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, 2002

OR

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

FOR THE TRANSITION PERIOD FROM TO .

COMMISSION FILE NUMBER 1-14365

EL PASO CORPORATION
(FORMERLY EL PASO ENERGY 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 [X] No [ ].

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

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes [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 28, 2002,
computed by reference to the closing sale price of the registrant's common stock
on the New York Stock Exchange on such date: $12,055,450,292.

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 March 27, 2003:
599,435,088

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: Portions of our definitive Proxy Statement for the 2003 Annual
Meeting of Stockholders, to be filed not later than 120 days after the end of
the fiscal year covered by this report, are incorporated by reference into Part
III.
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EL PASO CORPORATION

TABLE OF CONTENTS

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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
= billion British thermal unit
BBtue equivalents
Bcf = billion cubic feet
Bcfe = billion cubic feet of gas equivalents
MBbls = thousand barrels
Mcf = thousand cubic feet
Mcfe = thousand cubic feet of gas equivalents
Mgal = thousand gallons
MMBbls = million barrels
MMBtu = million British thermal units
MMcf = million cubic feet
MMcfe = million cubic feet of gas equivalents
MMDth = million dekatherm
MTons = thousand tons
MW = megawatt
MWh = megawatt hours
MMWh = thousand megawatt hours
Tcfe = trillion cubic feet of 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. 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.

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PART I

ITEM 1. BUSINESS

GENERAL

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. Since 1996, we have grown into an international
energy company whose operations extend from natural gas production and
extraction to power generation. Our growth during this period has been
accomplished through several significant acquisitions and internal growth
initiatives, each of which has expanded our competitive abilities in energy
markets in the United States and abroad. Some of the significant highlights
during this period were:

Since the fourth quarter of 2001, our industry and business have been
adversely impacted by a number of industry changing events, including:

- The bankruptcy of Enron Corp.;

- The decline in the energy trading industry;

- Credit ratings downgrades of us and other industry participants by
Moody's and Standard & Poor's to "below investment grade" status, and
we remain on negative outlook; and

- Regulatory and political pressure arising out of the western energy
crisis of 2000 and 2001.

Beginning in December 2001 and continuing throughout 2002 and the first
quarter of 2003, we responded to these industry developments by focusing on
activities that would enhance our liquidity and strengthen our capital
structure. These activities involved:

- selling marginally performing assets and businesses that were not core to
our fundamental base business of natural gas and pipelines;

- exiting complex areas that require higher credit support, such as energy
trading, and focusing instead on core cash generating businesses; and

- pursuing resolution of regulatory and litigation matters, which led to a
March 2003 agreement in principle to settle our primary exposure to the
western energy crisis (Western Energy Settlement).

In February 2003 we announced what we refer to as our 2003 Operational and
Financial Plan. This plan is based upon five key principles:

- Preserving and enhancing the value of our core businesses;

- Exiting non-core businesses quickly, but prudently;

- Strengthening and simplifying our balance sheet while maximizing
liquidity;

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- Aggressively pursuing additional cost reductions; and

- Continuing to work diligently to resolve litigation and regulatory
matters.

Our ongoing critical areas of focus are:

- Pipelines: Protecting and enhancing asset value in our natural gas
transportation business through continuous efficiency gains and prudent
and necessary capital spending.

- Production: Developing production opportunities in North America that
maximize volumes produced and minimize costs, thereby optimizing cash
flow per unit produced.

- Field Services: Optimizing stable cash flows from our investment in El
Paso Energy Partners, L.P.

- Global Power: Enhancing cash flows from existing projects, while selling
non-strategic power generation facilities.

We will also continue to focus on winding down our non-core businesses
including energy trading and petroleum markets as well as other capital
intensive businesses such as liquefied natural gas (LNG) operations.

SEGMENTS

Our operations are segregated into four primary business segments:
Pipelines, Production, Field Services and Merchant Energy. These segments are
strategic business units that provide a variety of energy products and services.
We manage each segment separately, and each segment requires different
technology and marketing strategies. As future developments in our businesses
occur, and as we carry out our ongoing strategy and plans, we will continue to
assess the appropriateness of our business segments. For the operating results
and identifiable assets by segment, you should see Part II, Item 8, Financial
Statements and Supplementary Data, Note 24, which is incorporated herein by
reference.

Our Pipelines segment owns or has interests in approximately 60,000 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 five largest consuming regions in the U.S.: the Gulf Coast, California, the
Northeast, the Midwest and the Southeast. These pipelines represent one of the
largest integrated coast-to-coast mainline natural gas transmission systems in
the U.S. Our U.S. pipeline systems also own or have interests in approximately
440 Bcf of storage capacity used to provide a variety of services to our
customers and own and operate an LNG terminal at Elba Island, Georgia. Our
international pipeline operations include access between our U.S. based systems
and Canada and Mexico as well as interests in three operating natural gas
transmission systems in Australia.

Our Production segment conducts our natural gas and oil exploration and
production activities. Domestically, we lease approximately 4 million net acres
in 16 states, including Louisiana, Oklahoma, Texas and Utah, and in the Gulf of
Mexico. We also have exploration and production rights in Australia, Bolivia,
Brazil, Canada, Hungary, Indonesia and Turkey. During 2002, daily equivalent
natural gas production exceeded 1.6 Bcfe/d, and our reserves at December 31,
2002, were approximately 5.2 Tcfe.

Our Field Services segment conducts our midstream activities. As part of
our plan to strengthen our capital structure and enhance our liquidity, we
completed a number of asset sales during 2002, 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 in 2000, to El Paso Energy Partners. El
Paso Energy Partners is a publicly traded master limited partnership for which
our subsidiary serves as general partner. As a result of asset sales to the
partnership and others during 2002, our remaining Field Services assets consist
of 23 processing plants and related gathering facilities located in the south
Texas, Louisiana, Mid-Continent and Rocky Mountain regions, as well as our
interests in El Paso Energy Partners. The partnership provides natural gas,
natural gas liquids (NGL) and oil gathering, transportation, processing,
fractionation, storage and other related services.

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Our Merchant Energy segment consists of three primary divisions: global
power, petroleum and energy trading. We are a significant owner of electric
generating capacity and own or have interests in 88 power plants in 18
countries. We operate three refineries that have the capacity to process
approximately 438 MBbls of crude oil per day and produce a variety of petroleum
products. We also produce agricultural and industrial chemicals at four
facilities in the U.S. and one in Canada. On February 5, 2003, we announced our
intent to sell our remaining petroleum and chemicals assets, except for our
Aruba refinery, as well as reduce our involvement in the LNG business. On
November 8, 2002, we announced our plan to exit the energy trading business and
pursue an orderly liquidation of our trading portfolio as a result of
diminishing business opportunities and higher capital costs for this activity.
During 2002 and the first part of 2003, we also completed or announced several
asset sales including the sale of our coal mining assets and operations,
petroleum assets and interests in power projects.

PIPELINES SEGMENT

Our Pipelines segment provides natural gas transmission, storage, gathering
and related services in the U.S. and internationally. We conduct our activities
primarily through seven wholly owned and seven partially owned interstate
transmission systems along with six underground natural gas storage entities and
an 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 is comprised of 4,530 MMcf/d of west-flow capacity (which
includes 230 MMcf/d added by our Line 2000 expansion project) and 800 MMcf/d
of east-end delivery capacity.

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(1) Includes throughput transported on behalf of affiliates.

Partially Owned Interstate Transmission Systems

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(1) Volumes represent the systems' total design capacity and average throughput
and are not adjusted for our ownership interest.
(2) The Alliance pipeline project commenced operations in the fourth quarter of
2000. We sold 12.3 percent of our equity interest in the system during the
fourth quarter of 2002, and the remaining 2.1 percent equity interest in the
first quarter of 2003.
(3) Our ownership interest increased from 19 percent to 30 percent effective
June 2001.

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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 139 Bcf contracted to affiliates. Storage capacity is
under long-term contracts and is not adjusted for our ownership interest.

In addition to our operations of natural gas 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 send-out of 675
MMcf/d and a base load send-out of 446 MMcf/d. The terminal was placed in
service and began receiving deliveries in December 2001. The capacity at the
terminal is currently contracted to our affiliate, El Paso Merchant Energy,
under a contract that extends through 2023. In September 2001, we announced
plans to expand the peak send out capacity of the Elba Island facility by 540
MMcf/d and the base load send out by 360 MMcf/d (for a total peak send out
capacity once completed of 1,215 MMcf/d and a base load send out of 806 MMcf/d).
The expansion will cost approximately $145 million and has a planned in-service
date of late 2005.

We have a number of transmission system expansion projects that have been
approved by the Federal Energy Regulatory Commission (FERC) as follows:

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(1) Pipeline 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.

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Our transportation, storage and related services (transportation services)
revenues consist of reservation and usage revenues. In 2002, approximately 87
percent of our transportation services revenues were attributable to a capacity
reservation or a demand charge paid by firm customers. These firm customers are
obligated to pay a monthly demand charge, regardless of the amount of natural
gas they transport or store, for the term of their contracts. The remaining 13
percent of our transportation services revenue was attributable to usage
charges, based largely on the volumes of gas actually transported or stored on
our pipeline systems.

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 marketing 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. Consequently, 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.

In Canada, our pipeline activities are regulated by the National Energy
Board. Similar to the FERC, the National Energy Board governs tariffs and rates,
and the construction and operation of natural gas pipelines in Canada. In
Australia, various regional and national agencies regulate the tariffs, rates
and operating activities of natural gas pipelines.

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. We believe that our systems
are in material compliance with the applicable requirements.

A discussion of significant rate and regulatory matters is included in Part
II, Item 8, Financial Statements and Supplementary Data, Note 20, and is
incorporated herein by reference.

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Markets and Competition

The following table details our markets and competition on each of our
wholly owned pipeline systems as of December 31, 2002:

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(1)Includes natural gas producers, marketers, end-users and other natural gas
transmission, distribution and electric generation companies.

(2)A discussion of significant rate and regulatory matters regarding EPNG's
capacity is included in Part II, Item 8, Financial Statements and
Supplementary Data, Note 20.

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(1)Includes natural gas producers, marketers, end-users and other natural gas
transmission, distribution and electric generation companies.

(2)The Cheyenne Plain project is a new 30-inch diameter pipeline proposed by us
to transport natural gas from the Cheyenne hub to the confluence of several
pipelines near Greensburg, Kansas. This pipeline is anticipated to be in
service in mid-2005 depending on the timing of regulatory approval.

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

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.

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.

As a result of the rating agencies downgrading the credit rating of several
members of the energy sector, including energy trading companies, and placing
them on negative credit watch, the creditworthiness of some customers has
deteriorated. We have taken actions to mitigate our exposure by requesting these
companies provide us with letters of credit or prepayments as permitted by our
tariffs. Our tariffs permit us to request additional credit assurance from our
shippers equal to the cost of performing transportation services for various
periods as specified in each tariff. If these companies experience financial
difficulties, or file for Chapter 11 bankruptcy protection, and our contracts
are not assumed by other counterparties, or if the capacity is unavailable for
resale, it could have a material adverse effect on our financial position,
operating results or cash flows.

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 have onshore and coal seam
operations and properties in 16 states and offshore operations and properties in
federal and state waters in the Gulf of Mexico. Internationally, we have
exploration and production rights in Australia, Bolivia, Brazil, Canada,
Hungary, Indonesia and Turkey.

Strategically, Production emphasizes disciplined investment criteria and
manages its existing production portfolio to maximize volumes and minimize
costs. It employs geophysical technology and seismic data processing to identify
economic hydrocarbon reserves. Production's deep drilling capabilities and
hydraulic fracturing technology allow it to optimize production with high-rate
completions at competitive reserve replacement costs. Production maintains an
active drilling program that capitalizes on its land and seismic holdings. It
also acquires production properties subject to acceptable investment return
criteria.

Natural Gas and Oil Reserves

The table below details Production's proved reserves at December 31, 2002.
Information in this table is based on the reserve report dated January 1, 2003,
prepared internally by Production and reviewed by Huddleston & Co., Inc. 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. These reserves include 465,783

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MMcfe of production delivery commitments under financing arrangements that
extend through 2042. The financing arrangement supported by these reserves
matures in 2006. Total proved reserves on the fields with this dedicated
production were 919,265 MMcfe. In addition, the table excludes the following
equity interests: Production's interest in UnoPaso (Pescada in Brazil); Merchant
Energy's interests in Sengkang in Indonesia, CAPSA and CAPEX in Argentina and
Aguaytia in Peru; and Field Services' interest in El Paso Energy Partners.
Combined proved natural gas reserves balances for these equity interests were
435,713 MMcf, liquids reserves were 39,693 MBbls and natural gas equivalents
were 673,871 MMcfe, all net to our ownership interests.

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(1) Net proved reserves exclude royalties and interests owned by others and
reflects contractual arrangements and royalty obligations in effect at the
time of the estimate.
(2) Includes oil, condensate and natural gas liquids.
(3) Includes international operations in Brazil, Hungary and Indonesia.

During 2002, as a result of our efforts to enhance our liquidity position,
we sold reserves totaling 1.8 Tcfe to various third parties. The reserves sold
were primarily located in Colorado, Texas, Utah and western Canada.

There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures, including many factors beyond Production's control.
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 natural gas and oil
properties owned by Production declines as reserves are depleted. Except to the
extent Production conducts successful exploration and development activities or
acquires additional properties containing proved reserves, or both, the proved
reserves of Production will decline as reserves are

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produced. For further discussion of our reserves, see Part II, Item 8, Financial
Statements and Supplementary Data, Note 28.

Wells and Acreage

The following table details Production's gross and net interest in
developed and undeveloped onshore, offshore, coal seam and international acreage
at December 31, 2002. Any acreage in which Production's 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.

The U.S. domestic net developed acreage is concentrated primarily in the
Gulf of Mexico (42 percent), Oklahoma (15 percent), Utah (14 percent), Texas (12
percent), and Louisiana (10 percent). Approximately 20 percent, 21 percent and
12 percent of our total U.S. net undeveloped acreage is held under leases that
have minimum remaining primary terms expiring in 2003, 2004 and 2005. During
2002, we sold approximately 421,316 net developed and 887,391 net undeveloped
acres primarily in Colorado, Texas, Utah and western Canada as a result of our
efforts to enhance our liquidity position.

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The following table details Production's working interests in onshore,
offshore, coal seam and international natural gas and oil wells at December 31,
2002:

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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.

During 2002, as a result of our efforts to enhance our liquidity position,
we sold approximately 2,055 net wells located primarily in Colorado, Texas, Utah
and western Canada.

The following table details Production's exploratory and development wells
drilled during the years 2000 through 2002:

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(1) Includes international operations in Australia, Brazil, 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.

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Net Production, Sales Prices, Transportation and Production Costs

The following tables detail Production's net production volumes, average
sales prices received, average transportation costs, average production costs
and production taxes associated with the sale of natural gas and oil for each of
the three years ended December 31:

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(1) Prices are stated before transportation costs.

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(1) Production costs include direct lifting costs (labor, repairs and
maintenance, materials and supplies) and the administrative costs of field
offices, insurance and property and severance taxes.

Acquisition, Development and Exploration Expenditures

The following table details information regarding Production's costs
incurred in its development, exploration and acquisition activities for each of
the three years ended December 31:

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(1) Includes international operations in Australia, Brazil, Hungary, Indonesia
and Turkey.

The table below details approximate amounts spent to develop proved
undeveloped reserves that were included in our reserve report as of January 1 of
each year:

Regulatory and Operating Environment

Production's natural gas and oil activities are regulated at the federal,
state and local levels, as well as internationally by the countries around the
world in which Production does 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. Production is also
subject to governmental safety regulations in the jurisdictions in which it
operates.

Production's 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.
Production's 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 Production's
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 behalf of Production for sudden and accidental spills and oil
pollution liability.

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Production's 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. Offshore operations may encounter usual marine perils, including
hurricanes and other adverse weather conditions, 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 Production with respect to potential losses
resulting from these operating hazards.

Markets and Competition

Our Production segment primarily sells its natural gas to third parties
through our Merchant Energy segment at spot market prices. As a result of our
plan to exit the energy trading business announced in November 2002, our
Production segment is currently evaluating how it will sell its production in
the future. Alternatives being considered include whether to cancel its
agreement with Merchant Energy and assume responsibility for natural gas sales
to third parties or enter into new marketing agreements with third parties
engaged in the marketing of natural gas. Production sells its natural gas
liquids at market prices under monthly or long-term contracts and its oil
production at posted prices, subject to adjustments for gravity and
transportation. Production also engages in hedging activities on its natural gas
and oil production to stabilize its cash flows and reduce the risk of downward
commodity price movements on sales of its production. This is achieved primarily
through natural gas and oil swaps. Under our hedging program, we may hedge up to
50 percent of our anticipated production for a rolling 12-month forward period.

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. Production's competitors include major and intermediate
sized natural gas and oil companies, independent natural gas and oil operations
and individual producers or operators with varying scopes of operations and
financial resources. Competitive factors include price, contract terms and
quality of service. 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.

FIELD SERVICES SEGMENT

Our Field Services segment provides customers with wellhead-to-mainline
services, including natural gas gathering, products extraction, fractionation,
dehydration, purification, compression and transportation of natural gas and
NGL. It also provides well-ties and real-time information services, including
electronic wellhead gas flow measurement.

Field Services' assets include natural gas gathering and NGL pipelines,
treating, processing and fractionation facilities, in the south Texas,
Louisiana, Mid-Continent and Rocky Mountain regions.

El Paso Energy Partners Company, a subsidiary in our Field Services segment
serves as the sole general partner of El Paso Energy Partners. We currently own
26.5 percent, or 11,674,245 of the partnership's common units and the one
percent general partner interest. The remaining 73.5 percent of the common units
of the limited partnership are owned by public unit holders (including small
amounts owned by the general partner's management and employees), none of which
exceeds a 10 percent ownership interest. Field Services also owns all 125,392 of
the outstanding Series B preference units and all 10,937,500 of the outstanding
Series C units issued in November 2002, which are non-voting. Our overall voting
interest in El Paso Energy Partners is 26.5 percent.

As the general partner, Field Services manages the partnership's daily
operations. Employees of Field Services perform all of the limited partnership's
administrative and operational activities under a general and administrative
services agreement or, in some cases, separate operational agreements. El Paso
Energy Partners contributes to our income through our general partner interest
and our ownership of common and preference units. We do not have any loans to or
from El Paso Energy Partners. In addition, we have not provided any guarantees,
either monetary or performance, on behalf of or for the benefit of El Paso
Energy Partners nor do we have any other liabilities other than those arising in
the normal course of business or those arising out of our role as the general
partner in El Paso Energy Partners.
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El Paso Energy Partners provides a capital-efficient means of expanding our
midstream business, and through our general partner relationship, we have used
the partnership as our primary means of growth of our midstream natural gas
business. El Paso Energy Partners manages a balanced, diversified portfolio of
interests and assets related to the midstream energy sector, which includes:

- offshore oil and natural gas pipelines, platforms, processing facilities
and other energy infrastructure in the Gulf of Mexico, primarily offshore
Louisiana and Texas;

- onshore natural gas pipelines and processing facilities in Alabama,
Colorado, Louisiana, Mississippi, New Mexico and Texas;

- onshore NGL pipelines and fractionation facilities in Texas; and

- onshore natural gas and NGL storage facilities in Mississippi, Louisiana
and Texas.

We enter into transactions with El Paso Energy Partners in the normal
course of business for the purchase of natural gas and for services such as
transportation and fractionation, storage, processing and other types of
operational services. For a further discussion of these activities and the
impact of El Paso Energy Partners on our Field Services operations, see Part II,
Item 7, Management's Discussion and Analysis of Financial Condition and Results
of Operations.

The following tables provide information on Field Services' natural gas
gathering and transportation facilities, its processing facilities and the
facilities of its equity method investees:

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

(1) During 2002, we sold a number of assets to El Paso Energy Partners including
gathering and processing assets in the San Juan Basin of New Mexico and our
Texas midstream assets, most of which we acquired in December 2000.

(2) The increase in activity from 2000 to 2001 is a result of our acquisition of
PG&E's Texas Midstream operations in December 2000.

(3) All volumetric information for El Paso Energy Partners reflects 100 percent
of El Paso Energy Partners' interest. Mileage and volumetric information
have not been reduced to reflect our net ownership.

Regulatory Environment

Some of Field Services' operations 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 Field Services' operations 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.

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

Markets and Competition

Field Services competes with major interstate and intrastate pipeline
companies in transporting natural gas and NGL. Field Services also competes 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. 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.

MERCHANT ENERGY SEGMENT

Our Merchant Energy segment consists of three primary divisions: global
power, petroleum and energy trading.

Global Power

Our global power division includes the ownership and operation of domestic
and international power generation facilities. Our commercial focus in the power
generation business has been to either develop projects in which new long-term
power purchase agreements allow for an acceptable return on capital, or to
acquire projects with existing attractive power purchase agreements. Under this
strategy, we have become a significant U.S.-based independent power generator
and currently own or have interests in 88 power plants in 18 countries. These
plants represent 20,665 gross megawatts of generating capacity, 72 percent of
which is sold under power purchase or tolling agreements with terms in excess of
five years. Of these facilities, 60 percent are natural gas fired, 11 percent
are geothermal and the remaining 29 percent use coal or NGL as fuel or are
hydroelectric plants. As part of our 2003 Operational and Financial Plan, we
have announced the planned sales of some of these power generation assets. Most
of our power plants are partially owned by us through either a direct equity
investment or through our unconsolidated affiliates, Chaparral Investors, L.L.C.
(Chaparral) and Gemstone. As of December 31, 2002, we had a direct investment in
the following power plants:

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

(1) Gross megawatts represent tested generating capacity of these facilities.
(2) Chaparral also owns an interest in these projects.
(3) These projects were sold in 2003.

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

(1) Gross megawatts represent tested generating capacity of these facilities.
(2) These projects were sold in 2003.
(3) Gemstone also owns an interest in these projects.
(4) Chaparral also owns an interest in these projects.
(5) This plant is under construction.

We conduct a significant portion of our domestic power activity through our
investment in Chaparral. At December 31, 2002, we owned 20 percent of Chaparral,
and Limestone Electron Trust (Limestone), an unrelated party capitalized by
private equity and debt, owned the remaining 80 percent. Limestone is controlled
by investment affiliates of Credit Suisse First Boston Corporation. In March
2003, we notified Limestone that we will exercise our right under the
partnership agreements to acquire all of the outstanding third party equity in
Limestone. On March 17, 2003, we contributed $1 billion to Limestone in exchange
for a non-controlling interest. Limestone used the proceeds from the
contribution to pay off $1 billion of the Limestone notes that matured on that
date. Following our additional investment of $1 billion in Limestone, our
effective ownership of Chaparral increased to approximately 90 percent, but
neither our rights nor the rights of Limestone to participate in the operating
decisions of Chaparral changed. As a result, we continue to account for our
investment in Chaparral as an equity investment. We will consolidate Chaparral
upon the purchase of the remaining third party equity interest in Limestone,
which we expect to occur in May 2003.

Chaparral was formed during 1999 to obtain low-cost financing to fund the
growth of our unregulated domestic power generation and related businesses.
During 2002, Chaparral's primary focus was on restructuring power contracts. A
power contract restructuring is accomplished typically by amending an
above-market power contract that requires delivery of power from a dedicated
power plant and replacing it with low-cost power obtained from the market.
Chaparral also operates power plants whose contracts have been previously
restructured on a merchant basis, which means that these plants operate and sell
power to the wholesale market in periods where power prices are high enough that
it is economical to do so. Through Chaparral, we have investments in 34 U.S.
power generation facilities with a total generating capacity of approximately
5,592 gross megawatts. Most of Chaparral's plants provide power under long-term
contracts. We serve as the manager of Chaparral under a management agreement
that expires in 2006, and we were paid a management fee for the services we
performed under this agreement through the end of 2002. This fee was based on
how well we performed as the manager of Chaparral, and was determined by
evaluating the present value of the portfolio of power assets held by Chaparral.
Our management fee is subject to the approval of our joint venture partner
annually. In 2002, the management fee was $205 million consisting of a $185
million performance fee plus a $20 million annual cost reimbursement. We will
not earn a fee from Chaparral in 2003.

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As of December 31, 2002, Chaparral owned or had interests in the following
power plants:

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

(1) Gross megawatts represent the tested generating capacity of these
facilities.
(2) We also own a direct interest in these projects.
(3) These project companies own interests in multiple plants.
(4) These plants are under construction.

Internationally, our focus has been on building and acquiring energy
infrastructure in developed economies, and to a lesser degree in selected
emerging markets. Our primary areas of focus historically have included Brazil,
Europe and Asia. We principally conduct our Brazilian development activities
within an investment that we refer to as Gemstone. We own approximately 50
percent of Gemstone, and Gemstone Investors, an unrelated party capitalized by
private equity (Rabobank International) and debt, owns the remaining 50 percent.
Gemstone Investor Limited also indirectly purchased preferred interests in two
of our consolidated power projects in Brazil. The Gemstone structure owns or has
interests in five Brazilian power generation facilities with a total generating
capacity of approximately 2,184 gross megawatts. We serve as the manager of
Gemstone under a management agreement that expires in 2004, under which we are
paid a fee that reimburses us for the cost to provide the management services,
which cannot exceed $2 million on an annual basis. Our activities as manager of
Gemstone include:

- management of the operations and commercial activities of the facilities;

- project financings, sales and acquisitions; and

- daily administration activities of accounting, tax, legal and treasury
functions.

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As of December 31, 2002, Gemstone owned or had interests in the following
power plants:

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

(1) Gross megawatts represent the tested generating capacity of these
facilities.

(2) The second phase of this project is under construction.

(3) These are consolidated power projects in which Gemstone owns a preferred
ownership interest.

Rabobank International, the third party investor in Gemstone, has the right
to remove us as manager of Gemstone. In January 2003, Rabobank notified us that
it planned to remove us as manager. We retained our management rights by
agreeing to purchase Rabobank's $50 million of equity in Gemstone on or before
April 17, 2003. We will consolidate Gemstone, its related power plants and its
debt on the purchase date, unless we replace Rabobank with another partner.

For a further discussion of both Chaparral's and Gemstone's activities, see
Part II, Item 7, Management's Discussion and Analysis of Financial Condition and
Results of Operations and Part II, Item 8, Financial Statements and
Supplementary Data, Note 26.

Detailed below are our power generation projects, by region (segregated by
those that are consolidated and those that are not) as of December 31, 2002:

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

(1) Gross megawatts represent the tested generating capacity of these
facilities.
(2) Net megawatts represent our net ownership in the facilities.

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

(1) Gross megawatts represent the tested generating capacity of these
facilities.
(2) Net megawatts represent our net ownership in the facilities.

Petroleum

In February 2003, we announced our intent to sell substantially all of our
petroleum business (with the exception of our Aruba refinery) since it is not
core to our primary natural gas business. In addition, we also announced our
intent to minimize our involvement in a developing LNG business because the
significant capital and credit requirements associated with this business were
in excess of our current financial capacity.

Our existing petroleum division: (i) owns or has interests in four crude
oil refineries and five chemical production facilities; (ii) has petroleum
terminalling and related marketing operations; and (iii) has blending and
packaging operations that produce and distribute a variety of lubricants and
automotive related products. Of the four refineries we own, we operate three of
them. The three refineries we operate have a throughput capability of
approximately 438 MBbls of crude oil per day to produce a variety of gasolines,
diesel fuels, asphalt, industrial fuels and other products. Our chemical
facilities have a production capability of 3,800 tons per day and produce
various industrial and agricultural products.

In 2002, our refineries operated at 64 percent of their average combined
capacity, at 70 percent in 2001 and at 93 percent in 2000. The aggregate sales
volumes at our wholly owned refineries were approximately 110 MMBbls in 2002,
131 MMBbls in 2001 and 182 MMBbls in 2000. Of our total refinery sales in 2002,
38 percent was gasoline, 41 percent was middle distillates, such as jet fuel,
diesel fuel and home heating oil, and 21 percent was heavy industrial fuels and
other products.

The following table presents average daily throughput and storage capacity
at our wholly owned refineries at December 31:

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

(1) In June 2001, we leased our Corpus Christi refinery to Valero Energy
Corporation for 20 years. In February 2003, Valero exercised its option to
purchase the plant and related assets. These volumes only reflect those
produced prior to our lease of the facilities.

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Our chemical plants produce agricultural fertilizers, gasoline additives
and other industrial products from facilities in Nevada, Oregon and Wyoming. The
following table presents sales volumes from our wholly owned chemical facilities
in the U.S. for each of the three years ended December 31:

Since January 2003, we have sold the majority of our interests in our
Florida petroleum terminals, our tug and barge operations, our leasehold crude
business and asphalt operations and all of our interests in the Corpus Christi
refinery. We expect to sell the rest of the assets associated with our petroleum
business in 2003, with the exception of the Aruba refinery.

Our LNG business contracts for LNG terminalling and regasification
capacity, coordinates short and long-term LNG supply deliveries and, prior to
our announced intent to minimize our involvement in this business, was
developing an international LNG supply, marketing and infrastructure business.
As of December 31, 2002, our LNG business had contracted for 163 Bcf per year of
LNG regasification capacity at the Elba Island location in Georgia, which is
contracted through 2023.

We have contracted for 103 Bcf per year of LNG supplies at market sensitive
prices, under the terms of a long-term Caribbean supply agreement. Initial
deliveries under this agreement are scheduled to commence in June 2003. In May
2002, we received final approval from the Norwegian and United States
governments for an LNG purchase and sale agreement signed in October 2001 with
Snohvit, which is a consortium of natural gas production companies led by
Statoil ASA. In the fourth quarter of 2002, we completed a sale of our position
in the LNG purchase and sale agreement and an assignment of our capacity rights
at the Cove Point LNG regasification facility to Statoil for $210 million.

During 2001 and 2002, we contracted to charter four LNG tankers, with an
option to charter a fifth ship, to transport LNG from supply areas to domestic
and international market centers. In February 2003, following our announced plan
to minimize our involvement in the LNG business, we entered into various
agreements with the ship owners under which all four of the ship charters and
our option for chartering the fifth ship were cancelled in consideration of
payments by us totaling $24 million. On two of the ship charters, the ship
owners assumed responsibility for the charter of those vessels, and we paid $20
million for the capital costs associated with fitting those two ships with
regasification capabilities. In connection with transferring the chartering
responsibilities back to the ship owners, we agreed to provide letters of
credit, fully collateralized by cash, equal to $120 million that could be drawn
on by the ship owners. These letters of credit are intended to cover additional
capital costs and any shortfalls in the rates at which they are able to charter
the vessels, compared to the rates provided for in the original charter
agreements, as adjusted for capital costs we have already paid. In the event
that the ship owners are able to charter the ships at rates in excess of the
original rates, as adjusted, we will share in the benefits. We also retained
rights to charter some of the vessels for our use in potential future LNG
activities. In connection with these transactions, our future exposure to the
ship arrangements is limited to $120 million. We also transferred our interest
in our Baja LNG development project to an unaffiliated third party in connection
with these transactions. We are exploring our options with respect to the
remainder of our LNG business, including the sales of assets and supply and
sales contracts, and participating in joint ventures that would use our Energy
Bridge technology (technology which uses regasification capability on board the
LNG transport ships in combination with or instead of using land-based
facilities).

Energy Trading

At the beginning of 2002, we were one of the largest energy marketers in
North America. Our trading activities included providing both short and
long-term supplies of energy commodities to a broad range of
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wholesale customers worldwide. We traded natural gas, power, crude oil, other
energy commodities and related financial instruments in North America and Europe
and provided pricing and valuation analysis for the entire Merchant Energy
segment. Detailed below is our marketed and traded energy commodity sales
volumes that were settled during each of the three years ended December 31:

Volumes 2002 2001 2000
------- ------- -------
Physical
Natural gas (BBtu/d)............................... 11,879 9,230 7,768
Power (MMWh)....................................... 469,477 217,387 115,303
Financial settlements (BBtue/d)....................... 188,467 143,095 98,630

Due to deterioration of the energy trading environment, we decided in
November 2002 to exit the energy trading business and pursue an orderly
liquidation of our trading portfolio. We anticipate this liquidation will
continue through 2004. Our liquidation strategy is intended to:

- maximize cash flow from the trading portfolio;

- reduce our risk in an uncertain environment; and

- avoid inefficient sales of the portfolio i