchase and supply contracts related to our power
restructuring business discussed below. We will also continue to seek
opportunities to sell or otherwise divest these remaining domestic assets and
some of our international assets, such that our long-term focus will be on
maximizing the value of our international power assets primarily in Brazil.

22

Domestic Power. As of December 31, 2003, we owned or had direct investment
interests in the following domestic power plants:

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

(1) These power facilities are reflected as investments in unconsolidated
affiliates in our financial statements.

(2) These power facilities (referred to as merchant plants) do not have
long-term power purchase agreements with third parties. Our energy marketing
and trading division sells the power that a majority of these facilities
generate to the wholesale power market.

(3) Represents our ownership interest in the Juniper holding company. This
company owns equity interests in 10 domestic power facilities.

(4) In December 2003, our Board approved a plan for selling these power
facilities.

(5) This power facility is currently being leased to a third party who has an
option to purchase in 2005.

Prior to 2003, we conducted a significant portion of our domestic power
activity through our ownership in Chaparral, an unconsolidated joint venture
formed for the purpose of investing in the domestic power industry. During the
first six months of 2003, we acquired our joint venture partner's interest and
began consolidating Chaparral effective January 1, 2003.

In addition to our domestic power plants above, we were involved in
activities in 2001 and 2002 that we have referred to as our power restructuring
business. These activities involved restructuring above-market, long-term power
purchase agreements with utilities that were originally tied to older power
plants built under the Public Utility Regulatory Policies Act of 1978 (PURPA).
These PURPA facilities were typically less efficient and more costly to operate
than newer power generation facilities. Our power restructuring activities
included restructuring the contracts held by our consolidated power plants such
as our Eagle Point power facility, and restructuring of contracts at plants
owned by Chaparral, such as Chaparral's Newark Bay, Bayonne and Camden power
facilities. In a restructuring, the contracts were amended so that the power
sold to the utilities did not have to be provided from the specific power plant,
but could be obtained in the

23

wholesale power market. While we are no longer actively seeking to restructure
additional power purchase contracts, we continue to manage the physical purchase
and sale of electricity as required under the following previously restructured
power contracts:

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

(1) We sold these restructured power contracts in 2004.

International Power. As of December 31, 2003, we owned or had a direct
investment in the following international power plants (only significant assets
and investments are listed):

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

(1) These power facilities are reflected as investments in unconsolidated
affiliates in our financial statements.

(2) This facility's power sales contract is currently in arbitration.

(3) Although a majority of the power generated by this power facility is sold to
the wholesale power markets, Petrobras provides a minimum level of capacity
and revenue under its contract until 2007.

From November 2001 to April 2003, several of our power facilities in Brazil
were owned and managed by Gemstone, an unconsolidated joint venture formed for
the purpose of investing in the Brazilian power industry. In April 2003, we
acquired our joint venture partner's interest and began consolidating Gemstone.

24

In addition to the international power plants above, our Global Power
division also has investments in the following international pipelines:

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

(1) Volumes represent the pipeline's total design capacity and average
throughput and are not adjusted for our ownership interest.

As discussed above, we are actively divesting substantially all of our
domestic power plants, with 23 power plants sold as of September 2004, another 8
power plants currently under sales contracts and most of the remaining domestic
plants approved by our Board of Directors for sale. Several of the power plants
under sales contracts are subject to rights of existing partners to purchase our
interest in such plants and many of the power plants require consents from third
parties prior to consummating the sale of the plants. Internationally, our
long-term focus is to integrate our Brazilian businesses to better unify our
efforts and economies of scale in Brazil. We intend to sell substantially all of
our other international power operations, our domestic restructured power
contracts and our other domestic power plants as opportunities arise.

Regulatory Environment. Our domestic power generation activities are
regulated by the FERC under the Federal Power Act with respect to the rates,
terms and conditions of service of these regulated plants. In addition, exports
of electricity outside of the U.S. must be approved by the Department of Energy.
Our cogeneration power production activities are regulated by the FERC under
PURPA with respect to rates, procurement and provision of services and operating
standards. Our power generation activities are also subject to federal, state
and local environmental regulations.

Our international power generation activities are regulated by numerous
governmental agencies in the countries in which these projects are located. Many
of the countries in which we conduct business have recently developed or are
developing new regulatory and legal structures to accommodate private and
foreign-owned businesses. These regulatory and legal structures and their
interpretation and application by administrative agencies are relatively new,
are sometimes limited and are at risk to change, which may affect our
contractual arrangements. Many detailed rules and procedures are yet to be
issued, and we expect that the interpretation and modification of existing rules
in these jurisdictions will evolve over time.

Markets and Competition. Many of our domestic power generation facilities
sell power pursuant to long-term power purchase agreements with investor-owned
utilities in the U.S. The terms of the power purchase agreements for our
facilities are such that our revenues from these facilities are not
significantly impacted by competition from other sources of generation. The U.S.
power generation industry continues to evolve and regulatory initiatives have
been adopted at the federal and state levels aimed at increasing competition in
the power generation business. As a result, it is likely that when the power
purchase agreements expire, these facilities will be required to compete in the
same market as our other power facilities without power purchase agreements, in
which operating efficiency and other economic factors determine success. We are
likely to face intense competition from generation companies as well as from the
wholesale power markets.

Many of our international power generation facilities sell power under
long-term power purchase agreements primarily with power transmission and
distribution companies owned by the local governments where the facilities are
located. When these long-term contracts expire, these facilities will be subject
to regional market and competitive risks.

Energy Marketing and Trading

During 2001 and 2002, we entered into a variety of physical and financial
transactions in the commodity markets. As a result of the deterioration of the
energy trading environment in late 2001 and 2002 and the reduced availability of
credit to us, we announced in November 2002 that we would reduce our involvement
in the energy trading business and pursue an orderly liquidation of our trading
portfolio. As part of our

25

Long-Range Plan, we announced that our historical energy trading operations
would become a marketing and trading business focused on the marketing and
physical trading of the natural gas and oil from our Production segment. As of
December 31, 2003, we had executed contracts with third parties, primarily fixed
for floating swaps, that effectively hedged 38.9 TBtu of our Production
segment's anticipated natural gas production through 2012. The volumes as of
December 31, 2003 have been adjusted for a restatement of the accounting
treatment for these hedging activities. See Part II, Item 8, Financial
Statements and Supplementary Data, Note 1, for a further discussion of this
restatement. In May 2004, we entered into additional hedges for 5.5 TBtu of our
Production segment's anticipated natural gas production through 2007. In
addition, in August 2004, we entered into hedges for 1.1 MMBbls of our
Production segment's anticipated oil production in Brazil through 2007. As of
September 2004, we continued to have a number of transactions from our
historical trading portfolio that we are actively working to liquidate.

Our Energy Marketing and Trading division's portfolio is grouped into
several categories. Each of these categories includes contracts with third
parties and contracts with affiliates that require physical delivery of a
commodity or financial settlement. The types of contracts used in this division
are as follows:

Natural gas. These contracts include long-term obligations to deliver
natural gas to power plants. We currently have seven significant physical
natural gas contracts with power plants. These contracts have various
expiration dates ranging from 2007 to 2028, with expected obligations under
individual contracts with third parties ranging from 30,000 MMBtu/d to
142,000 MMBtu/d. Also included in our natural gas portfolio are other
contracts that we use to manage the risk associated with our long-term
supply obligations and those historically associated with our merchant LNG
business.

Power. These contracts include long-term obligations to provide power
to our Global Power division for their restructured domestic power
contracts. We currently have four power supply contracts with the largest
of these being a contract with Morgan Stanley for approximately 1.7 MMWh
per year extending through 2016. We also have other contracts that require
the physical delivery of power or that are used to manage the risk
associated with our obligations to supply power.

Tolling. These contracts provide us with the right to require a
counterparty to convert natural gas into electricity. Under these
arrangements, we supply the natural gas used in the underlying power plants
and sell the electricity produced by the power plant. In exchange for this
right, we pay a monthly fixed fee and a variable fee based on the quantity
of electricity produced. We currently have two unaffiliated physical
tolling contracts, the largest of which is our contract on the Cordova
power project in the Midwest, which has an expiration date of 2019.

Transportation. These contracts give us the right to transport
natural gas using pipeline capacity for a fixed demand charge plus variable
transportation costs. Our natural gas transportation contracts have 1.7
Bcf/d of capacity as of December 31, 2003 and have contractual expiration
dates through 2028. Our ability to utilize our transportation capacity is
dependent on several factors including the difference in natural gas prices
at receipt and delivery locations along the pipeline system and the amount
of capital required to support credit demands from our gas suppliers.

Storage. These contracts give us the ability to inject, withdraw and
store natural gas in various locations. Through these contracts, we
currently have access to storage capacity totaling 22 Bcf as of December
31, 2003 with contractual terms that currently extend through 2007.

Markets and Competition. Our Energy Marketing and Trading division
operates in a highly competitive environment. Our primary competitors include:

- affiliates of major oil and natural gas producers;

- large domestic and foreign utility companies;

- affiliates of large local distribution companies;

- affiliates of other interstate and intrastate pipelines; and

26

- independent energy marketers and power producers with varying scopes of
operations and financial resources.

Our Energy Marketing and Trading division competes on the basis of price,
operating efficiency, technological advances, experience in the marketplace and
counterparty credit. Each market served is influenced directly or indirectly by
energy market economics.

LNG

Our merchant LNG terminalling and transportation business (which does not
include the Elba Island facility owned by our Pipelines segment) contracted for
LNG terminalling and regasification capacity and coordinated short and long-term
LNG supply deliveries. Our merchant LNG terminalling and transportation business
owned several terminals under development in Baja, Altimira and the Bahamas. We
also held a patent on our Energy Bridge technology and several long-term charter
arrangements on ships that employed this technology. This technology involved
using ships to liquify and then regasify natural gas for delivery to pipeline
offtakers. In 2003, we announced our intent to exit this business because of the
significant capital and credit requirements of this business. We have either
sold or are in the process of selling all of our merchant LNG terminals,
including the remaining assets and intellectual property rights related to our
Energy Bridge technology. We are also terminating our remaining obligations
under the long-term ship charters related to this technology.

OTHER OPERATIONS AND ASSETS

We currently have a number of other assets and businesses that are either
included as part of our corporate activities or as discontinued operations.

Corporate Activities

Through our corporate group, we perform management, legal, accounting,
financial, tax, consulting, administrative and other services for our operating
business segments. The costs of providing these services are allocated to our
business segments. Our remaining telecommunications business and a retail
business (which was sold in 2001 and 2002) and our discontinued operations,
which include our petroleum markets and coal businesses, are also included in
our corporate activities.

Telecommunications

Our telecommunications business focuses on providing Texas-based metro
transport services and collocation and cross-connect services in Chicago. Our
Texas metro transport business provides bandwidth transport services to
wholesale and commercial customers in Austin, San Antonio, Dallas, Ft. Worth and
Houston. Our collocation and cross-connect services are available through our
Chicago telecommunications facility, the Lakeside Technology Center. This
facility provides space for telecommunication carriers that is designed for
their unique equipment needs and provides access to multiple network connections
of various telecommunication carriers. As of December 31, 2003, we had
approximately $160 million of remaining assets in our telecommunications
business, primarily consisting of our Texas metro transport business and our
Lakeside Technology Center. In April 2004, we sold a 28 percent interest in our
Texas metro transport business to Genesis Park, L.P., a third party investment
partnership, and the name of that business was changed to Alpheus
Communications.

Discontinued Operations

Our discontinued operations consist of our petroleum markets and coal
mining businesses.

Petroleum Markets. In 2003, we announced our intent to sell our petroleum
markets business since it was not core to our primary natural gas business.
During 2003 and 2004, we sold substantially all of our petroleum markets assets.
As of December 31, 2003, our petroleum markets business owned or had interests
in two crude oil refineries and two chemical production facilities and had
petroleum terminalling and related

27

marketing operations. Our refineries operated at 74 percent of their combined
daily capacity in 2003, at 66 percent in 2002 and at 71 percent in 2001. The
aggregate sales volumes at our wholly owned refineries were approximately 118
MMBbls in 2003, 110 MMBbls in 2002 and 131 MMBbls in 2001. Of our total refinery
sales in 2003, 24 percent was gasoline, 38 percent was middle distillates, such
as jet fuel, diesel fuel and home heating oil, and 38 percent was heavy
industrial fuels and other products. The following table presents information on
our wholly owned refineries as of and for the years ended December 31:

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

(1) In March 2004, we completed the sale of our Aruba refinery to Valero Energy
Corporation.
(2) In January 2004, we completed the sale of our Eagle Point refinery to Sunoco
Corporation.
(3) In July 2003, we sold our Mobile refinery to Trigeant EP. Ltd. These volumes
only reflect those produced prior to the sale of the refinery.

Our chemical plants produce gasoline additives and paraxylene at our
facilities in Wyoming and Montreal. The following table provides information on
sales volumes from our wholly owned chemical facilities in the U.S. for each of
the three years ended December 31:

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

(1) In December 2003, we sold our chemical facilities that produced
nitrogen-based industrial and agricultural products to Dyno Nobel, Inc. We
expect to sell our remaining chemical facilities in the fourth quarter of
2004.

(2) Removed from service in October 2003.

Our petroleum markets business is subject to federal, state and local
environmental regulations and its customers are principally independent energy
marketers and retailers.

Coal Mining. Prior to its discontinuance in 2002, our coal mining business
controlled reserves totaling 524 million recoverable tons and produced
high-quality bituminous coal from reserves in Kentucky, Virginia and West
Virginia. The extracted coal was primarily sold under long-term contracts to
power generation facilities in the eastern U.S. During late 2002 and early 2003,
these operations were sold.

ENVIRONMENTAL

A description of our environmental activities is included in Part II, Item
8, Financial Statements and Supplementary Data, Note 22, and is incorporated
herein by reference.

EMPLOYEES

As of September 24, 2004, we had approximately 7,574 full-time employees,
of which 34 are subject to collective bargaining arrangements.

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EXECUTIVE OFFICERS OF THE REGISTRANT

Our executive officers as of September 10, 2004, are listed below. Prior to
August 1, 1998, all references to El Paso refer to positions held with El Paso
Natural Gas Company.

Douglas L. Foshee has been President, Chief Executive Officer, and a
Director of El Paso since September 2003. Mr. Foshee became Executive Vice
President and Chief Operating Officer of Halliburton Company in 2003, having
joined that company in 2001 as Executive Vice President and Chief Financial
Officer. Prior to that, Mr. Foshee was President, Chief Executive Officer, and
Chairman of the Board at Nuevo Energy Company. From 1993 to 1997, Mr. Foshee
served Torch Energy Advisors Inc. in various capacities, including Chief
Operating Officer and Chief Executive Officer. He held various positions in
finance and new business ventures with ARCO International Oil and Gas Company
and spent seven years in commercial banking, primarily as an energy lender.

D. Dwight Scott has been Executive Vice President and Chief Financial
Officer of El Paso since October 2002. Mr. Scott served as Senior Vice President
of Finance and Planning for El Paso from July 2002 to September 2002. Mr. Scott
was Executive Vice President of Power for El Paso Merchant Energy from December
2001 to June 2002, and he served as Chief Financial Officer of El Paso Global
Networks from October 2000 to November 2001. From January 1999 to October 2000,
he served as a managing director in the energy investment banking practice of
Donaldson, Lufkin and Jenrette.

John W. Somerhalder II has been an Executive Vice President of El Paso
since April 2000, and President of the Pipeline Group since January 2001. He has
been Chairman of the Board of Tennessee Gas Pipeline Company, El Paso Natural
Gas Company and Southern Natural Gas Company since January 2000 and Chairman of
the Board of ANR Pipeline Company and Colorado Interstate Gas Company since
January 2001. He was President of Tennessee Gas Pipeline Company from December
1996 to January 2000, President of El Paso Energy Resources Company from April
1996 to December 1996 and Senior Vice President of El Paso from August 1992 to
April 1996.

Robert W. Baker has been Executive Vice President and General Counsel of El
Paso since January 2004. From February 2003 to December 2003, he served as
Executive Vice President of El Paso and President of El Paso Merchant Energy. He
was Senior Vice President and Deputy General Counsel of El Paso from January
2002 to February 2003. Prior to that time he held various positions in the legal
department of Tenneco Energy and El Paso since 1983.

Robert G. Phillips has been President of El Paso Field Services since June
1997. He was President of El Paso Energy Resources Company from December 1996 to
June 1997, President of El Paso Field Services from April 1996 to December 1996
and was Senior Vice President of El Paso from September 1995 to April 1996.
Prior to that period, Mr. Phillips was Chief Executive Officer of Eastex Energy,
Inc. Mr. Phillips is the Chairman of the Board of Directors of GulfTerra Energy
Company, L.L.C., the general partner of GulfTerra Energy Partners, L.P.

Lisa A. Stewart has been President of El Paso Production and Non-Regulated
Operations since February 2004. Ms. Stewart was Executive Vice President of
Business Development and Exploration and Production Services for Apache
Corporation from 1995 to February 2004. From 1984 to 1995, Ms. Stewart worked in
various positions for Apache Corporation.

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AVAILABLE INFORMATION

Our website is http://www.elpaso.com. We make available, free of charge on
or through our website, our annual, quarterly and current reports, and any
amendments to those reports, as soon as is reasonably possible after these
reports are filed with the Securities and Exchange Commission (SEC). Each of our
Board's standing committee charters, our Corporate Governance Guidelines and our
Code of Business Conduct are also available, free of charge, through our
website. Information contained on our website is not part of this report.

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

More details on the cases listed below and a description of our legal
proceedings are included in Part II, Item 8, Financial Statements and
Supplementary Data, Note 22, and is incorporated herein by reference.

The purported shareholder class actions filed in the U.S. District Court
for the Southern District of Texas, Houston Division, are: Marvin Goldfarb, et
al v. El Paso Corporation, William Wise, H. Brent Austin, and Rodney D. Erskine,
filed July 18, 2002; Residuary Estate Mollie Nussbacher, Adele Brody Life
Tenant, et al v. El Paso Corporation, William Wise, and H. Brent Austin, filed
July 25, 2002; George S. Johnson, et al v. El Paso Corporation, William Wise,
and H. Brent Austin, filed July 29, 2002; Renneck Wilson, et al v. El Paso
Corporation, William Wise, H. Brent Austin, and Rodney D. Erskine, filed August
1, 2002; and Sandra Joan Malin Revocable Trust, et al v. El Paso Corporation,
William Wise, H. Brent Austin, and Rodney D. Erskine, filed August 1, 2002; Lee
S. Shalov, et al v. El Paso Corporation, William Wise, H. Brent Austin, and
Rodney D. Erskine, filed August 15, 2002; Paul C. Scott, et al v. El Paso
Corporation, William Wise, H. Brent Austin, and Rodney D. Erskine, filed August
22, 2002; Brenda Greenblatt, et al v. El Paso Corporation, William Wise, H.
Brent Austin, and Rodney D. Erskine, filed August 23, 2002; Stefanie Beck, et al
v. El Paso Corporation, William Wise, and H. Brent Austin, filed August 23,
2002; J. Wayne Knowles, et al v. El Paso Corporation, William Wise, H. Brent
Austin, and Rodney D. Erskine, filed September 13, 2002; The Ezra Charitable
Trust, et al v. El Paso Corporation, William Wise, Rodney D. Erskine and H.
Brent Austin, filed October 4, 2002. The purported shareholder class actions
relating to our reserve restatement filed in the U.S. District Court for the
Southern District of Texas, Houston Division, which have now been consolidated
with the above referenced purported shareholder class actions, are: James Felton
v. El Paso Corporation, Ronald Kuehn, Jr., Douglas Foshee and D. Dwight Scott;
Sinclair Haberman v. El Paso Corporation, Ronald Kuehn, Jr., and William Wise;
Patrick Hinner v. El Paso Corporation, Ronald Kuehn, Jr., Douglas Foshee, D.
Dwight Scott and William Wise; Stanley Peltz v. El Paso Corporation, Ronald
Kuehn, Jr., Douglas Foshee and D. Dwight Scott; Yolanda Cifarelli v. El Paso
Corporation, Ronald Kuehn, Jr., Douglas Foshee and D. Dwight Scott; Andrew W.
Albstein v. El Paso Corporation, William Wise; George S. Johnson v. El Paso
Corporation, Ronald Kuehn, Jr., Douglas Foshee, and D. Dwight Scott; Robert
Corwin v. El Paso Corporation, Mark Leland, Brent Austin; Ronald Kuehn, Jr., D.
Dwight Scott and William Wise; Michael Copland v. El Paso Corporation, Ronald
Kuehn, Jr., Douglas Foshee and D. Dwight Scott; Leslie Turbowitz v. El Paso
Corporation, Mark Leland, Brent Austin, Ronald Kuehn, Jr., D. Dwight Scott and
William Wise; David Sadek v. El Paso Corporation, Ronald Kuehn, Jr., Douglas
Foshee, D. Dwight Scott; Stanley Sved v. El Paso Corporation, Ronald Kuehn, Jr.,
and William Wise; Nancy Gougler v. El Paso Corporation, Ronald Kuehn, Jr.,
Douglas Foshee and D. Dwight Scott; William Sinnreich v. El Paso Corporation,
Ronald Kuehn, Jr., Douglas Foshee, D. Dwight Scott and William Wise; Joseph
Fisher v. El Paso Corporation, Ronald Kuehn, Jr., Douglas Foshee, D. Dwight
Scott and William Wise; and Glickenhaus & Co.

30

v. El Paso Corporation, Rod Erskine, Ronald Kuehn, Jr., Brent Austin, William
Wise, Douglas Foshee and D. Dwight Scott; Haberman v. El Paso Corporation et al
and Thompson v. El Paso Corporation et al. The purported shareholder action
filed in the Southern District of New York is IRA F.B.O. Michael Conner et al v.
El Paso Corporation, William Wise, H. Brent Austin, Jeffrey Beason, Ralph Eads,
D. Dwight Scott, Credit Suisse First Boston, J.P. Morgan Securities, filed
October 25, 2002.

The shareholder derivative actions filed in Houston are Grunet Realty Corp.
v. William A. Wise, Byron Allumbaugh, John Bissell, Juan Carlos Braniff, James
Gibbons, Anthony Hall Jr., Ronald Kuehn Jr., J. Carleton MacNeil Jr., Thomas
McDade, Malcolm Wallop, Joe Wyatt and Dwight Scott, filed August 22, 2002. The
consolidated shareholder derivative action filed in Houston is John Gebhart and
Marilyn Clark v. El Paso Natural Gas, El Paso Merchant Energy, Byron Allumbaugh,
John Bissell, Juan Carlos Braniff, James Gibbons, Anthony Hall Jr., Ronald
Kuehn, Jr., J. Carleton MacNeil, Jr., Thomas McDade, Malcolm Wallop, William
Wise, Joe Wyatt, Ralph Eads, Brent Austin and John Somerhalder filed in November
2002. The shareholder derivative lawsuit filed in Delaware is Stephen Brudno et
al v. William A. Wise et al filed in October 2002.

The ERISA Class Action Suit is William H. Lewis III v. El Paso Corporation,
H. Brent Austin et al. It is pending in the U.S. District Court for the Southern
District of Texas, Houston Division.

The following is a description of environmental proceedings to which a
governmental authority is a party and potential monetary sanctions are $100,000
or more.

Kentucky PCB Project. In November 1988, the Kentucky environmental agency
filed a complaint in a Kentucky state court alleging that TGP discharged
pollutants into the waters of the state and disposed of PCBs without a permit.
The agency sought an injunction against future discharges, an order to remediate
or remove PCBs and a civil penalty. TGP entered into interim agreed orders with
the agency to resolve many of the issues raised in the complaint. The relevant
Kentucky compressor stations are being remediated under a 1994 consent order
with the Environmental Protection Agency (EPA). Despite TGP's remediation
efforts, the agency may raise additional technical issues or seek additional
remediation work and/or penalties in the future.

Toca Air Permit Violation. In June 2003, SNG notified the Louisiana
Department of Environmental Quality (LDEQ) that it had discovered possible
compliance issues with respect to operations at its Toca Compressor Station. In
response to a request from LDEQ, SNG submitted a detailed report to LDEQ in
September 2003, documenting that there had been unpermitted emissions from nine
condensate storage tanks and a tank truck loading station. In December 2003,
LDEQ issued a Consolidated Compliance Order and Notice of Potential Penalty
requiring SNG to complete certain tasks to correct the existing operating permit
and achieve compliance with federal and state laws and regulations. SNG's Toca
Compressor Station will invest an estimated $6 million to upgrade the station's
environmental controls by 2005. SNG filed a revised permit application and plan
for compliance in January 2004. On May 6, 2004, LDEQ and SNG agreed to settle
the enforcement matter for a penalty of $66,000.

Shoup Natural Gas Processing Plant. On December 16, 2003, El Paso Field
Services, L.P. received a Notice of Enforcement (NOE) from the Texas Commission
on Environmental Quality (TCEQ) concerning alleged Clean Air Act violations at
its Shoup, Texas plant. The NOE included a draft Agreed Order assessing a
penalty of $365,750 for the cited violations. The alleged violations pertained
to exceeding the emission limit, testing, reporting, and recordkeeping issues in
2001. We have responded to the NOE disputing the alleged violation and the
proposed penalty.

Corpus Christi Refinery Air Violations. On March 18, 2004, the Texas
Commission on Environmental Quality (TCEQ) issued an "Executive Director's
Preliminary Report and Petition" seeking $645,477 in penalties relating to air
violations alleged to have occurred at our former Corpus Christi, Texas refinery
from 1996 to 2000. We have filed a hearing request to protect our procedural
rights and have initiated negotiations with the TCEQ.

Coastal Eagle Point. The Coastal Eagle Point Oil Company received several
Administrative Orders and Notices of Civil Administrative Penalty Assessment
from the New Jersey Department of Environmental
31

Protection (DEP). The Orders alleged noncompliance with the New Jersey Air
Pollution Control Act, primarily pertaining to excess emissions reported since
1998 by the Eagle Point refinery in Westville, New Jersey. On February 24, 2003,
EPA Region 2 issued a Compliance Order based on a 1999 EPA inspection of the
refinery's leak detection and repair (LDAR) program. Alleged violations include
a failure to monitor all components and failure to timely repair leaking
components. The Eagle Point refinery resolved the claims of the U.S. and the
State of New Jersey in a Consent Decree on September 30, 2003, pursuant to the
EPA's refinery enforcement initiative. The Consent Decree was entered on
December 2, 2003. We paid a civil penalty of $1.25 million to the U.S. and $1.25
million to New Jersey. We contributed $1.0 million to an environmentally
beneficial project near the refinery. The Eagle Point refinery will invest an
estimated $3 to $7 million to upgrade the plant's environmental controls by
2008. The Eagle Point Refinery was sold in January 2004. We will share certain
future costs associated with implementation of the Consent Decree pursuant to
the Purchase and Sale Agreement. On April 1, 2004, the DEP issued an
Administrative Order and Notice of Civil Administrative Penalty Assessment
seeking $183,000 in penalties for excess emission events that occurred during
the fourth quarter of 2003 at the refinery, prior to the sale. We are reviewing
the information behind the excess emission events and have filed an
administrative appeal contesting the penalty.

St. Helens. On November 11, 2003, our St. Helens, Oregon chemical plant
discovered a release of ammonia at the facility and reported the release to the
National Response Center and state and local contacts on November 12, 2003. The
EPA has alleged violations of the Comprehensive Environmental Response,
Compensation and Liability Act (CERCLA) and the Emergency Planning and Community
Right-to-Know Act (EPCRA) reporting requirements associated with the reporting
of the release. On December 3, 2003, the St. Helens plant was sold to Dyno
Nobel, Inc. On April 21, 2004, the EPA issued a demand to El Paso Merchant
Energy -- Petroleum Company for penalties for the alleged violations. We
responded to the EPA's demand, and we have resolved the alleged violations by
agreeing to a penalty of $50,345 and by agreeing to conduct a supplemental
project costing $59,581.

Natural Buttes. On May 19, 2003, we met with the EPA to discuss potential
"prevention of significant deterioration" violations due to a de-bottlenecking
modification at Colorado Interstate Gas Company's facility. The EPA issued an
Administrative Compliance Order and we are in negotiations with the EPA as to
the appropriate penalty.

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

None.

32

PART II

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

Our common stock is traded on the New York Stock Exchange under the symbol
EP. As of September 24, 2004, we had 51,553 stockholders of record, which does
not include beneficial owners whose shares are held by a clearing agency, such
as a broker or bank.

The following table reflects the quarterly high and low sales prices for
our common stock based on the daily composite listing of stock transactions for
the New York Stock Exchange and the cash dividends we declared in each quarter:

On July 16, 2004, we declared quarterly dividends of $0.04 per share of our
common stock, payable on October 4, 2004, to shareholders of record as of
September 3, 2004. Future dividends will be dependent upon business conditions,
earnings, our cash requirements and other relevant factors.

Equity Security Units

In June 2002, we issued 11.5 million, 9% equity security units. Equity
security units consist of two securities: i) a purchase contract on which we pay
quarterly contract adjustment payments at an annual rate of 2.86% and that
requires its holder to buy our common stock on a stated settlement date of
August 16, 2005, and ii) a senior note due August 16, 2007, with a principal
amount of $50 per unit, and on which we pay quarterly interest payments at an
annual rate of 6.14%. The senior notes we issued had a total principal value of
$575 million and are pledged to secure the holders' obligation to purchase
shares of our common stock under the purchase contracts. In December 2003, we
completed a tender offer to exchange 6,057,953 of the outstanding equity
security units, which represented approximately 53 percent of the total units
outstanding. For each unit tendered, the holder received 2.5063 shares of common
stock and cash in the amount of $9.70 per equity security unit. In the exchange,
we issued a total of 15,182,972 shares of our common stock that had a total
market value of $119 million, and paid $59 million in cash. The common stock was
issued under Section 3(a)(9) of the Securities Act of 1933.

Odd-lot Sales Program

We have an odd-lot stock sales program available to stockholders who own
fewer than 100 shares of our common stock. This voluntary program offers these
stockholders a convenient method to sell all of their odd-lot shares at one time
without incurring any brokerage costs. We also have a dividend reinvestment and
common stock purchase plan available to all of our common stockholders of
record. This voluntary plan provides our stockholders a convenient and
economical means of increasing their holdings in our common

33

stock. Neither the odd-lot program nor the dividend reinvestment and common
stock purchase plan have a termination date; however, we may suspend either at
any time. You should direct your inquiries to Fleet National Bank, care of
EquiServe, our exchange agent at 1-877-453-1503.

A description of our equity compensation plan information is included in
Part III, Item 12, Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters, and is incorporated herein by
reference.

ITEM 6. SELECTED FINANCIAL DATA

The information for the years from 1999 until 2002 and for the first nine
months of 2003 has been restated. For a further discussion of this restatement
and the 2003, 2002 and 2001 restatement amounts, see Item 8, Financial
Statements and Supplementary Data, Note 1. See the notes to the table below for
the impact of this restatement on 2000 and 1999. The following historical
selected financial data excludes our petroleum markets and coal mining
businesses, which are presented as discontinued operations in our financial
statements for all periods. The selected financial data below should be read
together with Item 7, Management's Discussion and Analysis of Financial
Condition and Results of Operations and Item 8, Financial Statements and
Supplementary Data included in this Annual Report on Form 10-K. These selected
historical results are not necessarily indicative of results to be expected in
the future.

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

(1) In February 2004, we completed an assessment of our December 31, 2003 proved
natural gas and oil reserve estimates. The assessment indicated a downward
revision to our proved reserve estimates of 1.8 Tcfe was needed. Upon
completion of an investigation into the factors that caused this revision,
we determined that a material portion of the revision should be reflected in
all of the historical periods included in this Annual Report on Form 10-K.
As a result, we restated our historical financial statements for all periods
to reflect the impacts of the revised reserve estimates on the financial
statement amounts. In August 2004, we also determined that we had not
properly applied generally accepted accounting principles related to many of
our historical hedges, primarily those associated with hedges of our
anticipated natural gas production. After an investigation into this matter,
we determined that a further restatement of our financial statements would
be required. The cumulative impact of the restatements on total
stockholders' equity as of September 30, 2003 (the most recent balance sheet
filed) was a reduction of approximately $2.4 billion. Of this amount, $1.7
billion related to our restatement for reserves and $0.7 billion related to
the restatement for certain hedges. The cumulative impact includes a
reduction to beginning stockholders' equity as of January 1, 2001 of
approximately $2.0 billion, of which $1.3 billion relates to our restatement
for reserves and $0.7 billion relates to the restatement for certain hedges.
See Item 8, Financial Statements and Supplementary Data, Note 1, for a
further discussion of our restatement processes as well as

34

the financial impacts of the restatements on 2001, 2002 and 2003. The
financial impacts on 1999 and 2000 of the restatements were as follows:

The restated stockholders' equity at December 31, 1999 includes an increase
in 1999 income of $215 million, net of tax, due to a reduced ceiling test
charge, lower depletion expense and the recognition of income that was
previously deferred on hedges of our natural gas production. It also
includes a reduction to beginning retained earnings of $1.5 billion for
charges that would have occurred in periods prior to January 1, 1999 as a
result of our revised reserve levels. As discussed in Item 8, Financial
Statements and Supplementary Data, Note 1, we revised our reserve estimates
for the periods from December 31, 2000 to September 30, 2003 using a reserve
reconstruction approach. For each quarter from December 31, 1998 through the
third quarter of 2000, we estimated reserves using an approach that involved
the use of a "reserve over production ratio" based on the reconstructed
December 31, 2000 reserve estimates. The reserve over production ratio
provided the estimated life of reserves based on production levels. We
applied that ratio to the actual historical period production levels to
calculate estimated historical reserves for each period. In determining the
reserve over production ratio to use for each period, historical prices at
the end of each quarter were considered, since at different pricing levels,
more or less reserves are economical to produce, which also impacts capital
cost, operating cost and revenue assumptions in determining cash flows that
will be derived from reserves. These overall quarterly reserve levels were
then used to recalculate the associated net future cash flows for each
quarter during those periods. Ceiling test charges and depreciation,
depletion and amortization rates were then determined based on these
restated estimated reserve levels and related net future cash flows.
Finally, we assessed the reasonableness of our initial adjustment as of
December 31, 1998 based on historical prices and our historical capitalized
costs prior to that time. Based on that assessment, we believe the amount
recorded as a retained earnings adjustment on January 1, 1999 reasonably
reflects the financial statement impact of our restated reserve levels that
would have occurred prior to that time. We believe the approach used to
reconstruct our historical reserves estimates was reasonable in light of the
information available to us and the circumstances surrounding our
restatement. See Item 8, Financial Statements and Supplementary Data, Note
1, for a further discussion of the methodologies used to restate our natural
gas and oil reserves and the reasons for the differences in the methods used
in computing our restated reserves.

(2) The impacts of the historical restatements for the years ended December 31,
2000 and 1999 have not been audited.

(3) In 2003, we entered into an agreement in principle to settle claims
associated with the western energy crisis of 2000 and 2001. This settlement
resulted in charges of $104 million in 2003 and $899 million in 2002, both
before income taxes. We also incurred losses in 2003 of $1.2 billion and in
2002 of $0.9 billion related to impairments of assets and equity investments
as well as restructuring charges related to industry changes and the related
realignment of our businesses in response to those changes. In addition, we
incurred ceiling test charges (restated) of $76 million, $128 million and
$2,143 million in 2003, 2002 and 2001 on our full cost natural gas and oil
properties. During 2001, we merged with The Coastal Corporation and incurred
costs and asset impairments related to this merger that totaled
approximately $1.5 billion. In 1999, we incurred $557 million of merger
related and asset impairment charges primarily related to our merger with
Sonat Inc. and incurred $121 million of ceiling test charges (restated). For
further discussions of events affecting comparability of our results in
2003, 2002 and 2001, see Item 8, Financial Statements and Supplementary
Data, Notes 5 through 9.

(4) Cash dividends declared per share of common stock represent the historical
dividends declared by El Paso for all periods presented.

(5) The increase in total assets during 2000 was a result of the consolidation
of Engage Energy US, LP into Coastal Merchant Energy and the growth of our
Merchant Energy segment in 2000.

(6) The increases in total long-term financing obligations in 2002 and 2003 was
a result of the consolidations of our Chaparral and Gemstone power
investments, the restructuring of other financing transactions, and the
reclassification of securities of subsidiaries as a result of our adoption
of Statement of Financial Accounting Standards (SFAS) No. 150, Accounting
for Certain Financial Instruments with Characteristics of both Liabilities
and Equity, during 2003.

35

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

Our Management's Discussion and Analysis includes forward-looking
statements that are subject to risks and uncertainties. Actual results may
differ substantially from the statements we make in this section due to a number
of factors that are discussed beginning on page 78. The historical financial
information in this section has been restated, as further discussed in Item 8,
Financial Statements and Supplementary Data, Note 1. The information contained
in this discussion also presents our petroleum markets and our coal mining
businesses as discontinued operations for all periods.

OVERVIEW

Our business purpose is to provide natural gas and related energy products
in a safe, efficient and dependable manner. We own North America's largest
natural gas pipeline system and are a large independent natural gas producer. We
also own and operate midstream assets and investments, a domestic and
international power business, an energy marketing and trading business, a small
telecommunications business and currently have for sale or have sold petroleum,
coal and liquified natural gas businesses. Since the end of 2001, our business
activities have largely been focused on maintaining our core businesses of
pipelines and production, while attempting to liquidate or otherwise divest of
those businesses and operations that were not core to our long-term objectives,
or that were not performing consistently with the expectations we had for them
at the time we made the investment. Our overall objective during this period has
been to reduce debt and improve liquidity, while at the same time invest in our
core business activities. In 2002 and 2003, we spent 87 percent and 91 percent,
respectively, of our capital investment dollars in our pipeline, midstream and
production businesses.

We have liquidated or divested our interests in many of our non-core
assets. Coupled with declines in value of some of our business ventures, these
sales have resulted in sales prices that are well below the carrying values of
these businesses and assets, resulting in significant recorded losses.

The year ended December 31, 2003 was a year of significant change in our
business strategy and our financial condition. In 2003:

- We completed the sale of a number of assets and investments including
production properties, 50 percent of the general partner interest in
GulfTerra, a significant portion of our worldwide petroleum markets
operations, a portion of our domestic power generation operations and our
merchant LNG business. Total proceeds from these sales were approximately
$3.3 billion;

- We completed a number of financial transactions that allowed us to
maintain our access to needed capital to meet our cash requirements,
simplify our capital structure, and eliminate a significant amount of
off-balance sheet obligations and preferred securities;

- We implemented a cost-reduction program that identified $445 million of
cost reductions in our business over 2003 and 2004 and initiated a
program targeting an additional $150 million of savings by 2006;

- We completed the Western Energy Settlement which became effective in June
2004, resolving a substantial uncertainty arising from the California
energy crisis in 2001; and

- We announced our Long-Range Plan that, among other things, defines our
core businesses, establishes a timeline for debt reduction, sets a
timetable for exiting non-core businesses and assets and sets financial
goals for the company.

Many of the changes we experienced in 2003 resulted in significant losses
and declining operating cash flows produced by our businesses. Furthermore, in
February 2004, we completed the December 31, 2003 reserve estimation process for
the proved natural gas and oil reserves in our Production segment. The results
of this process indicated that a significant downward revision to those reserve
estimates was needed. In August 2004, we also determined that we had not
properly applied generally accepted accounting principles related to

36

many of our historical hedges, primarily those associated with hedges of our
anticipated natural gas production. After investigations into these issues, we
determined that a restatement of our historical financial information was
required. Accordingly, we restated our historical financial statements to
reflect the financial impact of these revised proved reserve estimates and to
revise our historical accounting for these derivatives. See Item 8, Financial
Statements and Supplementary Data, Note 1, for a discussion of these
restatements.

The events described above increased the risk involved in owning our
securities. Despite the reductions in our credit ratings to well below
investment grade, we believe that the Long-Range Plan that we have outlined will
allow us to manage these increased risks in an acceptable manner and allow us to
again become a strong natural gas company in North America. In the following
sections of our Management's Discussion and Analysis, we address these events,
our outlook and our Long-Range Plan in greater detail.

CAPITAL STRUCTURE

During 2003, we took steps intended to simplify our financial and capital
structure, refinance shorter term obligations and reduce guarantees and other
"off-balance sheet" obligations, replacing them with direct financial
obligations. These actions included entering into a new $3 billion revolving
credit facility, acquiring and consolidating a number of entities with existing
debt, refinancing shorter-term obligations with longer-term borrowings and
redeeming and eliminating preferred interests in our subsidiaries as follows (in
millions):

Short-term financing obligations, including current
maturities................................................ $ 2,075
Notes payable to affiliates................................. 390
Long-term financing obligations............................. 16,106
Securities of subsidiaries.................................. 3,420
-------
Total debt and securities of subsidiaries as of
December 31, 2002................................ 21,991
-------
Principal amounts borrowed(1)............................... 4,250
Repayments of principal(1).................................. (3,982)
Other changes in debt:
Acquisition of Chaparral and Gemstone(2).................. 2,578
Operating leases and refinanced securities of
subsidiaries........................................... 1,018
Reclassifications of preferred interests as long-term
financing obligations(3)............................... 625
Sales of entities(4)...................................... (710)
Exchange of equity security units(5)...................... (303)
Elimination of affiliated obligations..................... (326)
Redemptions and eliminations of securities of
subsidiaries(6)........................................... (2,973)
Other....................................................... 11
-------
Total debt and securities of subsidiaries as of
December 31, 2003................................ $22,179(7)
=======

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

(1) Includes $500 million of borrowings and $1,150 million of repayments under
our $3 billion revolving credit facility.
(2) Approximately $1.6 billion of this amount relates to non-recourse project
financing or contract debt and includes $75 million related to Macae which
was consolidated as a consequence of our acquisition of Gemstone in April
2003.
(3) Relates to our adoption of SFAS No. 150. See Item 8, Financial Statements
and Supplementary Data, Notes 2, 20 and 21.
(4) Includes $571 million in debt obligations related to the sale of East Coast
Power and $139 million related to the sale of Mohawk River Funding I.
(5) See Item 8, Financial Statements and Supplementary Data, Note 24.
(6) Redemptions and eliminations represent preferred interests of consolidated
subsidiaries that were either repaid or refinanced as debt.
(7) Does not include $370 million of long-term debt, which was retired in March
2004, related to our Aruba refinery that is classified as discontinued
operations and $174 million of debt related to power assets that are
classified as held for sale.

For a further discussion of our long-term debt and other financing
obligations, and other credit facilities, see Item 8, Financial Statements and
Supplementary Data, Note 20.

37

CAPITAL RESOURCES AND LIQUIDITY

We rely on cash generated from our internal operations as our primary
source of liquidity, as well as available credit facilities, project and bank
financings, proceeds from asset sales and the issuance of long-term debt,
preferred securities and equity securities. From time to time, we have also used
structured financing transactions that are sometimes referred to as off-balance
sheet arrangements. We expect that our future funding for working capital needs,
capital expenditures, long-term debt repayments, dividends and other financing
activities will continue to be provided from some or all of these sources,
although we do not expect to use off-balance sheet arrangements to the same
degree in the future. Each of our existing and projected sources of cash are
impacted by operational and financial risks that influence the overall amount of
cash generated and the capital available to us. For example, cash generated by
our business operations may be impacted by changes in commodity prices or
demands for our commodities or services due to weather patterns, competition
from other providers or alternative energy sources. Collateral demands or
recovery of cash posted as collateral are impacted by natural gas prices,
hedging levels and the credit quality of us and our counterparties. Cash
generated by future asset sales may depend on the overall economic conditions of
the industries served by these assets, the condition and location of the assets
and the number of interested buyers. In addition, our future liquidity will be
impacted by our ability to access capital markets which may be restricted due to
our credit ratings, general market conditions, and by limitations on our ability
to access our shelf registration statement as further discussed in Item 8,
Financial Statements and Supplementary Data, Note 20. For a further discussion
of risks that can impact our liquidity, see our risk factors beginning on page
78. The following is a summary of our cash flow activities between January 1,
2004 and June 30, 2004.

Financing Activities
Reduction in debt (including discontinued
operations)(2)......................................... $(1,347)
Issuance of common stock.................................. 73
Dividends................................................. (49)
Other..................................................... (16)
-------
Net cash used in financing activities..................... (1,339)
-------
Change in cash......................................... $ (17)
=======

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

(1) In 2004, we made payments under the Western Energy Settlement of
approximately $602 million, which included $468 million held in escrow as of
December 31, 2003. The $602 million payment of this liability is shown as an
operating cash outflow and the decrease in restricted cash related to the
release of escrowed funds is shown as a cash inflow from investing
activities.

(2) Relates primarily to proceeds from the sale of our Aruba refinery.

38

For the first half of 2004, our discretionary and maintenance capital needs
were met primarily through operating cash flows. For the next twelve months, we
anticipate that our discretionary and maintenance capital needs will continue to
be met primarily through operating cash flows, supplemented by continued
recovery of cash provided as collateral to various counterparties and by project
financings for our Cheyenne Plains project. Our estimated cash flow and cash
requirements may change significantly, and our analysis is intended to provide a
better understanding our liquidity outlook.

The following tables reflect our available liquidity as of June 30, 2004
and our estimated sources and uses of funds for the period from July 2004
through June 2005 (in billions):

Sources as of June 30, 2004
Available cash............................................ $1.0
Available capacity under our $3 billion revolving credit
facility(1)............................................ 1.2
----
Net available liquidity..................................... $2.2
====

Estimated cash sources
Announced asset sales(2).................................. $1.8
Other asset sales......................................... 0.3
----
Anticipated cash sources............................. $2.1
====
Estimated cash needs
Debt maturities........................................... $1.5
Revolving credit facility maturity(3)..................... 0.6
Dividends................................................. 0.1
----
Anticipated cash needs............................... $2.2
====

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

(1) Upon the close of the Enterprise transaction, which includes the sale of the
Series A and Series C units in GulfTerra that collateralize our revolver,
our borrowing capacity under our revolver will decrease by approximately
$0.5 billion.

(2) Includes approximately $1.0 billion expected to be received upon completion
of the Enterprise transaction and $0.8 billion to be received upon
completion of our remaining announced power plant and other asset sales.

(3) Does not reflect $1.1 billion of letters of credit issued pursuant to the $3
billion revolving credit facility. We are in the process of refinancing this
facility which matures on June 30, 2005.

Our net available liquidity above includes our $3 billion revolving credit
facility that matures on June 30, 2005. The facility is collateralized by our
equity interests in TGP, EPNG, ANR, CIG, Southern Gas Storage Company, ANR
Storage Company and our Series A common units and Series C units in GulfTerra.
We are in the process of negotiating the refinancing of this facility and
currently expect to be successful in obtaining this refinancing. In the event we
are unable to refinance our existing $3 billion revolving credit facility by
June 30, 2005, we would be obligated to repay the outstanding amounts, and make
alternative arrangements for the letters of credit issued pursuant to this
credit facility. As of June 30, 2004, we had borrowed $600 million and issued
approximately $1.1 billion of letters of credit under this credit facility.

Although we expect to successfully refinance all or a portion of our
existing $3 billion revolving credit facility, if we were unsuccessful, we
believe we could adjust our planned capital expenditures and increase our
planned asset sales to meet any shortfall in liquidity, and at the same time
provide for the operations of the company. Further, if we were required to repay
our obligations under the $3 billion revolving credit facility, many of the
assets that currently collateralize this facility, including our equity
interests in TGP, EPNG, ANR, CIG, Southern Gas Storage Company, ANR Storage
Company and some of our Series A common units in GulfTerra, would become
available to support new financing transactions. Although we cannot guarantee
the outcome of future events, we believe that this available collateral would be
adequate to provide financing sufficient to meet our liquidity needs.

In February 2004, we completed the December 31, 2003 reserve estimation
process for the proved natural gas and oil reserves in our Production segment.
As a result of this review, we announced that we were significantly reducing our
proved natural gas and oil reserve estimates. In August 2004, we also determined
39

that we had not properly accounted for certain derivatives, primarily those
related to hedges of our anticipated natural gas production. After
investigations into these matters, we concluded that a restatement of our
historical financial statements for both of these matters was required.

We believe that the material restatements of our financial statements as
discussed in Item 8, Financial Statements and Supplementary Data, Note 1 would
have constituted events of default under our $3 billion revolving credit
facility and various other financing transactions, specifically under the
provisions of these arrangements related to representations and warranties on
the accuracy of our historical financial statements and on our debt to total
capitalization ratio. During 2004, we received several waivers on our $3 billion
revolving credit facility and various other financing transactions to address
these issues. These waivers continue to be effective. We also received an
extension of time with various lenders until November 30, 2004 to file our first
and second quarter 2004 Forms 10-Q, which we expect to meet. If we are unable to
file these Forms 10-Q by that date and are not able to negotiate an additional
extension of the filing deadline, our $3 billion revolving credit facility and
various other transactions could be accelerated. As part of obtaining these
waivers, we also amended various provisions of the $3 billion revolving credit
facility, including provisions related to events of default, and limitations on
our ability as well as the ability of our subsidiaries to repay indebtedness
scheduled to mature after June 30, 2005. Based upon a review of the covenants
contained in our indentures and the financing agreements of our other
outstanding indebtedness, the acceleration of our $3 billion revolving credit
facility could constitute an event of default under some of our other debt
agreements. In addition, three of our subsidiaries have indentures associated
with their public debt that contain $5 million cross-acceleration provisions.

Various other financing arrangements entered into by us and our
subsidiaries, including El Paso CGP Company (El Paso CGP) and El Paso Production
Holding Company, include covenants that require us to file financial statements
within specified time periods. Non-compliance with these covenants does not
constitute an automatic event of default. Instead, such agreements are subject
to acceleration when the indenture trustee or the holders of at least 25 percent
of the outstanding principal amount of any series of debt provides notice to the
issuer of non-compliance under the indenture. In that event, the non-compliance
can be cured by filing financial statements within specified periods of time
(between 30 and 90 days after receipt of notice depending on the particular
indenture) to avoid acceleration of repayment. The holders of El Paso Production
Holding Company's debt obligations waived its financial filing requirements
through December 31, 2004. The filing of the first and second quarter 2004 Forms
10-Q for these subsidiaries will cure the events of non-compliance resulting
from the failure to file financial statements on these subsidiaries. In
addition, neither we nor any of our subsidiaries have received a notice of the
default caused by our failure, or the failure of our subsidiaries to file
financial statements. In the event of an acceleration, we may be unable to meet
our payment obligations with respect to the related indebtedness.

Furthermore, the material restatement of our financial statements for the
period ended December 31, 2001 could cause a default under the financing
agreements entered into in connection with our $950 million Gemstone notes due
October 31, 2004. Currently, $748 million of Gemstone notes are outstanding.
However, we currently expect to repay these notes in full upon their maturity on
October 31, 2004.

Our subsidiaries are a significant potential source of liquidity to us, and
they participate in our cash management program to the extent they are permitted
under their financing agreements and indentures. Under the cash management
program, depending on whether a participating subsidiary has short-term cash
surpluses or requirements, we either provide cash to it or it provides cash to
us. If we were to incur an event of default under our credit facilities, we
would be unable to obtain cash from our pipeline subsidiaries, which are the
primary source of cash under this program. Currently, one of our subsidiaries,
CIG, is not advancing funds to us via our cash management program due to its
expected cash needs. In addition, our ownership interests in a number of our
subsidiaries and investments serve as collateral under our revolving credit
facility and our other borrowings. If the lenders under the credit facility or
those other borrowings were to exercise their rights to this collateral, we
could be required to liquidate these investments.

40

If, as a result of the events described above, we were subject to voluntary
or involuntary bankruptcy proceedings, our creditors could attempt to make
claims against our subsidiaries, including claims to substantively consolidate
those subsidiaries. We believe that claims to substantively consolidate our
subsidiaries would be without merit. However, there is no assurance that our
creditors would not advance such a claim in a bankruptcy proceeding. If our
creditors were able to substantively consolidate our subsidiaries in a
bankruptcy proceeding, it could have a material adverse effect on our financial
condition and our liquidity.

Despite the events described above, we believe we will be able to meet our
liquidity and cash needs for the remainder of 2004 and through June 2005 through
a combination of sources, including cash on hand, cash generated from our
operations, borrowings under our $3 billion revolving credit facility, proceeds
from asset sales, reduction of discretionary capital expenditures and the
possible issuance of long-term debt, preferred and/or equity securities.
However, a number of factors could influence our liquidity sources, as well as
the timing and ultimate outcome of our ongoing efforts and plans. These factors
are discussed in detail beginning on page 78.

Overview of Cash Flow Activities for 2003

For the years ended December 31, 2003 and 2002, our cash flows are
summarized as follows:

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

(1) Only individual line items in cash flows from operating activities have been
restated. Total cash flows from continuing operating activities, investing
activities, and financing activities, as well as discontinued operations
were unaffected by our restatements.

41

We generated cash from several sources, including our principal continuing
operations as well as through our discontinued operations, sales of assets and
issuances of long-term debt. We used a major portion of that cash to fund our
capital expenditures, purchase additional investments in subsidiaries, retire
long-term debt and make payments on amounts outstanding under the revolving
credit facilities and redeem preferred interests in several of our subsidiaries
held by minority interest owners. Overall, our cash sources and uses during 2003
are summarized as follows (in billions):

Cash inflows
Cash flows from continuing operating activities........... $ 2.4
Net proceeds from the sale of assets and investments...... 2.5
Net proceeds from the issuance of long-term debt.......... 3.6
Borrowings under revolving credit facility................ 0.5
Proceeds from the issuance of common stock................ 0.1
Net discontinued operations activity...................... 0.4
-----
Total cash inflows..................................... 9.5
-----
Cash outflows
Additions to property, plant and equipment................ 2.5
Net cash paid to acquire Chaparral and Gemstone........... 1.1
Net payments of restricted cash........................... 0.5
Payments to redeem preferred interests of consolidated
subsidiaries........................................... 1.3
Payments to retire long-term debt......................... 2.8
Payments on revolving credit facilities................... 1.2
Dividends paid to common stockholders..................... 0.2
Other..................................................... 0.1
-----
Total cash outflows.................................... 9.7
-----
Net decrease in cash................................. $(0.2)
=====

Cash From Continuing Operating Activities

Overall, cash generated from continuing operating activities was $2.4
billion during 2003 versus $0.7 billion in 2002. The $1.7 billion year-over-year
increase in operating cash flow was due primarily to the timing of cash receipts
and payments related to our energy marketing and trading operations. During
2002, increases in natural gas prices and our credit rating downgrades caused us
to use approximately $0.9 billion of operating cash flow to meet margin calls on
our trading positions. In late 2002, we began actively liquidating the positions
in our trading portfolio, in part to recover this cash and as part of the
reduction of our involvement in energy trading activities. In 2003, we generated
operating cash flow of approximately $0.5 billion primarily from the settlement
of positions in our trading portfolio. Since the beginning of 2003, we have
recovered $0.1 billion of cash posted for collateral and margin call
requirements through the overall reduction in transactions requiring collateral.
We have also recovered cash totalling $0.6 billion from our margin calls in 2003
by substituting letters of credit under our $3 billion revolving credit
facilities for actual cash on deposit. As a result, our overall margin activity
in 2003 was a source of cash of approximately $0.7 billion.

Our cash margin positions are significantly impacted by our credit quality
and the credit quality of our counterparties, commodity prices and the
availability of letter of credit or other non-cash collateral. Following our
credit rating downgrades, credit extended to us by our counterparties was
lowered requiring us to post additional margins. Many of our counterparties also
posted letters of credit with us requiring us to return their margin deposits.
In addition, the impact on our operating cash flows from changes in commodity
prices depends on whether the prices of our derivative instruments are above or
below market prices at the time. When these prices are below market, as they
were in 2002 and 2003, we are required to make margin deposits. However, these
margin deposits will be recovered when we sell the underlying commodities and
settle the positions or when natural gas prices decrease. At December 31, 2003,
we held $0.2 billion of cash and $0.3 billion of letters of credit as collateral
from third parties related to our price risk management activities

42

and have posted as collateral $0.2 billion of cash and $0.9 billion letters of
credit to third parties related to those activities.

Partially offsetting this overall increase in operating cash flow was a
year-over-year $0.4 billion increase in interest payments on our long-term
financing obligations, which resulted from the issuance and consolidation of
debt in 2003.

Cash From Continuing Investing Activities

Net cash used in our continuing investing activities was $1.6 billion for
the year ended December 31, 2003. Our continuing investing activities consisted
primarily of capital expenditures and equity investments of $3.6 billion and
additions to restricted cash of $0.5 billion, which were offset by net proceeds
from sales of assets and investments of $2.5 billion. Our 2003 capital
expenditures and net additions to equity investments included the following (in
billions):

Production exploration, development and acquisition
expenditures(1)........................................... $1.6
Pipeline expansion, maintenance and integrity projects...... 0.8
Investments in and net advances to unconsolidated
affiliates(2)............................................. 1.1
Other (primarily power projects)............................ 0.1
----
Total capital expenditures and net additions to
equity investments................................. $3.6
====

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

(1) Amounts include $0.2 billion of capital expenditures paid in 2003 related to
projects started and costs accrued in prior years.

(2) Amount is primarily related to purchases of third party investment interests
in Chaparral and Gemstone (see Item 8, Financial Statements and
Supplementary Data, Note 3).

As indicated above, we currently expect to reduce our total capital
expenditures in our Production segment from approximately $1.4 billion in 2003
to approximately $850 million in 2004. In October 2003, we entered into
agreements with two separate third parties whereby they agreed to contribute
capital for the drilling and completion of two specific packages of wells in
exchange for a net profits interest in each well. In 2003, we received funds of
approximately $130 million from these third parties under these agreements which
supplemented our overall capital program. Additional wells will be drilled under
these agreements in 2004, and while one party has elected to cease further
investment in one of the specific packages of wells, additional funds will be
received in 2004 under these agreements to supplement our 2004 capital program.
See Item 8, Financial Statements and Supplementary Data, Note 30, for a further
discussion of these agreements.

43

Cash received from our continuing investing activities includes $2.5
billion from the sale of assets and investments. Our asset sales proceeds
primarily relate to sales of natural gas and oil properties in western Canada,
New Mexico, Texas, Louisiana, Oklahoma and the Gulf of Mexico for $0.7 billion,
the sale of an equity investment in CE Generation for $0.2 billion, the sale of
East Coast Power for $0.4 billion, the sale of other pipelines, power and
processing assets for $0.6 billion, and the sale of our 50 percent interest in
the general partner of GulfTerra and other interests in GulfTerra for $0.6
billion. By segment, sales completed in 2003 and 2002 and those announced to
date or completed in 2004 are as follows:

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

(1) Excludes proceeds from sales of discontinued operations of $128 million in
2002, $747 million in 2003 and $905 million in 2004.

We will continue to divest our non-core assets based on the strategic
direction outlined in our Long-Range Plan (see Item 1, Business for a further
discussion of our Long-Range Plan, and Item 8, Financial Statements and
Supplementary Data, Notes 4 and 12, for a further discussion of these
divestitures and asset divestitures of our discontinued operations).

Cash From Continuing Financing Activities

Net cash used in our continuing financing activities was $0.9 billion for
the year ended December 31, 2003. Cash provided from our financing activities
included the net proceeds from the issuance of long-term debt of $3.6 billion,
$0.4 billion of cash contributed by our discontinued operations and cash
generated from the issuance of common stock of $0.1 billion. Cash used in our
financing activities included net repayments of $0.7 billion on revolving credit
facilities and $2.8 billion of payments made to retire third party long-term
debt. We also paid $1.3 billion to fully redeem our Trinity River, Clydesdale
and Coastal Securities preferred securities transactions and paid dividends to
common stockholders of $0.2 billion. See Item 8, Financial Statements and
Supplementary Data, Note 20, for a detail of our financing activities.

Cash Flows of Discontinued Operations

During 2003, our discontinued operations generated $0.4 billion of cash
through sales of inventories at our refineries and through asset sales which
raised a combined $0.6 billion, offset by capital expenditures of $0.2 billion.
These net cash inflows were distributed to our continuing operations.

CONTRACTUAL OBLIGATIONS AND OFF-BALANCE SHEET ARRANGEMENTS

In the course of our business activities, we enter into a variety of
financing arrangements and contractual obligations. The following discusses
those contingent obligations, often referred to as off-balance sheet
arrangements. We also present aggregated information on our contractual cash
obligations, some of which are reflected in our financial statements, such as
short and long-term debt and other accrued liabilities. Other obligations such
as operating leases and capital commitments are not reflected in our financial
statements.

44

OFF-BALANCE SHEET ARRANGEMENTS AND RELATED LIABILITIES

Guarantees

We are involved in various joint ventures and other ownership arrangements
that sometimes require additional financial support that results in the issuance
of financial and performance guarantees. In a financial guarantee, we are
obligated to make payments if the guaranteed party fails to make payments under,
or violates the terms of, the financial arrangement. In a performance guarantee,
we provide assurance that the guaranteed party will execute on the terms of the
contract. If they do not, we are required to perform on their behalf. For
example, if the guaranteed party is required to deliver natural gas to a third
party and then fails to do so, we would be required to either deliver that
natural gas or make payments to the third party equal to the difference between
the contract price and the market value of the natural gas. As of December 31,
2003, we had approximately $277 million of both financial and performance
guarantees not otherwise reflected in our financial statements.

We also periodically provide indemnification arrangements related to assets
or businesses we have sold. These arrangements include indemnifications for
income taxes, the resolution of existing disputes, environmental matters, and
necessary expenditures to ensure the safety and integrity of the assets sold. In
these cases, we evaluate at the time the guaranty is entered into and in each
period thereafter whether a liability exists and, if so, if it can be estimated.
We record accruals when both these criteria are met. As of December 31, 2003, we
had accrued $78 million related to these arrangements.

Other Arrangements

During 2003, we completed the consolidation and/or repayment of our
remaining off-balance sheet obligations including Chaparral, Gemstone, and
residual value guarantees related to two operating leases for our Lakeside
Technology Center telecommunications facility and our Aruba refinery.

CONTRACTUAL OBLIGATIONS

The following table summarizes our contractual obligations as of December
31, 2003, for each of the years presented (all amounts are undiscounted):

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

(1) See Item 8, Financial Statements and Supplementary Data, Note 20.

(2) See Item 8, Financial Statements and Supplementary Data, Note 6. As of
December 31, 2003, we held deposits of $468 million in an escrow account to
fund a portion this obligation. In June 2004, we paid approximately $602
million related to the obligation.

(3) Includes contractual, environmental and other obligations included in other
noncurrent liabilities in our balance sheet. Excludes expected
contributions to our pension and other postretirement benefit plans of $65
million in 2004 and $229 million for the four year period ended December
31, 2008, because these expected contributions are not contractually
required.

(4) See Item 8, Financial Statements and Supplementary Data, Note 22.

45

(5) Other contractual commitments and purchase obligations are defined as
legally enforceable agreements to purchase goods or services that have fixed
or minimum quantities and fixed or minimum variable price provisions, and
that detail approximate timing of the underlying obligations.

(6) These are commitments for demand charges on our tolling arrangements and for
firm access to natural gas transportation and storage capacity.

(7) Includes purchase commitments for natural gas and power.

(8) Includes commitments for drilling and seismic activities in our production
operations and various other maintenance, engineering, procurement and
construction contracts used by our other operations.

COMMODITY-BASED DERIVATIVE CONTRACTS

We utilize derivative financial instruments in hedging activities, power
contract restructuring activities and in our historical energy trading
activities. In the tables below, derivatives designated as hedges primarily
consist of instruments used to hedge natural gas production. Derivatives from
power contract restructuring activities relate to power purchase and sale
agreements that arose from our activities in that business and other
commodity-based derivative contracts relate to our historical energy trading
activities.

The following table details the fair value of our commodity-based
derivative contracts by year of maturity and valuation methodology as of
December 31, 2003:

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

(1) Includes $189 million of intercompany derivatives that eliminate in
consolidation, and have no impact on our consolidated assets and liabilities
from price risk management activities. During 2004, we have sold power
contract derivatives representing $942 million of the total assets from
power contract restructuring derivatives as of December 31, 2003.

(2) Exchange-traded positions are traded on active exchanges such as the New
York Mercantile Exchange, the International Petroleum Exchange and the
London Clearinghouse.

46

Below is a reconciliation of our commodity-based derivatives for the years
ended December 31, 2003 and 2002. These amounts reflect the restatement of
derivatives historically accounted for as hedges that have been determined to
not qualify for hedge accounting. In August 2004, we determined we had
incorrectly accounted for certain of our historical hedges, primarily associated
with our natural gas production. See Item 8, Financial Statements and
Supplementary Data, Note 1 for a discussion of this restatement.

The fair value of contract settlements during the period represents the
estimated amounts of derivative contracts settled through physical delivery of a
commodity or by a claim to cash as accounts receivable or payable. The fair
value of contract settlements also includes physical or financial contract
terminations due to counterparty bankruptcies and the sale or settlement of
derivative contracts through early termination or through the sale of the
entities that own these contracts.

The initially recorded value of new contracts includes the fair value of
origination transactions at the inception of the transaction. In 2002, the
initially recorded value of new contracts includes a $59 million gain related to
the completion of our Snohvit LNG supply contract in our other commodity-based
derivatives and a $898 million gain related to our Eagle Point power contract
restructuring transaction.

The change in fair value of contracts during the year represents the change
in value of contracts from the beginning of the period, or the date of their
origination or acquisition, until their settlement or, if not settled, until the
end of the period.

During 2003, in conjunction with our acquisition of Chaparral, we
consolidated derivative contracts that had a fair value of approximately $1.2
billion on the date acquired. The majority of the value of these contracts was
for power purchase agreements and power supply agreements related to power
contract restructuring activities conducted by Chaparral.

47

RESULTS OF OPERATIONS

OVERVIEW

Since 2001, we have experienced tremendous change in our businesses. Prior
to this time, we had grown through mergers and acquisitions and internal growth
initiatives, and at the same time had incurred significant amounts of debt and
other obligations. In late 2001, driven by the bankruptcy of a number of energy
sector participants, followed by increased scrutiny of our debt levels and
credit rating downgrades of our debt and the debt of many of our competitors,
our focus changed to improving liquidity, paying down debt, resolving
substantial contingences and returning to our core natural gas businesses.
Accordingly, our operating results during this three year period have been
substantially impacted by a number of significant events, such as asset sales,
significant legal settlements and ongoing business restructuring efforts as part
of this change in focus.

In February 2004, we completed the December 31, 2003 reserve estimation
process for our proved natural gas and oil reserve estimates. The results of
this process indicated that a 1.8 Tcfe downward revision in our proved reserves
was needed. After an investigation into the factors that caused this revision,
we determined that a material portion of these reserve revisions should be
reflected in the historical periods in this Annual Report on Form 10-K. In
August 2004, we also determined that we had not properly applied the accounting
related to many of our historical hedges, primarily those associated with hedges
of our anticipated natural gas production. Following an investigation into this
matter, we concluded that our historical financial statements should be further
restated. Accordingly, our historical financial results for 1999 through 2002
and for the first three quarters of 2003 were restated for these matters. See
Item 8, Financial Statements and Supplementary Data, Note 1, for a further
discussion of these restatements.

As of December 31, 2003, our operating business segments were Pipelines,
Production, Field Services and Merchant Energy. These segments provide a variety
of energy products and services. They are managed separately and each requires
different technology, operational and marketing strategies. Under our Long-Range
Plan announced in December 2003, our businesses will be divided into two primary
business lines: regulated and unregulated. Our regulated business will include
our existing Pipelines segment, while our unregulated business will include our
existing Production, Field Services and Merchant Energy segments.

Our management uses EBIT to assess the operating results and effectiveness
of our business segments. We define EBIT as net income (loss) adjusted for (i)
items that do not impact our income (loss) from continuing operations, such as
extraordinary items, discontinued operations and the impact of accounting
changes, (ii) income taxes, (iii) interest and debt expense and (iv)
distributions on preferred interests of consolidated subsidiaries. Our
businesses consist of consolidated operations as well as investments in
unconsolidated affiliates. We exclude interest and debt expense and
distributions on preferred interests of consolidated subsidiaries so that
investors may evaluate our operating results without regard to our financing
methods or capital structure. We believe EBIT is helpful to our investors
because it allows them to more effectively evaluate the operating performance of
both our consolidated businesses and our unconsolidated investments 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.

48

Below is a reconciliation of our EBIT (by segment) to our consolidated net
loss for each of the three years ended December 31:

Our earnings in each period were impacted both favorably and unfavorably by
a number of factors affecting our businesses that are enumerated in the table
below. The discussion that follows summarizes these factors and their impact on
our operating segments and our corporate and other operations. For a more
detailed discussion of these factors and other items impacting our financial
performance, see the individual segment and other results included in Item 8,
Financial Statements and Supplementary Data, Notes 5 through 10, and 28.

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

(1) Includes net impairments of cost-based investments included in other income
and expense.

(2) Includes $51 million of accretion expense and $15 million of other charges
included in operation and maintenance expense associated with the Western
Energy Settlement.

(3) Includes $182 million of charges related to changes in accounting estimates
in 2001 associated with additional environmental remediation liabilities,
accrued legal obligations and usability of spare parts inventories.

49

As indicated in the tables above, our EBIT during the past three years has
been impacted by a number of significant developments and events in our business
and industry. In addition to the items described above, two of our operating
segments have experienced significant earnings volatility during this period.
Much of this volatility occurred in our Merchant Energy segment. Beginning in
2002, Merchant Energy began a process of exiting its trading business. At the
same time, the overall energy trading industry declined following the financial
collapse of Enron in late 2001. The combination of these actions and events
resulted in substantial losses in Merchant Energy in 2002 and 2003 compared with
2001. We expect that this segment will continue to experience losses in 2004 as
it continues the liquidation of its trading business.

Our Production segment also experienced earnings volatility from 2001 to
2003 and in 2003 benefited from a favorable pricing environment that allowed for
improved results. However, during that three-year period, our Production segment
sold a significant number of natural gas and oil properties which, coupled with
generally disappointing drilling results and mechanical failures on certain
wells, produced a steady decline in production volumes during that timeframe.
The favorable pricing environment will continue to provide benefits to the
segment during 2004, although its future results will largely be impacted by its
ability to grow its existing reserve base through a successful drilling program
and/or acquisitions.

Finally, during 2001, 2002 and 2003, we incurred approximately $1.8 billion
(including $1.4 billion during 2003) in pretax losses in exiting our petroleum
markets, coal and chemicals businesses, which are classified as discontinued
operations.

Below is a further discussion of the year over year results of each of our
business segments, our corporate activities, interest and debt expense,
distributions on preferred interests of consolidated subsidiaries, income taxes
and the results of our discontinued operations.

INDIVIDUAL SEGMENT RESULTS

The results for 2002 and 2001, as well as for the nine months ended
September 30, 2003 of our Pipelines, Production and Merchant Energy segments
presented and discussed below have been restated for adjustments to our natural
gas reserve estimates and for the manner in which we accounted for many of our
historical hedges, primarily those associated with hedges of our anticipated
natural gas production. See Item 8, Financial Statements and Supplementary Data,
Note 1 for a further discussion of the restatements and the manner in which our
segments were affected. In addition the Merchant Energy segment has been
restated to reflect the reclassification of our historical coal mining and
petroleum markets businesses as discontinued operations.

REGULATED BUSINESSES -- PIPELINES SEGMENT

Our Pipelines segment consists of interstate natural gas transmission,
storage and related services, primarily in the U.S. 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. In addition, some of our
customers have shifted from a traditional dependence solely on long-term
contracts to a portfolio approach which balances short-term opportunities with
long-term commitments. This shift has impacted the volatility of our revenues,
and is due to changes in market conditions and competition driven by state
utility deregulation, local distribution company mergers, new supply sources,
volatility in natural gas prices, demand for short-term capacity and new markets
in power plants.

We are regulated by the FERC, which regulates the rates we can charge our
customers. These rates are a function of the costs of providing services to our
customers, including a reasonable return on our invested capital. As a result,
our revenues 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 existing
customer contracts or re-market expiring contracted capacity is dependent on the
competitive alternatives, the regulatory environment at the federal, state and
local levels and market supply and demand factors at the

50

relevant dates these contracts are extended or expire. The duration of new or
renegotiated contracts will be affected by current prices, competitive
conditions and judgments concerning future market trends and volatility. Subject
to regulatory constraints, we attempt to re-contract or re-market our capacity
at the maximum rates allowed under our tariffs, although, at times, we discount
these rates to remain competitive. The level of discount varies for each of our
pipeline systems. In addition, the FERC has issued various orders related to the
allocation of capacity on the EPNG system, one of our pipeline systems. These
orders impacted our 2003 Pipeline segment revenues and will continue to impact
its future results. In addition, we expect lower annual revenues of
approximately $22 million due to the expiration of certain other risk sharing
provisions on the EPNG system.

Below are the operating results and analysis of these results for our
Pipelines segment for each of the three years ended December 31:

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

(1) Within our revenues and operating expenses are amounts recorded under a
number of natural gas purchase and sale agreements. These contracts are
based on market prices and impact our revenues and operating expenses with
little impact on operating income or EBIT. For the years ended December 31,
2003, 2002 and 2001, revenues on these contracts were $70 million, $56
million and $91 million, and operating expenses were $68 million, $53
million and $90 million.

(2) Throughput volumes excludes volumes related to our equity investments in the
Alliance Pipeline and Portland Natural Gas Transmission systems which were
sold. Throughput volumes exclude intrasegment activities. Prior period
volumes have been restated to reflect current year presentation which
includes billable transportation throughput volume for storage injection and
withdrawal.

Our segment results have been restated in 2002 and 2001 to reflect
adjustments for non-qualifying cash flow hedges of production owned by CIG. For
a further discussion of the restatement, see Item 8, Financial Statements and
Supplementary Data, Note 1.

Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

For the year ended December 31, 2003, our EBIT was $418 million higher than
in 2002. Reduced operating expenses of $238 million, higher non-operating income
of $143 million and improved revenues of $37 million in 2003 contributed to our
improved EBIT performance.

Our 2003 operating expense reductions resulted primarily from the impact of
the Western Energy Settlement reached in 2003. EPNG was a party to that
settlement and recorded a charge in its 2002 operating expenses of $412 million
for its share of the expected settlement amounts. This charge represented the
value of El Paso stock and cash that EPNG would pay to the settling parties. In
the second quarter of 2003, the settlement was finalized and EPNG recorded an
additional net pretax charge of $127 million. Also during 2003, accretion
expense and other miscellaneous charges of $13 million were recorded and
included in

51

operating expenses. Year over year, the difference in recorded charges on the
Western Energy Settlement resulted in a positive operating expense impact of
$272 million.

The $143 million increase in other income resulted primarily from
impairment charges in 2002 related to our equity investment in EPIC Energy
Australia Trust (EPIC). In 2002, we recorded impairments of our Australian
investment of $153 million due to an unfavorable regulatory environment,
increased competition and operational complexities in Australia. During the
second quarter of 2004, we substantially exited our investments in Australian
operations. Partially offsetting these impairment charges were lower equity
earnings of $20 million from our investment in the Alliance Pipeline, which we
sold in the first quarter of 2003.

Our 2003 EBIT was also favorably impacted by our re-application of
Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the
Effects of Certain Types of Regulation, by our CIG and WIC systems, resulting in
an $18 million one-time increase in other income. This income resulted from
recording the regulatory assets of these systems. SFAS No. 71 allows a company
to capitalize items that will be considered in future rate proceedings and this
income resulted from the capitalization of those items that we believe will be
considered in CIG's and WIC's future rate cases. At the same time CIG and WIC
re-applied SFAS No. 71, they adopted the FERC depreciation rate for their
regulated plant and equipment. This change will result in depreciation expense
increases in the future of approximately $9 million annually. Based on our
estimates, we anticipate that the overall annual EBIT impact as a result of our
re-application of SFAS No. 71 will be an annual reduction of EBIT of
approximately $10 million.

The $37 million increase in our revenues was the result of a number of
revenue items, the more significant of which are discussed below. In 2003, we
experienced higher revenues of $57 million due to higher volumes and prices on
natural gas retained on our regulated systems in excess of amounts we used in
our pipeline operations. In addition, completed system expansions and new
transportation contracts increased revenues by $41 million, which, when
considering the operating expense impact of these expansions, increased EBIT by
$37 million. Offsetting these revenue increases was the impact of expiring
capacity contracts which EPNG was prohibited from remarketing due to the FERC
orders and other capacity that EPNG was required to make available to its former
full requirements (FR) customers related to its Line 2000 Power-up project. The
impact of these orders was a decrease in revenues of $35 million. With the
completion of Phases I and II of its Line 2000 Power-up project in February and
April of 2004, EPNG's requirement to dedicate capacity to its FR customers was
terminated. Also contributing to lower revenues was CIG's sale of its Panhandle
field and other production properties in July 2002, which reduced revenues by
$50 million and, when considering related operating expense reductions, resulted
in an EBIT decline of $29 million.

Year Ended December 31, 2002 Compared to Year Ended December 31, 2001

Our EBIT for 2002 decreased $216 million from 2001. This decrease primarily
resulted from a $153 million impairment charge recorded in other income on our
investment in Australia and a $99 million increase in 2002 in operating
expenses. These operating expenses included a $412 million charge in 2002
associated with our Western Energy Settlement and $313 million of merger related
and asset impairment charges in 2001 related to our merger with Coastal. Also
impacting the EBIT decrease were $49 million of lower revenues from capacity
sold under short-term contracts and lower throughput from reduced electric
demand and milder weather in our market areas, a $59 million decrease in
revenues from lower natural gas prices which impacts the income we recognize
from natural gas recovered under our tariffs in excess of the amounts used in
our pipeline operations, and a $49 million reduction in revenues and a $27
million decrease in EBIT as a result of CIG's sale of its Panhandle field in
July 2002. Partially offsetting these EBIT reductions were $27 million of lower
general, administrative and operating costs as a result of cost efficiencies
achieved following the Coastal merger, $49 million of other operating cost
reductions due to lower electrical prices, natural gas imbalance pricing changes
and lower allocated overhead, environmental and legal costs. Further offsetting
these EBIT reductions were the favorable impact of system expansions completed
in 2001 and 2002 as well as a full year of operations at our Elba Island LNG
facility, which increased revenues by $83 million, operating expenses by $33
million and EBIT by $50 million.

52

UNREGULATED BUSINESSES -- PRODUCTION SEGMENT

Our Production segment results have been restated for revisions to our
natural gas and oil reserve estimates and for our accounting for many of our
historical hedges, primarily those associated with hedges of our anticipated
natural gas production. Our Production segment conducts our natural gas and oil
exploration and production activities. Our operating results are driven by a
variety of factors including the ability to locate and develop economic natural
gas and oil reserves, extract those reserves with minimal production costs and
sell the products at attractive prices. Consistent with our Long-Range Plan
announced in December 2003, our long-term strategy includes developing our
production opportunities primarily in the U.S. and Brazil, while prudently
divesting of production properties outside of these regions. As of September
2004, we have sold our production operations in Canada and substantially all of
our operations in Indonesia. Our operations in Canada included activities in
Nova Scotia where, in the first quarter of 2004, we drilled an exploratory well
that was not commercially viable and recorded a $24 million ceiling test charge.
Also in 2004, we acquired the remaining 50 percent interest in our investment in
UnoPaso to increase our production operations in Brazil.

In June 2004, we announced a back-to-basics plan for our production
business. This plan emphasizes strict capital discipline designed to improve
capital efficiency through the use of standardized risk analysis, a heightened
focus on cost control, and revised controls for booking proved natural gas and
oil reserves. This back-to-basics approach is expected to stabilize production
by improving the production mix across our operating areas and generate more
predictable returns.

Reserves and Costs

In February 2004, we completed our estimates of our proved natural gas and
oil reserves as of December 31, 2003. These estimates were prepared internally
by us. Ryder Scott Company and Huddleston & Co., Inc., independent petroleum
engineering firms, performed independent reserve estimates of our proved
reserves for 90 percent and 10 percent of our properties. The total estimate of
proved reserves prepared by these engineers is within five percent of our
internally prepared estimates.

The proved reserve estimate as of December 31, 2003 indicated a 1.8 Tcfe
downward revision of our proved natural gas and oil reserves was needed. The
downward revisions related primarily to our Coal Seam, Texas onshore and
offshore Gulf of Mexico regions. Due to the significance of the reserve
revision, the Audit Committee of the Board of Directors engaged a law firm to
conduct an independent investigation into the reasons for the revisions. The
investigation concluded that a material portion of these revisions related to
prior periods, and as a result we have restated our historical reserve estimates
and our historical financial information derived from these estimates. The
reserve restatement involved utilizing the reserve estimate prepared as of
December 31, 2003 and then reconstructing historical reserve data using actual
historical production data and re-engineered sales of proved reserves. Following
this reserve reconstruction and the recalculation of the discounted future net
cash flows, ceiling test calculations, depletion rates, and gains and losses on
asset sales were recomputed for each period restated. See Item 8, Financial
Statements and Supplementary Data, Notes 1, 9 and 30 for a discussion of our
ceiling test calculation and the restatement of our natural gas and oil
reserves. The restatement will result in a lower depletion rate and reduced
exposure to ceiling test charges in the future than would have been the case
absent the restatement.

Since December 31, 2001, we have sold approximately 1.3 Tcfe of proved
reserves in multiple sales transactions with various third parties. The sale of
these reserves, combined with the normal production declines, mechanical
failures on certain producing wells and disappointing drilling results, have
resulted in our total equivalent production levels declining each quarter since
the first quarter of 2002. For 2003, our total equivalent production has
declined approximately 165 Bcfe or 28 percent as compared to 2002. In addition,
since our depletion rate is determined under the full cost method of accounting,
we expect a higher depletion rate as a result of higher finding and development
costs experienced this year, coupled with a significantly lower reserve base.
After taking into consideration the restatement of our natural gas and oil
reserves for prior periods and the impacts on our restatement of production and
other hedges discussed above, our unit of production depletion rate was
approximately $1.58 per Mcfe and $1.64 per Mcfe for the first and second
quarters of 2004. We expect this rate to be approximately $1.74 per Mcfe for the
third quarter of 2004. See

53

Item 8, Financial Statements and Supplementary Data, Note 30, for a discussion
of our natural gas and oil reserves. For the first eight months of 2004, daily
production has averaged approximately 855 MMcfe/d; however, for the month of
August 2004, daily production averaged approximately 810 MMcfe/d. Our future
trends in production and our depreciation, depletion and amortization rates will
be dependent upon the amount of capital allocated to our Production segment, the
level of success in our drilling programs and future sales activities relating
to our proved reserves.

Production Hedging

We have historically hedged a portion of our anticipated natural gas
production by entering into affiliated hedge transactions with our Merchant
Energy segment, which would then enter into identical transactions with third
parties to complete the hedge. During August 2004, we determined that we had not
properly applied the accounting rules related to many of the historical hedges
of our anticipated natural gas production. Specifically, we determined that many
of the hedges put in place by Merchant Energy did not qualify as hedges for
consolidated reporting purposes, as, in many cases, Merchant Energy had entered
into an offsetting trading transaction. Consequently, we restated our accounting
for these hedges and have not reflected these transactions as hedges in our
segment results or the information presented below.

We primarily conduct our hedging activities through natural gas and oil
derivatives on our natural gas and oil production to stabilize cash flows and
reduce the risk of downward commodity price movements on our sales. Because this
hedging strategy only partially reduces our exposure to downward movements in
commodity prices, our reported results of operations, financial position and
cash flows can be impacted significantly by movements in commodity prices from
period to period. During 2003, we did not add additional hedges on our future
production. Below are the hedging positions on our anticipated natural gas
production as of December 31, 2003:

In May 2004, we entered into the following additional hedges on our future
natural gas production:

In August 2004, we entered into the following hedges on our future oil
production in Brazil:

54

Operating Results

Below are the operating results and analysis of these results for our
Production segment for each of the three years ended December 31:

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

(1) Amounts restated include operating revenues, depreciation, depletion, and
amortization and ceiling test and other charges as well as related subtotals
and totals. Additionally, average realized prices including hedges and unit
of production depletion costs have been restated.

(2) Production costs include lease operating costs and production related taxes
(including ad valorem and severance taxes).

(3) Includes ceiling test charges, restructuring and merger-related costs, asset
impairments, gain (loss) on long-lived assets and changes in accounting
estimates.

(4) Transportation costs are included in operating expenses on our consolidated
statements of income.

(5) Prices are stated before transportation costs.

55

Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

For the year ended December 31, 2003, EBIT was $259 million higher than in
2002. The increase was primarily due to higher revenues resulting from higher
realized natural gas prices, partially offset by lower production volumes as a
result of asset sales, normal production declines and disappointing drilling
results.

Operating Revenues. The following table describes the variance in revenue
between 2003 and 2002 due to: (i) changes in average realized market prices
excluding hedges, (ii) changes in production volumes, and (iii) the effects of
hedges on our revenues.

Our 2003 operating revenues increased $226 million as compared to 2002
primarily due to higher market prices for natural gas and oil offset by lower
production volumes and an unfavorable impact from our hedging program. The
decline in our natural gas volumes was due to the sale of properties in New
Mexico, Oklahoma, Texas, Utah, offshore Gulf of Mexico and western Canada,
normal production declines, mechanical failures in several of our producing
wells and disappointing drilling results. Our production declines and mechanical
failures were primarily in our Texas onshore and offshore Gulf of Mexico
regions. Our 2003 oil, condensate and liquids volume declines were also
primarily due to asset sales, and production declines and mechanical failures in
certain producing wells in our offshore Gulf of Mexico region.

Average realized natural gas prices in 2003, excluding hedges, were $2.32
per Mcf higher than in 2002, an increase of 73 percent. However, partially
offsetting the revenue increase were $36 million of hedging losses in 2003 as
compared to $83 million of hedging gains in 2002 relating to our natural gas
hedge positions. These hedging losses and gains represent the difference between
our hedge price and the market price at the time the hedge positions were
settled. We expect to continue to incur hedge losses in 2004 based on current
market prices for natural gas relative to the prices at which our natural gas
production is hedged.

Operating Expenses. Total operating expenses were $3 million lower in 2003
as compared to 2002 primarily due to a lower depreciation, depletion and
amortization expenses as a result of asset sales and lower production costs,
offset by higher ceiling test and other charges and general and administrative
costs.

Total depreciation, depletion, and amortization expense decreased by $16
million in 2003 as compared to 2002 primarily due to lower production volumes
partially offset by higher unit of production depletion rates. Lower production
volumes in 2003 due to the asset sales, normal production declines and
mechanical failures discussed above reduced our depreciation, depletion and
amortization expenses by $168 million. Partially offsetting lower production
volumes were higher depletion rates that contributed an increase of $130 million
in our depreciation, depletion, and amortization expense. The higher depletion
rate was due to higher finding and development costs in 2003 as a result of
disappointing drilling results and a lower reserve base due to asset sales. Also
offsetting the overall decrease in 2003 was $23 million incurred in 2003 for the
accretion of our liability for asset retirement obligations.

Production costs decreased by $65 million in 2003 as compared to 2002 due
to the asset sales discussed above. However, our production cost per equivalent
unit in 2003 increased by 10 percent or $0.05 per Mcfe primarily as a result of
higher production taxes in 2003 due to higher natural gas and oil prices and
higher tax credits taken in 2002 on high cost natural gas wells.

Ceiling test and other charges increased by $45 million in 2003, compared
to 2002. In 2003, we incurred $76 million in non-cash full cost ceiling test
charges for our Canadian full cost pool and other international properties,
primarily in Brazil and Australia, and a $75 million impairment of the goodwill
associated with our Canadian operations. Also in 2003 we recorded $18 million in
asset impairments net of gains on non-full cost

56

pool asset sales, and $6 million in restructuring costs. In 2002, we recorded
non-cash full cost ceiling test charges of $128 million related to our Canadian
full cost pool and other international properties, primarily in Brazil,
Indonesia, Turkey and Australia.

General and administrative expenses were $35 million higher than in 2002,
or an increase of $0.17 per Mcfe. The increase was primarily due to higher
corporate overhead allocations and lower capitalized costs. Also contributing to
the per unit increase were lower production volumes due to asset sales discussed
above. Our total general and administrative expenses have decreased primarily
due to staff reductions in the first quarter of 2004. Additionally, El Paso
announced plans to reduce its corporate expenses as part of its Long-Range Plan,
which is expected to reduce our corporate overhead allocations.

Year Ended December 31, 2002 Compared to Year Ended December 31, 2001

For the year ended December 31, 2002, EBIT was $1.8 billion higher than in
2001. The increase was primarily due to lower operating expenses in 2002 from
lower ceiling test and other charges, partially offset by the impacts of lower
natural gas prices and lower natural gas volumes due to asset sales.

Operating Revenues. The following table describes the variance in revenue
between 2002 and 2001 due to: (i) changes in average realized market prices
excluding hedges, (ii) changes in production volumes, and (iii) the effects of
hedges on our revenues.

Our 2002 operating revenues decreased by $483 million as compared to 2001
primarily due to lower natural gas prices and lower production volumes. The
decline in our natural gas volumes was primarily due to the sale of properties
in Colorado, Utah, and Texas.

Average realized natural gas prices in 2002, excluding hedges, were $1.07
per Mcf lower than in 2001, a decrease of 25 percent. Partially offsetting these
reductions were $83 million of hedging gains in 2002 versus $247 million of
hedging losses in 2001 relating to our natural gas hedge positions. These hedge
losses and gains represent the difference between our hedge price and the market
price at the time the hedge positions were settled.

Operating Expenses. Total operating expenses were $2.3 billion lower in
2002 as compared to 2001 primarily due to lower non-cash full cost ceiling test
and other charges and depreciation, depletion and amortization expense.

Ceiling test and other charges for the year ended December 31, 2002, were
$2.1 billion lower than in 2001. In 2002, we incurred $128 million in non-cash
full cost ceiling test charges for our Canadian full cost pool and other
international properties, primarily in Brazil, Indonesia, Turkey and Australia,
as compared to charges of $2.1 billion in 2001 on our domestic and international
properties, primarily in Canada, Brazil, Indonesia and Turkey. In addition, in
2001, we incurred merger-related and other costs of $73 million related to
combining our production operations following the Coastal merger.

Total depreciation, depletion and amortization expense decreased in 2002 by
$175 million as compared to 2001 primarily due to lower production volumes as a
result of asset sales, and lower unit of production depletion rates. The lower
production volumes in 2002 reduced our depreciation, depletion and amortization
expense by $71 million and the lower depletion rates contributed to a decrease
of $106 million.

Production costs decreased by $32 million in 2002 as compared to 2001
primarily due to lower production volumes as a result of the asset sales
mentioned above. However, our production costs per equivalent unit were

57

relatively flat in 2002 as compared to 2001. A decrease of 43 percent, or $0.06
per Mcfe, in production taxes was largely offset by an increase in lease
operating costs of $0.05 per Mcfe due to higher labor and workover expenses.
Lower production taxes were primarily due to lower natural gas and oil prices
and tax credits taken in 2002 related to high cost natural gas wells.

General and administrative expenses increased by $32 million from 2001, or
an increase of $0.06 per Mcfe primarily due to higher corporate overhead
allocations and lower production volumes.

UNREGULATED BUSINESSES -- FIELD SERVICES SEGMENT

Our Field Services segment conducts our midstream activities which include
gathering and processing of natural gas. For the majority of 2003, our assets
principally consisted of our general and limited partner holdings of GulfTerra,
a publicly traded master limited partnership in which our subsidiary serves as
the general partner and our consolidated processing assets in south Texas and
south Louisiana. For a discussion of our ownership interests in GulfTerra and
our activities with the partnership, see Item 8, Financial Statements and
Supplementary Data, Note 28. Prior to 2003, our Field Services segment owned
gathering, processing and fractionation assets.

Investment in GulfTerra

We recognize earnings and receive cash from GulfTerra in several ways,
including through a share of the partnership's cash distributions and through
our ownership of limited, preferred and general partner interests. During 2003,
the primary source of earnings in our Field Services segment was from our equity
investment in GulfTerra. Our sale of an effective 50 percent interest in
GulfTerra's general partner in December 2003 as well as the expected completion
of the sale in 2004 of our remaining interest in the general partner of
GulfTerra (upon which we will receive cash and a 9.9 percent interest in the
general partner of GulfTerra and Enterprise) will result in lower equity
earnings in 2004. We also receive management fees under an agreement to provide
operational and administrative services to the partnership. These management
fees have increased as a result of GulfTerra's asset acquisitions in 2002 and
2003, but will terminate at the time of the merger of GulfTerra and Enterprise.
In addition, we are reimbursed for costs paid directly by us on the
partnership's behalf. For the years ended December 31, 2003 and 2002 and 2001,
we were reimbursed approximately $91 million, $60 million, and $33 million for
expenses incurred on behalf of the partnership. During 2003, our equity
investment earnings and cash distributions received from GulfTerra were as
follows:

In addition to our equity investment earnings above, we realized other
income and losses in the fourth quarter of 2003 related to our investment in
GulfTerra as follows:

- a realized loss of $11 million on the redemption by GulfTerra of all of
our Series B units for total proceeds of $156 million;

- a realized gain of $8 million related to our sale of GulfTerra common
units; and

- a net realized gain of $269 million related to the sale of our effective
50 percent interest in the general partner to Enterprise for net proceeds
of $421 million as discussed below.

The sale of one-half of our general partner interest to Enterprise was the
first step in a series of transactions in which GulfTerra will merge with
Enterprise to form one of the largest energy master limited

58

partnerships in the U.S. The merger and related transactions, which are
discussed more fully in Item 8, Financial Statements and Supplementary Data,
Note 28, are subject to customary approvals and is expected to be completed in
the third quarter of 2004.

From 2001 to 2003, we entered into a number of asset sales transactions
with GulfTerra. In 2003, we exchanged communications assets for a release of our
obligation to repurchase the Chaco cryogenic natural gas processing plant in
2021. We recognized a net gain on this transaction of $67 million. In 2002, we
sold assets to GulfTerra for total proceeds of $1.5 billion, including
gathering, processing and transmission assets and substantially all our assets
in the San Juan Basin. Total net gains recognized on the assets sold in 2002
were approximately $210 million. In 2001, we sold assets to GulfTerra for total
proceeds of $255 million, including processing and NGL transportation and
fractionation assets, as well as an investment in Deepwater Holdings, an entity
that owned several pipeline gathering systems in the Gulf of Mexico. The
majority of these assets had been acquired by us one year earlier in a purchase
transaction and accordingly had been recorded at their fair value. As a result,
these sales resulted in no gains or losses. In conjunction with the 2002 sales,
we agreed to reimburse GulfTerra for a portion of its future pipeline integrity
costs related to these assets through 2006. At the time of these sales, we were
unable to estimate the liability associated with this obligation as we and
GulfTerra were in the early stages of our pipeline integrity programs. In
December 2003, we amended this agreement to clarify the types and amounts of
reimbursable costs, and also began reviewing GulfTerra's pipeline integrity
results. This review has continued during 2004. Based on those results, and on
our experience to date related to our own pipeline integrity projects, we
determined that the obligation was both probable and could be estimated. As a
result, we recognized a $74 million loss on this agreement in 2003.

Other Asset Sales

In addition to the sales to GulfTerra discussed above, during 2003 we sold
our gathering systems located in Wyoming to Western Gas Resources, Inc. We also
sold our midstream assets in the Mid-Continent and north Louisiana regions to
Regency Gas Services LLC, an investment of Charlesbank Capital Partners, LLC.
Our Mid-Continent assets primarily included our Greenwood, Hugoton, Keyes and
Mocane natural gas gathering systems, our Sturgis, Mocane and Lakin processing
plants and our processing arrangements at three additional processing plants.
Our north Louisiana assets primarily included our Dubach processing plant and
Gulf States interstate natural gas transmission system.

Gathering and Processing Operations

By the end of 2003, our remaining gathering and processing assets consisted
primarily of south Texas gathering and processing assets and south Louisiana
processing assets. Our south Texas processing plants will be sold to Enterprise
in 2004 as part of the merger between Enterprise and GulfTerra. At that point,
most of our gathering and processing business will be conducted through our
ownership interests in the merged partnership.

We attempt to balance earnings in our gathering and processing business
through a combination of fixed fee-based and market-based services. A majority
of our gathering operations earn margins from fixed fee-based services. However,
some of these operations earn margins from market-based rates. Revenues from
these market-based rate services are the product of the market price, usually
related to the monthly natural gas price index and the volume gathered. Our
processing operations earn a margin based on fixed-fee contracts,
percentage-of-proceeds contracts and make-whole contracts.
Percentage-of-proceeds contracts allow us to retain a percentage of the product
as a fee for the service provided. Make-whole contracts allow us to retain the
extracted liquid products and return to the producer a Btu equivalent amount of
natural gas. Under our percentage-of-proceeds contracts and make-whole
contracts, we may have more sensitivity to price changes during periods when
natural gas and NGL prices are volatile.

59

Below are the operating results and analysis of these results for our Field
Services segment for each of the three years ended December 31:

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

(1) Gross margins consist of operating revenues less cost of products sold. We
believe this measurement is more meaningful for understanding and analyzing
our Field Services operating results because commodity costs play such a
significant role in the determination of profit from our midstream
activities.

Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

For the year ended December 31, 2003, our EBIT was $156 million lower than
2002. Our asset sales in 2003 and 2002 contributed a year over year decrease in
our EBIT of $119 million. We also had $191 million of additional impairments in
2003 compared to 2002. Throughout 2003, natural gas prices were higher relative
to NGL prices, which further reduced EBIT at our processing plants by $11
million. Partially offsetting these declines were $71 million of year over year
net gains realized on the sale of assets in 2003 and 2002, as well as higher
equity earnings of $83 million from our investment in GulfTerra.

The decrease in our gathering and processing gross margins was primarily
the combined result of asset sales and the impact of higher natural gas prices
relative to NGL prices. Our asset sales decreased 2003 gathering margins by $154
million and our 2003 processing margins by $46 million. On our processing and
gathering assets, we experienced higher natural gas prices during 2003 which
reduced our margin per unit at these plants and also minimized the amount of
NGLs extracted, both resulting in lower realized margins and EBIT in 2003 of $11
million.

Our higher operating expenses in 2003 were the result of a $74 million loss
related to our pipeline integrity agreement with GulfTerra in 2003, impairments
on our south Texas gathering and processing assets based on our planned sale of
these assets to Enterprise along with an impairment on our Altonah processing
facility both of which totaled $171 million in 2003, compared with $66 million
of impairments in 2002 on our north Louisiana facilities resulting from the
decision to sell those facilities. We also realized net gains on sales of assets
of $74 million in 2003 compared with $245 million in 2002. The increase in
impairments in 2003 and higher realized gains in 2002 resulted in a year over
year increase in operating expenses of $276 million. Partially offsetting these
increases were higher reimbursements from GulfTerra of $17 million for
administrative and other services and lower operating expenses of $81 million
related to asset sales.

The $310 million increase in other income was primarily due to the $269
million net gain on our sale of an effective 50 percent interest in the general
partner of GulfTerra to Enterprise, as well as an increase in earnings from our
investment in the partnership of $83 million in 2003. Also contributing to the
year over year increase was a loss in 2002 on our investment in the Aux Sable
NGL plant and our Black Forks natural gas processing plant of $50 million and a
gain of $8 million on the sale of a portion of our interest in GulfTerra's
common

60

units in 2003. Partially offsetting these increases were impairments in 2003 on
our investments in Dauphin Island Gathering Partners and Mobile Bay Processing
Partners of $86 million and an $11 million loss on the redemption of our Series
B units in GulfTerra.

Year Ended December 31, 2002 Compared to Year Ended December 31, 2001

For the year ended December 31, 2002, our EBIT was $93 million higher than
2001. During 2002, lower margins of $134 million from the sales of midstream
assets to GulfTerra along with a decrease in processing margins of $58 million
due to lower NGL prices, were offset by lower 2002 operating costs of $361
million. In our operating expenses, we recognized a net gain in 2002 on the
sales of our San Juan Basin assets, our Natural Buttes and Ouray systems and our
Dragon Trail processing plant of $245 million. We also experienced lower
operating costs in 2002 as a result of asset sales of $83 million and from the
favorable impact on operating expenses from 2001 merger charges of $46 million
incurred related to El Paso's merger with Coastal (see Item 8, Financial
Statements and Supplementary Data, Note 5, for a discussion of these merger
charges). Partially offsetting these lower operating costs were 2002 impairment
charges of $66 million on our north Louisiana facilities.

During 2002, equity earnings from our investments were $54 million lower
than 2001. The decrease was primarily due to $50 million of losses during 2002,
on the sales of our investments in the Aux Sable NGL plant and our Black Forks
natural gas processing plant.

61

UNREGULATED BUSINESSES -- MERCHANT ENERGY SEGMENT

Our Merchant Energy segment consists of a Global Power division, an Energy
Marketing and Trading division and a LNG division. Historically, it also had a
petroleum markets division. In 2003, our Board of Directors approved the sale of
these petroleum markets operations and, as a result, we reclassified that
division as discontinued operations for all periods presented. The Energy
Marketing and Trading division of the Merchant Energy segment has historically
entered into transactions with third parties to accomplish hedges for the
Production segment, for a subsidiary in our Pipelines segment and on its own
behalf for capacity it held on natural gas pipelines. This division also
conducted non-hedging transactions on its own behalf. In August 2004, we
determined that we had not properly applied the accounting related to many of
our historical hedges, primarily those associated with hedges of our anticipated
natural gas production. As a result, we were required to restate our historical
financial information to revise this accounting, which included the restatement
of the historical financial statements of the Energy Marketing and Trading
division. For a further discussion of this restatement, see Item 8, Financial
Statements and Supplementary Data, Note 1. Below are the restated operating
results and analysis of these results for our Merchant Energy segment for the
three years ended December 31 (in millions):

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

(1) Gross margin for our Global Power division consists of revenues from our
power plants and the initial net gains and losses incurred in connection
with the restructuring of power contracts, as well as the subsequent
revenues, cost of electricity purchases and changes in fair value of those
contracts. The cost of fuel used in the power generation process is included
in operating expenses. Gross margin for our energy marketing and trading
division consists of revenues from commodity trading and origination
activities less the costs of commodities sold, including changes in the fair
value of our derivative contracts.

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GLOBAL POWER DIVISION

Our Global Power division has three primary business activities: domestic
power plant operations, domestic power contract restructuring activities and
international power plant operations. Since December 31, 2003, we have sold a
substantial portion of our domestic power plant operations and our domestic
power contract restructuring activities for proceeds of approximately $537
million and the assumption by the buyer of approximately $926 million of debt.
Each activity is further discussed below.

Below are the operating results of these activities within our Global Power
division for the three years ended December 31. We have evaluated our operating
results using EBIT due to several significant consolidations and transactions
that affect year-to-year comparability and because our operations include both
equity and consolidated investments.

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

(1) Other consists of the indirect expenses and general and administrative costs
associated with our domestic and international operations, including legal,
finance, and engineering costs and the effects of our financial services
business and power turbine inventory on our operations. Direct general and
administrative expenses of our domestic and international operations are
included in EBIT of those operations.

Domestic Power Plant Operations

Overview. Our domestic operations relate to the ownership and operation of
power plant assets in the U.S. We own two types of domestic plants -- contracted
power operations and merchant power operations. Our contracted power operations
include power plants that have dedicated power contracts with customers
(generally electric utilities) for the generation and sale of power. Since the
long-term sales contracts and long-term fuel contracts in these operations
generally contain fixed prices, operating results in this business are fairly
stable. However, some of our contracted operations have derivative fuel supply
contracts that are recorded at fair value and are subject to changes in fair
value, generally driven by changing prices in the fuels used to fire the plants
(primarily natural gas). Operating results at these plants may vary from period
to period.

Our merchant power operations include plants that operate during peak
periods without dedicated power contracts. Generally, these plants operate when
there is demand for their power and when the market price of power exceeds the
plant's variable costs of generating power. Many of our merchant plants have
contractual obligations, such as transportation capacity contracts, that
represent fixed costs for the plant. Our ability to recover these fixed
operating costs depends largely on electricity demand and the volume of power
generated as well as the margins that can be realized.

Historically, we conducted a significant portion of our domestic power
operations through Chaparral, an unconsolidated joint venture. In 2003, we
acquired the remaining joint venture partner's interest in Chaparral and
consolidated its operations effective January 1, 2003. As a result, our 2003
operating results include the consolidated revenues, expenses and equity
earnings from each of Chaparral's power plants while our 2001 and 2002 operating
results only include the equity earnings and management fees we earned from
Chaparral.

EBIT Analysis. Our 2003 EBIT loss in domestic power plant operations of
$383 million was primarily due to $419 million of asset impairments on our
domestic power plants and our Chaparral investment. The

63

plant impairments resulted from the anticipated sale of most of our domestic
power plants in 2004 as well as operational and contractual issues at several of
our domestic plants. The impairment of Chaparral was the result of declines in
the investment's value that were considered to be other than temporary. See Item
8, Financial Statements and Supplementary Data, Notes 2 and 3, for more
information on these impairments. In 2004, we may record additional impairments
on our power plants as a result of ongoing negotiations related to sales of our
domestic power plants and an ongoing operational and contractual issue at one of
our domestic plants. See Note 28 for a further discussion of this matter. In
2003, we also recorded an $88 million loss primarily due to the write-off of
receivables as a result of the transfer of our interest in the Milford power
facility to the plant's lenders. See Item 8, Financial Statements and
Supplementary Data, Note 28, for a further description of the Milford transfer.
Also contributing to these losses was a $21 million operating loss at our Eagle
Point power plant. Partially offsetting these losses was $105 million of
operating income generated by the power plants from Chaparral that we
consolidated in January 2003.

In December 2003, our Board of Directors approved the sale of substantially
all of our domestic power plant operations, which we expect to complete in 2004.
The majority of plants we sold in 2003 and 2004 or expect to sell in 2004 are
contracted plants that generated EBIT (before realized gains and losses and
impairments) in 2003 of $160 million. By comparison, our merchant plants that we
sold or expect to sell in 2004 generated EBIT losses (also before realized gains
and losses and impairments) in 2003 of $47 million. Our 2004 operating results
will be impacted by the timing and nature of the plants sold.

For the year ended December 31, 2002, our domestic power plant operations
generated EBIT of $80 million. This EBIT was primarily generated by the equity
earnings and management fees we received from Chaparral of $124 million in 2002.
As described above, Chaparral was consolidated in 2003. Also contributing to
EBIT was $20 million of operating income generated by our Eagle Point plant
before the restructuring of its power sales contract in March 2002 (see power
restructuring discussion below). Following the restructuring, the Eagle Point
plant's operating income decreased. Partially offsetting these increases was a
$74 million impairment of our CE Generation power plant in 2002, which resulted
from the anticipated sale of this plant in early 2003. This plant generated
operating income of $22 million in 2002.

For the year ended December 31, 2001, our domestic power plant operations
generated EBIT of $317 million. This EBIT was primarily generated by the equity
earnings and management fees we received from Chaparral of $222 million in 2001.
Also contributing to our 2001 EBIT was $22 million of operating income earned by
our Eagle Point power plant in 2001 before the restructuring of its power sales
contract in 2002. Our CE Generation power plant, which we sold in early 2003,
also generated operating income of $29 million in 2001.

Domestic Power Contract Restructuring Business

Overview. In 2001 and 2002, we and Chaparral restructured several
above-market, long-term power sales contracts with regulated utilities that were
originally tied to older power plants built under PURPA. These contracts were
amended so that the power sold to the utilities was not required to be delivered
from the specified power generation plant, but could be obtained in the
wholesale power market. For a further discussion of our power restructuring
activities, see Item 8, Financial Statements and Supplementary Data, Note 15.

As a result of our credit rating downgrades and economic changes in the
power market, we are no longer pursuing additional power contract restructuring
activities. In 2003, our power restructuring business related solely to the
management of our existing restructured power contracts. In 2001 and 2002, our
results included the impact of power contract restructuring transactions we
completed in those years, in addition to the results of managing these
contracts. On an ongoing basis, the results of our power restructuring business
will consist of the physical sales and purchases of electricity and changes in
fair value of the derivative contracts. Changes in the discount rate used to
calculate the fair value of our power restructuring derivatives, which are based
in part on the credit ratings of our counterparties, can significantly impact
our earnings. See Item 7A, Quantitative and Qualitative Disclosures About Market
Risk for a further discussion of this discount rate risk.

64

Our domestic restructured power contracts currently face a number of risks
that may impact our operating results in the future. We have been actively
divesting the entities that hold our domestic restructured power contracts.
These entities hold power supply and power purchase agreements and have debt.
The power agreements are derivatives carried at fair value while the debt is
recorded based on its original issuance cost. The proceeds we received in past
sale transactions and may receive in future transactions generally differs from
the net assets of these entities, resulting in losses. Reasons for the
differences can include the use of different assumptions by the buyer in
determining the fair value of these instruments. We experienced this when we
sold Utility Contract Funding (UCF) at a loss of approximately $100 million in
2004 and Mohawk River Funding I and IV at a loss of approximately $15 million in
2003, and based on a pending sale of Cedar Brakes I and II that has been
approved by our Board of Directors, we could incur significant additional losses
in the future.

We own restructured power contracts with a fair value of $1.5 billion that
are with a single counterparty, Public Service Electric and Gas (PSEG). PSEG is
currently rated "investment grade" by Moody's Investor's Services and Standard &
Poor's. Changes in the creditworthiness of PSEG could materially impact the fair
value of these contracts and our results of operations. This risk was reduced in
June 2004 when we sold UCF to Bear Stearns. We also have a restructured power
contract held by Mohawk River Funding III with U.S. Gen New England. U.S. Gen
filed for bankruptcy in 2003, and increases or decreases in the amount
recoverable from our bankruptcy claims may significantly impact our future
operating results.

EBIT Analysis. For the year ended December 31, 2003, our domestic power
contract restructuring business generated EBIT of $150 million. The restructured
power contracts we acquired from Chaparral in 2003 increased in fair value by
$75 million and our UCF and other restructured power contracts increased in fair
value by $65 million. These increases resulted primarily from the accretion of
the discounted value of these contracts. Partially offsetting this EBIT was $15
million of losses and impairments related to the sale of two of our power
contract restructuring entities, Mohawk River Funding I and IV.

For the year ended December 31, 2002, our domestic power contract
restructuring business generated EBIT of $341 million. In 2002 we restructured
the power sales contracts at our Eagle Point (also known as UCF) and Mount
Carmel power plants, which resulted in net gains of $501 million, net of
minority interest. Partially offsetting these gains was a $90 million contract
termination fee we paid in 2002 to terminate a steam contract between our Eagle
Point power plant and the Eagle Point refinery (which is included in
discontinued operations). Also offsetting these gains was a $80 million loss on
a power supply agreement that we entered into with our energy marketing and
trading division in 2002 associated with the Eagle Point power contract
restructuring transaction. The $90 million and $80 million losses were
eliminated from El Paso's consolidated results.

For the year ended December 31, 2001, our domestic power contract
restructuring business generated EBIT of $31 million. In 2001 we restructured
the power sales contract at our CDECCA power plant (also known as Mohawk River
Funding IV), which resulted in a net gain of $31 million.

International Power Plant Operations

Overview. Our international operations primarily include contracted plants
and pipelines located in South America, Central America, Asia, and Europe. From
November 2001 to April 2003, we conducted a majority of our power plant
operations in Brazil through Gemstone, an unconsolidated joint venture. In the
second quarter of 2003, we acquired our joint venture partner's interest in
Gemstone and began consolidating Gemstone's debt and its investments in the
Macae, Porto Velho and Araucaria power plants. As a result, our consolidated
operating results beginning in April 2003 include the revenues, expenses and
equity earnings from Gemstone's assets. Our 2001 and 2002 operating results only
include the equity earnings we earned from Gemstone. Due to deteriorating
economic conditions in several South American, Central American and Asian
countries, we have recorded impairments on our international power plants in
2001 and 2002. For a further discussion of these impairments, see Item 8,
Financial Statements and Supplementary Data, Note 28.

65

As part of our Long-Range Plan, we announced our intent to dispose of a
majority of our international power operations over the next several years, with
the exception of our Brazilian power operations. The future operating results of
our global power division will be impacted by the timing of these sales.

EBIT Analysis-Brazil. For the year ended December 31, 2003, our Brazilian
power operations generated EBIT of $177 million. This EBIT was primarily
generated from operating income of $156 million at our Macae power plant, which
operated at its full operational capacity throughout 2003. Our Macae power
plant's power sales contract expires in 2007, at which time the plant will
convert into a merchant plant that can enter into new bilateral power contracts.
Also contributing to EBIT was $28 million of earnings from our interest in the
Porto Velho power plant, which reached full commercial operations in the third
quarter of 2003.

For the year ended December 31, 2002, our Brazilian power operations
generated EBIT of $78 million. This EBIT was primarily generated from our equity
earnings of $109 million from Gemstone, which was created in November 2001. As
described above, we consolidated Gemstone and its interests in the Macae and
Porto Velho power plants in 2003. The operations of these two power plants were
the primary contributors to Gemstone's equity earnings. Partially offsetting
these earnings was a $19 million fee we paid related to the cancellation of a
turbine purchase order.

For the year ended December 31, 2001, our Brazilian power operations
generated EBIT of $114 million. This EBIT was primarily generated from $75
million of fees that we earned for engineering, construction management and
other services for the Macae power project before Gemstone acquired Macae. Also
contributing to this EBIT was $23 million of operating income at our Rio Negro
power plant.

In 2002 and 2003, Rio Negro's power purchaser disputed and did not pay some
of its billings, which significantly decreased the power plant's operating
income in those years. The power purchase agreements for the Manaus and Rio
Negro Plants expire in 2005 and 2006. Based on the anticipated results of
negotiations for the renewal of these contracts we recorded a $135 million
impairment charge in the first quarter of 2004. See Item 8, Financial Statements
and Supplementary Data, Note 22 for a description of these matters.

EBIT Analysis-Other International. For the year ended December 31, 2003,
our other international power operations generated EBIT of $119 million. This
EBIT was primarily generated from operating income of $49 million at our 15
Asian power plants. Also contributing to this EBIT was a $28 million gain on the
sale of two of our Argentinean power plants. Our remaining EBIT was primarily
generated by our Central American and European power plants.

For the year ended December 31, 2002, the EBIT loss from our other
international power plant operations was $246 million. This loss was primarily
due to the $342 million impairment of our Argentinean power plants and the $48
million impairment of our Chinese and Indian power plants due to deteriorating
economic conditions in those countries. Partially offsetting these losses was a
$77 million net gain we recorded on the restructuring and termination of a power
contract at our Nejapa power plant in El Salvador. Also offsetting these losses
was operating income of $46 million at our Asian power plants.

For the year ended December 31, 2001, our other international power
operations generated EBIT of $9 million. This EBIT was primarily generated from
operating income of $52 million at our Asian power plants and $21 million of
operating income earned by our Nejapa power plant before the restructuring of
its power sales contract. Also contributing to this EBIT was operating income of
$12 million at our Samalayuca power plant in Mexico, which we sold in 2002.
Partially offsetting this income was $74 million impairment of our East Asia and
Fife power plants in 2001 due to deteriorating economic conditions in the
countries where those power plants are located.

Other Global Power Operations

For the year ended December 31, 2003, the EBIT loss from our other global
power operations was $70 million. This loss was primarily due to a $22 million
settlement charge in 2003 associated with the cancellation of purchase
obligations on two power turbines and an $11 million impairment of our
capitalized turbine costs. The remaining EBIT loss was primarily due to general
and administrative costs in our global

66

power division, which have remained relatively consistent in 2002 and 2003. We
expect these costs to decrease in 2004 as we sell our domestic power assets,
partially offset by increased severance due to the asset sales.

For the year ended December 31, 2002, the EBIT loss from our other global
power operations was $259 million. This loss was primarily due to a $162 million
impairment of our capitalized domestic and international turbine costs and a $44
million goodwill impairment charge on our financial services business that we
recorded in 2002 due to our reduced capital expenditure plans related to future
power and financial services investments. The remaining EBIT loss was primarily
due to general and administrative costs in our global power division.

For the year ended December 31, 2001, the EBIT loss from our other global
power operations was $10 million. This loss was primarily due to general and
administrative costs in our global power division.

ENERGY MARKETING AND TRADING DIVISION

Our Energy Marketing and Trading division's operations primarily center
around the management of its trading portfolio and marketing of our natural gas
and oil production. As mentioned previously, the information related to this
division has been restated to correct the manner in which we accounted for many
of the hedges of our anticipated natural gas production and certain other
derivative transactions. As a result of the deterioration of the energy trading
environment in late 2001 and 2002, we announced in November 2002 that we would
reduce our involvement in the energy marketing and trading business and pursue
an orderly liquidation of our trading portfolio.

As a part of our Long-Range Plan, we announced that our historical energy
trading operations would become a marketing and trading business focused
principally on the physical marketing of natural gas and oil produced in our
Production segment. At this time, we do not anticipate the early liquidation of
all the transactions in our trading portfolio before the end of their contract
term. We may retain contracts because (i) they are either uneconomical to sell
or terminate in the current environment due to their contractual terms or credit
concerns of the counterparty, (ii) a sale would require an acceleration of cash
demands, or (iii) they represent hedges associated with activities reflected in
other segments of our business including our Production segment and our global
power division. Changes to our liquidation strategy may impact the cash flows
and the financial results of this division.

Our trading portfolio contains derivative and non-derivative contracts. Our
derivative contracts primarily impact our gross margin through changes in their
fair value each period. The fair value of our derivative contracts fluctuates
monthly because of a variety of market factors that impact commodity prices,
which are difficult to estimate or predict. For a discussion on our methodology
of determining the fair value of our derivative contracts, see Item 8, Financial
Statements and Supplementary Data, Note 15. Our non-derivative contracts
primarily relate to obligations under our long-term pipeline transportation and
natural gas storage contracts. In 2003, demand charges on these contracts were
$177 million. The transportation contracts impact our gross margin as delivery
or service under the contract occurs, and income or loss is based on the
difference between the demand charge and the locational price difference for the
delivery points under the contract.

During 2003, our trading business operated in a challenging environment
with reduced liquidity, lower credit standing of participants and a general
decline in the number of trading counterparties. Additionally, in the fourth
quarter of 2002, we implemented new accounting rules (Emerging Issues Task Force
(EITF) Issue No. 02-3, Issues Related to Accounting for Contracts Involved in
Energy Trading and Risk Management Activities) that significantly impacted the
carrying value of our portfolio. Many contracts which were accounted for as
derivative contracts in 2002 are now accounted for as non-derivative contracts.
All of these factors reduce the comparability of our operating results between
periods.

67

Below are the operating results and analysis of these results for our
Energy Marketing and Trading division for each of the three years ended December
31:

Year Ended December 31, 2003

For the year ended December 31, 2003, we had an EBIT loss of $809 million.
During 2003, we experienced a $424 million decrease in the fair value of our
derivatives, primarily our natural gas contracts. We sell natural gas at a fixed
price in many of these contracts. With the significant increase in natural gas
prices during 2003, the difference between the fixed prices in these contracts
and the market prices continued to increase and, as a result, the fair value of
these derivatives decreased resulting in losses. Also contributing to this loss
was $47 million of gross margin losses from the early termination of our
derivative and non-derivative contracts that resulted from the ongoing
liquidation of our trading portfolio in 2003. We also recorded a $32 million net
reduction in the carrying value of bankruptcy claims on three of our trading
counterparties, NRG Power Marketing, Mirant Corporation and Enron Corporation,
which is included in gross margin. Our non-derivative contracts had settlement
losses of $165 million in 2003, which were primarily due to demand charges we
could not recover on our transportation contracts. In 2003, price differentials
at the contractual delivery points were not wide enough to recover our demand
charges under these contracts. Partially offsetting these losses was a $30
million gross margin gain on the sale of several LNG contracts and a $78 million
increase in the fair value of our Midwest derivative tolling agreement. This
tolling contract is sensitive to changes in forecasted power prices relative to
natural gas prices in the Midwest. These forecasted power prices increased
significantly relative to natural gas prices at the end of 2003, which increased
the fair value of this contract by $52 million in the fourth quarter of 2003. We
expect the fair value of this contract will be volatile over its entire contract
term, which extends through 2019. In 2003, we also recorded $26 million of
accretion expense, net of adjustments, on our portion of the Western Energy
Settlement, and $28 million of bad debt expense associated with a fuel supply
agreement we have with the Berkshire power plant in operating expenses. See Item
8, Financial Statements and Supplementary Data, Note 28 for a further discussion
of Berkshire. Our remaining 2003 operating expenses of $129 million included
general and administrative expenses, which decreased from 2002 to 2003 due to
decreases in employee headcount in 2003. We anticipate that these costs will
continue to decline as a result of previous and future employee headcount and
other cost reductions in this division through 2004.

Year Ended December 31, 2002

For the year ended December 31, 2002, we had an EBIT loss of approximately
$2 billion. This loss was primarily the result of a $1.2 billion decrease in the
fair value of our derivative positions, which are included in gross margin. In
2002, we experienced general market declines in energy trading resulting from
lower price volatility in the natural gas and power markets and a generally
weaker trading and credit environment in 2002. Additionally, in the fourth
quarter of 2002, many of the participants in the trading industry, including us,
publicly announced their intention to discontinue or significantly reduce
trading operations, which we believe, along with other factors caused a
deterioration of the market valuations of trading and marketing assets. The
decrease in the fair value of our derivatives was primarily related to the
reduced option value, with the remainder of the decrease resulting from
volatility of forward prices and reductions in creditworthiness of our
counterparties. Additionally, because of these issues, we significantly reduced
our origination activities in 2002 compared to 2001. Also contributing to the
loss was a decrease in gross margin of $25 million that resulted from the early
termination of several of our non-derivative transportation contracts that
resulted from the

68

ongoing liquidation of our trading portfolio in 2002. Partially offsetting these
losses was a $59 million gain we recorded in the second quarter of 2002 on a
long-term LNG supply contract with Snohvit, which was subsequently sold in the
fourth quarter of 2002. Also contributing to this loss was a $487 million charge
related to the Western Energy Settlement, which is included in operating
expenses. Our remaining 2002 operating expenses of $190 million include general
and administrative expenses, which increased from 2001 to 2002 due to an
expansion of our trading operations in 2002 before the decision to liquidate our
trading portfolio in late 2002.

Year Ended December 31, 2001

For the year ended December 31, 2001, we had EBIT of approximately $1.7
billion. This EBIT was primarily due to a $1.6 billion increase in the fair
value of our derivatives in 2001 from increases in trading volumes and price
volatility of our trading portfolio, net of reserves established for the
bankruptcy of Enron in 2001. In addition, we sell natural gas at a fixed price
in many of our natural gas derivative contracts. With the significant decrease
in natural gas prices during 2001, the difference between the fixed prices in
these contracts and the market prices continued to improve and, as a result, the
fair value of these derivatives increased resulting in mark-to-market gains. We
also originated several power, natural gas and transportation contracts in 2001
that generated gross margin of $211 million. Partially offsetting this EBIT was
2001 operating expenses of $137 million. These operating expenses include
general and administrative expenses, which steadily increased before the
decision to liquidate our trading portfolio in late 2002.

LNG DIVISION

In 2001 and 2002, our LNG division included the development of LNG
terminals and our Energy Bridge technology and holding the long-term charter
arrangements on ships that employed this technology. In 2003, we announced our
intent to exit this business because of the significant capital and credit
requirements associated with this business. We have either sold or are in the
process of selling all of our LNG operations.

Results of our LNG division were as follows for each of the three years
ended December 31:

Year Ended December 31, 2003

We reported an EBIT loss of $185 million for the year ended December 31,
2003. This loss primarily resulted from a $119 million loss on the sale of the
assets and intellectual property rights related to our Energy Bridge technology,
as well as the termination our obligations under the long-term ship charters
related to this technology. Also contributing to this loss were $33 million of
other asset impairments of our capitalized terminal development and testing
facility costs. Our realized and unrealized losses were included as part of our
operating expenses.

Years Ended December 31, 2002 and 2001

We reported an EBIT loss of $35 million and $25 million for the years ended
December 31, 2002 and 2001 related primarily to our operating expenses. These
operating expenses related to environmental and engineering costs we incurred
related to the development of our terminals and testing the regasification
process used by our Energy Bridge technology.

69

CORPORATE AND OTHER EXPENSES, NET

Our Corporate and Other operations include general and administrative
functions as well as the operations of our telecommunications and other
miscellaneous businesses. During 2001, there was a significant downturn in the
telecommunications market. As a result, we refocused our telecommunications
strategy and reduced our capital investment in this business. We currently
provide wholesale metropolitan transport services in Texas and collocation
services through a facility in Chicago. In April 2004, we sold 28 percent of our
interest in our Texas metro transport business to Genesis Park, L.P., a third
party investment partnership, and changed the name to Alpheus Communications.

In December 2002, we decided to exit our long-haul and metro dark fiber
business because of the minimal contribution and high cost of maintaining this
business. Under these circumstances, we reduced the carrying value of our
inventory to $5 million by recording an impairment of $153 million. The market
value was determined by an independent appraiser who evaluated the dark fiber
value based on market conditions existing in the fourth quarter of 2002 and
recent liquidation values for dark fiber. In addition, because of the continuing
decline of economic conditions in the telecommunications industry, we
periodically evaluated the fair value of our Texas-based assets. During 2003, we
recognized a $163 million goodwill impairment based on our evaluations of the
amounts we would recover from this business.

Our collocation and cross-connect services are available through our
Lakeside Technology Center, a Chicago-based telecommunications facility. The
building design, which is beneficial for the needs of a telecommunications
provider, has limited alternative uses. Due to the ongoing decline in the
industry and the loss of a significant tenant in the building in 2002, we
recorded a contingent loss totaling $113 million, of which $11 million was
recognized immediately. The remaining $102 million was being recorded as a
quarterly charge until the end of the lease in 2006. In 2003, upon the
consolidation of the lessor, to whom we provided a full guarantee of repayment,
we recognized an additional impairment of $127 million.

In May 2004, we announced we would consolidate our Houston-based operations
into one location. We anticipate the consolidation will be substantially
complete by the end of 2004. As a result, we have established or will establish
an accrual to record a liability for our obligations under the terms of the
leases in the period that the space is vacated and available for subleasing. We
currently lease approximately 912,000 square feet of office space in the
buildings we are vacating under various leases with lease terms expiring in 2004
through 2014. We estimate the total accrual for the relocation will be
approximately $80 million to $100 million. Expenses related to the relocation
will be expensed in the period that they are incurred.

Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

Corporate and other net expenses for the year ended December 31, 2003, were
$368 million higher than in 2002. During 2003, we recorded impairment charges of
$396 million, including an impairment of goodwill of $163 million in our
telecommunications business and the losses recorded on our Lakeside Technology
Center, both of which are discussed above. In 2002, we recorded $153 million of
valuation adjustments of our dark fiber inventory and a $15 million impairment
of our right-of-way assets in our telecommunications business. In 2003, we also
incurred $42 million of employee severance costs and a $37 million loss compared
with a $21 million gain in 2002 on early debt extinguishments. These actions
were part of our continuing efforts to reduce debt and lower our costs. We
expect to incur additional employee severance costs in 2004 as these cost
reduction efforts continue. In 2002, we recorded $51 million of restructuring
related costs. See Item 8, Financial Statements and Supplementary Data, Note 5,
for a further discussion of these charges. Finally, we recorded $112 million of
net foreign currency losses in 2003 versus $90 million of net losses in 2002,
primarily related to our Euro-denominated debt.

Year Ended December 31, 2002 Compared to Year Ended December 31, 2001

Corporate and other net expenses for the year ended December 31, 2002, were
$1.1 billion lower than in 2001. In 2001, we recorded $1.2 billion in
merger-related and asset impairment charges related to our merger with Coastal.
We also recognized additional 2001 costs of $144 million related to increased
estimates of environmental remediation costs, legal obligations and reductions
in the fair value of spare parts inventories to
70

reflect changes in usability of spare parts inventories based on an ongoing
evaluation of our operating standards and plans following the Coastal merger. In
2002, we recorded a $168 million valuation adjustment of our dark fiber
inventory and right-of-way assets as discussed above, $90 million of net foreign
currency losses and various incremental costs related to our 2002 restructuring
activities.

INTEREST AND DEBT EXPENSE

Over the past three years, our interest and debt expense increased. During
this period, we issued debt to finance the growth of our business segments and
consolidated several "off-balance sheet" financing obligations in order to
simplify our balance sheet. During this period, our overall debt balances
increased from approximately $16 billion in 2001 to $22 billion by December 31,
2003. During this growth period, we have raised funds in both domestic and
international capital markets, the majority of which was fixed rate debt. In the
future, our ability to access the capital markets and issue debt securities will
be a function of market conditions and our credit ratings at that time. Based on
a number of rating actions since the latter part of 2002, we anticipate that we
will incur higher interest rates on any future debt issuances. Furthermore,
since some of our debt offerings have been in foreign markets, currency
fluctuations can impact the cost of that debt. In December 2003, we announced
under our Long-Term Plan that we would reduce our long-term debt. As we continue
to repay our debt obligations, our interest expense will decline in 2004 and
beyond. For a further discussion of changes in our debt instruments, see Item 8,
Financial Statements and Supplementary Data, Note 20. Below is an analysis of
our interest and debt expense for each of the three years ended December 31 (in
millions):

Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

Interest expense on long-term debt for the year ended December 31, 2003,
was $475 million higher than in 2002. The increase was due to higher average
debt balances in 2003 compared with 2002. We consolidated Chaparral, Gemstone
and Lakeside in 2003, which increased our debt by $2.1 billion as of December
31, 2003 and increased our interest expense by $236 million in 2003. In
addition, our debt and other financing obligations increased by another $1.0
billion in 2003 associated with other debt issuances and consolidations. We also
consolidated approximately $1.5 billion of debt in early 2003 that we paid off
in late 2003. These two changes in debt increased our interest expense by
approximately $219 million in 2003. Also contributing to the increase was $20
million due to the reclassification of $625 million of preferred securities as a
result of the adoption of SFAS No. 150. Additionally, our interest expense
increased in 2003 due to debt issuances and debt consolidations in 2003 at
higher average interest rates than debt retired during the period.

Interest expense on revolving credit facilities for the year ended December
31, 2003, was $105 million higher than in 2002 due to the higher borrowings
under these facilities in 2003. Our average revolving credit balances, which
were based on daily ending balances, were approximately $1.5 billion, with an
average interest rate of 3.97% during 2003.

Interest expense on commercial paper for the year ended December 31, 2003,
was $26 million lower than in 2002 due to the discontinuance of commercial paper
activities in the fourth quarter of 2002.

Other interest for the year ended December 31, 2003, was $58 million lower
than in 2002. The decrease was primarily due to a $23 million reduction in
interest expense from the retirement of other financing obligations, a $16
million reduction in affiliated interest expense on notes we had with Chaparral
and Gemstone which were eliminated as a result of the consolidation of these
investments in the second quarter of

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2003, and a $19 million decrease due to the discontinuance of factoring
activities in 2003. These decreases were partially offset by a $7 million
increase as a result of the write-off of unamortized financing costs due to the
retirement of the Trinity River financing arrangement in 2003.

Capitalized interest for the year ended December 31, 2003, was $2 million
higher than in 2002 primarily due to higher average interest rates in 2003 than
in 2002.

Year Ended December 31, 2002 Compared to Year Ended December 31, 2001

Interest expense on long-term debt for the year ended December 31, 2002,
was $204 million higher than in 2001. The increase was due to a higher average
debt balance. During 2002, we issued long-term debt of approximately $4.4
billion that had an average interest rate of 7.9%. These issuances increased
interest on long-term debt by approximately $233 million. During the same year,
we retired approximately $1.5 billion of long-term debt that had an average
interest rate of 5.19%, resulting in a decrease to interest expense from these
retirements of approximately $35 million. The remaining increase was primarily
due to various debt issuances during 2001 that were outstanding for the entire
year in 2002.

Interest expense on revolving credit facilities for the year December 31,
2002, was $12 million lower than in 2001 due to the lower borrowings under these
facilities in 2002. Our average revolving credit balances, which were based on
daily ending balances, were approximately $144 million, with an average interest
rate of 3.36% during 2002.

Interest expense on commercial paper for the year ended December 31, 2002,
was $44 million lower than in 2001 primarily due to lower average short-term
interest rates on commercial paper activities in 2002.

Other interest for the year ended December 31, 2002, was $15 million lower
than in 2001. The decrease was primarily due to an $8 million decrease in
interest resulting from retirement of our other financing obligations, an $8
million decrease in interest related to a decline of receivable factoring, and
an $8 million decrease in interest due to termination of a marketing sales
contract during 2002. These decreases were partially offset by a $9 million
increase in interest from the debt securities issued to Gemstone in November
2001.

Capitalized interest for the year ended December 31, 2002, was $31 million
lower than in 2001 primarily due to the lower interest rates in 2002 than in
2001.

DISTRIBUTIONS ON PREFERRED INTERESTS OF CONSOLIDATED SUBSIDIARIES

Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

Distributions on preferred interests of consolidated subsidiaries for the
year ended December 31, 2003, were $107 million lower than in 2002 due to the
redemptions of the preferred stock on two of our subsidiaries, Trinity River and
Coastal Securities, the consolidation of Gemstone which had a preferred interest
of $300 million in one of our subsidiaries, the refinancing and redemption of
our Clydesdale financing arrangement and the reclassification of our Capital
Trust I and Coastal Finance I mandatorily redeemable preferred securities to
long-term financing obligations as a result of the adoption of SFAS No. 150. As
a result of this reclassification, we began recording the preferred returns on
these securities as interest expense rather than as distributions of preferred
interests.

As a result of our actions in 2003, our remaining preferred interests
outstanding as of December 31, 2003 only consist of $300 million of preferred
stock of El Paso Tennessee Pipeline Co. and a number of smaller interests in
other consolidated subsidiaries.

Year Ended December 31, 2002 Compared to Year Ended December 31, 2001

Distributions on preferred interests of consolidated subsidiaries for the
year ended December 31, 2002, were $58 million lower than in 2001 primarily due
to the redemptions of the preferred interests related to El Paso Oil & Gas
Resources, El Paso Oil & Gas Associates, Coastal Limited Ventures, Capital Trust
IV and the partial redemption of our Clydesdale financing arrangement. The
decrease was also due to lower interest rates in 2002. Most of the preferred
returns were based on variable short-term rates, which were lower on

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average in 2002 than in 2001. Partially offsetting these decreases were higher
returns on preferred interests issued as part of our Gemstone investment
completed in November 2001.

For a further discussion of our borrowings and other financing activities
related to our consolidated subsidiaries, see Item 8, Financial Statements and
Supplementary Data, Note 21.

INCOME TAXES

Income tax benefits for the years ended December 31, 2003, 2002 and 2001
were $584 million, $649 million and $70 million resulting in effective tax rates
of 49 percent, 33 percent and 15 percent. Of the 2003 amount, $139 million
related to tax benefits recorded on abandonments and sales of certain of our
foreign investments. The effective tax rate for 2003 absent these benefits would
have been 37 percent. Included in the 2001 tax benefit was a tax charge of $115
million related to non-deductible merger charges and changes in our estimate of
additional tax liabilities. Taxes on the majority of these estimated additional
liabilities were paid in 2001. The effective tax rate for 2001 absent these
charges would have been 40 percent. Differences in our effective tax rates from
the statutory tax rate of 35 percent in all years were primarily a result of the
following factors:

- state income taxes;

- earnings from unconsolidated affiliates where we anticipate receiving
dividends;

- non-deductible portion of merger-related costs and other tax adjustments
to provide for revised estimated liabilities;

- foreign income taxed at different rates;

- abandonments and sales of foreign investments;

- valuation allowances;

- deferred credit on loss carryovers;

- non-deductible dividends on the preferred stock of a subsidiary;

- non-conventional fuel tax credits;

- goodwill impairment; and

- depreciation, depletion and amortization.

For a reconciliation of the statutory rate to our effective tax rate, as
well as matters that could impact our future tax expense, see Item 8, Financial
Statements and Supplementary Data, Note 11.

Included in our deferred tax assets (excluding valuation allowances) as of
December 31, 2003 was $400 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
expenses related to 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. For a discussion of valuation allowances based
on our ability to utilize state tax benefits from deduction of the charge we
took related to the Western Energy Settlement, see Item 8, Financial Statements
and Supplementary Data, Note 11.

DISCONTINUED OPERATIONS

In 2002 and 2003, we made the decision to eliminate our involvement in
several businesses and to sell the related assets and liabilities, and, as a
result, we reported the following operations as discontinued operations as of
December 31, 2003 and 2002 and for the years ended December 31, 2003, 2002, and
2001.

Petroleum Markets Operations

During 2003, our Board of Directors authorized the sale of substantially
all of our petroleum markets operations. Based on our intent to dispose of these
operations, we adjusted these assets to their estimated fair value and
recognized pre-tax charges during 2003 totaling approximately $1.5 billion,
which included $1.1 billion related to our Aruba refinery and $264 million
related to the impairment of our Eagle Point

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refinery. In 2003, we completed the sales of $664 million of these assets and
completed an additional $905 million in early 2004. We completed the sale of
substantially all of our remaining petroleum markets assets in 2004.

Coal Mining Operations

In late 2002 and the first quarter of 2003, we sold our coal mining
operations. These operations consisted of fifteen active underground and two
surface mines located in Kentucky, Virginia and West Virginia. Following the
authorization of the sale by our Board of Directors, we recorded impairment
charges of $185 million in our loss from discontinued operations during 2002. We
have now fully exited our coal operations.

For each of the three years ended December 31, the after-tax income (loss)
related to our discontinued operations was as follows (in millions):

For the year ended December 31, 2003, we reported a loss from our
discontinued operations of $1.3 billion. This was primarily due to impairments
of long-lived assets of $1.5 billion, including $1.1 billion related to our
Aruba refinery and $264 million related to our Eagle Point refinery. In
addition, our Aruba refinery continued to generate operating losses of
approximately $82 million. These losses resulted from lower throughput at Aruba
due primarily to operational difficulties following a fire at the facility in
April 2001 and scheduled turnaround maintenance activities. Our losses were
partially offset by operating income at our Eagle Point refinery of
approximately $42 million. This income resulted from higher margins at Eagle
Point due to a widening difference between the price of the crude oil inputs
used by the refinery and the prices we sold the refined products produced. This
loss was also partially offset by $90 million of gains recorded on the sale of
our Florida terminalling and transportation assets, asphalt facilities and
chemical facilities in 2003 and $65 million of business interruption and
property damage insurance recoveries related to the Aruba facility fire in 2001.

For the year ended December 31, 2002, we reported a loss from discontinued
operations of $365 million. This was primarily due to operating losses of
approximately $129 million at our Aruba refinery, resulting from operational
difficulties following the fire at the facility. Also contributing to this loss
was a $185 million impairment of our coal mining operations and a $91 million
impairment of our MTBE chemical processing plant. Our losses were partially
offset by operating income at our Eagle Point refinery of approximately $97
million, resulting from higher throughput at Eagle Point during 2002 due to a
widening difference between the price of the crude oil input used by the
refinery and the prices at which we sold the products produced. This loss was
also partially offset by $46 million of insurance recoveries in 2002 related to
the assets destroyed in the Aruba fire.

For the year ended December 31, 2001, we reported a loss from discontinued
operations of $85 million. This loss included $262 million of merger-related
costs, asset impairments and other charges associated with our merger with
Coastal in 2001. See Item 8, Financial Statements and Supplementary Data, Notes
5 and 7 for a discussion of these merger-related costs and asset impairments.
Also contributing to the loss was an operating loss of $87 million at the Eagle
Point refinery as a result of lower margins and throughput. Partially offsetting
these losses was $97 million of insurance recoveries related to the fire at the
Aruba refinery, operating income of $126 million from our refined product and
crude oil marketing activities and $23 million of other income which includes
equity earnings and income from the lease of our Corpus Christi refinery to
Valero.

COMMITMENTS AND CONTINGENCIES

For a discussion of our commitments and contingencies, see Item 8,
Financial Statements and Supplementary Data, Note 22, incorporated herein by
reference.

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CRITICAL ACCOUNTING POLICIES

Our critical accounting policies are those accounting policies that involve
the use of complicated processes, assumptions and/or judgments in the
preparation of our financial statements. We have discussed the development and
selection of our critical accounting policies and related disclosures with the
audit committee of our Board of Directors and have identified the following
critical accounting policies for the current year.

Price Risk Management Activities. We record the derivative instruments
used in our price risk management activities at their fair values in our balance
sheet. We estimate the fair value of our derivative instruments using exchange
prices, third-party pricing data and valuation techniques that incorporate
specific contractual terms, statistical and simulation analysis and present
value concepts. One of the primary assumptions used to estimate the fair value
of our derivative instruments is pricing. Our pricing assumptions are based upon
price curves derived from actual prices observed in the market, pricing
information supplied by a third-party valuation specialist and independent
pricing sources and models that rely on this forward pricing information. Other
significant assumptions that we use in determining the fair value of our
derivative instruments are those related to time value, anticipated market
liquidity and credit risk of our counterparties. The assumptions and
methodologies that we use to determine the fair values of our derivatives may
differ from those used by our derivative counterparties. These differences can
be significant and could impact our future operating results as we settle these
derivative positions.

Accounting for Natural Gas and Oil Producing Activities. We use the full
cost method to account for our natural gas and oil producing activities. Under
this accounting method, we capitalize substantially all of the costs incurred in
connection with the acquisition, development and exploration of natural gas and
oil reserves in full cost pools maintained by geographic areas, regardless of
whether reserves are actually discovered.

The process of estimating natural gas and oil reserves, particularly proved
undeveloped and proved non-producing reserves, is very complex, requiring
significant judgment in the evaluation of all available geological, geophysical,
engineering and economic data. As of December 31, 2003, of our total proved
reserves, 34 percent were undeveloped and 12 percent were developed, but
non-producing. In addition, the data for a given field may also change
substantially over time as a result of numerous factors, including additional
development activity, evolving production history and a continual reassessment
of the viability of production under changing economic conditions. As a result,
material revisions to existing reserve estimates occur from time to time.
Although every reasonable effort is made to ensure that reserve estimates
reported represent the most accurate assessments possible, the subjective
decisions and variances in available data for various fields increases the
likelihood of significant changes in these estimates. If all other factors are
held constant, an increase in estimated proved reserves decreases our unit of
production depletion rate. Higher reserves can also reduce the likelihood of
ceiling test impairments. For further discussions of our reserves as well as the
restatement of our historical financial statements as a result of downward
revisions to our reserve estimates, see Part I, Item 1, Business, under
Production segment and Item 8, Financial Statements and Supplementary Data,
Notes 1 and 30.

Under the full cost accounting method, we are required to conduct quarterly
impairment tests of our capitalized costs in each of our full cost pools. This
impairment test is referred to as a ceiling test. Our total capitalized costs,
net of related income tax effects, are limited to a ceiling based on the present
value of future net revenues using end of period spot prices, discounted at 10
percent, plus the lower of cost or fair market value of unproved properties, net
of related income tax effects. If these discounted revenues are not equal to or
greater than total capitalized costs, we are required to write-down our
capitalized costs to this level. Our ceiling test calculations include the
effects of derivative instruments we have designated as, and that qualify as,
cash flow hedges of our anticipated future natural gas and oil production. As a
result of determining that we had not properly applied the accounting rules for
hedges of our natural gas production, we recorded additional ceiling test
charges in 2001. See a further discussion of the restatement for the manner in
which we historically accounted for natural gas hedges in Item 8, Financial
Statements and Supplementary Data, Note 1.

75

The ceiling test calculation assumes that the price in effect on the last
day of the quarter is held constant over the life of the reserves, even though
actual prices of natural gas and oil are volatile and change from period to
period. We attempt to realize more determinable cash flows through the use of
hedges, but a decline in commodity prices can impact the results of our ceiling
test and may result in writedowns.

Asset Impairments. The asset impairment accounting rules require us to
continually monitor our businesses and the business environment to determine if
an event has occurred indicating that a long-lived asset or investment may be
impaired. If an event occurs, which is a determination that involves judgment,
we then assess the expected future cash flows against which to compare the
carrying value of the asset group being evaluated, a process which also involves
judgment. We ultimately arrive at the fair value of the asset which is
determined through a combination of estimating the proceeds from the sale of the
asset, less anticipated selling costs (if we intend to sell the asset), or the
discounted estimated cash flows of the asset based on current and anticipated
future market conditions (if we intend to hold the asset). The assessment of
project level cash flows requires us to make projections and assumptions for
many years into the future for pricing, demand, competition, operating costs,
legal and regulatory issues and other factors and these variables can, and often
do, differ from our estimates. These changes can have either a positive or
negative impact on our impairment estimates. We recorded impairments of our
long-lived assets of $880 million, $444 million and $75 million during the years
ended December 31, 2003, 2002 and 2001. We recorded impairments of our
discontinued operations of $1.5 billion, $290 million and $103 million during
the years ended December 31, 2003, 2002 and 2001. Future changes in the economic
and business environment can impact our original and ongoing assessments of
potential impairments.

Accounting for Environmental Reserves. We accrue environmental reserves
when our assessments indicate that it is probable that a liability has been
incurred or an asset will not be recovered, and an amount can be reasonably
estimated. Estimates of our liabilities are based on currently available facts,
existing technology and presently enacted laws and regulations taking into
consideration the likely effects of societal and economic factors, and include
estimates of associated onsite, offsite and groundwater technical studies, and
legal costs. Actual results may differ from our estimates, and our estimates can
be, and often are, revised in the future, either negatively or positively,
depending upon actual outcomes or changes in expectations based on the facts
surrounding each exposure.

As of December 31, 2003, we had accrued approximately $412 million for
environmental matters. Our reserve estimates range from approximately $412
million to approximately $632 million. Our accrual represents a combination of
two estimation methodologies. First, where the most likely outcome can be
reasonably estimated, that cost has been accrued ($94 million). Second, where
the most likely outcome cannot be estimated, a range of costs is established
($318 million to $538 million) and the lower end of the range has been accrued.

Accounting for Pension and Other Postretirement Benefits. Our accruals
related to our pension and other postretirement benefits are based on actuarial
calculations. In performing these calculations, our actuaries must use
assumptions, including those related to the return that we expect to earn on our
plan assets, discount rates used in calculating benefit obligations, the rate at
which we expect the compensation of our employees to increase over the plan
term, the cost of health care when benefits are provided under our plans and
other factors.

Actual results may differ from the assumptions included in these actuarial
calculations, and as a result our estimates associated with our pension and
other postretirement benefits can be, and often are, revised in the future, with
either a negative or positive effect on the costs we recognize and the accruals
we make. The following table shows the impact of a one percent change in the
primary assumptions used in our actuarial

76

calculations associated with our pension and other postretirement benefits for
the year ended December 31, 2003 (in millions):

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

(1) If the actual return on plan assets was one percent lower than the expected
return on plan assets, our expected cash contributions to our pension and
other postretirement benefit plans would not significantly change.

Our discount rate assumptions reflect the rates of return on the
investments we expect to use to settle our pension and other postretirement
obligations in the future. We combined current and expected rates of return on
investment grade corporate bonds to develop the discount rates used in our
benefit expense and obligation estimates as of September 30, 2003.

Our estimates for our net benefit expense (income) are partially based on
the expected return on pension plan assets. We use a market-related value of
plan assets to determine the expected return on pension plan assets. In
determining the market-related value of plan assets, differences between
expected and actual asset returns are deferred and recognized over three years.
Due to losses in our pension plan assets during 2002, the fair value of plan
assets used to determine the 2003 net benefit expense (income) was less than the
market-related value of plan assets. If we used the fair value of our plan
assets instead of the market-related value of plan assets in determining the
expected return on pension plan assets, our net benefit income would have been
$108 million lower for the year ended December 31, 2003.

We have not recorded an additional pension liability for our primary
pension plan because the fair value of plan assets exceeded the accumulated
benefit obligation in that plan by approximately $202 million and $362 million
as of September 30, 2003 and December 31, 2003. If the accumulated benefit
obligation exceeded plan assets under this primary pension plan as of September
30, 2003, we would have recorded a pre-tax additional pension liability of
approximately $960 million, plus an amount equal to the excess of the
accumulated benefit obligation over plan assets of the primary pension plan. We
would have also recorded an amount equal to this additional pension liability to
accumulated other comprehensive loss, net of taxes, in our balance sheet.

NEW ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

See Item 8, Financial Statements and Supplementary Data, Note 2 under New
Accounting Pronouncements Issued But Not Yet Adopted which is incorporated
herein by reference.

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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
differences between assumed facts or bases and actual results can be material,
depending upon the circumstances. Where, in any forward-looking statement, we or
our management express an expectation or belief as to future results, that
expectation or belief is expressed in good faith and is believed to have a
reasonable basis. We cannot assure you, however, that the statement of
expectation or belief will result or be achieved or accomplished. The words
"believe," "expect," "estimate," "anticipate" and similar expressions will
generally identify forward-looking statements. All of our forward-looking
statements, whether written or oral, are expressly qualified by these cautionary
statements and any other cautionary statements that may accompany such
forward-looking 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 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 LIQUIDITY

WE HAVE SIGNIFICANT DEBT AND BELOW INVESTMENT GRADE CREDIT RATINGS, WHICH HAVE
IMPACTED AND WILL CONTINUE TO IMPACT OUR FINANCIAL CONDITION, RESULTS OF
OPERATIONS AND LIQUIDITY.

We have significant debt of approximately $22 billion as of December 31,
2003 and have significant debt service and debt maturity obligations. The
ratings assigned to our senior unsecured indebtedness are 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). These ratings have increased our cost of capital and our operating
costs, particularly in our trading operations, and could impede our access to
capital markets. Moreover, we must retain greater liquidity levels to operate
our business than if we had investment grade credit ratings. Our expected debt
maturities as of December 31, 2003 for 2004, 2005 and 2006 are $1,409 million,
$1,585 million and $1,769 million, respectively. If our ability to generate or
access capital becomes significantly restrained, our financial condition and
future results of operations could be significantly adversely affected. See Item
8, Financial Statements and Supplementary Data, Note 20, for a further
discussion of our debt.

WE MAY NOT ACHIEVE ALL OF THE OBJECTIVES SET FORTH IN OUR LONG-RANGE PLAN IN A
TIMELY MANNER OR AT ALL.

Our ability to achieve the objectives of our Long-Range Plan, as well as
the timing of their achievement, if at all, is subject, in part, to factors
beyond our control. These factors include (1) our ability to raise cash from
asset sales, which may be impacted by our ability to locate potential buyers in
a timely fashion and obtain a reasonable price or by competing asset sale
programs by our competitors, (2) our ability to recover working capital, (3) our
ability to generate additional cash by improving the performance of our pipeline
and production operations, (4) our ability to exit the power, trading and LNG
businesses in the manner and within the time period we expect, (5) our ability
to significantly reduce debt, and (6) our ability to preserve sufficient cash
flow to service our debt and other obligations. If we fail to achieve in a
timely manner the targets of our Long-Range Plan, our liquidity or financial
position could be materially adversely affected. In addition, it is possible
that any of the asset sales contemplated by our Long-Range Plan could be at
prices that are below our current book value for the assets, which could result
in recorded losses that could be substantial.

78

A BREACH OF THE COVENANTS APPLICABLE TO OUR DEBT AND OTHER FINANCING
OBLIGATIONS COULD AFFECT OUR ABILITY TO BORROW FUNDS AND COULD ACCELERATE OUR
DEBT AND OTHER FINANCING OBLIGATIONS AND THOSE OF OUR SUBSIDIARIES.

Our debt and other financing obligations contain restrictive covenants and
cross-acceleration provisions. A breach of any of these covenants could preclude
us or our subsidiaries from issuing letters of credit and from borrowing under
our $3 billion revolving credit facility, and could accelerate our long-term
debt and other financing obligations and that of our subsidiaries. If this were
to occur, we may not be able to repay such debt and other financing obligations
upon such acceleration.

As discussed in Item 8, Financial Statements and Supplementary Data, Note
1, we have restated our historical financial statements to reflect a reduction
in our historically reported proved natural gas and oil reserves and to revise
the manner in which we accounted for certain hedges primarily associated with
our anticipated natural gas production.

We believe that the material restatements of our financial statements as
discussed in Item 8, Financial Statements and Supplementary Data, Note 1 would
have constituted events of default under our $3 billion revolving credit
facility and various other financing transactions; specifically under the
provisions of these arrangements related to representations and warranties on
the accuracy of our historical financial statements and on our debt to total
capitalization ratio. During 2004, we received several waivers on our $3 billion
revolving credit facility and various other financing transactions to address
these issues. These waivers continue to be effective. We also received an
extension with various lenders until November 30, 2004 to file our first and
second quarter 2004 Forms 10-Q, which we expect to meet. If we are unable to
file these Forms 10-Q by that date and are not able to negotiate an additional
extension of the filing deadline, our $3 billion revolving credit facility and
various other transactions could be accelerated. As part of obtaining these
waivers, we also amended various provisions of the $3 billion revolving credit
facility, including provisions related to events of default and limitations on
our ability as well as that of our subsidiaries, to repay indebtedness scheduled
to mature after June 30, 2005. Based upon a review of the covenants contained in
our indentures and the financing agreements of our other outstanding
indebtedness, the acceleration of our $3 billion revolving credit facility could
constitute an event of default under some of our other debt agreements. In
addition, three of our subsidiaries have indentures associated with their public
debt that contain $5 million cross-acceleration provisions.

Various other financing arrangements entered into by us and our
subsidiaries, including El Paso CGP and El Paso Production Holding Company,
include covenants that require us to file financial statements within specified
time periods. Non-compliance with such covenants does not constitute an
automatic event of default. Instead, such agreements are subject to acceleration
when the indenture trustee or the holders of at least 25 percent of the
outstanding principal amount of any series of debt provides notice to the issuer
of non-compliance under the indenture. In that event, the non-compliance can be
cured by filing financial statements within specified periods of time (between
30 and 90 days after receipt of notice depending on the particular indenture) to
avoid acceleration of repayment. The holders of El Paso Production Holding
Company's debt obligations waived the financial filing requirements through
December 31, 2004. The filing of our first and second quarter 2004 Forms 10-Q
for these subsidiaries will cure the event of non-compliance resulting from our
failure to file financial statements on these subsidiaries. In addition, neither
we nor any of our subsidiaries have received notice of the default caused by our
failure to file our financial statements or the financial statements of our
subsidiaries also impacted by the restatement. In the event of an acceleration,
we may be unable to meet our payment obligations with respect to the related
indebtedness.

Furthermore, material restatements of our financial statements for the
period ended December 31, 2001 could cause a default under the financing
agreements entered into in connection with our $950 million Gemstone notes due
October 31, 2004. Currently, $748 million of Gemstone notes are outstanding.
However, we currently expect to repay these notes in full upon their maturity on
October 31, 2004.

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OUR ABILITY TO ACCESS CAPITAL MARKETS UNDER OUR EXISTING SHELF REGISTRATION
STATEMENT MAY BE LIMITED AS A RESULT OF THE RESTATEMENT OF OUR HISTORICAL
FINANCIAL RESULTS.

In March 2004, we announced that a downward revision of our natural gas and
oil reserves would result in a restatement of our historical financial
statements. In August 2004, we announced that we would be required to further
restate our historical financial statements for the manner in which we applied
the accounting rules related to our hedges of our natural gas production and
certain other derivatives. As a result of the time required to complete these
revisions, our annual report on this Form 10-K was not filed in a timely manner
which, for a period of 12 months from the date of this filing, will restrict our
ability to access approximately $1 billion of capacity under our shelf
registration statement without filing additional disclosure information with the
SEC, which may be subject to a full review. The additional disclosure
requirements, and any related review by the SEC, could be expensive and impede
our ability to access capital in a timely fashion. If our ability to access
capital becomes significantly restrained, our financial condition and future
results of operations could be significantly adversely affected.

WE ARE SUBJECT TO FINANCING AND INTEREST RATE EXPOSURE RISKS.

Our future success depends on our ability to access capital markets and
obtain financing at cost effective rates. Our ability to access financial
markets and obtain cost-effective rates in the future are dependent on a number
of factors, many of which we cannot control, including changes in:

- our credit ratings;

- interest rates;

- the structured and commercial financial markets;

- market perceptions of us or the natural gas and energy industry;

- changes in tax rates due to new tax laws;

- our stock price; and

- changes in market prices for energy.

RISKS RELATED TO LEGAL AND REGULATORY MATTERS

ONGOING LITIGATION AND INVESTIGATIONS RELATED TO OUR FINANCIAL STATEMENTS
ASSOCIATED WITH OUR RESERVE ESTIMATES AND HEDGES COULD SIGNIFICANTLY ADVERSELY
AFFECT OUR BUSINESS.

In May 2004, we completed an independent investigation of the reason for or
cause of the significant revisions to our natural gas and oil reserves.
Following this investigation, we announced that we would reduce our proved
natural gas and oil reserve estimates as of December 31, 2003 by approximately
1.8 Tcfe and, as a result, restate our historical financial statements. In
August 2004, we announced that we would be required to further restate our
historical financial statements for the manner in which we applied the
accounting rules related to many of our historical hedges, primarily those
associated with hedges of our anticipated natural gas production, and conducted
an additional investigation into the reasons for this restatement. As a result
of our reduction in reserve estimates, several class action lawsuits were filed
against us and several of our subsidiaries. The reserve revisions are also the
subject of investigations by the SEC and the U.S. Attorney and the hedging
matters are also the subject of an investigation by the U.S. Attorney and may
become the subject of a separate inquiry by the SEC, any of which could result
in significant fines against us. These investigations and lawsuits, and possible
future claims based on these same facts, may further negatively impact our
credit ratings and place further demands on our liquidity. We cannot provide
assurance at this time that the effects and results of these or other
investigations or of the class action lawsuits will not be material to our
financial conditions, results of operations and liquidity.

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IF WE ARE UNABLE TO CERTIFY THE EFFECTIVENESS OF OUR INTERNAL CONTROLS OVER
FINANCIAL REPORTING, WE COULD SUFFER A LOSS OF PUBLIC CONFIDENCE IN OUR
INTERNAL CONTROLS, WHICH COULD HAVE A NEGATIVE IMPACT ON OUR FINANCIAL
PERFORMANCE AND THE MARKET VALUE OF OUR COMMON STOCK.

Item 308 of Regulation S-K, which was promulgated pursuant to Section 404
of the Sarbanes-Oxley Act of 2002, requires us, as of December 31, 2004, to
provide an annual report on our internal controls over financial reporting,
including an assessment as to whether or not our internal controls over
financial reporting are effective. We are also required to have our auditors
attest to our assessment and to individually opine on the effectiveness of our
internal controls over financial reporting. In connection with our ongoing
efforts to assess the effectiveness of the design and operation of our internal
controls, we have identified several deficiencies that collectively constitute a
material weakness in our internal controls. We have taken or are taking
significant steps to remediate these deficiencies. For more information
regarding our evaluation of our internal controls, the identified deficiencies
therein and our remediation efforts related thereto, see Item 9A, Controls and
Procedures. If we timely complete our assessment of our internal controls, but
we do not adequately address known material weaknesses or we discover other
material weaknesses, this will be disclosed in management's assessment of our
internal controls in our periodic filings. If our auditor either disagrees with
our assessment or otherwise concludes that our internal controls are not
effective, this will be disclosed in the auditor's report on internal controls
in our periodic filings. Furthermore, if we or our auditors are unable to timely
complete an assessment of our internal controls or our auditors' review of our
assessment efforts, we would be deficient in our reporting obligations under the
Securities Exchange Act of 1934, which may restrict our access to the capital
markets and would result in non-compliance with the filing obligations in a
significant portion of our financing documents, which could result in an event
of default under one or more of those documents. Under any of these
circumstances, we could be subjected to additional regulatory scrutiny and
suffer a loss of public confidence in our internal controls, which could have a
negative impact on our financial performance and the market value of our common
stock.

THE AGENCIES THAT REGULATE OUR PIPELINE BUSINESSES AND THEIR CUSTOMERS AFFECT
OUR PROFITABILITY.

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

In addition, increased regulatory requirements relating to the integrity of
our pipelines requires additional spending in order to maintain compliance with
these requirements. Any additional requirements that are enacted could
significantly increase the amount of these expenditures.

Further, state agencies that regulate our pipelines' local distribution
company customers could impose requirements that could impact demand for our
pipelines' 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. Some of these sites have been designated as
Superfund sites by the EPA under the Comprehensive Environmental Response,
Compensation and Liability Act. We are also party to legal proceedings involving
environmental matters pending in various courts and agencies.

Compliance with environmental laws and regulations can require significant
costs, such as costs of clean-up and damages arising out of contaminated
properties, and the failure to comply with environmental

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laws and regulations may result in fines and penalties being imposed. 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 concerning our environmental
matters, see Part I, Item 3, Legal Proceedings, and Item 8, Financial Statements
and Supplementary Data, Note 22.

COSTS OF OTHER LITIGATION MATTERS COULD EXCEED OUR ESTIMATES.

We are involved in various lawsuits in which we or our subsidiaries have
been sued. Although we believe we have established appropriate reserves for
these liabilities, we could be required to set aside additional reserves in the
future and these amounts could be material. For additional information
concerning our litigation matters, see Part I, Item 8, Financial Statements and
Supplementary Data, Note 22.

RISKS RELATED TO OUR BUSINESS

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 domestic and foreign 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.

THE SUCCESS OF OUR PIPELINE BUSINESS, IN PART, DEPENDS ON FACTORS BEYOND OUR
CONTROL.

Most of the natural gas and natural gas liquids we transport and store are
owned by third parties. As a result, the volume of natural gas and natural gas
liquids 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 throughput, to renegotiate existing contracts as they expire,
or to remarket unsubscribed capacity on our pipeline systems:

- 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 action of regulatory bodies;

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- 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 a pipeline subsidiary; and

- unfavorable movements in natural gas and liquids prices.

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

Substantially all of our pipeline subsidiaries' revenues are generated
under contracts which expire periodically and must be renegotiated and extended
or replaced. We cannot assure that we will be able to extend or replace these
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, EPNG's largest customer, requested, and in September 2004 received, the
approval of the California Public Utilities Commission to give notice to
terminate certain of its transportation agreements with us by February 25, 2005,
with the intent of negotiating to reduce its capacity holdings on that pipeline
system as part of an effort to diversify its capacity holdings. For a further
discussion of these matters, see Part I, Item I, Business -- Regulated
Businesses -- Pipelines Segment, Markets and Competition.

In particular, our ability to extend and/or replace 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 our interstate pipelines;

- 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 PIPELINE
BUSINESSES.

Revenues generated by our transmission, storage, and processing contracts
depend on volumes and rates, both of which can be affected by the prices of
natural gas and natural gas liquids. Increased 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 transmission, storage and processing
operations is subject to continued development of additional oil and natural gas
reserves 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, storage and processing through our systems or
facilities. 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

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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 sale or transportation of natural
gas and natural gas liquids;

- abundance of supplies of alternative energy sources; and

- political unrest among oil producing countries.

NATURAL GAS AND OIL PRICES ARE VOLATILE. A SUBSTANTIAL DECREASE IN NATURAL GAS
AND OIL PRICES OR CHANGES IN BASIS DIFFERENTIALS COULD ADVERSELY AFFECT THE
FINANCIAL RESULTS OF OUR EXPLORATION AND PRODUCTION BUSINESS.

Our future financial condition, revenues, results of operations, cash
flows, future rate of growth and the carrying value of our natural gas and oil
properties depend primarily upon the prices we receive for our natural gas and
oil production. Natural gas and oil prices historically have been volatile and
are likely to continue to be volatile in the future, especially given current
world geopolitical conditions. The prices for natural gas and oil are subject to
a variety of additional factors that are beyond our control. These factors
include:

- the level of consumer demand for, and the supply of, natural gas and oil;

- commodity processing, gathering and transportation availability;

- the level of imports of, and the price of, foreign natural gas and oil;

- the ability of the members of the Organization of Petroleum Exporting
Countries to agree to and maintain oil price and production controls;

- domestic governmental regulations and taxes;

- the price and availability of alternative fuel sources;

- weather conditions;

- market uncertainty;

- political conditions or hostilities in natural gas and oil producing
regions;

- worldwide economic conditions; and

- decreased demand for the use of natural gas and oil because of market
concerns about global warming or changes in governmental policies and
regulations due to climate change initiatives.

Further, because approximately 83 percent of our proved reserves at
December 31, 2003 were natural gas reserves, we are substantially more sensitive
to changes in natural gas prices than we are to changes in oil prices. Declines
in natural gas and oil prices would not only reduce revenue, but could reduce
the amount of natural gas and oil that we can produce economically and, as a
result, could adversely affect the financial results of our production business.
Changes in natural gas and oil prices can have a significant impact on the
calculation of our full cost ceiling test. A significant decline in natural gas
and oil prices could result in a downward revision of our reserves and a
write-down of the carrying value of our natural gas and oil properties which
could be substantial, and would negatively impact our net income and
stockholders' equity.

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THE SUCCESS OF OUR NATURAL GAS AND OIL EXPLORATION AND PRODUCTION BUSINESSES IS
DEPENDENT, IN PART, ON FACTORS THAT ARE BEYOND OUR CONTROL.

In addition to prices, the performance of our natural gas and oil
exploration and production businesses is dependent, in part, upon a number of
factors that we cannot control, including:

- the results of future drilling activity, including exploratory programs
that recently have not been successful;

- our ability to identify and precisely locate prospective geologic
structures and to drill and successfully complete wells in those
structures in a timely manner;

- our ability to expand our leased land positions in desirable areas, which
often are subject to intensely competitive conditions;

- increased competition in the search for and acquisition of reserves;

- future drilling, production and development costs, including drilling rig
rates and oil field services costs;

- future tax policies, rates, and drilling or production incentives by
state, federal, or foreign governments;

- increased federal or state regulations, including environmental
regulations, that limit or restrict the ability to drill natural gas or
oil wells, reduce operational flexibility, or increase capital and
operating costs;

- decreased demand for the use of natural gas and oil because of market
concerns about global warming or changes in governmental policies and
regulations due to climate change initiatives;

- declines in production volumes, including those from the Gulf of Mexico;
and

- continued access to sufficient capital to fund drilling programs to
develop and replace a reserve base with rapid depletion characteristics.

OUR NATURAL GAS AND OIL DRILLING AND PRODUCING OPERATIONS INVOLVE MANY RISKS
AND MAY NOT BE PROFITABLE.

Our operations are subject to all the risks normally incident to the
operation and development of natural gas and oil properties and the drilling of
natural gas and oil wells, including well blowouts, cratering and explosions,
pipe failure, fires, formations with abnormal pressures, uncontrollable flows of
natural gas, oil, brine or well fluids, release of contaminants into the
environment and other environmental hazards and risks. The nature of the risks
is such that some liabilities could exceed our insurance policy limits, or, as
in the case of environmental fines and penalties, cannot be insured. As a
result, we could incur substantial costs that could adversely affect our future
results of operations, cash flows or financial condition.

In addition, in our drilling operations we are subject to the risk that we
will not encounter commercially productive reservoirs as evidenced by our lack
of success in recent exploratory programs. New wells drilled by us may be
unproductive, or we may not recover all or any portion of our investment in
those wells. Drilling for natural gas and oil can be unprofitable, not only
because of dry holes but also due to wells that are productive but do not
produce sufficient net reserves to return a profit at then realized prices after
deducting drilling, operating and other costs.

ESTIMATING OUR RESERVES, PRODUCTION AND FUTURE NET CASH FLOW IS DIFFICULT.

Estimating quantities of proved natural gas and oil reserves is a complex
process that involves significant interpretations and assumptions. It requires
interpretations of available technical data and various estimates, including
estimates based upon assumptions relating to economic factors, such as future
commodity prices, production costs, severance and excise taxes, capital
expenditures and workover and remedial costs, and the assumed effect of
governmental regulation. As a result, our reserve estimates are inherently
imprecise. Also, the use of a 10 percent discount factor for estimating the
value of our reserves, as prescribed by the SEC, may not necessarily represent
the most appropriate discount factor, given actual interest rates and risks to
which our production business or the natural gas and oil industry, in general,
are subject. Any significant variations
85

from the interpretations or assumptions used in our estimates or changes of
conditions could cause the estimated quantities and net present value of our
reserves to differ materially.

The reserve data included in this report represents estimates. You should
not assume that the present values referred to in this report represent the
current market value of our estimated natural gas and oil reserves. The timing
of the production and the expenses from development and production of natural
gas and oil properties will affect both the timing of actual future net cash
flows from our proved reserves and their present value. Changes in the present
value of these reserves could cause a write-down in the carrying value of our
natural gas and oil properties, which could be substantial, and would negatively
affect our net income and stockholders' equity.

As of December 31, 2003, approximately 34 percent of our estimated proved
reserves were undeveloped. Recovery of undeveloped reserves requires significant
capital expenditures and successful drilling operations. The reserve data
assumes that we can and will make these expenditures and conduct these
operations successfully, but future events, including commodity price changes,
may cause these assumptions to change. In addition, estimates of undeveloped
reserves and proved but non-producing reserves are subject to greater
uncertainties than estimates of producing reserves.

THE SUCCESS OF OUR POWER GENERATION ACTIVITIES, IN PART, DEPENDS ON MANY
FACTORS BEYOND OUR CONTROL.

The success of our remaining domestic and international power projects
could be adversely affected by factors beyond our control, including:

- alternative sources and supplies of energy becoming available due to new
technologies and interest in self generation and cogeneration;

- increases in the costs of generation, including increases in fuel costs;

- uncertain regulatory conditions resulting from the ongoing deregulation
of the electric industry in the U.S. and in foreign jurisdictions;

- our ability to negotiate successfully and enter into, advantageous power
purchase and supply agreements;

- the possibility of a reduction in the projected rate of growth in
electricity usage as a result of factors such as regional economic
conditions, excessive reserve margins and the implementation of
conservation programs;

- risks incidental to the operation and maintenance of power generation
facilities;

- the inability of customers to pay amounts owed under power purchase
agreements;

- the increasing price volatility due to deregulation and changes in
commodity trading practices; and

- over-capacity of generation in markets served by the power plants we own
or in which we have an interest.

OUR USE OF DERIVATIVE FINANCIAL INSTRUMENTS COULD RESULT IN FINANCIAL LOSSES.

Some of our subsidiaries use futures, swaps and option contracts traded on
the New York Mercantile Exchange, over-the-counter options and price and basis
swaps with other natural gas merchants and financial institutions. To the extent
we have unhedged positions or hedging procedures do not work as planned,
fluctuating commodity prices could cause our sales, net income, and cash
requirements to be volatile.

We could incur financial losses in the future as a result of volatility in
the market values of the energy commodities we trade, or if one of our
counterparties fails to perform under a contract. The valuation of these
financial instruments involves estimates. Changes in the assumptions underlying
these estimates can occur, changing our valuation of these instruments and
potentially resulting in financial losses. To the extent we hedge our commodity
price exposure and interest rate exposure, we forego the benefits we would
otherwise experience if commodity prices were to increase, or interest rates
were to change. The use of derivatives also
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requires the posting of cash collateral with our counterparties which can impact
our working capital (current assets and liabilities) when commodity prices or
interest rates change. For additional information concerning our derivative
financial instruments, see Item 7A, Quantitative and Qualitative Disclosures
About Market Risk and Item 8, Financial Statements and Supplementary Data, Note
14.

OUR FOREIGN OPERATIONS AND INVESTMENTS INVOLVE SPECIAL RISKS.

Our activities in areas outside the U.S., including a material
concentration and investment exposure in our international power, pipeline and
production projects of approximately $1.6 billion located in Brazil and
approximately $0.3 billion in Pakistan, are subject to the risks inherent in
foreign operations, including:

- loss of revenue, property and equipment as a result of hazards such as
expropriation, nationalization, wars, insurrection and other political
risks;

- the effects of currency fluctuations and exchange controls, such as
devaluation of foreign currencies and other economic problems; and

- changes in laws, regulations and policies of foreign governments,
including those associated with changes in the governing parties.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to several market risks in our normal business activities.
Market risk is the potential loss that may result from market changes associated
with an existing or forecasted financial or commodity transaction. The types of
market risks we are exposed to and examples of each are:

- Commodity Price Risk

- Natural gas prices change, impacting the forecasted sale of natural
gas in our Production segment;

- Price spreads between natural gas and natural gas liquids change,
making the natural gas liquids we produce in our Field Services
segment less valuable;

- Locational price differences in natural gas change, affecting our
ability to optimize pipeline transportation capacity contracts held in
our Merchant Energy segment; and

- Electricity and natural gas prices change, affecting the value of our
natural gas contracts, power contracts and tolling contracts held in
our Merchant Energy segment.

- Interest Rate Risk

- Changes in interest rates affect the interest expense we incur on our
variable-rate debt and the fair value of our fixed-rate debt; and

- Changes in interest rates used in the estimation of the fair value of
our derivative positions can result in increases or decreases in the
unrealized value of those positions.

- Foreign Currency Exchange Rate Risk

- Weakening or strengthening of the U.S. dollar relative to the Euro can
result in an increase or decrease in the value of our Euro-denominated
debt obligations and the related interest costs associated with that
debt; and

- Changes in foreign currencies exchange rates where we have
international investments may impact the value of those investments
and the earnings and cash flows from those investments.

Each segment manages these risks by frequently entering into contractual
commitments involving physical or financial settlement that attempts to limit
the amount of risk or opportunity related to future market movements. Our risk
management activities typically involve the use of the following types of
contracts:

- Forward contracts, which commit us to purchase or sell energy commodities
in the future, involving the physical delivery of an energy commodity,
and energy related contracts including transportation, storage,
transmission and power tolling arrangements;

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- Futures contracts, which are exchange-traded standardized commitments to
purchase or sell a commodity or financial instrument, or to make a cash
settlement, at a specific price and future date;

- Options, which convey the right to buy or sell a commodity, financial
instrument or index at a predetermined price;

- Swaps, which require payments to or from counterparties based upon the
differential between two prices for a predetermined contractual
(notional) quantity; and

- Structured contracts, which may involve a variety of the above
characteristics.

Many of the contracts we utilize in our risk management activities are
derivative financial instruments. Discussions of our accounting policies for
derivative instruments are included in Item 8, Financial Statements and
Supplementary Data, Notes 2 and 15.

COMMODITY PRICE RISK

We are exposed to a variety of commodity price risks in the normal course
of our business activities. The nature of these market price risks varies by
segment.

Merchant Energy

Our Merchant Energy segment attempts to mitigate its exposure to commodity
price risk through the use of various financial instruments, including forwards,
swaps, options and futures. We measure risks from Merchant Energy's commodity
and energy-related contracts on a daily basis using a Value-at-Risk simulation.
This simulation allows us to determine the maximum expected one-day unfavorable
impact on the fair values of those contracts due to adverse market movements
over a defined period of time within a specified confidence level, and monitors
our risk in comparison to established thresholds. We use what is known as the
historical simulation technique for measuring Value-at-Risk. This technique
simulates potential outcomes in the value of our portfolio based on market-based
price changes. Our exposure to changes in fundamental prices over the long-term
can vary from the exposure using the one-day assumption in our Value-at-Risk
simulations. We supplement our Value-at-Risk simulations with additional
fundamental and market-based price analyses, including scenario analysis and
stress testing to determine our portfolio's sensitivity to its underlying risks.

Our maximum expected one-day unfavorable impact on the fair values of our
commodity and energy-related contracts as measured by Value-at-Risk based on a
confidence level of 95 percent and a one-day holding period was $34 million as
of December 31, 2003 and 2002. Our highest, lowest and average of the month end
values for Value-at-Risk during 2003 was $48 million, $23 million and $37
million. Actual losses in fair value may exceed those measured by Value-at-Risk.
The amounts for 2002 have been restated to reflect a change in our accounting
for hedges of our anticipated natural gas production and certain other
derivatives. In August 2004, we determined that these hedges did not qualify as
cash flow hedges at a consolidated reporting level and, as a result, were
required to be recorded as mark-to-market contracts that are subject to the same
commodity price risk as our other trading contracts. Our Value-at-Risk was
restated to reflect the derivatives that no longer qualified for hedge
accounting.

After the restatement, our Merchant Energy segment's primary exposure to
commodity price risk relates to its natural gas positions and its derivative
tolling contract in the Midwest. These positions have been sensitive to the
price changes in natural gas and power that occurred in 2003. This has caused
significant fluctuations in our earnings and our Value-at-Risk from period to
period.

Production

Our Production segment attempts to mitigate commodity price risk and to
stabilize cash flows associated with its forecasted sales of our natural gas and
oil production through the use of derivative natural gas and oil swap contracts.
The table below presents the hypothetical sensitivity to changes in fair values
arising from immediate selected potential changes in the quoted market prices of
the derivative commodity instruments we use to mitigate these market risks that
were outstanding at December 31, 2003 and 2002. This information has

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also been restated to reflect only derivative commodity instruments that qualify
for accounting purposes as hedges of anticipated natural gas production. Any
gain or loss on these derivative commodity instruments would be substantially
offset by a corresponding gain or loss on the hedged commodity positions, which
are not included in the table.

The derivatives described above do not hedge all of our commodity price
risk related to our forecasted sales of our natural gas production and as a
result, we are subject to commodity price risks on our remaining forecasted
natural gas production. In addition, we entered into new hedges in 2004 for 5.5
TBtu of our anticipated natural gas production at an average price of $5.64 per
MMBtu and 1.1 MMBbls of our anticipated crude oil production at an average price
of $35.15 per Bbl.

Field Services

Our Field Services segment does not significantly utilize financial
instruments to mitigate our exposure to the natural gas liquids it retains in
its processing operations since this overall exposure is not material to our
overall operations.

INTEREST RATE RISK

Debt

Many of our debt-related financial instruments and project financing
arrangements are sensitive to changes in interest rates. The table below shows
the maturity of the carrying amounts and related weighted-average interest rates
on our interest-bearing securities, by expected maturity dates and the fair
values of those securities. As of December 31, 2003 and 2002, the carrying
amounts of short-term borrowings are representative of fair values because of
the short-term maturity of these instruments. The fair value of the long-term
securities has been estimated based on quoted market prices for the same or
similar issues.

Derivatives from Power Contract Restructuring Activities

Derivatives associated with our power contract restructuring business in
the global power division of our Merchant Energy segment are valued using
estimated future market power prices and a discount rate that considers the
appropriate U.S. Treasury rate plus a credit spread specific to the contract's
counterparty. We make adjustments to this discount rate when we believe that
market changes in the rates result in changes in value that can be realized in a
current transaction between willing parties. Since September 30, 2002, in order

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to provide for market risk, we have not reflected the increase in value that
would result from decreases in U.S. Treasury rates because we believe the
resulting increase in the value of these non-trading derivatives could not be
realized in a current transaction between willing parties. Had we reflected the
actual U.S. Treasury yields as of December 31, 2003 in our valuation, the value
of our third party non-trading derivatives would have been higher by
approximately $125 million. To the extent there is commodity price risk
associated with these derivative contracts, it is included in our Value-at-Risk
calculation discussed above, but our exposure to changes in interest rates and
credit spreads has not been included in our Value-at-Risk calculation. As of
December 31, 2003, a ten percent increase or decrease in the discount rate used
to value third party positions would result in an increase (decrease) in the
fair value of these derivative contracts of $(56) million and $59 million. As a
result of the sale of UCF in 2004, and our pending sale of Cedar Brakes I and II
in 2004, our sensitivity to interest rate changes in these derivatives will
decrease.

FOREIGN CURRENCY EXCHANGE RATE RISK

Debt

Our exposure to foreign currency exchange rates relate primarily to changes
in foreign currency rates on our Euro-denominated debt obligations. As of
December 31, 2003, we have Euro-denominated debt with a principal amount of
E1,050 million of which E550 million matures in 2006, and E500 matures in 2009.
As of December 31, 2003 and 2002 we had entered into hedge transactions to
effectively convert E625 million and E275 million of debt into $645 million and
$255 million. In 2004, we entered into cross currency hedge transactions that
convert E100 million fixed rate debt into $121 million floating rate debt. The
remaining principal at December 31, 2003 and 2002 of E425 million and E775
million was subject to foreign currency exchange risk. For a sensitivity
analysis, a hypothetical ten percent increase or decrease in the Euro/USD
exchange rate of 1.2595, with all other variables held constant, at December 31,
2003, would increase or decrease the carrying value of our unhedged
Euro-denominated debt by approximately $54 million.

Power Contracts

Several of our international power plants in Asia, Central America and
Europe have long-term power sales contracts that are denominated in the local
country's currencies. As a result, we are subject to foreign currency exchange
risk related to these power sales contracts. We do not believe that this
exposure is material to our operations and have not chosen to mitigate this
exposure.

90

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

Below is an index to the financial statements and notes contained in Item
8, Financial Statements and Supplementary Data.

91

EL PASO CORPORATION

CONSOLIDATED STATEMENTS OF INCOME
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)

See accompanying notes.
92

EL PASO CORPORATION

CONSOLIDATED BALANCE SHEETS
(IN MILLIONS, EXCEPT SHARE AMOUNTS)

See accompanying notes.
93

EL PASO CORPORATION

CONSOLIDATED BALANCE SHEETS -- (CONTINUED)
(IN MILLIONS, EXCEPT SHARE AMOUNTS)

See accompanying notes.
94

EL PASO CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN MILLIONS)

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

(1) Only individual line items in cash flows from operating activities have been
restated. Total cash flows from continuing operating, investing and
financing activities, as well as discontinued operations, were unaffected.
See accompanying notes.
95

EL PASO CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS -- (CONTINUED)
(IN MILLIONS)

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

(1) Only individual line items in cash flows from operating activities have been
restated. Total cash flows from continuing operating, investing and
financing activities, as well as discontinued operations, were unaffected.

See accompanying notes.
96

EL PASO CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS OF SHARES AND MILLIONS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)

See accompanying notes.
97

EL PASO CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(IN MILLIONS)

See accompanying notes.
98

EL PASO CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. RESTATEMENT OF HISTORICAL FINANCIAL STATEMENTS AND LIQUIDITY

During 2004, we identified several issues that resulted in a restatement of
the amounts we had previously reported in our historical financial statements
for the periods from 1999 to 2002 and for the first nine months of 2003. These
restatements related to revisions to our historical estimates of proved natural
gas reserves and for the manner in which we accounted for certain derivatives,
primarily those related to hedges of our natural gas production. Each of these
restatements is discussed below.

RESTATEMENT OF HISTORICAL FINANCIAL STATEMENTS

Reserve Revisions. In February 2004, we completed the December 31, 2003
reserve estimation process for the proved natural gas and oil reserves in our
Production segment. At the same time, our independent reserve engineers
completed their estimates of our proved reserves. Overall, our internally
prepared reserve estimates were within 5 percent of the total of the estimates
of our independent reserve engineers. The proved reserve estimates as of
December 31, 2003 indicated a 1.8 Tcfe or approximate 41 percent downward
revision in our proved natural gas and oil reserves was needed. Given the size
of this revision, the Audit Committee of our Board of Directors initiated an
independent investigation to be conducted by an outside law firm to determine
the factors that contributed to this significant downward revision. The scope of
the investigation included (1) assessing the reasons for the downward revisions,
(2) evaluating the internal controls associated with the booking of reserves,
(3) suggesting any recommendations with regard to improvements in internal
controls and processes and (4) recommending any remedial actions that may be
required. The investigation included the completion of more than 200 interviews
and the review of more than 100,000 documents. Based on the investigation
results, we concluded that a material portion of the negative reserve revisions
should have been reflected in periods prior to 2003 and would require a revision
of the historical reserve estimates included in our supplemental natural gas and
oil operations data. Quantities of proven natural gas and oil reserves are used
in determining financial statement amounts, including ceiling test charges,
depletion expense and gains and losses on property sales. The revision of our
historical reserve estimates required the restatement of the financial statement
information derived from these estimates. The investigation found that certain
personnel used aggressive, and at times, unsupportable methods to book proved
reserves. In some instances, certain personnel provided historical proved
reserve estimates that they knew or should have known were incorrect at the time
they were reported. The investigation also found that we did not, in some cases,
maintain adequate documentation and records to support historically booked
reserves. Based on the results of the investigation, we (a) reviewed
alternatives with respect to the method or methods to be used to restate our
reserve amounts in prior periods and (b) assessed and implemented remedial
actions related to our management structure, internal control environment and
internal control processes.

Accounting for Certain Derivatives. In August 2004, we evaluated the
manner in which we historically accounted for hedges of our anticipated natural
gas production and certain other hedging transactions related primarily to
pipeline capacity held on pipelines and hedges of anticipated production owned
by one of our pipeline subsidiaries. We entered into a significant number of
hedge transactions from 1999 until 2002. In these hedge transactions, certain of
our subsidiaries would enter into affiliated derivative positions with our
Merchant Energy segment (usually fixed for floating swaps). Our Merchant Energy
segment would then enter into an identical transaction with a third party to
complete an accounting hedge for consolidated reporting purposes (the "hedge
transaction"). To accomplish its own portfolio management objectives, the
Merchant Energy segment would, in many cases, then enter into an offsetting
transaction with that same third party. Most of the transactions with third
parties to create the hedge and complete the offsetting transactions were
implemented under Master ISDA swap agreements. A total of 457 hedging
transactions took place during this timeframe, and 110, or approximately 24
percent involved the use of an offsetting transaction. However, approximately 79
percent of the volumes hedged during that period involved the use of an
offsetting

99

transaction. In applying the accounting treatment for these transactions in
prior periods, we originally concluded that the hedge and offsetting transaction
had economic substance separate and apart from each other. This conclusion was
based upon several factors including (i) all of the hedges and the offsetting
transactions were entered into at market prices, (ii) that our Merchant Energy
segment had a valid business purpose for entering into the offsetting
transaction (i.e. to permit the Company to manage the overall price risk
exposure of the trading portfolio on a more efficient basis), and (iii) the view
that there was credit risk associated with the separate enforcement of the
hedges and offsetting transactions. In reaching the conclusion to restate our
historical accounting related to these hedging transactions, we determined that
we had not properly applied generally accepted accounting principles, or GAAP.
First, we reviewed the factors that supported our original accounting
determinations, which took into consideration the underlying business purpose
for entering into the offsetting transactions, the pricing of the transactions,
and the economic substance of the offsetting transactions. Upon our review of
these factors, when considered in aggregate, we determined that the hedge and
the offsetting transaction did not meet the requirements to be treated as
separate transactions under GAAP. Principally, we determined that our business
purpose for the offsetting transaction was not alone sufficient to satisfy the
standards for separate accounting treatment from the hedge transaction. GAAP
requires that the objective of the two transactions is not one that may be
accomplished in a single transaction. Our production and other hedge objectives
could have been accomplished through a single, though less efficient,
transaction. In addition, we considered two additional factors in reaching this
conclusion. First, we found that some of the offsetting transactions were not
entered into within a range of the then current market prices. Second, we
determined that there was not, as a general matter, sufficient credit risk
associated with the separate enforcement of these transactions to support our
original conclusion that the transactions had economic substance. Based on these
conclusions, we determined that a restatement of our historical financial
statements was required. Following our determination that a restatement was
needed, we conducted an investigation into (a) the reasons for the restatement
and (b) remedial actions, if any, that should be taken.

Restatement Methodologies

Reserve Revisions. Because of concerns over our historical documentation
supporting reserves and the aggressive, and sometimes unsupportable methods that
were used by personnel in booking proved reserves, the methodology we adopted to
restate our reserves for the years ended December 31, 2001 and 2002 and the nine
months ended September 30, 2003, was a reserve reconstruction approach. Under
this method, we utilized the estimated proved reserves as of December 31, 2003
that were derived from our review completed in February 2004, and then
determined historical reserves by adjusting these reserves for actual historical
production data and other known data to determine the reconstructed estimates of
reserves at each period end. The basic assumption underlying our methodology was
that the December 31, 2003 reserve report represented the most recent, reliable
and available information and was our best estimate of proved reserves. That
report, therefore, became the basis of our historical reserve reconstruction. We
then created a reconstruction process by adding actual production volumes in
prior periods, on a well by well basis, with adjustments for assets sold (the
more significant sales were re-evaluated by one of our independent reserve
engineers since the proved reserves that were sold were not in the December 31,
2003 reserve report and needed to be re-evaluated given the findings in the
investigation) and other known information during the period such as cost and
capital spending during the restatement period.

We applied the approach described above back to December 31, 2000. However,
for periods prior to December 31, 2000, which were necessary to determine the
impact of the reserve restatement on beginning stockholders' equity as of
January 1, 2001, we did not have access to the necessary detailed electronic
records to apply this methodology. This was due, in part, to some of the
documentation issues identified in the investigation, and numerous changes to
our personnel immediately following our past mergers, which impacted our ability
to locate that historical documentation. As a result, we used our December 31,
2000 reserve levels determined by the reconstruction approach described above as
the foundation for estimating reserves and related future cash flows (for
ceiling test purposes) for periods prior to December 31, 2000. This estimation
approach involved the use of a "reserve over production ratio" based on the
reconstructed December 31, 2000 reserve estimates. The reserve over production
ratio provided the estimated life of reserves based on production levels. We
applied that ratio to the actual historical period production levels to
calculate
100

estimated historical reserves for each period. In determining the reserve over
production ratio to use for each period, historical prices were considered since
at different pricing levels, varying levels of reserves are economical to
produce, which also impacted capital cost, operating cost and revenue
assumptions in determining cash flows that would be derived from reserves.

Overall, our restatement approach allowed us to recalculate reasonable
proved reserve estimates at the end of each quarter over the last five years.
Once we determined the historical reserve levels, we then calculated our
estimated future net cash flows at the end of each quarter. These revised
quarterly proved reserves and the resulting discounted net cash flows were then
used to perform the ceiling test, calculate our depreciation, depletion and
amortization rate, income taxes and evaluate gain or loss recognition on asset
sales for each quarter. Finally, we assessed the adequacy of our overall
approach based on historical prices and historically capitalized costs leading
up to the earliest period in which our restatement was performed. Based on that
assessment, we believe the amount recorded as a retained earnings adjustment on
January 1, 1999 reasonably reflects the financial statement impact of our
restated reserve levels that would have occurred prior to that time.

We believe the approach used to restate our historical reserves is a
reasonable approach and is appropriate in these circumstances. It is based on a
current, thoroughly reviewed and well documented reserve study and reflects
actual historical data. However, it does have some limitations. First, the
restated reserve levels and reported earnings do not incorporate normal positive
or negative revisions in reserves that could have resulted for reasons such as
mechanical failures, changes in estimates or the impact of actual drilling
results on proved undeveloped reserves. These are normally occurring changes to
reserves estimates that, because of the methodology we used, will not be
reflected during the year they actually occurred. Rather, they will be part of
our beginning retained earnings adjustments. Overall, we believe their effects
on our reported results would be similar. Second, because we had to use a
variation of the methodology for the years 1999 and 2000, to determine the
impact on our retained earnings at January 1, 2001, the restated reserves for
these periods may not be comparable to the reserve amounts that would have
resulted from an actual reconstruction and none of the periods would be
identical to a completely re-engineered approach. Overall, however, we believe
our approach, given the results of the investigation and documentation issues
discussed above, provides a reasonable approach to revising our historical
reserve data that presents our related historical financial results in
accordance with generally accepted accounting principles.

We also considered other restatement methodologies such as re-engineering
specific production and reserve areas to determine, in hindsight, where previous
estimates should have been adjusted in specific periods. We rejected this
approach for several reasons. First, this method would not have produced, in our
view, a more accurate result than the method we adopted, particularly given our
concerns with respect to the timing of when the reserves were originally
recorded. Second, it was very difficult to make reasonable assessments of how
specific reserves should have been booked at a particular time without being
influenced by subsequent data, especially in light of the assumptions that had
already been made in the reserve estimation process. Third, the investigation
identified that (a) a large number of personnel were responsible for making
reserve estimates and that there was not a consistent or centralized approach
used in the reserve estimation process, including the assumptions used in the
process or the documentation generated in support of these assumptions and (b)
there was a lack of controls over inputs into the reserve data base. As a result
of such factors, the integrity of the data could not be reasonably relied upon
for a detailed re-engineering of reserves. Finally, the findings of the
independent investigation identified that there was inadequate detailed
historical, technical documentation to support the booking of certain reported
reserves. Consequently, without such detailed documentation, it would be
extremely difficult, and in some cases impossible, to determine with precision
the appropriate time that specific reserves should have been removed from the
proved reserves category.

101

Our reserve restatement methodology resulted in the following revisions to
our proved natural gas and oil reserves (Bcfe) (Unaudited):

The restatement of our proved reserves also impacted previously reported
items in our supplemental information on our natural gas and oil activities,
including the classification of costs incurred in natural gas and oil activities
between exploration or development cost. For a further discussion of our natural
gas and oil reserves, see Note 30, Supplemental Natural Gas and Oil Operations.

Production and Certain Other Hedges. As stated above, we entered a series
of derivative transactions related to a substantial portion of our anticipated
natural gas production and certain other derivative transactions. These
transactions included: (i) our Production and Pipeline segment affiliated hedges
with our Merchant Energy segment; (ii) Merchant Energy's identical transaction
with a third party (the hedge transaction); and (iii) Merchant Energy's
offsetting transaction with the same third party (the offsetting transaction).
Our historical accounting for derivative transactions (i) and (ii) above was to
defer their income statement impacts until settlement of the underlying
transactions. The impacts of Merchant Energy's offsetting transactions (positive
or negative) were reflected in our income statement on a mark-to-market basis.
Over the period from 1999 to September 30, 2003, we recognized a total of
approximately $499 million, before taxes, of mark-to-market income related to
the offsetting transactions while deferring a similar loss in accumulated other
comprehensive income on the hedges. To restate our historical results, we
reversed amounts deferred in accumulated other comprehensive income related to
the hedges and reflected them on a mark-to-market basis in our income statement
for each period. On a consolidated level, the effect of reversing these amounts
out of accumulated other comprehensive income and into the income statement in
each period did not have a material impact in that reported period's
consolidated stockholders' equity. However, it did affect reported income or
loss in each period. In addition, the loss of hedge accounting in historical
periods affected our ceiling test calculations in those periods, resulting in
additional losses. For a further discussion of the impacts of this restatement,
see discussion below.

On our business segments, we evaluated whether the affected segments should
reflect the affiliated transaction between Production and Merchant Energy in
their individual segment results or whether we should conclude that since these
derivatives did not qualify as hedges at a consolidated reporting level, they
should not be reported as hedges at the individual segment level. We concluded
that had we known the original transactions would not have qualified as hedges
for consolidated reporting purposes, we would not have entered into the original
transactions. Accordingly, for presenting our individual segment results, we
reversed the impacts of the transactions that did not qualify as hedges for
consolidated purposes. See Note 26 for a presentation of restated historical
segment results.

102

Financial Impact of Restatement

The total cumulative impact of the restatements that affect