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, 2001

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. [ ]

STATE THE AGGREGATE MARKET VALUE OF THE VOTING STOCK 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 March 12, 2002,
computed by reference to the closing sale price of the registrant's common stock
on the New York Stock Exchange on such date: $23,959,866,645

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 12, 2002:
532,441,481

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 2002 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
MMBbls = million barrels
MMBtu = million British thermal units
Mcf = thousand cubic feet
Mcfe = thousand cubic feet of gas equivalents
MMcf = million cubic feet
MMcfe = million cubic feet of gas equivalents
Mgal = thousand gallons
MTons = thousand tons
MWh = megawatt hours
MMWh = thousand megawatt hours
TBtu = trillion British thermal units
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 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

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 1995, we have grown into a global energy
company whose operations extend from natural gas production and extraction to
power generation. Our significant growth during this period has been
accomplished through a series of strategic acquisitions, transactions and
internal growth initiatives, each of which has expanded our competitive
abilities in the U.S. and global energy markets. These milestones include:

Our principal operations include:

- natural gas transportation, gathering, processing and storage;

- natural gas and oil exploration, development and production;

- energy and energy-related commodities and product marketing;

- power generation;

- energy infrastructure facility development and operation;

- petroleum refining;

- chemicals production; and

- coal mining.

1

SEGMENTS

Our operations are segregated into four primary business segments:
Pipelines, Merchant Energy, Production and Field Services. 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. For information relating to operating
revenues, operating income, earnings before interest expense and income taxes
(EBIT) and identifiable assets by segment, you should see Part II, Item 8,
Financial Statements and Supplementary Data, Note 18, 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 over 430 Bcf of
storage capacity used to provide a variety of services to our customers and own
and operate a liquefied natural gas (LNG) terminal at Elba Island, Georgia that
was reactivated in 2001. Our international pipeline operations include access
between our U.S. based systems and Canada and Mexico as well as interests in
three major operating natural gas transmission systems in Australia.

Our Merchant Energy segment is involved in a broad range of energy-related
activities including asset ownership, customer origination, marketing and
trading and financial services. We are one of North America's premier wholesale
energy commodity marketers and traders, and we buy, sell and trade natural gas,
power, crude oil, refined products, coal and other energy commodities in the
U.S. and internationally. We are also a significant owner of electric generating
capacity and own or have interests in 95 facilities in 20 countries. The three
refineries we operate 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 five facilities in the U.S. Our coal
mining operations produce high-quality, bituminous coal with reserves in
Kentucky, Virginia and West Virginia. Our financial services businesses manage
investments in the North American energy industry. Most recently, Merchant
Energy has announced its expansion into the LNG business.

Our Production segment leases approximately 5 million net acres in 19
states, including Colorado, Louisiana, Oklahoma, Texas, Utah, West Virginia and
Wyoming, and in the Gulf of Mexico. We also have exploration and production
rights in Australia, Bolivia, Brazil, Canada, Hungary, Indonesia and Turkey.
During 2001, daily equivalent natural gas production exceeded 1.7 Bcfe/d, and
our reserves at December 31, 2001, were approximately 6.7 Tcfe.

Our Field Services segment provides natural gas gathering, products
extraction, fractionation, dehydration, purification, compression and intrastate
transmission services. These services include gathering natural gas from more
than 15,000 natural gas wells with approximately 21,000 miles of natural gas
gathering and natural gas liquids pipelines, and approximately 30 natural gas
processing, treating and fractionation facilities located in some of the most
active production areas in the U.S., including the San Juan Basin, east and
south Texas, Louisiana, the Gulf of Mexico and the Rocky Mountains. We conduct
our intrastate transmission operations through interests in six intrastate
systems, which serve a majority of the metropolitan areas and industrial load
centers in Texas as well as markets in Louisiana. Our primary vehicle for growth
and development of midstream energy assets is El Paso Energy Partners, L.P., a
publicly traded master limited partnership in which we serve as the general
partner. El Paso Energy Partners provides natural gas, natural gas liquids and
oil gathering and transportation, storage and other related services.

2

PIPELINES SEGMENT

Our Pipelines segment provides natural gas transmission services in the
U.S. and internationally. We conduct our activities through seven wholly owned
and eight partially owned interstate transmission systems along with six
underground natural gas storage facilities and a 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.

3

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.
(3) Our ownership interest increased from 19 percent to 30 percent effective
June 2001.

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

UNDERGROUND NATURAL GAS STORAGE FACILITIES

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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.

In addition to our operations of natural gas pipeline systems and storage
facilities, we own a 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 and was reactivated in December
2001.

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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.

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 system operates under separate FERC approved tariffs
that establish rates, terms and conditions under which each system provides
services to its customers. Generally, the FERC's authority extends to:

- transportation and storage of natural gas, rates and charges;

- certification and construction of new facilities;

- extension or abandonment of services and facilities;

- maintenance of accounts and records;

- relationships between pipeline and marketing affiliates;

- depreciation and amortization policies;

- acquisition and disposition of facilities; and

- initiation and discontinuation of services.

Our wholly and partially owned domestic pipelines and storage facilities
have tariffs established through filings with the FERC that have a variety of
terms and conditions, each of which affects their operations and their ability
to recover fees for the services they provide. Generally, changes to these fees
or terms of service can only be implemented upon approval by the FERC.

In Canada, our pipeline operating 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.

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Our interstate pipeline systems are also subject to the Natural Gas
Pipeline Safety Act of 1968, which establishes pipeline and LNG plant safety
requirements, the National Environmental Policy Act and other environmental
legislation. Each of our systems has a continuing program of inspection designed
to keep all of our facilities in compliance with pollution control and pipeline
safety requirements. We believe that our systems are in compliance with the
applicable requirements.

We are also subject to regulation with respect to safety requirements in
the design, construction, operation and maintenance of our interstate natural
gas transmission and storage facilities by the U.S. Department of
Transportation. Additionally, we are subject to similar safety requirements from
the U.S. Department of Labor's Occupational Safety and Health Administration
related to our processing plants. Operations on U.S. government land are
regulated by the U.S. Department of the Interior.

For a discussion of significant rate and regulatory matters, see Part II,
Item 8, Financial Statements and Supplementary Data, Note 14.

Markets and Competition

Our interstate transmission systems face varying degrees of competition
from other pipelines, as well as alternative energy sources, such as
electricity, hydroelectric power, coal and fuel oil. Also, the potential
consequences of proposed and ongoing restructuring and deregulation of the
electric power industry are currently unclear. Restructuring and deregulation
may benefit the natural gas industry by creating more demand for natural gas
turbine generated electric power, or it may hamper demand by allowing a more
effective use of surplus electric capacity through increased wheeling as a
result of open access. The following table details our markets and competition
on each of our wholly owned pipeline systems:

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

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

The ability of our pipeline systems to extend their existing contracts or
re-market expiring capacity with their customers is based on a variety of
factors, including competitive alternatives, the regulatory environment at the
local, state and federal levels and market supply and demand factors at the
relevant extension or expiration dates. While every attempt is made to
re-negotiate contract terms at fully-subscribed quantities and at maximum rates
allowed under their tariffs, our pipelines must at times discount their rates to
remain competitive.

7

MERCHANT ENERGY SEGMENT

Our Merchant Energy segment is involved in a broad range of activities in
the energy marketplace, including asset ownership, customer origination,
marketing and trading and financial services.

ASSET OWNERSHIP

Merchant Energy's Asset Ownership activities include ownership interests in
domestic and international power generation, refining and chemicals operations,
coal mining and an emerging LNG business.

Power Generation. Our commercial focus in the power generation business is
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 95 power plants in 20 countries. These plants represent 22,109
gross megawatts of generating capacity, 85 percent of which is sold under power
purchase or tolling agreements with terms in excess of five years. Of these
facilities, 61 percent are natural gas fired, 11 percent are geothermal and 28
percent are a combination of coal, natural gas liquids and hydroelectric.

A significant portion of our domestic activity is conducted within an
unconsolidated affiliate, Chaparral Investors, L.L.C. Chaparral's primary
strategy is to acquire power plants with above-market power contracts and
restructure these contracts by offering a lower power sales cost to the plants'
customers, which are typically electric utilities. Through Chaparral (an entity
that we have also referred to in our public disclosures as Electron), we have
invested in 39 U.S. power generation facilities with a total generating capacity
of approximately 5,900 gross megawatts. We serve as the manager of Chaparral
under a management agreement that expires in 2006, and are paid an annual
performance-based fee for the services we perform under this agreement. Our
activities as manager of Chaparral include:

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

- project-level contract restructurings and monetizations;

- project financings, sales and acquisitions;

- identification, evaluation, negotiation and consummation of new
investments in energy assets; and

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

Internationally, our focus is on building energy infrastructure in
developed economies, and to a lesser degree in selected emerging markets. Our
primary areas of focus include Brazil, Europe, Korea and Japan. We principally
conduct our Brazilian development activities within an unconsolidated affiliate
that we refer to as Gemstone. Through our ownership interest in Gemstone, we
have invested in five Brazilian power generation facilities with a total
generating capacity of approximately 2,156 gross megawatts. We serve as the
manager of Gemstone under a management agreement that expires in 2004. Our
activities as manager of Gemstone are similar to those described above for
Chaparral.

8

Detailed below are our power generation projects, by region, that are
either operational or in various stages of construction:

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(1) Net Megawatts represent our net ownership in the facilities.

Refining and Chemicals. Our Refining and Chemicals business: (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. The 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 2001, our refineries operated at 70 percent of their average combined
capacity and at 93 percent in each of 2000 and 1999. The aggregate sales volumes
at our wholly owned refineries were approximately 131 MMBbls in 2001, 182 MMBbls
in 2000 and 171 MMBbls in 1999. Of our total refinery sales in 2001, 39 percent
was gasoline, 39 percent was middle distillates, such as jet fuel, diesel fuel
and home heating oil, and 22 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:

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(1) In June 2001, we leased our Corpus Christi refinery to Valero Energy
Corporation. The lease is for 20 years, and Valero has an option to purchase
the refinery beginning in 2003. 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, Texas and
Wyoming. The following table presents sales volumes from our wholly owned
chemical facilities for each of the three years ended December 31:

Coal Mining. Our Coal mining business controls reserves totaling 524
million recoverable tons and produces high-quality bituminous coal from reserves
in Kentucky, Virginia and West Virginia. The extracted coal is primarily sold
under long-term contracts to power generation facilities in the eastern U.S.
During the year ended December 31, 2001, coal production totaled 11.5 million
tons.

LNG. Our LNG business contracts for LNG terminalling and regasification
capacity, coordinates short and long term LNG supply deliveries and is
developing an international LNG supply, marketing and infrastructure business.
As of December 31, 2001, our LNG business had contracted for 284 Bcf per year of
LNG regasification capacity at three locations along the Eastern and Gulf of
Mexico coastal regions of the U.S. as follows:

We have also contracted for 105 Bcf per year of long-term supplies of LNG
at market sensitive prices, which will be delivered from the Caribbean beginning
in 2002. In addition, we have contracted to lease four LNG tankers to transport
LNG from supply areas to domestic and international market centers. These ships
are currently being constructed by third parties with the first ship scheduled
for delivery in 2003.

Operations. Merchant Energy has established an Operations group to manage
the daily operations of Merchant Energy's worldwide assets. This group operates
22 generating facilities in the U.S. and eight facilities in six foreign
countries.

CUSTOMER ORIGINATION, MARKETING AND TRADING

Our Merchant Energy segment is one of the largest energy marketers in North
America, and manages a large network of energy shipping, transmission,
transportation, terminalling, refining and generation assets, both owned and
under contract, which are used in the delivery of natural gas, petroleum,
petroleum products and power. Merchant Energy's customer origination activities
provide short and long-term supplies of energy commodities to a broad range of
wholesale customers worldwide. These activities provide customers with
alternatives to meet their energy supply needs and manage their associated
energy risks through Merchant Energy's: (i) knowledge of the marketplace; (ii)
network of delivery infrastructure; (iii) supply aggregation and transportation
management capabilities; and (iv) valuation and integrated price risk management
skills. Merchant Energy's marketing and trading groups trade natural gas, power,
crude oil, other energy commodities and related financial instruments in North
America and Europe and provide pricing and valuation analysis for the entire
segment. These groups manage the inherent risk of Merchant Energy's asset and
trading portfolios using value-at-risk limits approved by the Audit Committee of
our Board of Directors and attempt to optimize the value of the segment's asset
portfolio.

10

During 2001, Merchant Energy's traded volumes increased across all
commodity groups. Detailed below is the marketed and traded energy commodity
volumes for each of the three years ended December 31:

Volumes 2001 2000 1999
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Physical
Natural gas (BBtue/d).............................. 9,230 7,768 6,713
Power (MMWh)....................................... 221,075 118,672 79,361
Crude oil and refined products (MBbls)............. 698,933 667,834 664,935
Coal (MTons)....................................... 10,343 9,834 8,980
Financial settlements (BBtue/d)....................... 232,282 151,115 113,814

FINANCIAL SERVICES

Our Financial Services group provides institutional and retail funds
management and makes capital investments for Merchant Energy. It conducts these
activities primarily through two subsidiaries, EnCap Investments L.L.C., and
Enerplus Global Investment Management, Inc.

EnCap is an institutional funds management firm specializing in financing
independent oil and natural gas producers. EnCap manages four separate
institutional oil and natural gas investment funds in the U.S. and serves as
investment advisor to Energy Capital Investment Company PLC, a publicly traded
investment company in the United Kingdom. Enerplus is an institutional and
retail funds management firm in Canada. EnCap and Enerplus manage funds that had
a combined market value of approximately $1.4 billion at December 31, 2001.

Regulatory Environment

Merchant Energy's domestic power generation activities are regulated by the
FERC under the Federal Power Act with respect to its rates, terms and conditions
of service. In addition, exports of electricity outside of the U.S. must be
approved by the Department of Energy. Its cogeneration power production
activities are regulated by the FERC under the Public Utility Regulatory
Policies Act (PURPA) with respect to rates, procurement and provision of
services and operating standards. Its power generation and refining, chemical
and petroleum activities are also subject to federal and state environmental
regulations, including the U.S. Environmental Protection Agency (EPA)
regulations. We believe that our operations are in compliance with the
applicable requirements.

Merchant Energy's foreign operations are regulated by numerous governmental
agencies in the countries in which these projects are located. Many of the
countries in which Merchant Energy conducts and will 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 and sometimes limited. Many detailed rules and procedures are
yet to be issued, and we expect that the interpretation of existing rules in
these jurisdictions will evolve over time. We believe that our operations are in
compliance with all environmental laws and regulations in the applicable foreign
jurisdictions.

Markets and Competition

Merchant Energy maintains a diverse supplier and customer base. During
2001, its activities served over 4,600 suppliers and 6,700 customers around the
world.

Merchant Energy's trading, marketing, refining, chemicals and energy
infrastructure development businesses operate in a highly competitive
environment. Its primary competitors include:

- affiliates of major oil and natural gas producers;

- multi-national energy infrastructure companies;

- large domestic and foreign utility companies;

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- affiliates of large local distribution companies;

- affiliates of other interstate and intrastate pipelines;

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

- independent refining and chemical companies.

Merchant Energy competes on the basis of price, access to production,
imbalance management, operating efficiency, technological advances, experience
in the marketplace and counterparty credit. Each market served by Merchant
Energy is influenced directly or indirectly by energy market economics.

Many of Merchant Energy's generation facilities sell power pursuant to
long-term agreements with investor-owned utilities in the U.S. The terms of its
power purchase agreements for its facilities are such that Merchant Energy's
revenues from these facilities are not significantly impacted by competition
from other sources of generation. The power generation industry is rapidly
evolving and regulatory initiatives have been adopted at the federal and state
level 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 a significantly different market in
which operating efficiency and other economic factors will determine success.
Merchant Energy is likely to face intense competition from generation companies
as well as from the wholesale power markets. The successful acquisition of new
business opportunities is dependent on Merchant Energy's ability to respond to
requests to provide new services, mitigate potential risks and maintain strong
business development, legal, financial and operational support teams with
experience in the marketplace.

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 properties in
19 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.

Production primarily sells its natural gas to third parties through our
Merchant Energy segment at
spot-market prices. It 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 engages in hedging
activities on its natural gas and oil production to stabilize cash flows and
reduce the risk of downward commodity price movements on sales of its
production. During 2001, approximately 80 percent of the segment's overall
production was hedged at fixed prices.

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 attractive 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, 2001.
Information in this table is based on the reserve report dated January 1, 2002,
prepared internally by Production and reviewed by Huddleston & Co., Inc. This
information agrees with estimates of reserves filed with other federal agencies
except for differences of less than 5 percent resulting from actual production,
acquisitions, property sales, necessary reserve revisions and additions to
reflect actual experience. These reserves include 124,158 MMcfe of production
delivery commitments under financing arrangements that extend through 2005.
Total proved reserves on the fields with this dedicated production were
1,981,239 MMcfe. In addition, the table excludes Production's 50 percent
interest in UnoPaso (Pescada in Brazil), Merchant Energy's 50 percent equity
interest in Sengkang in Indonesia, Merchant Energy's 45 percent and 24.75
percent equity interests in
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CAPSA and CAPEX in Argentina and Field Services' 27 percent equity interest in
El Paso Energy Partners. Combined proved natural gas reserves balances for these
equity interests were 361,997 MMcf, liquids reserves were 44,711 MBbls and
natural gas equivalents were 630,263 MMcfe, all net of 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 and Indonesia.
(4) Includes natural gas and oil properties owned by Colorado Interstate Gas
Company and its subsidiaries.

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 the control of
Production. 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. 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 produced.

For further discussion of our reserves, see Part II, Item 8, Financial
Statements and Supplementary Data, Note 22.

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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, 2001. Any acreage in which Production's interest is limited to
owned royalty, overriding royalty and other similar interests is excluded.

The U.S. domestic net developed acreage is concentrated primarily in the
Gulf of Mexico (26 percent), Texas (24 percent), Utah (17 percent), Colorado (8
percent), Oklahoma (7 percent), West Virginia (6 percent), Wyoming (5 percent)
and Louisiana (5 percent). Approximately 20 percent, 15 percent and 14 percent
of our total U.S. net undeveloped acreage is held under leases that have minimum
remaining primary terms expiring in 2002, 2003 and 2004.

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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,
2001:

The following table details Production's exploratory and development wells
drilled during the years 1999 through 2001:

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

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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, Unit Prices and Production Costs

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

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(1) Includes costs associated with transporting volumes sold and the effects of
our hedging program.
(2) Includes direct lifting costs (labor, repairs and maintenance, materials and
supplies) and the administrative costs of field offices, insurance and
property and severance taxes.

16

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:

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

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

Excluded from the table above is $15 million of costs in 2001 attributable
to Natural Gas Systems.

17

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 U.S. 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 pollution 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 compliance with the applicable requirements. In
addition, we maintain insurance on behalf of Production for sudden and
accidental spills and oil pollution liability.

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. However, insurance is not available to
Production against all operational risks.

Markets and Competition

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
natural gas liquids. It also provides well-ties and real-time information
services, including electronic wellhead gas flow measurement.

Field Services' assets include natural gas gathering and natural gas
liquids pipelines, treating, processing and fractionation facilities in the San
Juan Basin and the Rocky Mountain region, referred to as the Western Division;
in the producing regions of east and south Texas, Mid-Continent, Permian Basin
and the Gulf of Mexico, referred to as the Central Division; and in Louisiana,
referred to as the Eastern Division.

A subsidiary in our Field Services segment serves as the general partner of
El Paso Energy Partners and owns a one percent general partner interest and 26
percent of the partnership's common units. Field Services also owns preferred
units of the partnership that have a $143 million liquidation value. As the
general partner, Field Services manages the partnership's daily operations and
strategic direction. Employees of Field Services perform all of the
partnership's administrative and operational activities under a management
agreement or, in some cases, separate operational agreements. El Paso Energy
Partners provides gathering, transportation, fractionation, storage and other
related activities for producers of natural gas, natural gas liquids and oil.

18

El Paso Energy Partners owns or has interests in natural gas and oil pipeline
systems, offshore platforms, natural gas storage facilities, producing oil and
natural gas properties, natural gas liquids gathering and transportation
pipelines, fractionation plants and a natural gas processing plant.

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) Mileage amounts are approximate for the total systems and have not been
reduced to reflect Field Services' net ownership.

(2) All volumetric information reflects Field Services' net interest.

(3) The Central Division includes our acquisition of PG&E's Texas Midstream
operations in December 2000. In February 2002, we announced our plan to sell
9,400 miles of intrastate pipelines and 1,300 miles of gathering systems to
El Paso Energy Partners.

(4) Reflects the acquisition of TransCanada Gas Processing U.S.A. in December
1999.

(5) Aux Sable went in service in December 2000.

(6) Mobile Bay went in service in April 1999.

Regulatory Environment

Some of Field Services' and El Paso Energy Partners' 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' and El Paso Energy Partners' 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 and El Paso Energy Partners file the appropriate rate tariffs and
operate under the applicable rules and regulations of the Railroad Commission.

In addition, some of Field Services' and El Paso Energy Partners'
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 the National Environmental Policy Act. Each of the pipelines has a
continuing program of inspection designed to keep all of the facilities in
compliance with pollution control and pipeline safety requirements, and Field
Services and El Paso Energy Partners believe that these systems are in
compliance with applicable requirements.

19

Markets and Competition

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

CORPORATE AND OTHER OPERATIONS

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 other operations include the assets and operations of our
telecommunication business, which involves providing wholesale transport
services, primarily to metropolitan areas in Texas, and operating a facility
that provides customers with fiber access and interconnectivity in Chicago,
Illinois.

ENVIRONMENTAL

A description of our environmental activities is included in Part II, Item
8, Financial Statements and Supplementary Data, Note 14, and is incorporated
herein by reference.

EMPLOYEES

As of March 12, 2002, we had approximately 14,180 full-time employees, of
which 889 are subject to collective bargaining arrangements.

20

EXECUTIVE OFFICERS OF THE REGISTRANT

Our executive officers as of February 28, 2002, are listed below. Prior to
August 1, 1998, all references to El Paso refer to positions held with El Paso
Natural Gas Company.

Mr. Wise has been Chief Executive Officer since January 1990 and the
Chairman of the Board of Directors since January 2001. He was also Chairman of
the Board from January 1994 until October 1999. Mr. Wise became the President of
El Paso in July 1998 and also served in that capacity from January 1990 to April
1996. Mr. Wise is a member of the Board of Directors of Praxair, Inc. and is the
Chairman of the Board of El Paso Tennessee Pipeline Co. and El Paso Energy
Partners Company, the general partner of El Paso Energy Partners L.P.

Mr. Austin has been an Executive Vice President since May 1995. He has been
our Chief Financial Officer since April 1992. Prior to that period, he served in
various positions with Burlington Resources Inc. and Burlington Northern Inc.
Mr. Austin is a member of the Board of Directors of El Paso Tennessee Pipeline
Co. and El Paso Energy Partners Company, the general partner of El Paso Energy
Partners, L.P.

Mr. Eads has been an Executive Vice President since July 1999 and President
of the El Paso Merchant Energy Group since January 2001. Mr. Eads was a Managing
Director and Co-Head of the Energy Group at Donaldson, Lufkin & Jenrette from
January 1996 through June 1999. Prior to that period, he was Managing Director,
Head of Energy at S.G. Warburg & Company.

Mr. Richards has been an Executive Vice President since December 1996. From
January 1991 until December 1996, he was a Senior Vice President of El Paso. Mr.
Richards is a member of the Board of Directors of El Paso Tennessee Pipeline Co.

Mr. Somerhalder has been an Executive Vice President of El Paso since April
2000, and President of our Pipeline segment since January 2001. He has been
Chairman of the Board of TGP, EPNG, and SNG since January 2000. He was President
of TGP from December 1996 to January 2000, President of El Paso Energy Resources
Company from April 1996 to December 1996 and a Senior Vice President of El Paso
from August 1992 to April 1996.

Ms. Heeg has been Executive Vice President and General Counsel of El Paso
since January 1, 2002. She was Senior Vice President and Deputy General Counsel
from April 2001 to December 2001 and Vice

21

President and Associate General Counsel for regulated pipelines from 1997 to
2001. Ms. Heeg has held various positions in the legal department of Tenneco
Energy and El Paso since 1996. Ms. Heeg is a member of the Board of Directors of
El Paso Tennessee Pipeline Co.

Mr. Jenkins has been Executive Vice President of El Paso since January
2002. He was President of El Paso Global Networks from August 2000 to January
2002. He was President of Merchant Energy from December 1996 to August 2000. He
was Senior Vice President and General Manager of Entergy Corp. from May 1996 to
December 1996. Prior to that period, he was President and Chief Executive
Officer of Hadson Gas Services Company.

Mr. Erskine has been President of El Paso Production since our merger with
Coastal in January 2001. He was Senior Vice President of Coastal from August
1997. He has held various positions with Coastal Oil & Gas Corporation, a
subsidiary of Coastal, since 1994.

Mr. Kelley has been President of El Paso International since January 2001.
He was Executive Vice President of Business Development and commercial
management for El Paso International since 1996. Prior to that period, Mr.
Kelley held various positions with Tenneco Energy.

Mr. 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 Field Services from April 1996 to December 1996 and was a
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 a member of the Board of Directors of El Paso Energy Partners
Company, the general partner of El Paso Energy Partners, L.P.

Mr. Clark C. Smith has been President of El Paso Merchant Energy North
America since August 2000. He served as President and CEO of Engage Energy Inc.
since 1997. Prior to that period, he held the position of President and CEO of
Coastal Gas Marketing Company and held several positions with Enron Corp.

Mr. William A. Smith has been President of El Paso Global LNG since March
2001. He was an Executive Vice President of El Paso from October 1999 to March
2001. He was Executive Vice President and General Counsel of Sonat Inc. from
1995 to September 1999. He was Vice Chairman of Sonat Exploration from 1994 to
1995 and Chairman and President of SNG from 1989 to 1994.

Executive officers hold offices until their successors are elected and
qualified, subject to their earlier removal. Each of these elected officers also
hold offices and/or director positions with our affiliated entities.

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 current taxes, liens incident to minor
encumbrances, and easements and restrictions that do not materially detract from
the value of these properties or our interests therein, or the use of these
properties in our businesses. We believe that our properties are adequate and
suitable for the conduct of our business in the future.

ITEM 3. LEGAL PROCEEDINGS

A description of our legal proceedings is included in Part II, Item 8,
Financial Statements and Supplementary Data, Note 14, and is incorporated herein
by reference.

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

None.

22

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 and the Pacific
Exchange under the symbol EP. As of March 12, 2002, we had 55,069 stockholders
of record. This does not include individual participants who own our common
stock, but 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:

In January 2002, our Board of Directors declared a quarterly dividend of
$0.2175 per share of common stock, payable on April 3, 2002, to stockholders of
record on March 1, 2002. Future dividends will be dependent upon business
conditions, earnings, our cash requirements and other relevant factors.

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 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, our exchange agent at
1-877-453-1503.

23

ITEM 6. SELECTED FINANCIAL DATA

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

(1) Our operating results and financial position data reflect the acquisitions
of PG&E's Texas Midstream operations in December 2000 and DeepTech
International in August 1998. These acquisitions were accounted for as
purchases, and therefore operating results are included in our results
prospectively from the purchase date.
(2) Our operating revenues and total assets reflect the significant growth in
our Merchant Energy operations during 2001 and 2000 as well as the
consolidation of the U.S. operations of Coastal Merchant Energy in September
2000.
(3) Our 2001 costs relate primarily to our merger with Coastal, and our 1999
costs relate primarily to our merger with Sonat.
(4) Ceiling test charges are reductions in earnings that result when capitalized
costs of natural gas and oil properties exceed the upper limit, or ceiling,
on the value of these properties.
(5) Cash dividends declared per share of common stock represent the historical
dividends declared by El Paso for all periods presented.

24

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

GENERAL

Over the past several years, our business activities and operations have
grown dramatically as a result of significant acquisitions, transactions, and
internal growth initiatives that have enhanced our ability to compete in the
global energy industry. This growth has significantly expanded our operating
scope, our ability to generate operating cash flows and our needs for cash for
investment opportunities. Consequently, we have substantially expanded our
credit facilities and entered into other financing arrangements and facilities
to meet our needs during this period. The more significant events are discussed
below.

Merger with The Coastal Corporation

In January 2001, we merged with The Coastal Corporation. We accounted for
the merger as a pooling of interests and converted each share of Coastal common
stock and Class A common stock on a tax-free basis into 1.23 shares of our
common stock. We also exchanged Coastal's outstanding convertible preferred
stock for our common stock on the same basis as if the preferred stock had been
converted into Coastal common stock immediately prior to the merger. We issued a
total of 271 million shares, including 4 million shares issued to holders of
Coastal stock options. Our discussion and analysis of our financial condition
and results of operations reflects the combined information of our two companies
for all periods presented.

In connection with a Federal Trade Commission (FTC) order related to this
merger, in 2001 we sold our Gulfstream pipeline project and Midwestern Gas
Transmission system and our investments in the Empire State, Stingray, U-T
Offshore and Iroquois pipeline systems. Proceeds from these sales were
approximately $279 million and we recognized an extraordinary gain of $26
million, net of income taxes of $27 million, on these transactions.

Purchase of Texas Midstream Operations

In December 2000, we completed our purchase of Pacific Gas & Electric's
(PG&E's)Texas Midstream operations for $887 million, including $527 million of
assumed debt. We accounted for this acquisition as a purchase. The assets
acquired consist of 7,500 miles of intrastate natural gas transmission and
natural gas liquids pipelines that transport approximately 2.8 Bcf/d, nine
natural gas processing plants that process 1.5 Bcf/d and rights to 7.2 Bcf of
natural gas storage capacity. These assets serve a majority of the metropolitan
areas and the largest industrial load centers in Texas, as well as numerous
natural gas trading hubs. These assets also create a physical link between our
EPNG and TGP systems. Results from this acquisition are reflected in our results
of operations from the date of purchase.

In December 2000, to comply with an FTC order, we sold our interest in
Oasis Pipeline Company. Proceeds from the sale were $22 million, and we
recognized an extraordinary loss of $19 million, net of income taxes of $9
million.

In March 2001, we sold some of the acquired natural gas liquids
transportation and fractionation assets to El Paso Energy Partners for
approximately $133 million. The assets sold included more than 600 miles of
natural gas liquids gathering and transportation pipelines and three
fractionation plants located in south Texas. In February 2002, we announced the
sale of the remaining natural gas transmission assets to El Paso Energy
Partners. See a further discussion of this sale under our discussion of the
segment operating results for the Field Services segment.

Merger with Sonat Inc.

In October 1999, we completed our merger with Sonat, Inc. We accounted for
the merger as a pooling of interests and converted each share of Sonat common
stock into one share of our common stock. We issued approximately 110 million
shares. In connection with an FTC order related to this merger, we sold our East
Tennessee Natural Gas Company and Sea Robin Pipeline Company pipeline systems as
well as our one-third

25

interest in the Destin Pipeline Company system. Proceeds from the sales were
approximately $616 million, and we recognized an extraordinary gain of $89
million, net of income taxes of $59 million.

Balance Sheet Enhancement Plan

In December 2001, we announced a plan to strengthen our capital structure
and enhance our liquidity in response to changes in market conditions in our
industry. This plan involves the sale of assets, a reduction in capital
spending, the issuance of equity and the elimination or renegotiation of the
rating triggers for several of our financing arrangements. The goal of the plan
is to reduce our debt to total capital ratio to 50 percent by the end of 2002.
For further information about this plan, see the discussion under Future
Liquidity.

Merger-Related Costs, Asset Impairments and Other Charges

Below are the charges incurred that had a significant impact on our results
of operations, financial position and cash flows for each of the three years
ended December 31:

Merger-Related Costs. Our merger-related costs relate to our mergers with
Coastal and Sonat and consisted of the following for each of the three years
ended December 31:

Employee severance, retention and transition costs include direct payments
to, and benefit costs for, severed employees and early retirees that occurred as
a result of our merger-related workforce reduction and consolidation. Following
the Coastal merger, we completed an employee restructuring across all of our
operating segments, resulting in the reduction of 3,285 full-time positions
through a combination of early retirements and terminations. Following the Sonat
merger, a total of approximately 870 full-time positions were eliminated in a
similar restructuring. Employee severance costs include actual severance
payments and costs for pension and post-retirement benefits settled and
curtailed under existing benefit plans as a result of these restructurings.
Retention charges include payments to employees who were retained following the
mergers and payments to employees to satisfy contractual obligations. Transition
costs relate to costs to relocate employees and costs for severed and retired
employees arising after their severance date to transition their jobs into the
ongoing workforce. The pension and post-retirement benefits were accrued on the
merger date and will be paid over the applicable benefit periods of the
terminated and retired employees. All other costs were expensed as incurred and
have been paid.

Also included in the 2001 employee severance, retention and transition
costs was a charge of $278 million resulting from the issuance of approximately
4 million shares of common stock on the date of the Coastal merger in exchange
for the fair value of Coastal employees' and directors' stock options.

26

Transaction costs include investment banking, legal, accounting, consulting
and other advisory fees incurred to obtain federal and state regulatory
approvals and take other actions necessary to complete our mergers. All of these
items were expensed in the periods in which they were incurred.

Business and operational integration costs include charges to consolidate
facilities and operations of our business segments, such as lease termination
and abandonment charges, recognition of the mark-to-market value of energy
trading contracts resulting from changes in how these contracts are managed
under our combined operating strategy and incremental fees under software and
seismic license agreements. Also included in the 2001 charges are approximately
$222 million in estimated lease related costs to relocate our pipeline
operations from Detroit, Michigan to Houston, Texas and from El Paso, Texas to
Colorado Springs, Colorado. These charges were accrued at the time we completed
our relocations and closed these offices. The amounts accrued will be paid over
the term of the applicable non-cancelable lease agreements. All other costs were
expensed as incurred.

Merger-related asset impairments relate to write-offs or write-downs of
capitalized costs for duplicate systems, redundant facilities and assets whose
value was impaired as a result of decisions on the strategic direction of our
combined operations following our merger with Coastal. These charges occurred in
our Merchant Energy, Production and Pipelines segments, and all of these assets
have either had their operations suspended or continue to be held for use. The
charges taken were based on a comparison of the cost of the assets to their
estimated fair value to the ongoing operations based on this change in operating
strategy.

Other costs include payments made in satisfaction of obligations arising
from the FTC approval of our merger with Coastal and other miscellaneous
charges. These items were expensed in the period in which they were incurred.

Asset Impairments. The 2001 asset impairment charges resulted from the
write-downs of our investments in several international power projects in our
Merchant Energy segment and several telecommunications investments in our
Corporate and Other operations. The 2000 charges consisted of the impairment of
coal mining and refining assets in our Merchant Energy segment and a gas
processing facility in our Field Services segment. The 1999 charge occurred in
the Pipeline segment and was derived from impairments of regulatory assets that
were not recoverable based on the settlement of a rate case. The impairments in
all periods were primarily a result of weak or changing economic conditions
causing permanent declines in the value of these assets, and the charges taken
for all assets were based on a comparison of each asset's carrying value to its
estimated fair value based on future estimated cash flows. These assets continue
to be held for use, or their operations have been suspended.

Changes in Accounting Estimates. Our 2001 changes in accounting estimates
consist of $232 million in additional environmental remediation liabilities, $47
million of additional accrued legal obligations and a $38 million charge to
reduce the value of our spare parts inventories to reflect changes in the
usability of these parts in our worldwide operations. These changes were
primarily the result of several events that occurred as part of and following
our merger with Coastal, including the consolidation of numerous operating
locations, the sale of a majority of our retail gas stations, the shutdown of
our Midwest refining operations and the lease of our Corpus Christi refinery.
These changes were also a direct result of a fire at our Aruba refinery. Also
impacting these amounts was the evaluation of the operating standards,
strategies and plans of our combined company following the merger. These charges
are included as operating expenses in our income statement and reduced our net
income before extraordinary items and net income for the year ended December 31,
2001, by approximately $215 million.

Ceiling Test Charges. Under the full cost method of accounting for natural
gas and oil properties, we perform quarterly ceiling tests to evaluate whether
the carrying value of natural gas and oil properties exceeds the present value
of future net revenues, discounted at 10 percent, plus the lower of cost or fair
market value of unproved properties. During the third quarter of 2001,
capitalized costs exceeded this ceiling limit by $135 million, including $87
million for our Canadian full cost pool, $28 million for our Brazilian full cost
pool and $20 million for other international production operations, primarily in
Turkey. These charges were based on the November 1, 2001 daily posted oil and
natural gas sales prices. During 1999, we incurred charges related to our U.S.
full cost pool of $352 million based on end of period natural gas and oil
prices. The natural
27

gas and oil prices used in both periods were adjusted for oilfield or gas
gathering hub and wellhead price differences as appropriate. These non-cash
write-downs are included in our income statement as ceiling test charges.

We use financial instruments to hedge against volatility of natural gas and
oil prices. The impact of these hedges was considered in the determination of
our ceiling test charge during 2001, and will be factored into future ceiling
test calculations. Had the impact of our hedges not been included in calculating
our 2001 ceiling test charge, the charge would not have materially changed since
we do not significantly hedge our international production activities.

Also as mentioned above, our 2001 charge was computed based on daily posted
prices on November 1, 2001. Had we computed this charge based on the daily oil
and natural gas prices as of September 30, 2001, the charge would have been
approximately $275 million, including approximately $227 million for our
Canadian full cost pool and $48 million for our Brazilian and other
international production operations, including the impact on future cash flows
of our hedging program. Had the impact of our hedging program been excluded, the
charges would have been approximately the same for our international full costs
pools and production operations, but we would have incurred an additional charge
of approximately $576 million related to our U.S. full cost pool.

RESULTS OF OPERATIONS

Our results of operations, along with the impact, by segment, of the
merger-related, asset impairment and other charges discussed above,
extraordinary items and accounting changes for each of the three years ended
December 31 were as follows:

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

(1) Pro-forma amounts should not be used as a substitute for amounts reported
under generally accepted accounting principles. They are presented solely to
improve the understanding of the impact of the charges reported during the
periods presented.

(2) In 2001, these gains were a result of FTC ordered sales in connection with
our Coastal merger, including the sales of our Gulfstream pipeline project
and Midwestern Gas Transmission system and our investments in the Empire
State, Stingray, U-T Offshore and Iroquois pipeline systems. In 2000, these
gains were a result of FTC ordered sales in connection with our Sonat
merger, including the sales of our East Tennessee and Sea Robin pipeline
systems.

SEGMENT RESULTS

Our four segments: Pipelines, Merchant Energy, Production and Field
Services are strategic business units that offer a variety of different energy
products and services, each requiring different technology and marketing
strategies. We evaluate our segment performance based on earnings before
interest expense and income taxes, or EBIT. Operating revenues and expenses by
segment include intersegment revenues and expenses which are eliminated in
consolidation. Because changes in energy commodity prices have a similar

28

impact on both our operating revenues and cost of products sold from period to
period, we believe that gross margin (revenue less cost of sales) provides a
more accurate and meaningful basis for analyzing operating results for the
trading and refining portions of Merchant Energy and for the Field Services
segment. For a further discussion of the individual segments, see the discussion
of our businesses beginning on page 1, as well as Item 8, Financial Statements
and Supplementary Data, Note 18.

Below is a discussion and analysis of the operating results of each of our
business segments. These results include the impact of the merger-related costs,
asset impairments and other charges discussed above for all years presented.

PIPELINES

Our Pipelines segment operates our interstate pipeline businesses. Each
pipeline system operates under a separate tariff that governs its operations,
terms and conditions of service and rates. Operating results for our pipeline
systems have generally been stable because the majority of the revenues are
based on fixed reservation charges. As a result, we expect changes in this
aspect of our business to be primarily driven by regulatory actions, system
expansions and contractual events. Commodity or throughput-based revenues
account for a smaller portion of our operating results. These revenues vary from
period to period, and system to system, and are impacted by factors such as
weather, operating efficiencies, competition from other pipelines and
fluctuations in natural gas prices. Results of operations of the Pipelines
segment were as follows for each of the three years ended December 31:

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

(1) Throughput volumes exclude those related to pipeline systems sold in
connection with FTC orders related to our Coastal and Sonat mergers
including the Midwestern Gas Transmission, East Tennessee Natural Gas and
Sea Robin systems; and the Destin, Empire State and Iroquois pipeline
investments. Throughput volumes exclude intrasegment activities.

YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000

Operating revenues for the year ended December 31, 2001, were $7 million
higher than the same period in 2000. The increase was due to higher reservation
revenues on the EPNG system as a result of a larger portion of its capacity sold
at maximum tariff rates versus the same period in 2000 and the impact of
completed system expansions and new storage and transportation contracts on ANR
and CIG during 2001. Also contributing to the increase were the impact of higher
natural gas prices in the first and second quarters on sales of segment-owned
production, sales of excess natural gas and sales under regulated natural gas
sales contracts, as well as higher throughput from increased deliveries to
California and other western states. These increases were partially offset by
lower 2001 revenues resulting from contract remarketing on the TGP system in
late 2000 and the impact of the sales of the Midwestern Gas Transmission system
in April 2001, Crystal Gas Storage in September 2000 and the East Tennessee
Natural Gas and Sea Robin systems in the first

29

quarter of 2000. Also partially offsetting the increase were lower 2001 sales of
base gas from abandoned storage fields, the favorable resolution of natural gas
price-related contingencies on CIG in 2000, lower transportation revenues in
2001 on TGP as a result of higher proportion of short versus long hauls compared
to 2000 and lower remarketed rates on seasonal turned-back capacity in 2001 as a
result of SNG's 2000 rate case settlement allowing some customers to partially
reduce their firm transportation capacity.

Operating expenses for the year ended December 31, 2001, were $267 million
higher than the same period in 2000 primarily as a result of the merger-related
and other charges in 2001 discussed previously. Also contributing to the
increase was the impact of higher natural gas prices in the first half of 2001
on natural gas purchase contracts, higher purchase gas costs due to the net
impact of a natural gas imbalance revaluation in 2001 as a result of falling gas
prices during the second half of the year, increases to our reserve for bad
debts as a result of our exposure in connection with the bankruptcy of Enron
Corp., and a one-time favorable adjustment to depreciation expense during the
first quarter of 2000 as a result of approval by the FERC to reactivate the Elba
Island LNG facility. Partially offsetting the increase were lower operating and
maintenance expenses due to cost efficiencies following the merger with Coastal
and reduced operating and depreciation expenses due to the sales of the
Midwestern Gas Transmission system in April 2001, Crystal Gas Storage in
September 2000 and East Tennessee and Sea Robin in the first quarter of 2000.

Other income for the year ended December 31, 2001, was $25 million lower
than the same period in 2000 due to lower 2001 equity earnings on our Australian
pipelines and Citrus Corp., which owns the Florida Gas Transmission System, and
gains from the sales of non-pipeline assets in 2000. Also contributing to the
decrease was the impact on equity earnings due to the sales of our investments
in the Empire State and Iroquois pipeline systems in 2001 and the sale of our
one-third interest in Destin Pipeline Company in 2000. Partially offsetting the
decrease was increased earnings from our investment in the Alliance pipeline
project which commenced operations in the fourth quarter of 2000.

YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999

Operating revenues for the year ended December 31, 2000, were $15 million
lower than the same period in 1999. The decrease was due to the impact of our
sales of the East Tennessee Natural Gas and Sea Robin systems in the first
quarter of 2000 to comply with an FTC order related to our merger with Sonat,
the favorable resolution of regulatory issues in the first quarter of 1999 on
TGP and lower rates following SNG's May 2000 rate case settlement. Also
contributing to the decrease was the impact of customer settlements and contract
terminations in 2000 and resolutions of customer imbalance issues in 1999 on
TGP. Partially offsetting the decrease were higher revenues from transportation
and other services provided on each of our transmission systems due to improved
average throughput in 2000 versus 1999, higher realized prices on pipeline gas
sales in 2000, the favorable resolution of natural gas price-related
contingencies in 2000 on CIG, and revenues from the January 2000 acquisition of
Crystal Gas Storage which was sold in September 2000 to El Paso Energy Partners.

Operating expenses for the year ended December 31, 2000, were $104 million
lower than the same period in 1999. The decrease was due to cost efficiencies
following our merger with Sonat, lower operating costs due to the sales of East
Tennessee and Sea Robin in the first quarter of 2000 and a one-time favorable
adjustment to depreciation expense during the first quarter of 2000 as a result
of approval by the FERC to reactivate the Elba Island facility. Also
contributing to the decrease was the expense associated with the resolution of a
contested rate matter with a customer of EPNG, severance and termination charges
incurred as a result of our Sonat merger and the impairment of several SNG
expansion projects, all occurring in 1999. Additionally, an increase in
estimated future environmental costs and write-offs of duplicate information
technology assets in 1999 on SNG following our merger with Sonat contributed to
the decrease. The decrease was partially offset by higher gas costs related to
the Dakota gasification facility, higher system balancing requirements and the
impact of unfavorable producer and shipper settlements on EPNG.

Other income for the year ended December 31, 2000, was $34 million higher
than the same period in 1999. The increase was due to higher earnings on Citrus
Corp. as a result of a one-time benefit recorded in 2000, higher earnings from
our equity investments in 2000 as well as gains on the sale of non-pipeline
assets in

30

the third quarter of 2000. The increase was partially offset by the favorable
settlement of a regulatory issue in 1999, the elimination of an asset for the
future recovery of costs of the Elba Island facility and a lower allowance for
funds used during construction as a result of less expansion and construction
activity in 2000.

MERCHANT ENERGY

Our Merchant Energy segment is involved in a wide range of activities in
the wholesale energy markets, including asset ownership, customer origination,
marketing and trading and financial services. Each of the markets served by
Merchant Energy is highly competitive and is influenced directly or indirectly
by energy market economics. Prior to October 2000, Coastal conducted its
marketing and trading activities through Engage Energy U.S., L.P. and Engage
Canada, L.P., a joint venture between Coastal and Westcoast Energy Inc., a major
Canadian natural gas company. During the fourth quarter of 2000, Coastal
terminated the Engage joint venture and commenced its own marketing and trading
activities.

Asset Ownership

Merchant Energy's asset ownership activities include domestic and
international power plants, refining, chemical and coal mining operations, and
an emerging LNG business. In its power asset business, Merchant Energy owns or
has interests in 95 plants in 20 countries. The segment's domestic power
activities are principally conducted through Chaparral Investors, L.L.C., an
unconsolidated affiliate in which Merchant Energy has a 20 percent ownership
interest.

Chaparral. In 1999, we formed Chaparral. Through its subsidiaries,
Chaparral (also referred to as Electron) owns domestic power assets and is
funded with third party capital (80%) and El Paso capital (20%). We manage the
daily activities of Chaparral's assets and investments and are paid an annual
management fee. The basic strategy of Chaparral is:

- to acquire power facilities with attractive power contracts;

- to develop facilities that will operate under long-term tolling
agreements;

- to restructure the power sales, fuel supply and credit agreements of
PURPA facilities;

- to monetize these restructured arrangements to fund operations and grow
the venture; and

- to operate these facilities in a fully deregulated environment in a
manner that enhances their value.

Chaparral was formed in order to obtain low cost financing to grow new
business activities and to generate a stable fee-based income stream. Merchant
Energy's annual management fee is equal to 20% of the net present value of the
assets of Chaparral and must be approved by the third party investor. This net
present value, or NPV, represents the present value of anticipated future cash
flows of Chaparral's assets, net of its liabilities, less the estimated cost to
liquidate all third party capital. As of December 31, 2001, Chaparral held
assets with a NPV totaling approximately $925 million.

As of December 31, 2001, Chaparral's total assets were $2.5 billion and its
liabilities were $1.6 billion. Total third party capital in Chaparral was
approximately $1.15 billion, of which the debt component was $1.0 billion. In
order to lower the cost of the debt, we provided a contingent equity support
arrangement on this debt. Under this arrangement, we issued mandatorily
convertible preferred stock with an aggregate liquidation value of $1.0 billion
to a trust we control. We could be required to sell this stock to repay the
third party debt if, among other things, our credit ratings fall below
investment grade and our stock price falls below $27.07 for ten consecutive
trading days. We plan to amend this arrangement by eliminating the stock
price/credit downgrade events and replace it with an El Paso financial guarantee
in connection with our balance sheet enhancement plan. See a further discussion
of our balance sheet enhancement plan under Future Liquidity.

The future success of Chaparral will be dependent upon our ability to
successfully restructure existing assets in Chaparral, as well as acquire
additional power facilities. Chaparral may face increased competition in the
future for properties and facilities that are increasingly complicated to
acquire and restructure. In addition,
31

if not renegotiated or renewed, the debt financing that supports Chaparral
matures in the first quarter of 2003. While it is our intent to renew these
agreements, there are no guarantees that the financial investors will continue
to participate or that third party capital will be available for investment.

Merchant Energy conducts a variety of transactions with Chaparral and
generates earnings in several ways, which includes a performance-based
management fee, equity earnings from Chaparral's activities and margins on risk
management activities where Merchant Energy serves as the commodity provider for
many of Chaparral's fuel and power purchase contracts. Chaparral also reimburses
Merchant Energy for general and administrative expenses incurred on its behalf.
During 2001, Merchant Energy earned $147 million in management fees from
Chaparral and was reimbursed $20 million for general and administrative
expenses. It also recognized $75 million in equity earnings. For 2002, the
management fee will increase to approximately $185 million as approved by
Chaparral's third party investor in the fourth quarter of 2001. This management
fee increase reflects the growth that has occurred in the Chaparral asset
portfolio. Assumptions used in establishing the annual management fee include
estimates of future energy prices, future demand for power, timing and terms of
contract restructurings and future interest rates. These assumptions are based
on a combination of quoted market prices and rates, models which project future
market changes and anticipated demand, and other variables. Changes in these
assumptions can impact the annual management fee from year to year and these
changes can be material.

From time to time, we enter into transactions with Chaparral and its
affiliates to sell power assets. Merchant Energy's fiduciary responsibilities
under its management agreement with Chaparral require that these transactions be
entered into at fair and reasonable values. To ensure fairness, significant
transactions are evaluated and approved by the third party investor of Chaparral
as well as our Board of Directors. During 2001, Chaparral acquired power assets
from us with a fair value of $276 million. We did not recognize any gains or
losses on these transactions.

International Power Assets and Gemstone. Internationally, Merchant Energy's
power assets consist primarily of investments in joint ventures that construct
and operate power facilities and other infrastructure assets around the world.
In Brazil, these activities are conducted through Gemstone, an unconsolidated
affiliate through which Merchant Energy plans to expand its power investments in
that country. Gemstone was formed in 2001 with a third party investor primarily
to generate low-cost funds for financing power plants in Brazil and to reduce
risk through the introduction of third party equity. Total third party capital
in Gemstone at December 31, 2001, was $1 billion, of which the debt component
was $950 million. To lower the cost of this debt, we provided a contingent
equity support arrangement. Under this arrangement, we issued mandatorily
convertible preferred stock with an aggregate liquidation value of $950 million
to a trust we control. We could be required to sell this stock to repay the debt
if, among other things, our credit ratings fall below investment grade and our
stock price falls below $36.16 for ten consecutive trading days. In addition, if
not renegotiated or renewed, the debt financing that supports Gemstone matures
in 2004. We plan to amend this arrangement by eliminating the stock price/credit
downgrade events and replace it with an El Paso financial guarantee in
connection with our balance sheet enhancement plan. See a further discussion of
our balance sheet enhancement plan under Future Liquidity.

Brazil's power infrastructure has primarily been based on the use of
hydroelectric power generation. The success of Gemstone in the future will be
based on the demand for natural gas fired generation in Brazil, which may be
significantly impacted by the availability of competing generation, such as
hydroelectric power generation, which is less expensive to operate and more
abundant. Furthermore, there are numerous risks in operating internationally
which could impact Gemstone's ultimate success.

Earnings from Merchant Energy's international power activities, including
Gemstone, are derived primarily through equity earnings from these investments
and will be dependent on the ultimate success of privately owned power
generation and infrastructure development in countries where Merchant Energy
does business. During 2001, Merchant Energy recorded net equity earnings from
Gemstone of $2 million.

Refining, Chemical, Coal Mining and LNG. In addition to its power business,
Merchant Energy has refining, chemical and coal mining operations and an
emerging global LNG operation. Results from Merchant Energy's refining and
chemical operations are highly dependent on margin differentials between
feedstocks,
32

primarily crude oil and other petroleum products and market prices of the
products produced, both of which can be highly volatile. In our coal business,
results are driven by productivity of our mining operations along with the
market prices of the coal produced. In 2001, Merchant Energy increased the scope
of its activities in LNG, with full operations expected in 2003 and 2004. The
success of this business will be based substantially on the worldwide supply of
natural gas and demand for LNG which will depend on strong natural gas prices
and LNG shipping and terminalling infrastructure.

Customer Origination, Marketing and Trading

Merchant Energy's customer origination, marketing and trading activities
provide energy supply and risk management solutions for its customers and
affiliates involving natural gas, power, crude oil, refined products, chemicals
and coal. Merchant Energy assists its customers with energy supply aggregation,
storage and transportation management and provides them with an array of risk
management products. Merchant Energy also conducts a substantial energy trading
business that executes proprietary trading strategies and manages the segment's
risk across multiple commodities and over seasonally fluctuating energy demands
using consistent methodologies. During 2001 and 2000, U.S. energy supply and
demand resulted in substantial volatility in the energy markets that
significantly impacted Merchant Energy's earnings.

Merchant Energy's customer origination, marketing and trading groups
account for their activities using mark-to-market accounting. Under this
accounting method, financial instruments, physical commodity positions and
contractual energy-related transactions are recorded on the balance sheet and
the income statement at their fair value at the time they are entered into.
Subsequent to their inception, the transactions continue to be adjusted in the
balance sheet and income statement for changes in their fair value until they
are settled. Determining the fair value of these positions at inception and
until settlement principally involves the use of actively quoted prices and, to
a lesser degree, other valuation methods, including models that rely on actively
quoted prices. Approximately 9% of the value of our mark-to-market portfolio is
based on model valuations (i.e., not on active market quotes). Most of these
models are options-based valuations and involve contracts related to physical
assets. Examples of contracts that are generally valued using models include
natural gas pipeline capacity, natural gas storage contracts and to a lesser
extent power plant tolling agreements. Modeling allows us to value these
contracts, as well as manage them more effectively, providing lower cost service
to our customers, and to effectively measure and manage the risk associated with
them on a daily basis. Almost all of the model-based valuations we employ are
spread option valuations, such as location spread options (pipeline capacity),
time spread options (natural gas storage capacity) and spark spread options
(natural gas-fired power plant tolling). The price data underlying these models
is based, in part, on market data and our estimates of future prices for periods
which market data is limited. An important variable in these models is the
volatility of the prices underlying the contracts and the correlation of the
prices underlying the contracts. There is limited market price data related to
correlations and volatilities although significant implicit data does exist. We
use this implicit market data and historical data to determine volatilities and
correlation for calculation of these models. We believe these calculations to be
reliable predictors of value over time. In addition, Merchant Energy maintains a
risk controls group that verifies all market price data for accuracy,
independently of the marketing and trading groups and this group conducts these
activities on both actively quoted and model-derived information. Further, to
the extent there is uncertainty of the amounts we will ultimately realize from
these transactions, we adjust the amounts we recognize as income until these
uncertainties are resolved. These estimates are adjusted as assumptions change
or as transactions move closer to settlement and better estimates become
available.

As of December 31, 2001, the fair value of our trading-related price risk
management activities was $1,295 million, and total margins generated from these
activities during 2001 were $690 million.

33

The following table details the fair value of Merchant Energy's price risk
management activities by year of maturity and valuation methodology. The amounts
reflected as prices actively quoted are based on values determined by market
quotes and other actively traded data, primarily NYMEX and other exchange-based
information, including broker quotes. The amounts reflected as prices based on
models and other valuation methods represent the fair value of contracts
calculated based on internal models using the methods discussed above.

FAIR VALUE OF TRADING PRICE RISK MANAGEMENT CONTRACTS AS OF DECEMBER 31, 2001

A reconciliation of our 2001 trading activities is as follows (in
millions):

Fair value of contracts outstanding at December 31, 2000.... $ 2,200
-------

Fair value of contracts settled during the period........... (1,973)
Initial recorded value of new contracts..................... 160
Change in fair value of contracts........................... 678
Changes in fair value attributable to changes in valuation
techniques................................................ 2
Other....................................................... 228
-------
Net change in contracts outstanding during the period..... (905)
-------
Fair value of contracts outstanding at December 31,
2001(1)................................................... $ 1,295
=======

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

(1) At December 31, 2001, net assets from non-trading price risk management
activities were $426 million, and total net assets from all of our price
risk management activities were $1,721 million.

The fair value of contracts settled during the period represents the
amounts of traded contracts settled in cash, through physical delivery of a
commodity or by a claim to cash as accounts receivable or payable. The initial
recorded value of new contracts includes the fair value of origination
transactions at the time the transaction is initiated. 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, until their
settlement or, if not settled, until the end of the period. Included in change
in fair value of contracts during the year is a net loss of $109 million related
to changes in the market values of contracts transferred to our trading
portfolio as a result of a change in the manner in which these contracts were
managed following the Coastal merger. Included in other is the effect of natural
gas storage purchases and premiums paid on option contracts.

Financial Services

In the financial services area, Merchant Energy conducts energy financing
activities through its ownership of EnCap and Enerplus. EnCap manages four
separate oil and natural gas investment funds in the U.S. and serves as an
investment advisor to one fund in Europe. EnCap also facilitates investment in
emerging energy companies and earns a return from these investments. Enerplus,
which was acquired in 2000, is a Canadian investment management company which
conducts fund management activities similar to EnCap, but in Canada. Results
from Merchant Energy's financial services activities are based on a combination
of management fees and market based earnings on the investments held by these
companies.

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Below are Merchant Energy's operating results and traded volumes (excluding
intrasegment transactions) and an analysis of those results for each of the
three years ended December 31:

Volumes (Excludes intrasegment transactions):
Physical
Natural Gas (BBtue/d).............................. 9,230 7,768 6,713
Power (MMWh)....................................... 221,075 118,672 79,361
Crude oil and refined products (MBbls)............. 698,933 667,834 664,935
Coal (MTons)....................................... 10,343 9,834 8,980
Financial Settlements (Bbtue/d)...................... 232,282 151,115 113,814

YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000

Trading and refining gross margin consists of revenues from commodity
trading and origination activities less the costs of commodities sold as well as
revenues from refineries and chemical plants, less the cost of the feedstocks
used in the refining and production processes. For the year ended December 31,
2001, these gross margins were $199 million higher than the same period in 2000.
The increase was primarily due to higher trading margins in natural gas, power,
crude oil and refined products as a result of increased trading volumes and
price volatility as well as increased income from transactions originated during
2001. The increase in trading margins was partially offset by the negative
margins in refining resulting from a fire at our Aruba facility in April 2001,
the lease of our Corpus Christi refinery and related assets to Valero in June
2001, lower margins in heavy crude based refined products and lower margins and
throughput at the Eagle Point refinery as a result of decreased demand for jet
fuel following the events of September 11, 2001. Also offsetting this increase
were reserves established as a result of the bankruptcy of Enron Corp. in
December 2001.

Merchant Energy has conducted trading activities and held derivative
positions with Enron Corp. and its subsidiaries. In December of 2001, Enron and
certain of its subsidiaries sought protection from its creditors under Chapter
11 of the U.S. Bankruptcy Code. Following this filing, Merchant Energy
terminated all contracts with the Enron subsidiaries that filed for bankruptcy.
This resulted in the transfer of Merchant Energy's net derivative positions with
Enron out of price risk management activities to accounts receivable. In
addition, Merchant Energy established reserves on these receivables that it
believes are adequate based on the amounts it expects to collect through the
bankruptcy. In the first quarter of 2002, Merchant Energy asserted a claim
against Enron on the cancelled contracts.

Merchant Energy is a provider of power and natural gas to the state of
California. During the latter half of 2000 and continuing into the first half of
2001, California experienced sharp increases in wholesale power prices and
natural gas prices due to energy shortages resulting, in part, from a
combination of unusually warm summer weather followed by high winter demand, low
gas storage levels, lower hydroelectric power generation and maintenance
downtime of significant generation facilities. As a result, the two major
California utilities, Southern California Edison and Pacific Gas & Electric,
defaulted on payments to creditors and accumulated substantial under-collections
from customers. This resulted in their credit ratings being downgraded in 2001
from investment grade to below investment grade, and in April 2001, Pacific Gas
and Electric filed for bankruptcy. During 2001, we recognized revenues from
Pacific Gas & Electric and Southern California Edison that we believe are
appropriate based on their improving financial condition. This resulted in our
recognition of income on a portion of these transactions during the fourth
quarter based on improved credit exposure to customers in the state.

35

Operating and other revenues consist of revenues from domestic and
international power generation facilities and investments, including our
management fee from Chaparral, coal operations, and revenues from EnCap and the
other financial services business of Merchant Energy. For the year ended
December 31, 2001, operating and other revenues were $77 million higher than the
same period in 2000. The increase resulted from higher management fees from
Chaparral, higher revenues from EnCap and our other financial services due to
growth in these businesses, and revenues from the CEBU power project, a
Philippine project in which we acquired an additional interest and began
consolidating during the first quarter of 2001. Offsetting the increase were
revenues recorded in 2000 on our West Georgia power generation facility that was
sold in the fourth quarter of 2000.

Operating expenses for the year ended December 31, 2001, were $450 million
higher than the same period in 2000. The increase was primarily a result of
merger-related costs and asset impairments associated with combining operations
with Coastal, and changes in our estimates of environmental remediation costs,
legal obligations and spare parts inventory usability. Also contributing to the
increase were higher operating expenses resulting from the expansion of our
operations in Europe, Mexico, Brazil, Singapore, our liquefied natural gas
business and the consolidation of the CEBU power project. The increase also
resulted from higher fuel costs at our refineries due to higher natural gas
prices. All increases were partially offset by lower operating expenses
resulting from the lease of our Corpus Christi refinery and related assets to
Valero in June 2001 and 2000 costs related to the West Georgia plant which was
sold in the fourth quarter of 2000.

Other income for the year ended December 31, 2001, was $142 million higher
than the same period in 2000. The increase was the result of marketing, agency
and technical services fees related to the development of the Macae power
project in Brazil, and higher equity earnings from Chaparral and our investment
in the Capital District Energy power facility resulting primarily from the
completion of power contract restructurings. These increases were partially
offset by lower earnings on an Argentine investment, gains from the sale of a
portion of our East Asia Power project, and the sale of our interest in a
Guatemala power project, all occurring in 2000. Also offsetting the increase was
lower earnings from the Javelina project due to reduced margins.

YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999

Trading and refining gross margin for the year ended December 31, 2000, was
$512 million higher than the same period in 1999. Trading margins increased due
to significant price volatility in natural gas, power, crude oil and refined
products markets that increased the value of our trading portfolio during 2000
versus 1999. Refining margins increased resulting from an increase in sales
volumes, primarily due to expansion at our Aruba refinery, increased prices on
refined products in 2000 and improved brokerage margins. Also contributing to
the increase was higher income from transactions originated in 2000.

Operating and other revenues for the year ended December 31, 2000, were
$222 million higher than the same period in 1999. The increase was due to asset
management fees earned from Chaparral, which began operations during the fourth
quarter of 1999, revenues on the West Georgia power project, a seasonal peaking
facility that began operating in June 2000, and the consolidation of a Brazilian
power project in the latter part of 1999. Revenues on our Manchief power
project, which began operating in July 2000 and EnCap's financial services
activities in 2000 also contributed to the increase.

Operating expenses for the year ended December 31, 2000, were $184 million
higher than the same period in 1999. The increase is due to higher general and
administrative expenses and project development costs relating to international
projects in 2000 as well as higher repair and maintenance expense and fuel costs
relating to increased volumes in our refining operations. Also contributing to
the increase were fuel costs relating to our West Georgia power project, higher
depreciation expense relating to our Rensselaer generating facility, which was
acquired in 1999, and operating costs on the Manchief generation facility. These
increases were partially offset by higher reimbursement in 2000 of general and
administrative costs relating to Chaparral, a 1999 charge to eliminate a
minority investor in Sonat's marketing joint venture following the Sonat merger,
and 1999 asset writedowns and charges to consolidate accounting policies with
those of Sonat following the merger.

36

Other income for the year ended December 31, 2000, was $118 million higher
than the same period in 1999. The increase was due to higher earnings from CE
Generation, a power project acquired in March 1999, the benefit realized from
the formation of our East Asia Power joint venture in March 2000, and a gain
from the sale of our interest in a Guatemala power generation facility. Also
contributing to the increase were increased earnings from Engage prior to the
termination of the joint venture and a gain recorded in 2000 from the sale of 49
percent of our Montreal paraxylene facility. These increases were partially
offset by lower equity earnings from investments in various international
projects, primarily our investment in East Asia Power in the Philippines.

PRODUCTION

Production's operating results are driven by a variety of factors including
its ability to locate and develop economic natural gas and oil reserves, extract
those reserves with minimal production costs, sell the products at attractive
prices, and operate at the lowest cost level possible. In 2002, Production
expects to continue an active onshore and offshore development drilling program
to capitalize on its land and seismic holdings. The estimated capital
expenditures for Production in 2002 are $1.7 billion. Production will continue
to pursue strategic acquisitions of production properties and the development of
coal seam projects subject to acceptable return hurdles.

Production engages in hedging activities on its natural gas and oil
production in order to stabilize 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. During 2001, approximately 80 percent of the
segment's overall production was hedged at fixed prices. Our hedging program is
intended to hedge approximately 75 percent of our anticipated current year
production, approximately 50 percent of our anticipated succeeding year
production and a lesser percentage thereafter. Production's hedge positions are
monitored and evaluated in an effort to achieve its earnings objectives and
reduce the risks associated with spot-market price volatility.

In December 2001, we announced the sale of natural gas and oil properties
in connection with our balance sheet enhancement plan. See a discussion of our
plan in Future Liquidity.

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

37

YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000

Operating revenues for the year ended December 31, 2001, were $661 million
higher than the same period in 2000. The increase was attributable to higher
volumes and higher realized prices for natural gas and higher volumes for oil,
condensate and liquids than 2000.

Transportation and net product costs for the year ended December 31, 2001,
were $19 million higher than the same period in 2000 primarily due to higher
transported volumes and costs incurred to meet minimum payments on pipeline
agreements.

Operating expenses for the year ended December 31, 2001, were $336 million
higher than the same period in 2000. The increase was due to full cost ceiling
test charges of $135 million on international properties incurred in the third
quarter of 2001, higher depletion expense in 2001 as a result of increased
production volumes combined with higher capitalized costs in the full cost pool,
merger-related costs and increased oilfield service costs in 2001. Also
contributing to the increase were higher severance and other production taxes in
2001, resulting from higher production volumes and higher gas prices.

YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999

Operating revenues for the year ended December 31, 2000, were $578 million
higher than the same period in 1999. The increase was due to increased volumes
and higher realized prices for natural gas and oil, condensate and liquids.

Transportation and net product costs for the year ended December 31, 2000,
were $31 million higher than the same period in 1999 primarily due to higher
transported volumes and costs incurred to meet minimum production quantities
under pipeline agreements.

Operating expenses for the year ended December 31, 2000, were $152 million
lower than the same period in 1999. The decrease was due to full cost ceiling
test charges of $352 million incurred in the first quarter of 1999, decreased
2000 labor costs as a result of an organizational restructuring following our
Sonat merger and 1999 charges to retain Sonat's seismic data in our production
operations as a result of the merger. These decreases were partially offset by
higher 2000 depletion rates, higher production taxes and higher production
costs.

FIELD SERVICES

Our Field Services segment provides a variety of services for the midstream
component of our operations, including gathering and treating of natural gas,
processing and fractionation of natural gas, natural gas liquids and natural gas
derivative products, such as butane, ethane, and propane. Field Services also
serves as the general partner of El Paso Energy Partners, L.P.

Field Services attempts to balance its earnings from its operating
activities through a combination of fixed-fee based and market-based services. A
majority of Field Services gathering and treating operations earn margins from
fixed-fee-based services. However, some of its 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.

Processing and fractionation 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 processing or fractionation service. 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, Field Services may have more sensitivity to price changes
during periods when natural gas and natural gas liquids prices are volatile.

As the general partner of El Paso Energy Partners, we perform the
partnership's daily operations and provide the strategic direction and performs
all of its administrative and operational activities. We were reimbursed $34
million for these services during 2001. In addition, we recognized $47 million
in equity

38

earnings during 2001 from El Paso Energy Partners related to our general
partner, common and preferred units ownership interests.

We often enter into transactions with El Paso Energy Partners and its
affiliates to acquire or sell assets, and specific procedures have been
instituted for evaluating these transactions to ensure that they are in the best
interests of us and the partnership and are based on fair values. These
procedures require our Board of Directors to evaluate and approve, as
appropriate, transactions with the partnership. In addition, a special committee
comprised of the general partner's independent directors evaluates the
transactions on the partnership's behalf. This typically involves engaging an
independent financial advisor and independent legal counsel to assist with the
evaluation and to opine on its fairness.

During 2001, we sold several assets to the partnership, including
transportation and fractionation assets we acquired from PG&E and an investment
in Deepwater Holdings, an entity that owned several pipeline gathering systems
in the Gulf of Mexico. During 2001, the partnership also acquired the rights to
the Chaco processing facility from its previous owners. We currently lease this
facility under an agreement that expires in October 2002. In 2000, we sold an
intrastate pipeline system in Alabama and storage facilities in Mississippi to
the partnership. Each of these transactions was evaluated and approved, as
appropriate, by our Board of Directors and by the general partner's committee of
independent directors. Proceeds from our sales of assets to the partnership were
$344 million in 2001 and $197 million in 2000. The 2000 proceeds include $170
million of Series B preference units issued to us in exchange for the storage
facilities. We recognized an after-tax gain on these sales of $13 million in
2001. No gain or loss was recognized on the sales in 2000.

In February 2002, as part of the balance sheet enhancement plan, we
announced the sale of additional midstream assets to El Paso Energy Partners for
total consideration of $750 million. The primary assets to be sold include:

- 9,400 miles of intrastate transmission pipelines;

- 1,300 miles of gathering systems in the Permian Basin; and

- a 42.3 percent non-operating interest in the Indian Basin gas processing
and treating plant and associated gathering lines.

Proceeds will be approximately $554 million in cash and approximately $6
million in El Paso Energy Partners common units, along with the partnership's
interest in the Prince tension leg platform and a nine percent overriding
royalty interest that the partnership holds in the Prince field that have a
combined fair value estimated at $190 million. We expect to complete the
transaction in March 2002. The sale of these assets is contingent upon receiving
customary regulatory approvals and execution of definitive agreements. We do not
anticipate a material gain or loss on these transactions.

In addition to Field Services, several of our other segments also enter
into transactions with El Paso Energy Partners in the normal course of business
for the sale of natural gas and for services such as transportation and
fractionation, storage, processing and other types of operational services.
These transactions are based on similar terms as transactions with
non-affiliates.

39

Field Services' operating results and an analysis of those results are as
follows for each of the three years ended December 31, 2001:

YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000

Total gross margin for the year ended December 31, 2001, was $124 million
higher than the same period in 2000. The increase was primarily due to higher
volumes as a result of our acquisition of PG&E's Texas Midstream operations in
December 2000. Volumes also increased as a result of our acquisition of the
Indian Basin processing plant in the second quarter of 2000 combined with an
increase in Indian Basin's processing capacity in 2001. The increase in margin
was partially offset by higher processing costs associated with the new
processing arrangement with El Paso Energy Partners at the Chaco processing
facility in the fourth quarter of 2001. For the year ended December 31, 2001,
average gathering, treating and processing rates were lower compared to 2000 due
primarily to the different mix of assets and contract terms resulting from the
acquisition of PG&E's Texas Midstream operations.

Operating expenses for the year ended December 31, 2001, were $162 million
higher than the same period in 2000. The increase was due to higher operating,
depreciation and other expenses primarily resulting from the addition of PG&E's
Texas Midstream operations, as well as merger-related costs related to FTC
ordered sales of assets owned by El Paso Energy Partners, merger-related
employee severance and relocation expenses and other merger charges and changes
in our estimated environmental remediation liabilities in 2001.

Other income for the year ended December 31, 2001, was $19 million higher
than the same period in 2000. The increase was primarily due to increased
earnings from El Paso Energy Partners and a gain on the sale of our interest in
Deepwater Holdings in October 2001, partially offset by lower 2001 equity
earnings from Deepwater Holdings as a result of the sale. The increase was also
partially offset by equity investment losses from our Mobile Bay and Aux Sable
liquids processing facilities due to low natural gas liquids prices and a 2000
gain on the sale of our Colorado dry gathering system.

YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999

Total gross margin for the year ended December 31, 2000, was $148 million
higher than the same period in 1999. The increase was a result of higher
gathering and treating margins due to higher average gathering rates,
predominantly in the San Juan Basin, which are substantially indexed to natural
gas prices and higher average condensate prices. Our higher 2000 margin was
partially offset by the sale of El Paso Intrastate Alabama, a gathering system
in the coal-bed methane producing regions of Alabama, to El Paso Energy Partners
in March 2000. Processing margins were also higher due to higher natural gas and
natural gas liquids prices in 2000, our acquisition of the Indian Basin
processing plant in the second quarter of 2000 and higher

40

processing volumes due to the acquisition of gas processing and fractionation
facilities located in Louisiana at the end of 1999.

Operating expenses for the year ended December 31, 2000, were $56 million
higher than the same period in 1999 due to higher depreciation and amortization
from assets transferred from El Paso Natural Gas to Field Services following a
FERC order, the impairment of the Needle Mountain LNG processing facility in
2000 and higher expenses on Coastal's gas processing plants as a result of the
acquisition of processing and fractionation assets located in Louisiana in 1999.
The increase was partially offset by the impairment of gathering assets in 1999,
lower costs for labor and benefits and cost recoveries from managed facilities.

Other income for the year ended December 31, 2000, was $8 million lower
than the same period in 1999. The decrease was primarily due to net gains in
1999 from the sale of our interest in the Viosca Knoll gathering system to El
Paso Energy Partners in June 1999, as well as lower equity earnings in 2000
following the sale of our interest in Viosca Knoll.

CORPORATE AND OTHER EXPENSES, NET

Our Corporate and Other operations includes our general and administrative
activities, 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 start-up business. Our
current business strategy involves primarily the development of wholesale
metropolitan transport services, primarily in Texas. At December 31, 2001, our
investment in the telecommunications business was $555 million.

YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000

Corporate and Other expenses for the year ended December 31, 2001, were
$1,372 million higher than the same period in 2000. The increase was primarily a
result of merger-related charges in connection with our January 2001 merger with
Coastal, costs associated with increased estimates of environmental remediation
costs, legal obligations and usability of spare parts inventories and lower
margins due to the sale of substantially all of our retail gas stations in 2001.
Also contributing to our higher costs were operating losses associated with our
telecommunications business during 2001 which were approximately $72 million.

YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999

Corporate and Other expenses for the year ended December 31, 2000, were
$230 million lower than the same period in 1999. The decrease was primarily due
to costs related to our merger with Sonat in 1999, partially offset by costs
incurred in 2000 related to our merger with Coastal. Also offsetting the
decrease were increased funding commitments to the El Paso Energy Foundation in
2000.

INTEREST AND DEBT EXPENSE

YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000

Interest and debt expense for the year ended December 31, 2001, was $115
million higher than the same period in 2000. The increase was a result of higher
long-term and short-term borrowings and lower capitalized interest in 2001 for
ongoing capital projects, investment programs and operating requirements.

YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999

Interest and debt expense for the year ended December 31, 2000, was $264
million higher than the same period in 1999 primarily due to increased
borrowings under a combination of short-term and long-term programs to fund
capital expenditures, acquisitions and other investing activities, higher
average interest rates in 2000 and increased interest expense on borrowings from
Chaparral in 2000. This increase was partially offset by an increase in interest
capitalized.

41

MINORITY INTEREST

YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000

Minority interest for the year ended December 31, 2001, was $13 million
higher than the same period in 2000. Higher balances in minority interests as a
result of the issuance of additional preferred interests in Clydesdale
Associates L.P. and Topaz Investors L.L.C. (part of our Gemstone transaction)
and a full year of costs on Clydesdale and El Paso Energy Capital Trust IV, were
significantly offset by lower interest rates. Clydesdale and Capital Trust IV
were formed in May 2000.

YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999

Minority interest for the year ended December 31, 2000, was $111 million
higher than the same period in 1999 primarily due to a full year of costs
associated with the preferred interest in Trinity River Associates, L.L.C.,
formed in June 1999. Also contributing to the increase were costs associated
with a preferred interest in Clydesdale Associates, L.P. and distributions
associated with preferred securities of El Paso Energy Capital Trust IV, both of
which were formed in May 2000.

For a further discussion of our borrowing and other financing activities
during the period, see Securities of Subsidiaries and Minority Interests.

INCOME TAX EXPENSE

Income tax expense for the year ended December 31, 2001, was $182 million,
resulting in an effective tax rate of 73 percent. Of this amount, $115 million
related to non-deductible merger charges and changes in our estimate of
additional tax liabilities. The majority of these estimated additional
liabilities were paid in 2001 and are being contested by us. The effective tax
rate excluding these charges was 27 percent. For the years ended December 31,
2000 and 1999, income tax expense was $538 million and $93 million, resulting in
effective tax rates of 30 percent and 27 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;

- utilization of deferred credits on loss carryovers;

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

- non-conventional fuel tax credits; and

- depreciation, depletion and amortization.

For a reconciliation of the statutory rate of 35 percent to the effective
rates, see Item 8, Financial Statements and Supplementary Data, Note 6.

LIQUIDITY AND CAPITAL RESOURCES

GENERAL

During the year ended December 31, 2001, we generated over $9 billion of
cash through a combination of cash from operations, the issuance of long-term
debt and other financing obligations, and the issuance of equity. This cash was
used for capital expenditures, acquisitions, other investing activities,
long-term debt repayments, dividends and other financing activities. The
following is a further discussion of our operating, investing and financing cash
flows for the year ended December 31, 2001.

42

CASH FROM OPERATING ACTIVITIES

Net cash provided by our operating activities was $4.1 billion for the year
ended December 31, 2001, compared to $99 million for 2000. The increase was
primarily due to growth in cash-based earnings during 2001, resulting from
higher realized prices and volumes in our Production segment, along with
physical liquidations of net derivative trading positions related to our price
risk management activities. Partially offsetting these increases were cash
payments in 2001 for charges related to the merger with Coastal and higher
interest payments.

CASH FROM INVESTING ACTIVITIES

Net cash used in our investing activities was $5.0 billion for the year
ended December 31, 2001. Our investing activities principally consisted of
additions to property, plant, and equipment, including expenditures for
developmental drilling and expansion and construction projects. We had additions
to joint ventures and investments in unconsolidated affiliates, primarily
related to our investment in Gemstone along with our investments in five
coal-fired power plants and international power companies located in Brazil and
China. Our additions to investments also consisted of short-term notes from
unconsolidated affiliates. These notes are primarily related to a subsidiary of
Chaparral, and a significant portion of these notes were repaid during 2001. In
August 2001, we completed our acquisition of Velvet Exploration Ltd., a Canadian
exploration and development company, with properties located in the Foothills
and Deep Basin areas of western Alberta Province, Canada, at a cost of
approximately $230 million. Cash inflows from investment-related activities
included proceeds from the sale of our Manchief power facility to Chaparral, our
Midwestern Gas Transmission system, our Gulfstream pipeline project, and other
property, plant and equipment assets, along with proceeds from the sale of
substantially all of our retail gas stations in 2001. Additional cash inflows
included the sale of our interests in the Empire State and Iroquois pipeline
systems and the liquidation of a health management investment portfolio.

CASH FROM FINANCING ACTIVITIES

Net cash provided by our financing activities was $1.3 billion for the year
ended December 31, 2001. Cash provided from our financing activities included
the issuance of long-term debt, other financing obligations and notes to
unconsolidated affiliates primarily related to Gemstone. We also had issuances
of common stock as a result of an equity offering in December 2001, and the
exercise of employee stock options, as well as the issuance of preferred
securities related to one of our consolidated subsidiaries associated with
Gemstone. During 2001, we repaid short-term borrowings, other financing
obligations, retired long-term debt and paid dividends. We also repaid notes to
unconsolidated affiliates primarily related to Chaparral and Gemstone.

43

Our significant borrowing and repayment activities during 2001 are
presented below. These amounts do not include borrowings or repayments on our
short-term financing instruments with an original maturity of three months or
less, including our commercial paper programs and short-term credit facilities.

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

(1) Net proceeds were primarily used to repay short-term and long-term
borrowings and for general corporate purposes.

(2) These debentures are convertible into 8,456,589 shares of our common stock
which is based on a conversion rate of 4.7872 shares per $1,000 principal
amount at maturity. This rate was equivalent to an initial conversion price
of $94.604 per share of our common stock.

(3) In March 2001, we issued E550 million (approximately $510 million) of euro
notes at 5.75% due 2006. To reduce our exposure to foreign currency risk, we
entered into a swap transaction exchanging the euro note for a $510 million
U.S. dollar denominated obligation with a fixed interest rate of 6.61% for
the five-year term of the note.

(4) The loan is collateralized by the lease payments from Valero for our Corpus
Christi refinery and related assets. The interest rate on the loan is the
London Interbank Offered Rate (LIBOR) plus 1.425%. To reduce our exposure to
interest rate risk, we entered into a swap transaction with a notional
amount of $240 million exchanging LIBOR for a fixed rate of 3.07%. This
transaction results in the payment of a fixed rate of 4.495% until the swap
terminates in June 2003.

In December 2001, we issued 20.3 million shares of our common stock at a
price of $42.50 per share. Net proceeds of approximately $863 million were used
to retire short-term debt and for general corporate purposes.

Credit Facilities and Available Capacity

We use commercial paper programs to manage our short-term cash
requirements. Under our programs we can borrow up to $3 billion through a
combination of individual corporate, TGP and EPNG commercial paper programs of
$1 billion each.

We maintain a 3-year, $1 billion, revolving credit and competitive advance
facility under which we can conduct short-term borrowings and other commercial
credit transactions. This facility expires in 2003 and El Paso CGP (formerly
Coastal), EPNG and TGP are designated borrowers under the facility. In June
2001, we replaced an existing 364-day revolving credit facility with a renewable
$3 billion, 364-day revolving credit and competitive advance facility. EPNG and
TGP are also designated borrowers under this new facility. The interest rate on
these facilities varies and was based on LIBOR plus 50 basis points at December
31, 2001. No amounts were outstanding under these facilities at December 31,
2001.

44

In connection with our acquisition of PG&E's Texas Midstream operations in
December 2000, we established a $700 million short-term credit facility, under
which $455 million was outstanding on December 31, 2000. In February 2001, we
borrowed an additional $245 million under the facility. In two separate payments
in March and June 2001, we repaid the outstanding balance of the credit
facility, and the facility was terminated.

We also supplement our commercial paper program with other smaller
short-term credit facilities, some of which were used by Coastal prior to our
merger and which were terminated during the year.

In April 2001, we filed a shelf registration statement with the Securities
and Exchange Commission to sell, from time to time, up to a total of $3 billion
in debt securities, preferred and common stock, medium term notes, or trust
securities. At December 31, 2001, we had approximately $920 million remaining
from this shelf registration statement under which we issued additional
securities in January 2002.

As of December 31, 2001, TGP had $200 million, and SNG had $100 million
under shelf registration statements on file with the Securities and Exchange
Commission.

The availability of borrowings under our credit and borrowing agreements is
subject to specified conditions, which we believe we currently meet. These
conditions include compliance with the financial covenants and ratios required
by such agreements, absence of default under such agreements, and continued
accuracy of the representations and warranties contained in such agreements. Our
senior unsecured debt issues have been given investment grade ratings by
Standard & Poor's and Moody's.

2002 Activities

In January 2002, we increased our shelf registration statement from $920
million to $1.10 billion and issued $1.10 billion aggregate principal amount of
7.75% medium term notes due 2032. Net proceeds of approximately $1.08 billion,
net of issuance costs, were used to repay short-term borrowings and for general
corporate purposes. This issuance used up the remaining capacity on our previous
shelf registration statement. In February 2002, we filed a new shelf
registration statement with the Securities and Exchange Commission that allows
us to issue up to $3 billion. Under this registration statement we can issue a
combination of debt, equity and other instruments, including trust preferred
securities of El Paso Capital Trust II and El Paso Capital Trust III, trusts
wholly owned by us. If we issue securities from these trusts, we will be
required to issue full and unconditional guarantees on these securities.

Also in January 2002, we retired $100 million aggregate principal amount
7.85% notes and $215 million aggregate principal amount 7.75% notes. In March
2002, we retired $400 million of floating rate notes.

In January 2002, SNG filed a shelf registration statement increasing the
amount of debt it can issue from $100 million to $300 million. In February 2002,
SNG issued $300 million aggregate principal amount of 8.0% notes due 2032. Net
proceeds of approximately $297 million, net of issuance costs, were used for
general corporate purposes. This issuance used the remaining capacity on SNG's
shelf registration statement.

Future Liquidity

We rely on cash generated from our internal operations as our primary
source of liquidity. We supplement our internally generated cash through our
commercial paper programs, available credit facilities, bank financings, the
issuance of long-term debt, trust securities and equity securities. From time to
time, we also use structured financial products. We expect that our future
funding for working capital needs, capital expenditures, acquisitions, other
investing activities, long-term debt repayments, dividends and other financing
activities will continue to be provided from these sources.

Our cash from internal operations may change in the future due to a number
of factors, some of which we cannot control, including the price we will receive
for the products we sell and services we provide, the demand for our products
and services, margin requirements resulting from significant increases or
decreases in commodity prices, operational risks, and other factors. Our ability
to draw upon our available credit facilities will be dependent upon our ability
to comply with the conditions and requirements of our credit facilities, all of

45

which we believe we currently meet. Funding from the capital markets for
commercial paper, long-term debt or equity or other structured financial
products may be impacted by lack of liquidity for our industry segment, a change
in our credit rating or changes in market conditions. For a further discussion
of our business risks, see Risk Factors.

In December 2001, we announced a plan to strengthen our capital structure
and enhance our liquidity in response to the changes in market conditions. In
January 2002, our Board of Directors approved this plan. The key elements of our
plan are to raise approximately $2.25 billion or more in cash from sales of
assets, reduce net capital spending to approximately $3.1 billion in 2002,
increase our common equity through a combination of earnings and equity
financings, and eliminate or renegotiate the rating triggers in our Chaparral
and Gemstone investments and on our Trinity River and Clydesdale minority
interest financing transactions. The goal of the plan is to reduce our debt to
total capital ratio from 54.9 percent at December 31, 2001, to approximately 50
percent by the end of 2002. In December 2001, we issued 20.3 million shares of
our common stock generating $863 million. We also expect to have firm sales
agreements completed for more than half of the asset sales by the end of the
first quarter 2002, the first step of which we accomplished in February 2002
with the announcement of the sale of midstream assets to El Paso Energy Partners
for total consideration of approximately $750 million. Additional assets that
have been evaluated and may possibly be included in our asset sale program
include approximately $1 billion in exploration and production properties,
various refining and chemical assets, coal mining assets and power facilities.
The actual assets sold will depend on a number of factors including short-term
market developments, the availability of qualified buyers and acceptability of
any offers received. In addition, potential losses or write-downs in the value
of these assets could occur. Any proposed offer will be evaluated and approved
by a Committee of our Board of Directors prior to its completion. We intend to
commence exchange offers to the existing note holders of Chaparral and Gemstone
to eliminate the rating triggers and replace them with securities that have
direct financial guarantees from us, and expect to complete these exchange
offers in the second quarter of 2002. We also expect to commence our amendment
process on the Trinity River and Clydesdale transactions early in 2002. For a
discussion of the risks that may affect our balance sheet enhancement plan, see
Risk Factors.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

In the course of our business activities, we enter into a variety of
contractual obligations and commercial commitments. Some of these result in
direct obligations that are reflected in our balance sheet while others are
commitments, some firm and some based on uncertainties, that are not reflected
in our underlying financial statements.

CONTRACTUAL CASH OBLIGATIONS

The following table summarizes our contractual cash obligations by payment
due date. Each of these obligations is discussed in further detail below (in
millions):

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

(1) Our long-term cash obligations exclude $75 million in unamortized debt
discounts as of December 31, 2001.

(2) The maturity schedule for these instruments is based on the expiration
period of the underlying agreements.

46

Short-Term Cash Obligations

Our short-term contractual cash obligations as of December 31, 2001, were
as follows (in millions):

Commercial paper............................................ $1,265
Short-term credit facilities................................ 111
Notes payable............................................... 139
------
$1,515
======

We can borrow up to $3 billion under a combination of Corporate, TGP and
EPNG commercial paper programs of $1 billion each. At December 31, 2001, the
weighted average rate on commercial paper outstanding was 3.2%.

We also have short-term notes payable to banks of $139 million and short
term credit facilities of $111 million.

Long-Term Cash Obligations

Our long-term cash obligations as of December 31, 2001, were as follows (in
millions):

Unsecured notes and debentures.............................. $12,448
Convertible debentures...................................... 827
Collateralized notes........................................ 240
FELINE PRIDES(sm)........................................... 460
Other financing obligations................................. 715
-------
$14,690
=======

Our unsecured notes and debentures consists of third-party debt issued in
the normal course of our business activities. These notes are secured by our
general credit and that of our subsidiaries. The interest rates on these
instruments range from 5.75% to 10.75%, and maturity dates range from 2002 to
2037.

Our zero coupon convertible debentures have a maturity value of $1.8
billion, are due 2021 and have a yield to maturity of 4%. These debentures are
convertible into 8,456,589 shares of our common stock, which is based on a
conversion rate of 4.7872 shares per $1,000 principal amount at maturity. This
rate is equal to a conversion price of $94.604 per share of our common stock.

In October 2001, we borrowed $240 million due 2004 under a loan agreement.
The loan is collateralized by the lease payments from Valero under their lease
of our Corpus Christi refinery.

In 1999, we issued a total of 18,400,000 FELINE PRIDES(sm) consisting of
17,000,000 Income PRIDES with a stated value of $25 and 1,400,000 Growth PRIDES
with a stated value of $25. The Income PRIDES consist of a unit comprised of a
Senior Debenture and a purchase contract under which the holder is obligated to
purchase from us by no later than August 16, 2002 for $25 (the stated price) a
number of shares of our common stock. The Growth PRIDES consist of a unit
comprised of a purchase contract under which the holder is obligated to purchase
from us by no later than August 16, 2002 for $25 (the stated price) a number of
shares of our common stock and a 2.5% undivided beneficial interest in a
three-year Treasury security having a principal amount at maturity equal to
$1,000. Under the terms of the purchase contract in effect prior to our merger
with Coastal, the number of shares of common stock the holder of a PRIDE
received varied between 0.5384 and 0.6568 shares, depending on the price of
Coastal's common stock.

As a result of our merger with Coastal, and under the terms of the purchase
contract, the number of shares the holder of a PRIDE is entitled and required to
receive upon settlement became fixed at 0.6622 shares of El Paso common stock.
This will result in the issuance of approximately 12.2 million shares of El Paso
common stock.

Our other financing obligations consist of crude oil prepayments received
from third parties in exchange for our agreement to deliver a fixed quantity of
crude oil to a specified delivery point in the future and a

47

production payment received in exchange for delivery of a fixed quantity of
natural gas from our future production. The agreements, by their terms, can only
be settled through the delivery of the commodity. We have entered into commodity
swaps to effectively lock-in the value of these commitments to the third party
upon delivery of the commodity. It is our intention to negotiate a cash
settlement of the crude oil prepayments on or prior to the delivery dates under
the agreements. We will continue to deliver natural gas under the production
payment agreement according to its terms, but consider these agreements to be
financing arrangements. The carrying cost of the prepayments and the production
payment are recognized as interest expense in our income statement.

Obligations to Affiliates

Our obligations to unconsolidated affiliates as of December 31, 2001, were
as follows (in millions):

Gemstone.................................................... $346
Chaparral................................................... 458
Other....................................................... 68
----
$872
====

Gemstone. Our obligation to Gemstone consists of $346 million of debt
securities which are payable on demand and carry a fixed interest rate of 5.25%.

Chaparral. Our obligation to Chaparral consists of $169 million of debt
securities and $289 million of contingent interest promissory notes. The debt
securities are payable on demand and carry a fixed interest rate of 7.443%. The
contingent interest promissory notes carry a variable interest rate not to
exceed 12.75% and mature in 2019 through 2021.

Other. Our other obligations to affiliates include a line of credit with
an unconsolidated affiliate for $57 million, which had an interest rate of 5.27%
and miscellaneous notes with several unconsolidated affiliates for $11 million
which had an average interest rate of 2.45% at December 31, 2001.

Securities of Subsidiaries and Minority Interests

Over the past three years, we have entered into a number of transactions to
finance our consolidated subsidiaries. In most cases, these have been
accomplished through the sale of preferred interests in these entities, or
through structured financial transactions that are collateralized by the assets
of these subsidiaries. Total amounts outstanding under these programs at
December 31, 2001, were as follows (in millions):

Consolidated trusts(1)...................................... $ 925
Trinity River............................................... 980
Clydesdale.................................................. 1,000
Preferred stock of subsidiaries............................. 465
Gemstone.................................................... 300
Consolidated partnership.................................... 285
Other....................................................... 58
------
$4,013
======

Lines of Credit

We have a commitment to loan Mesquite, a subsidiary of Chaparral and our
affiliate, up to $725 million. As of December 31, 2001, Mesquite had borrowed
$552 million under this facility, resulting in undrawn commitment of $173
million. The interest rate on the facility is based on LIBOR plus a margin, and
was 2.64% at December 31, 2001.

Letters of Credit

We enter into letters of credit in the ordinary course of our operating
activities. As of December 31, 2001, we had outstanding letters of credit of
$465 million related to our marketing and trading activities, our domestic power
development and other operating activities.

Guarantees

Our involvement in joint ventures and project level construction and
finance results in the issuance of financial and non-financial guarantees in our
business activities. We also guarantee performance and

51

contractual commitments of companies within our consolidated group. There are
various events and circumstances that may require us to perform under our
guarantees, including:

- non-payment by the guaranteed party;

- non-compliance with the covenants of the transactions by the guaranteed
party;

- non-compliance by us with the provision of guarantees; and

- cross-acceleration with other transactions.

As of December 31, 2001, we had approximately $1.5 billion of guarantees in
connection with our international development and operating activities not
consolidated on our balance sheet and approximately $1.9 billion of guarantees
in connection with domestic development and operating activities not
consolidated on our balance sheet. Of these amounts, approximately $950 million
relates to our Gemstone investment and $1.0 billion relates to our Chaparral
investment.

Residual Value Guarantees

As of December 31, 2001, we have $738 million of residual value guarantees
supporting our operating leases. These leases expire in 2002 and 2006.

Other Commercial Commitments

From May to October 2001, we entered into agreements to time-charter four
separate ships to secure transportation for our developing liquefied natural gas
business. The agreements provide for deliveries of vessels between 2003 and
2005. Each time-charter has a 20-year term commencing when the vessels are
delivered with the possibility of two 5-year extensions. The total commitment
under the four time charter agreements is $1.8 billion.

CONTINGENCIES

For a discussion of our contingencies, see Item 8, Financial Statements and
Supplementary Data, Note 14, incorporated herein by reference.

CRITICAL ACCOUNTING POLICIES

The selection and application of accounting policies is an important
process that has developed as our business activities have evolved and as the
accounting rules have developed. Accounting rules generally do not involve a
selection among alternatives, but involve an implementation and interpretation
of existing rules and the use of judgment to the specific set of circumstances
existing in our business. We make every effort to properly comply with all
applicable rules on or before their adoption, and we believe the proper
implementation and consistent application of the accounting rules is critical.
However, not all situations are specifically addressed in the accounting
literature. In these cases, we must use our best judgment to adopt a policy for
accounting for these situations. We accomplish this by analogizing to similar
situations and the accounting guidance governing them, and often consult with
our independent accountants about the appropriate interpretation and application
of these policies. Our critical accounting policies include policies that are
related to specific business units, such as price risk management activities and
accounting for oil and gas activities, as well as broad policies that include
accounting for impairments and contingencies, consolidations and business
combinations. Each of these areas involves complex situations and a high degree
of judgment either in the application and interpretation of existing literature
or in the development of estimates that impact our financial statements.

Critical Accounting Policies

Price Risk Management Activities. We account for price risk management
activities based upon the fair value accounting methods prescribed by Emerging
Issues Task Force (EITF) Issue 98-10 and SFAS No. 133. EITF Issue 98-10 governs
the accounting for our energy trading activities while SFAS No. 133 prescribes
our

52

accounting for hedging activities and other derivatives. Both sets of accounting
rules require that we determine the fair value of the instruments we use in
these business activities and reflect them in our balance sheet at their fair
values. However, changes in the fair value from period to period for our energy
trading derivatives and fair value hedges are recorded in our income statement
each period while changes in the fair value of our cash flow hedges are
generally recognized in our income statement when the hedge is settled. Over
time, these methods will derive similar results. However, from period to period,
income under these methods can differ significantly.

One of the primary factors that can have an impact on our results each
period is the price assumptions used to value our energy trading derivatives and
fair value hedges. Many of these instruments have quoted market prices. However,
we are required to use internal valuation techniques or models, particularly in
our energy trading activities, to estimate the fair value of instruments that
are not traded on an active exchange or that have terms that extend beyond the
time period for which exchange-based quotes are available. These modeling
techniques require us to estimate future prices, price correlation, interest
rates and market volatility and liquidity. Our estimates also reflect the
potential impact of liquidating our position in an orderly manner over a
reasonable period of time under present market conditions, modeling risk, credit
risk of our counterparties and operational risk. The amounts we report in our
financial statements change as these estimates are revised to reflect actual
results, changes in market conditions or other factors, many of which are beyond
our control.

Another factor that can impact our results each period is our ability to
estimate the level of correlation between future changes in the fair value of
the hedge instrument and the transaction being hedged, both at the inception and
on an ongoing basis. This is complicated since energy commodity prices, the
primary risk we hedge, have quality and locational differences that can be
difficult to hedge effectively. The factors underlying our estimates of fair
value and our assessment of correlation of our hedging derivatives are impacted
by actual results and changes in conditions that affect these factors, many of
which are beyond our control.

Asset Impairments. The asset impairment accounting rules require us to
determine if an event has occurred indicating that a long-lived asset may be
impaired. In some cases, these events are clear. However, in many cases, a
clearly identifiable triggering event does not occur. Rather, a series of
individually insignificant events occur over a period of time leading to an
indication that an asset may be impaired. This can be further complicated where
we have investments in foreign countries or where we have projects where we are
not the operator. Events can occur that may not be known until a later date from
their occurrence. We continually monitor our businesses and the market and
business environments and make judgments and assessments about whether a
triggering event has occurred. If an event occurs, we make an estimate of our
future cash flows from these assets to determine if the asset is impaired. For
investments, we evaluate whether events and possible outcomes indicate that a
decline in the value of our investment that is other than temporary has
occurred, which also generally involves an assessment of project level cash
flows. These cash flow estimates require 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 estimates of impairment and can result in
additional charges. In addition, further changes in the economic and business
environment can impact our original and ongoing assessments of potential
impairment.

Accounting for Reserves. Our accounting for reserves policies cover a wide
variety of business activities, including reserves for potentially uncollectible
receivables, rate matters and legal and environmental exposures. We accrue these
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. Our estimates for these liabilities are based on currently available
facts and our estimates of the ultimate outcome or resolution of the liability
in the future. 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 the outcome or expectations based on the facts surrounding each
exposure.

Accounting for Natural Gas and Oil Producing Activities. We use the
full-cost method of accounting for our natural gas and oil producing activities.
Under this accounting method, we capitalize substantially all of the costs
incurred in connection with the exploration, acquisition and development of
natural gas and oil

53

reserves in full cost pools maintained by geographic area, regardless of whether
reserves are actually located. This method differs from the successful efforts
method of accounting for these activities. The primary difference between these
two methods is the treatment of exploratory dry hole costs, which are
exploration, acquisition and development costs on wells that do not yield
measurable reserves. Under the successful efforts method, these costs are
generally expensed when the determination is made that measurable reserves will
not be added. As a result, our financial statements will differ from companies
that apply the successful efforts method since we will generally reflect a
higher level of capitalized costs as well as a higher depletion rate.

Under the full cost accounting method, we conduct quarterly impairment
tests of our capitalized costs in each of our cost pools based on an assessment
of discounted cash flows. This test is referred to as a ceiling test. The two
primary factors impacting this test are reserve levels and current prices. In
addition, the prices we use in this assessment reflect the impact of our hedging
programs. Our risks related to this test are changing estimates of natural gas
and oil reserves and a decline in prices. The process of estimating natural gas
and oil reserves is very complex, requiring significant decisions in the
evaluation of all available geological, geophysical, engineering and economic
data. 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. The 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 continued decline in commodity prices will impact the results of
our ceiling test.

Accounting for Business Combinations. During the past three years, we have
completed several significant business combination transactions. In the future,
we may continue to grow our business through business combinations. Prior to the
issuance of SFAS No. 141, Business Combinations, in 2001, we applied the
guidance provided by Accounting Principles Board Opinion (APB) No. 16, and its
interpretations, as well as various other authoritative literature and
interpretations that address issues encountered in accounting for business
combinations. We accounted for our past combinations using both the purchase and
pooling of interests methods as was required prior to the issuance of SFAS No.
141, which only allows the use of the purchase method. The accounting for
business combinations, whether by the purchase or pooling of interests method,
is complicated and involves the use of significant judgment.

Under the purchase method of accounting, a business combination is
accounted for at a purchase price based upon the fair value of the consideration
given, whether it is in the form of cash, assets, stock or the assumption of
liabilities. The assets and liabilities acquired are measured at their fair
values, and the purchase price is allocated to the assets and liabilities based
upon these fair values. Determining the fair values of the assets and
liabilities acquired involves the use of judgment, since the majority of the
assets and liabilities acquired do not have fair values that are readily
determinable. Different techniques may be used to determine fair values,
including market prices, where available, appraisals, comparisons to
transactions for similar assets and liabilities and present value of estimated
future cash flows, among others. Since these estimates involve the use of
significant judgment, they can change as new information becomes available.

Under the pooling of interests method of accounting, a business combination
is accounted for using the historical cost of the entities involved in the
combination. The rules for the pooling of interests method of accounting are
highly complex, and involve the application of interpretations that have evolved
over the years since the original issuance of APB No. 16. Consequently, our
accounting for business combinations under this method requires us to apply the
existing accounting literature and interpretations to the specific situations
encountered in each transaction. As a result, there is a risk that our judgments
and interpretations could be viewed differently by others. In addition, even
though our Coastal and Sonat mergers occurred prior to the effective dates of
SFAS No. 141, we continue to take measures to ensure that these mergers continue
to qualify under the pooling rules. If we were unable to account for our Coastal
and Sonat mergers as poolings of interests, our financial statements would be
materially different.

54

Principles of Consolidation. We currently have interests in joint ventures,
equity investors and financing arrangements that, based on existing accounting
guidance precludes us from consolidating these entities. In December 2001, Enron
Corp., one of the largest companies in the energy industry, declared bankruptcy
in what has been viewed as one of the largest bankruptcies in history. In the
wake of this event, accounting standard setters, including the Securities and
Exchange Commission, are evaluating the existing accounting and disclosure rules
and requirements. One area that has received a high level of scrutiny is the
accounting rules related to consolidations, specifically those that address
special-purpose entities. Standard setting bodies and regulators are currently
evaluating the consolidation rules to determine whether the existing accounting
framework should change. In the future, there is risk that existing standards
will change, particularly in light of the events of 2001, and that these changes
could result in the consolidation in our financial statements of entities that
we do not currently consolidate.

For further details on these and our other significant accounting policies,
and the estimates, assumptions and judgments we use in applying these policies,
see Item 8, Financial Statements and Supplementary Data, Note 1.

New Accounting Pronouncements Issued But not Yet Adopted

Business Combinations. In July 2001, the Financial Accounting Standards
Board (FASB) issued SFAS No. 141, Business Combinations. This Statement requires
that all transactions that fit the definition of a business combination be
accounted for using the purchase method and prohibits the use of the pooling of
interests method for all business combinations initiated after June 30, 2001.
This Statement also establishes specific criteria for the recognition of
intangible assets separately from goodwill and requires unallocated negative
goodwill to be written off at the acquisition date as an extraordinary item. The
accounting for any business combinations we undertake in the future will be
impacted by this standard. The Statement also requires, upon adoption, that we
write off to income any negative goodwill recognized on business combinations
for which the acquisition date was before July 1, 2001, as the effect of a
change in accounting principle. We do not expect the negative goodwill
provisions of this pronouncement will have a material effect on our financial
statements.

Goodwill and Other Intangible Assets. In July 2001, the FASB issued SFAS
No. 142, Goodwill and Other Intangible Assets. This Statement requires that
goodwill no longer be amortized but periodically tested for impairment at least
on an annual basis. An intangible asset with an indefinite useful life can no
longer be amortized until its useful life becomes determinable. This Statement
has various effective dates, the most significant of which is January 1, 2002.
Upon adoption of this Statement on January 1, 2002, we will no longer recognize
annual amortization expense of approximately $50 million on goodwill and
indefinite-lived intangible assets. We do not expect the impairment provisions
of this pronouncement will have a material effect on our financial statements.

Accounting for Asset Retirement Obligations. In August 2001, the FASB
issued SFAS No. 143, Accounting for Asset Retirement Obligations. This Statement
requires companies to record a liability relating to the retirement and removal
of assets used in their business. The liability is discounted to its present
value, and the related asset value is increased by the amount of the resulting
liability. Over the life of the asset, the liability will be accreted to its
future value and eventually extinguished when the asset is taken out of service.
The provisions of this Statement are effective for fiscal years beginning after
June 15, 2002. We are currently evaluating the effects of this pronouncement.

Accounting for the Impairment or Disposal of Long-Lived Assets. In October
2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of
Long-Lived Assets. This Statement requires that long-lived assets that are to be
disposed of by sale be measured at the lower of book value or fair value less
cost to sell. The standard also expanded the scope of discontinued operations to
include all components of an entity with operations that can be distinguished
from the rest of the entity and that will be eliminated from the ongoing
operations of the entity in a disposal transaction. The provisions of this
Statement are effective for fiscal years beginning after December 15, 2001. The
provisions of this Statement will impact any asset dispositions we make after
January 1, 2002.

Under our balance sheet enhancement plan, we anticipate that we will sell a
variety of assets, including the previously announced sale of midstream assets
to El Paso Energy Partners, and the potential sales of
55

natural gas and oil properties and refining, chemical, coal mining and power
assets. Should these sales occur, based on our current assessment of SFAS No.
144's provisions, our coal mining, chemical and refining assets are likely to
qualify as discontinued operations under the standard. The other assets,
including the announced sale of midstream assets would, we believe, qualify as
assets held for sale. In addition, SFAS No. 144 establishes new rules when a
company begins to take action to either dispose of, or otherwise alter the
manner of operation of, an asset. Under these new rules, when it becomes "more
likely than not" that a company will alter its current operating plans, an
evaluation of possible impairment is made. Based on our announced actions to
date, we are currently evaluating whether the assets we may sell are impaired
under this standard. Based on preliminary indications of market value, coupled
with the near-term outlook for the refining and coal mining industries, we
anticipate that we may be required to write-down the carrying values of the
refining and coal mining assets we may sell by an amount that could range from
$145 million to $240 million after-tax under this standard. We continue to
evaluate these and the other assets that may be sold under as part of our plan.
See a further discussion of our balance sheet enhancement plan under Future
Liquidity.

Derivatives Implementation Group Issue C-16. In September 2001, the
Derivatives Implementation Group of the FASB cleared guidance on Issue C-16,
Scope Exceptions: Applying the Normal Purchases and Normal Sales Exception to
Contracts that Combine a Forward Contract and a Purchased Option Contract. This
guidance impacts the accounting for fuel supply contracts that require delivery
of a contractual minimum quantity of a fuel other than electricity at a fixed
price and have an option that permits the holder to take specified additional
amounts of fuel at the same fixed price at various times. We use fuel supply
contracts such as these in our power producing operations and currently do not
reflect them in our balance sheet since they are considered normal purchases
that are not classified as derivative instruments under SFAS No. 133. This
guidance becomes effective in the second quarter of 2002, and we will be
required to account for these contracts as derivative instruments under SFAS No.
133. We are currently evaluating the impact of this guidance on our financial
statements.

56

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 Commission 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.

THE SUCCESS OF OUR PIPELINE AND FIELD SERVICES BUSINESS DEPENDS ON FACTORS
BEYOND OUR CONTROL.

Most of the natural gas and natural gas liquids we transport, gather,
process 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 transmission, storage, gathering,
processing, and sales volumes and rates, to renegotiate existing contracts as
they expire or to remarket unsubscribed capacity:

- future weather conditions, including those that favor hydroelectric
generation or other alternative energy sources;

- price competition;

- drilling activity and supply availability;

- expiration of significant contracts; and

- service area competition.

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 natural gas transportation contracts which expire periodically and must be
renegotiated and extended or replaced. Although we actively pursue the
renegotiation, extension and/or replacement of these contracts, we cannot assure
you 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.

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

- the proposed construction by other companies of additional pipeline
capacity in markets served by our interstate pipelines;

- changes in state regulation of local distribution companies, which may
cause them to negotiate short-term contracts;

- reduced demand due to higher natural gas prices;

57

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

- the viability of our expansion projects.

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

FLUCTUATIONS IN ENERGY COMMODITY PRICES COULD ADVERSELY AFFECT OUR BUSINESS.

If natural gas prices in the supply basins connected to our pipeline
systems are higher than prices in other natural gas producing regions,
especially Canada, our ability to compete with other transporters may be
negatively impacted. Revenues generated by our transmission, gathering and
processing contracts depend on volumes and rates, both of which can be affected
by the prices of natural gas and natural gas liquids. The success of our
transmission, gathering and processing operations in the Gulf of Mexico is
subject to continued development of additional oil and natural gas reserves in
the vicinity of our facilities and our ability to access additional reserves 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, gathering and processing through our offshore facilities.
Fluctuations in energy prices, which may impact gathering rates and investments
by third parties in the development of new natural gas and oil reserves
connected to our gathering and processing facilities, 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; and

- abundance of supplies of alternative energy sources.

If there are reductions in the average volume of the natural gas and
natural gas liquids we transport, gather and process for a prolonged period, our
results of operations and financial position could be significantly, negatively
affected.

THE RATES WE ARE ABLE TO CHARGE OUR CUSTOMERS MAY BE REDUCED BY GOVERNMENTAL
AUTHORITIES.

Our pipeline businesses are regulated by the FERC, Department of
Transportation, Texas Railroad Commission and various state and local regulatory
agencies. In particular, the FERC generally limits the rates we are permitted to
charge our customers for interstate natural gas transportation and, in some
cases, sales of natural gas. If the rates we are permitted to charge our
customers for use of our regulated pipelines are lowered, or do not recover
current cost levels, or if the terms and conditions of tariffs or contracts are
modified, the profitability of our pipeline businesses may be reduced.

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

The performance of our natural gas and oil exploration and production
businesses is dependent upon a number of factors that we cannot control. These
factors include:

- fluctuations in natural gas and crude oil prices including basis
differentials;

- the results of future drilling activity;

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

58

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

- risks incident to operations of natural gas and oil wells;

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

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

ESTIMATES OF NATURAL GAS AND OIL RESERVES MAY CHANGE.

Actual production, revenues, taxes, development expenditures, and operating
expenses with respect to our reserves will likely vary from our estimates of
proved reserves of natural gas and oil, and those variances may be material. The
process of estimating natural gas and oil reserves is complex, requiring
significant decisions and assumptions in the evaluation of available geological,
geophysical, engineering, and economic data for each reservoir or deposit. As a
result, these estimates are inherently imprecise. Actual future production,
natural gas and oil prices, revenues, taxes, development expenditures, operating
expenses and quantities of recoverable natural gas and oil reserves may vary
substantially from our estimates. In addition, we may be required to revise the
reserve information, downward or upward, based on production history, results of
future exploration and development, prevailing natural gas and oil prices and
other factors, many of which will be beyond our control.

THE SUCCESS OF OUR POWER GENERATION AND MARKETING ACTIVITIES DEPENDS ON MANY
FACTORS BEYOND OUR CONTROL.

The success of our international and domestic power projects and power
marketing activities, and the amount of the related performance-based management
fee paid to us in connection with Chaparral, 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;

- uncertain regulatory conditions resulting from the ongoing deregulation
of the electric industry in the United States and in foreign
jurisdictions;

- our ability to negotiate successfully and enter into, restructure or
recontract advantageous long-term power purchase 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 and the implementation of conservation programs;

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

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

THE SUCCESS OF OUR REFINING AND CHEMICAL ACTIVITIES DEPENDS ON MANY FACTORS
BEYOND OUR CONTROL.

The success of our refining and chemical activities depends on many
factors, many of which are beyond our control, including:

- availability of alternative sources of supply, including those from new
refineries or foreign locations;

- ongoing regulations over and laws governing the sale and use of chemicals
we produce;

- demand for our products and the impact of economic recession on markets
for our products; and

- prices of feedstocks, primarily crude oil.

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

Some of our subsidiaries use futures 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. We could incur
financial losses in the future as a result of volatility in the market values of
the energy

59

commodities we trade, or if one of our counterparties fails to perform under a
contract. The valuation of these financial instruments can involve 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. 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 8.

ATTRACTIVE ACQUISITION AND INVESTMENT OPPORTUNITIES MAY NOT BE AVAILABLE.

Our ability to grow will depend, in part, upon our ability to identify and
complete attractive acquisition and investment opportunities. Opportunities for
growth through acquisitions and investments in joint ventures, and the future
operating results and success of these acquisitions and joint ventures within
and outside the United States may be subject to the effects of, and changes in
United States and foreign:

- trade and monetary policies;

- laws and regulations;

- political and economic developments;

- inflation rates;

- taxes; and

- operating conditions.

In addition, there is increased competition for acquisition and investment
opportunities. Increased competition could result in our not being the
successful bidder or making an acquisition at a higher relative price than we
have historically paid. Any of these occurrences would limit our ability to
fully execute our growth strategy.

OUR FOREIGN OPERATIONS AND INVESTMENTS INVOLVE SPECIAL RISKS.

Our activities in areas outside the U.S. 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.

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

Our current and former operations involve management of regulated materials
and are subject to various environmental laws and regulations. These laws and
regulations obligate us to clean up various sites at which petroleum, chemicals,
low-level radioactive substances or other regulated materials may have been
disposed of or released. Some of these sites have been designated 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.

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

- the difficulty of estimating clean up costs;

- 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

60

- 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. For additional
information concerning our environmental matters, see Item 8, Financial
Statements and Supplementary Data, Note 14.

OUR OPERATIONS ARE SUBJECT TO OPERATIONAL HAZARDS AND UNINSURED RISKS.

Our operations are subject to the inherent risks normally associated with
those operations, including explosions, pollution, release of toxic substances,
fires, hurricanes 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 these types of 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.

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. In addition, our trading business is
heavily dependent on favorable credit ratings, a downgrade of which can trigger
higher cash requirements and operating costs. 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:

- interest rates;

- tax rates due to new tax laws;

- the structured and commercial financial markets;

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

- our stock price; and

- our credit ratings.

Our inability to amend the rating triggers in Chaparral's and Gemstone's
third-party debt or otherwise refinance their debt could adversely impact our
credit ratings.

WE WILL FACE COMPETITION FROM THIRD PARTIES TO TRANSPORT, GATHER, PROCESS,
FRACTIONATE, STORE OR OTHERWISE HANDLE OIL, NATURAL GAS, NATURAL GAS LIQUIDS AND
OTHER PETROLEUM PRODUCTS.

The oil and natural gas business is highly competitive in the search for
and acquisition of reserves and in the gathering and marketing of oil and gas
production. Our competitors include the major oil companies, independent oil and
gas concerns, individual producers, gas marketers and major pipeline companies,
as well as participants in other industries supplying energy and fuel to
industrial, commercial and individual consumers. If we are unable to compete
with services offered by other energy enterprises, which may be larger, offer
more services, and possess greater resources, our future profitability may be
negatively impacted.

WE MAY NOT ACHIEVE ALL OF THE OBJECTIVES SET FORTH IN OUR BALANCE SHEET
ENHANCEMENT PROGRAM IN A TIMELY MANNER OR AT ALL.

Our ability to achieve all of the objectives of our balance sheet
enhancement program, as well as the timing of their achievement, if at all, is
subject to factors beyond our control, including:

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- our ability to raise $2.25 billion in cash from asset sales may be
impacted by our ability to locate potential buyers in a timely fashion
and obtain a reasonable price or by competing asset sales programs by our
competitors; in addition, even if we receive the cash amount announced
under the enhancement program, there is no guarantee that the results of
this program will be achieved; and

- our ability to amend the rating triggers on Chaparral's and Gemstone's
third party debt is conditional upon the approval of the existing note
holders and third party equity investors, our credit rating and
perceptions of our company and industry.

Other factors impacting our timing and our ability to complete our
enhancement program include our ability to issue equity securities which is
based on our stock price, credit ratings and liquidity in the capital markets,
and our ability to retain earnings which is based on operational factors,
economic conditions and commodity prices.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We use derivative financial instruments to manage market risks associated
with energy commodities, interest rates and foreign currency exchange rates. Our
primary market risk exposures are to changing commodity prices. Our market risks
are monitored by a corporate risk management committee to ensure compliance with
our overall stated risk management policies as approved by the Audit Committee
of our Board of Directors. This committee operates independently from the
business segments that create or actively manage these risk exposures.

During 2001, we experienced a significantly changing energy market brought
about by the energy crisis in California, the events of September 11th, the
bankruptcy of Enron Corp., and a significant decline in energy commodity prices.
We limited our market risk exposure during this period of market uncertainty by
continually monitoring our net physical and financial positions and assuming
minimal risk. We expect this continuous monitoring and reduced risk assumption
to continue in the near term.

TRADING COMMODITY PRICE RISK

Our Merchant Energy segment is exposed to market risks inherent in the
financial instruments it uses for trading energy and energy related commodities.
Merchant Energy records its energy trading activities, including transportation
capacity, tolling agreements and storage contracts at fair value. Changes in
fair value of these activities are reflected in our income statement. Merchant
Energy's policy is to manage commodity price risks through a variety of
financial instruments, including:

- exchange-traded futures contracts involving cash settlements;

- forward contracts involving cash settlements or physical delivery of an
energy commodity;

- swap contracts which require payments to (or receipts from)
counterparties based on the difference between a fixed and a variable
price, or two variable prices, for a commodity;

- exchange-traded and over-the-counter options; and

- other contractual arrangements.

Merchant Energy measures the risk in its traded commodity and energy
related contracts on a daily basis using a Value-at-Risk model to determine the
maximum potential one-day unfavorable impact on its earnings, due to normal
market movements, and monitors its risk in comparison to established thresholds.
Since 1998, Merchant Energy has used what is known as the variance-covariance
technique of measuring Value-at-Risk. This technique uses historical price
movements and specific, defined mathematical parameters to estimate the
characteristics of and the relationships between components of its assets and
liabilities held for price risk management activities. This method works well
for futures, forwards and swaps, but does not completely capture the risk of
option positions, especially for large deviations from current underlying
values. For this reason, Merchant Energy began measuring its Value-at-Risk using
a historical simulation technique in December 2001. This technique fully values
positions in every iteration of the simulation and captures risk from all types
of positions, including options. Merchant Energy also uses other measures to
provide additional assurance that the risks in its commodity and energy related
contracts are being properly monitored on a daily basis, including sensitivity
analysis, stress testing, credit risk management and the establishment of
parameters to monitor and measure risk exposure, highlight unfavorable trends,
and measure performance of the portfolio using applicable risk metrics.

The following table presents our potential one-day unfavorable impact on
earnings before interest and income taxes as measured by Value-at-Risk for our
traded commodity and energy related contracts and is prepared based on a
confidence level of 95 percent and a one-day holding period. The high and low
valuations represent the highest and lowest of the month end values during 2001.
The average valuation represents the

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average of the 2001 month end values. Actual losses may exceed those measured by
Value-at-Risk using either of the modeling techniques presented below:

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

(1) Portfolio Value-at-Risk represents the combined Value-at-Risk for the
trading and non-trading price risk management activities. The separate
calculation of Value-at-Risk for trading and non-trading commodity contracts
ignores the natural correlation that exists between traded and non-traded
commodity contracts and prices. As a result, the individually determined
values will be higher than the combined Value-at-Risk in most instances. We
manage our risks through a portfolio approach that balances both trading and
non-trading risks.

NON-TRADING COMMODITY PRICE RISK

Our segments are exposed to a variety of market risks in the normal course
of their business activities. Our Production segment has market risks related to
the oil and natural gas it produces. Our Field Services segment has market risks
related to the natural gas and natural gas liquids it retains in its processing
operations. The refining activities in our Merchant Energy segment are exposed
to market risks in both the feedstocks they use, primarily crude oil and
petroleum based products, as well as the refined products they sell. Our
Merchant Energy segment has market risks from changing prices of natural gas
between locations connected by transportation capacity on our pipelines. We
attempt to mitigate market risk associated with these significant physical
transactions through the use of non-trading financial instruments, including:

- exchange-traded futures contracts involving cash settlements;

- forward contracts involving cash settlements or physical delivery of an
energy commodity;

- swap contracts which require payments to (or receipts from)
counterparties based on the difference between a fixed and a variable
price, or two variable prices, for a commodity; and

- exchange-traded and over-the-counter options.

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, 2001 and 2000. 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.

In December 2001, we began measuring the risk associated with our commodity
contracts held for non-trading purposes using Value-at-Risk determined using the
historical simulation technique. Based on a

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confidence level of 95 percent and a one-day holding period, our estimated
potential one-day unfavorable impact on earnings before interest and income
taxes was $15 million at December 31, 2001.

INTEREST RATE RISK

Many of our debt related financial instruments, derivative contracts and
project financing arrangements are sensitive to market fluctuations in interest
rates. From time to time, we manage our exposure to interest rate risk through
the use of non-trading derivative financial instruments, primarily through
interest rate swaps.

As of December 31, 2001, we maintained an interest rate swap transaction
with a notional amount of $240 million exchanging LIBOR, a variable interest
rate, for a fixed rate of 3.07%. This transaction results in the payment of a
fixed rate of 4.49% until the swap terminates in June 2003. The fair value of
this swap was immaterial as of December 31, 2001.

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. As of December 31, 2001, 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 debt has been estimated
based on quoted market prices for the same or similar issues.

FOREIGN CURRENCY EXCHANGE RATE RISK

Our exposure to foreign currency exchange rates relates to changes in
foreign currency rates on our international power investments and operations,
our foreign trading operations and foreign debt obligations that are not
denominated or adjusted to U.S. dollars. From time to time, we manage this
exposure to changes in foreign currency exchange rates by entering into
derivative financial instruments, principally foreign currency forward purchase
and sale contracts. The following table summarizes the notional amounts, average

65

settlement rates, and fair value for foreign currency forward purchase and sale
contracts as of December 31, 2001:

The following table summarizes foreign currency forward purchase and sale
contracts by expected maturity dates along with annual anticipated cash flow
impacts as of December 31, 2001:

EQUITY RISK

Our Merchant Energy segment holds investments that expose us to price risk
associated with equity securities markets. We account for these investments
using investment company accounting. As a result, these holdings are measured at
their fair value with changes in fair value recorded in our income statement.
The fair value of these investments are determined based on estimates of amounts
that would be realized if these securities were sold. We also hold a variety of
publicly traded marketable equity securities. Below are the fair values of these
holdings at December 31, 2001 and 2000, as well as the impact of a ten percent
increase or decrease in the underlying fair values of these securities for each
period presented:

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

EL PASO CORPORATION

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

See accompanying notes.

67

EL PASO CORPORATION

CONSOLIDATED BALANCE SHEETS
(IN MILLIONS, EXCEPT SHARE AMOUNTS)

See accompanying notes.

68

EL PASO CORPORATION

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

See accompanying notes.

69

EL PASO CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN MILLIONS)

See accompanying notes.

70

EL PASO CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN MILLIONS)

See accompanying notes.

71

EL PASO CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
AND CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME
(IN MILLIONS)

See accompanying notes.

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EL PASO CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our consolidated financial statements include the accounts of all
majority-owned, controlled subsidiaries after the elimination of all significant
intercompany accounts and transactions. Our financial statements for prior
periods include reclassifications that were made to conform to the current year
presentation. Those reclassifications had no impact on reported net income or
stockholders' equity.

Principles of Consolidation

We consolidate entities when we have the ability to control the operating
and financial decisions and policies of that entity. Where we can exert
significant influence over, but do not control, those policies and decisions, we
apply the equity method of accounting. We use the cost method of accounting
where we are unable to exert significant influence over the entity. The
determination of our ability to control or exert significant influence over an
entity involves the use of judgment of the extent of our control or influence
and that of the other equity owners or participants of the entity.

Use of Estimates

The preparation of financial statements in conformity with U.S. generally
accepted accounting principles requires the use of estimates and assumptions
that affect the amounts we report as assets, liabilities, revenues, and expenses
and our disclosures in these financial statements. Actual results can, and often
do, differ from those estimates. Our accounting policies for asset impairments,
natural gas and oil properties, environmental costs and other contingencies, and
price risk management activities require estimates that involve complex
situations and a high degree of judgment. These estimates can, and often do,
change.

Accounting for Regulated Operations

Our interstate natural gas systems and storage operations are subject to
the jurisdiction of FERC in accordance with the Natural Gas Act of 1938 and the
Natural Gas Policy Act of 1978. Our regulated interstate systems apply the
provisions of Statement of Financial Accounting Standards No. 71, Accounting for
the Effects of Certain Types of Regulation, except for ANR, CIG and WIC, who
discontinued its application in 1996. Accounting for businesses that are
regulated and apply the provisions of SFAS No. 71 can differ from the accounting
requirements for non-regulated businesses. Transactions that have been recorded
differently as a result of regulatory accounting requirements include the
capitalization of an equity return component on regulated capital projects,
employee related benefits, and other costs and taxes included in, or expected to
be included in, future rates.

Cash and Cash Equivalents

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

Allowance for Doubtful Accounts

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

Inventory

Our inventory consists of refined products, crude oil and chemicals,
materials and supplies, natural gas in storage for non-trading purposes, coal
and optic fiber. We use the first-in, first-out method to account for our
refined products, crude oil and chemicals inventories and the average cost
method to account for our other

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inventories. We value all inventory at the lower of its cost or market value.
Our optic fiber has been classified as a long-term asset since we do not expect
to sell it in the next twelve months.

Natural Gas and Oil Imbalances

Natural gas and oil imbalances occur when the actual amount of natural gas
or oil delivered from or received by a pipeline system, processing plant or
storage facility differs from the contractual amount scheduled to be delivered
or received. We value these imbalances due to or from shippers and operators at
an appropriate market index price based on when we expect to settle the
imbalance. Imbalances are settled in cash or made up in-kind, subject to the
contractual terms of settlement.

Imbalances due from others are reported in our balance sheet as either
accounts receivable from customers or accounts receivable from unconsolidated
affiliates. Imbalances owed to others are reported on the balance sheet as
either trade accounts payable or accounts payable to unconsolidated affiliates.
In addition, all imbalances are classified as current or long-term depending on
when we expect to settle them.

Property, Plant and Equipment

Our property, plant and equipment is recorded at its original cost of
construction or, upon acquisition, at either the fair value of the assets
acquired or, the cost to the entity that first placed the asset in service. We
capitalize direct costs, such as labor and materials, and indirect costs, such
as overhead, interest and in our regulated businesses that apply the provisions
of SFAS No. 71, an equity return component. We capitalize the major units of
property replacements or improvements and expense minor items. Included in our
pipeline property balances are additional acquisition costs which represent the
excess purchase costs associated with purchase business combinations allocated
to our regulated interstate systems. These costs are amortized on a
straight-line basis, and we do not recover these excess costs in our rates.

The following table presents our property, plant and equipment by type,
depreciation method, remaining useful lives and depreciation rate:

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

(1) For our regulated interstate systems using SFAS No. 71, we use the composite
(group) method to depreciate regulated property, plant and equipment. Under
this method, assets with similar useful lives and other characteristics are
grouped and depreciated as one asset. We apply the depreciation rate
approved in our tariff, to the total cost of the group, until its net book
value equals its salvage value. We re-evaluate depreciation rates each time
we redevelop our transportation rates when we file with FERC for an increase
or decrease in rates.

When we retire regulated property, plant and equipment accounted for under
SFAS No. 71, we charge accumulated depreciation and amortization for the
original cost, plus the cost of retirement (the cost to remove, sell or
dispose), less its salvage value. We do not recognize a gain or loss unless we
sell an entire operating unit. We include gains or losses on dispositions of
operating units in income. When we retire regulated property, plant and
equipment not under SFAS No. 71 and non-regulated properties, we reduce
property, plant and equipment for its original cost, less accumulated
depreciation, and salvage. Any remaining gain or loss is recorded in income.

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Asset Impairments

We evaluate our long-lived assets for impairment in accordance with SFAS
No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of. If an adverse event or change in circumstances occurs,
we estimate the future cash flows from the asset, grouped together at the lowest
level for which separate cash flows can be measured, to determine if the asset
is impaired. If the total of the undiscounted future cash flows is less than the
carrying amount for the assets, we calculate the fair value of the assets either
through reference to sales data for similar assets, or by estimating the fair
value using a discounted cash flow approach. These cash flow estimates require
us to make estimates and assumptions for many years into the future for pricing,
demand, competition, operating costs, legal, regulatory and other factors, and
these assumptions can change either positively or negatively.

Natural Gas and Oil Properties

We use the full cost method to account for our natural gas and oil
properties. Under the full cost method, substantially all productive and
nonproductive costs incurred in connection with the acquisition, exploration and
development of natural gas and oil reserves are capitalized. These capitalized
costs include the costs of all unproved properties, internal costs directly
related to acquisition and exploration activities and capitalized interest.

We amortize these costs using the unit of production method over the life
of our proved reserves. Our total capitalized costs are limited to a ceiling
based on the present value of future net revenues using current prices,
discounted at 10 percent, plus the lower of cost or fair market value of
unproved properties. 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. We perform this ceiling test calculation each quarter. Any
required write-downs are included in our income statements as ceiling test
charges. Our ceiling test calculations include the effects of derivative
instruments we have designated as cash flow hedges of our anticipated future
natural gas and oil production.

We do not recognize a gain or loss on sales of our natural gas and oil
properties, unless the properties sold are significant. We treat sales as an
adjustment to the cost of our properties.

Planned Major Maintenance

Repair and maintenance costs are generally expensed as incurred, unless
they improve the operating efficiency or extend the useful life of an asset.

In our domestic refining business, repair and maintenance costs for planned
major maintenance activities are accrued as a liability in a systematic and
rational manner over the period of time until the planned major maintenance
activities occur. Any difference between the accrued liability and the actual
costs incurred in performing the maintenance activities are charged or credited
to expense at the time the maintenance occurs. At our international refineries,
the cost of each major maintenance activity is capitalized and amortized to
expense in a systematic and rational manner over the estimated period extending
to the next planned major maintenance activity. The types of costs we accrue in
conjunction with major maintenance at our refineries are outside contractor
costs, materials and supplies, company labor and other outside services. For our
domestic operations, we had accruals for major maintenance of $36 million and
$51 million at December 31, 2001 and 2000, and for our international operations,
we capitalized $56 million and $53 million at December 31, 2001 and 2000.

Intangible Assets

Intangible assets consist primarily of goodwill arising as a result of
mergers and acquisitions. We amortize these intangible assets using the
straight-line method over periods ranging from 5 to 40 years. We evaluate
impairment of goodwill in accordance with APB No. 17, Intangible Assets. Under
this methodology, when an event occurs that suggests that an impairment may have
occurred, we evaluate the undiscounted net cash flows of the asset or entity to
which the goodwill relates. If these cash flows are not sufficient to recover
the value of the asset or entity plus its related goodwill, these cash flows are
discounted at a risk-adjusted rate with any difference recorded as a charge in
our income statement.

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Revenue Recognition

Our regulated businesses recognize revenues from natural gas transportation
services and services other than transportation in the period when the service
is provided. Reserves are provided on revenues collected that may be subject to
refund in our pending rate proceedings.

Our non-regulated businesses record revenues when they are earned. Revenues
are earned when deliveries of physical commodities are made, or when services
are provided. See the discussion of price risk management activities below for
our revenue recognition policies on our trading activities.

Environmental Costs and Other Contingencies

We expense or capitalize expenditures for ongoing compliance with
environmental regulations that relate to past or current operations as
appropriate. We expense amounts for clean up of existing environmental
contamination caused by past operations which do not benefit future periods by
preventing or eliminating future contamination. We record liabilities when our
environmental assessments indicate that remediation efforts are probable, and
the costs 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 inflation and other
societal and economic factors, and include estimates of associated legal costs.
These amounts also consider prior experience in remediating contaminated sites,
other companies' clean-up experience and data released by the EPA or other
organizations. These estimates are subject to revision in future periods based
on actual costs or new circumstances and are included in our balance sheet in
other current and long-term liabilities at their undiscounted amounts. We
evaluate recoveries from insurance coverage, government sponsored and other
programs separately from our liability and, when recovery is assured, we record
and report an asset separately from the associated liability in our financial
statements.

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

Price Risk Management Activities

We engage in price risk management activities for both trading and for
non-trading purposes to manage market risks associated with commodities we
purchase and sell, interest rates and foreign currency exchange rates.

Our trading and non-trading price risk management activities involve the
use of a variety of derivative financial instruments, including:

- exchange-traded futures contracts that involve cash settlements;

- forward contracts that involve cash settlements or physical delivery of a
commodity;

- swap contracts that require payments to (or receipts from) counterparties
based on the difference between a fixed and a variable price, or two
variable prices, for a commodity; and

- exchange-traded and over-the-counter options.

Trading Activities. Our trading activities include the services we provide
in the energy sector, primarily related to the purchase and sale of energy
commodities. We account for our trading activities at their fair market value
under the requirements of EITF Issue 98-10, Accounting for Contracts Involved in
Energy Trading and Risk Management Activities. In addition to the derivatives
above, our trading activities also include non-derivative instruments such as
transportation and storage capacity contracts, and physical natural gas that is
actively traded. We reflect the market values of our trading activities in our
balance sheet as price risk management activities. These are classified as
current or long-term based on their anticipated settlement

76

date. In our income statement, we account for physical settlements that result
in delivery of a commodity as revenues or cost of products sold based on whether
we buy or sell the commodity. Financial settlements as well as changes in the
market value of traded positions are included in revenue.

Non-trading Activities. Our non-trading price risk management activities
involve the use of derivative financial instruments to hedge the impact of
market price risk exposures on our assets, liabilities, contractual commitments
and forecasted transactions related to our natural gas and oil production,
refining, natural gas transmission, power generation, financing and
international business activities. On January 1, 2001, we adopted the provisions
of SFAS No. 133, Accounting for Derivatives and Hedging Activities, in
accounting for our non-trading derivative instruments. Under SFAS No. 133, all
derivatives are reflected in our balance sheet at their fair market value. We do
not apply the mark-to-market method of accounting for contracts that qualify as
normal purchases and sales under SFAS No. 133.

We engage in two types of hedging activities: hedges of cash flow exposure
and hedges of fair value exposure. Hedges of cash flow exposure are entered into
to hedge a forecasted transaction or the variability of cash flows to be
received or paid related to a recognized asset or liability. Hedges of fair
value exposure are entered into to hedge the fair value of a recognized asset,
liability or a firm commitment. On the date that we enter into the derivative
contract, we designate the derivative as either a cash flow hedge or a fair
value hedge. Changes in the derivative fair values that are designated as cash
flow hedges are deferred to the extent that they are effective and are recorded
as a component of accumulated other comprehensive income until the hedged
transactions occur and are recognized in earnings. The ineffective portion of a
cash flow hedge's change in value is recognized immediately in earnings as a
component of operating revenues in our income statement. Changes in the
derivative fair values that are designated as fair value hedges are recognized
in earnings as offsets to the changes in fair values of related hedged assets,
liabilities or firm commitments.

As required by SFAS No. 133, we formally document all relationships between
hedging instruments and hedged items, as well as our risk management objectives,
strategies for undertaking various hedge transactions and our methods for
assessing and testing correlation and hedge ineffectiveness. All hedging
instruments are linked to the hedged asset, liability, firm commitment or
forecasted transaction. We also assess, both at the inception of the hedge and
on an on-going basis, whether the derivatives that are used in our hedging
transactions are highly effective in offsetting changes in cash flows or fair
values of the hedged items. We discontinue hedge accounting prospectively if we
determine that a derivative is no longer highly effective as a hedge.

The market value of both trading and non-trading instruments reflects our
best estimate and is based upon exchange or over-the-counter quotations whenever
they are available. Quoted valuations may not be available due to location
differences or terms that extend beyond the period for which quotations are
available. Where quotes are not available, we utilize other valuation techniques
or models to estimate market values. These modeling techniques require us to
make estimations of future prices, price correlation and market volatility and
liquidity. Our estimates also reflect factors for time value and volatility
underlying the contracts, the potential impact of liquidating our position in an
orderly manner over a reasonable period of time under present market conditions,
modeling risk, credit risk of our counterparties and operational risk. Our
actual results may differ from our estimates, and these differences can be
positive or negative.

Cash inflows and outflows associated with the settlement of both trading
and non-trading price risk management activities are recognized in operating
cash flows, and any receivables and payables resulting from these settlements
are reported separately from price risk management activities in our balance
sheet as trade receivables and payables.

Prior to our adoption of SFAS No. 133, we applied hedge accounting for our
non-trading derivatives only if the derivative reduced the risk of the
underlying hedged item, was designated as a hedge at its inception and was
expected to result in financial impacts which were inversely correlated to those
of the item being hedged. If correlation ceased to exist, hedge accounting was
terminated and the derivatives were recorded at their fair value in the balance
sheet and changes in fair value were recorded in income. Changes in the market
value of derivatives designated as hedges were deferred as deferred revenue or
expense until the gain or loss was recognized on the hedged transaction.
Derivatives held for non-trading purposes were recorded as gains or
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losses in operating income and cash inflows and outflows were recognized in
operating cash flow as the settlement of those transactions occurred.

Income Taxes

We report income taxes based on income reported on our tax returns along
with a provision for deferred income taxes. Deferred income taxes reflect the
estimated future tax consequences of differences between the financial statement
and tax bases of assets and liabilities and carryovers at each year end. We
account for tax credits under the flow-through method, which reduces the
provision for income taxes in the year the tax credits first become available.
We reduce deferred tax assets by a valuation allowance when, based on our
estimates, it is more likely than not that a portion of those assets will not be
realized in a future period. The estimates utilized in the recognition of
deferred tax assets are subject to revision, either up or down, in future
periods based on new facts or circumstances.

Foreign Currency Transactions and Translation

We record all currency transaction gains and losses in income. The net
currency loss recorded to income in 2001 was $13 million and was insignificant
in 2000. The U.S. dollar is the functional currency for substantially all of our
foreign operations. For foreign operations whose functional currency is deemed
to be other than the U.S. dollar, assets and liabilities are translated at
year-end exchange rates and included as a separate component of comprehensive
income and stockholders' equity. The cumulative currency translation loss
recorded in accumulated other comprehensive income was $97 million and $64
million at December 31, 2001 and 2000. Revenues and expenses are translated at
average exchange rates prevailing during the year.

Treasury Stock

We account for treasury stock using the cost method and report it in our
balance sheet as a reduction to stockholders' equity. Treasury stock sold or
issued is valued on a first-in, first-out basis. Included in treasury stock at
December 31, 2001, and 2000, were approximately 5.5 million shares and 5.8
million shares of common stock held in a trust under our deferred compensation
programs.

Stock-Based Compensation

We apply the provisions of Accounting Principles Board Opinion No. 25 and
its related interpretations in accounting for our stock compensation plans. We
have both fixed and variable compensation plans, and we account for these plans
using fixed and variable accounting as appropriate. Compensation expense for
variable plans, including restricted stock grants, is measured using the market
price of the stock on the date the number of shares in the grant becomes
determinable and is amortized into earnings over the period of service. Our
stock options are issued under a fixed plan. Accordingly, compensation expense
is not recognized for stock options unless the options were granted at an
exercise price lower than market on the grant date.

Earnings Per Share

Basic earnings per share represents the amount of earnings for the period
available to each share of common stock outstanding during the period. Diluted
earnings per share represents the amount of earnings for the period available to
each share of common stock outstanding during the period plus all potentially
dilutive common shares outstanding during the period. Differences between basic
and diluted shares outstanding in all periods are attributed to the dilutive
effects of restricted stock, stock options, trust preferred securities,
convertible debentures and our FELINE PRIDES(sm).

Cumulative Effect of Accounting Change

On January 1, 1999, we adopted Statement of Position 98-5, Reporting on the
Costs of Start-Up Activities. The statement defined start-up activities and
required start-up and organization costs be expensed as incurred. In addition,
it required that any such cost that existed on the balance sheet be expensed
upon

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adoption of the pronouncement. We recorded a charge of $13 million, net of
income taxes, as a cumulative effect of an accounting change upon adoption.

New Accounting Pronouncements Issued But Not Yet Adopted

During 2001, the Financial Accounting Standards Board issued SFAS No. 141,
Business Combinations, SFAS No. 142 Goodwill and Other Intangible Assets and
SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets.
Each of these standards has a required adoption date of January 1, 2002. SFAS
No. 141 will impact the manner in which we account for business combinations.
SFAS No. 142 will impact the manner in which we account for goodwill and test
goodwill for impairment. SFAS No. 144 will impact how we account for asset
impairments and the accounting for discontinued operations.

2. MERGERS, ACQUISITIONS AND DIVESTITURES

Coastal

In January 2001, we merged with Coastal. We accounted for the transaction
as a pooling of interests and converted each share of Coastal's common stock and
Class A common stock on a tax-free basis into 1.23 shares of our common stock.
We also exchanged Coastal's outstanding convertible preferred stock for our
common stock on the same basis as if the preferred stock had been converted into
Coastal common stock immediately prior to the merger. In the merger, we issued
approximately 271 million shares of our common stock, including 4 million shares
in exchange for Coastal stock options.

The following table presents the revenues and net income for the previously
separate companies and the combined amounts presented in these audited combined
financial statements. Several adjustments were made to conform the accounting
presentation of this financial information.

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(1) Conforming reclassifications primarily include a gross-up of revenues
associated with Coastal's physical petroleum marketing and trading
activities to be consistent with our method of reporting these revenues.

Texas Midstream Operations

In December 2000, we completed our purchase of Pacific Gas & Electric's
(PG&E's) Texas Midstream operations. The total value of the transaction was $887
million, including assumed debt of approximately $527 million. The transaction
was accounted for as a purchase and is included in our Field Services segment.

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The operations acquired consisted of 7,500 miles of intrastate natural gas
transmission and natural gas liquids pipelines that transport approximately 2.8
Bcf/d, nine natural gas processing and fractionation plants that currently
process 1.5 Bcf/d and rights to 7.2 Bcf of natural gas storage capacity. In
March 2001, we sold some of these acquired natural gas liquids transportation
and fractionation assets to El Paso Energy Partners for approximately $133
million.

Sonat

In October 1999, we completed our merger with Sonat, a diversified energy
holding company engaged in domestic natural gas and oil exploration and
production, the transmission and storage of natural gas, and natural gas and
power marketing. We accounted for the merger as a pooling of interests and
exchanged one share of our common stock was issued in exchange for each share of
Sonat common stock. Total common shares issued in the merger were approximately
110 million.

Divestitures

Under a Federal Trade Commission (FTC) order, as a result of our merger
with Coastal, we sold our Midwestern Gas Transmission system, our Gulfstream
pipeline project, our 50 percent interest in the Stingray and U-T Offshore
pipeline systems and our investments in the Empire State and Iroquois pipeline
systems. For the year ended December 31, 2001, net proceeds from these sales
were approximately $279 million, and we recognized an extraordinary net gain of
approximately $26 million, net of income taxes of approximately $27 million.

Additionally, El Paso Energy Partners, L.P. sold its interests in several
offshore assets under an FTC order related to our merger with Coastal. These
sales consisted of interests in seven natural gas pipeline systems, a
dehydration facility and two offshore platforms. Proceeds from the sales of
these assets were approximately $135 million and resulted in a loss to the
partnership of approximately $25 million. As consideration for these sales, we
committed to pay El Paso Energy Partners a series of payments totaling $29
million, and were required to contribute $40 million to a trust related to one
of the assets sold by El Paso Energy Partners. These payments have been recorded
as merger-related costs.

During 2000, we sold East Tennessee Natural Gas Company, Sea Robin Pipeline
Company and our one-third interest in Destin Pipeline Company to comply with an
FTC order related to our merger with Sonat. Net proceeds from these sales were
approximately $616 million, and we recognized an extraordinary gain of $89
million, net of income taxes of $59 million. In December 2000, we sold our
interest in Oasis Pipeline Company to comply with an FTC order. We incurred a
loss on this transaction of approximately $19 million, net of income taxes. We
recorded the gains and losses on these sales as extraordinary items in our
income statement.

In February 2002, we announced the sale of several midstream assets to El
Paso Energy Partners for total consideration of $750 million. The assets to be
sold include:

- 9,400 miles of intrastate transmission pipelines;

- 1,300 miles of gathering systems in the Permian Basin; and

- a 42.3 percent non-operating interest in the Indian Basin gas processing
and treating plant and associated gathering lines.

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3. MERGER-RELATED COSTS AND ASSET IMPAIRMENTS

We incurred costs related to our mergers with Coastal and Sonat and asset
impairments for each of the three years ended December 31 as follows:

Merger-Related Costs. Our merger-related costs relate to our mergers with
Coastal and Sonat and consisted of the following for each of the three years
ended December 31:

Employee severance, retention and transition costs include direct payments
to, and benefit costs for, severed employees and early retirees that occurred as
a result of our merger-related workforce reduction and consolidation. Following
the Coastal merger, we completed an employee restructuring across all of our
operating segments, resulting in the reduction of 3,285 full-time positions
through a combination of early retirements and terminations. Following the Sonat
merger, approximately 870 full-time positions were eliminated in a similar
restructuring. Employee severance costs include actual severance payments and
costs for pension and post-retirement benefits settled and curtailed under
existing benefit plans as a result of these restructurings. Retention charges
include payments to employees who were retained following the mergers and
payments to employees to satisfy contractual obligations. Transition costs
relate to costs to relocate employees and costs for severed and retired
employees arising after their severance date to transition their jobs into the
ongoing workforce. The pension and post-retirement benefits were accrued on the
merger date and will be paid over the applicable benefit periods of the
terminated and retired employees. All other costs were expensed as incurred and
have been paid.

Also included in the 2001 employee severance, retention and transition
costs was a charge of $278 million resulting from the issuance of approximately
4 million shares of our common stock on the date of the Coastal merger in
exchange for the fair value of Coastal employees' and directors' stock options.

Transaction costs include investment banking, legal, accounting, consulting
and other advisory fees incurred to obtain federal and state regulatory
approvals and take other actions necessary to complete our mergers. All of these
items were expensed in the periods in which they were incurred.

Business and operational integration costs include charges to consolidate
facilities and operations of our business segments, such as lease termination
and abandonment charges, recognition of the mark-to-market value of energy
trading contracts resulting from changes in how these contracts are managed
under our combined operating strategy and incremental fees under software and
seismic license agreements. Also included in the 2001 charges are approximately
$222 million in estimated lease related costs to relocate our pipeline
operations from Detroit, Michigan to Houston, Texas and from El Paso, Texas to
Colorado Springs, Colorado. These charges were accrued at the time we completed
our relocations and closed these offices. The amounts accrued will be paid over
the term of the applicable non-cancelable lease agreements. All other costs were
expensed as incurred.

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Merger-related asset impairments relate to write-offs or write-downs of
capitalized costs for duplicate systems and facilities and assets whose value
was impaired as a result of decisions on the strategic direction of our combined
operations following our merger with Coastal. These charges occurred in our
Merchant Energy, Production and Pipelines segments, and all of these assets have
either had their operations suspended or continue to be held for use. The
charges taken were based on a comparison of the cost of the assets to their
estimated fair value to the ongoing operations based on this change in operating
strategy.

Other costs include payments made in satisfaction of obligations arising
from the FTC approval of our merger with Coastal and other miscellaneous
charges. These items were expensed in the period in which they were incurred.

Asset Impairments. The 2001 asset impairment charges resulted from the
write-downs of our investments in several international power projects in our
Merchant Energy segment and several telecommunications investments in our
Corporate and Other operations. The 2000 charges consisted of the impairment of
coal mining and refining assets in our Merchant Energy segment and a gas
processing facility in our Field Services segment. The 1999 charge occurred in
the Pipeline segment and was derived from impairments of regulatory assets that
were not recoverable based on the settlement of a rate case. The impairments in
all periods were primarily a result of weak or changing economic conditions
causing permanent declines in the value of these assets, and the charges taken
for all assets were based on a comparison of each asset's carrying value to its
estimated fair value based on future estimated cash flows. These assets continue
to be held for use, or their operations have been suspended.

4. CHANGES IN ACCOUNTING ESTIMATES

Included in our operation and maintenance costs for the year ended December
31, 2001, were approximately $317 million in costs related to changes in
accounting estimates which consist of $232 million in additional environmental
remediation liabilities, $47 million of additional accrued legal obligations and
a $38 million charge to reduce the value of our spare parts inventories to
reflect changes in the usability of these parts in our worldwide operations.
These changes were primarily the result of several events that occurred as part
of and following our merger with Coastal, including the consolidation of
numerous operating locations, the sale of a majority of our retail gas stations,
the shutdown of our Midwest refining operations and the lease of our Corpus
Christi refinery. These changes were also a direct result of a fire at our Aruba
refinery. Also impacting these amounts was the evaluation of the operating
standards, strategies and plans of our combined company following the merger.
These charges are included as operating expenses in our income statement and
reduced our net income before extraordinary items and net income for the year
ended December 31, 2001, by approximately $215 million.

5. CEILING TEST CHARGES

Under the full cost method of accounting for natural gas and oil
properties, we perform quarterly ceiling tests to evaluate whether the carrying
value of natural gas and oil properties exceeds the present value of future net
revenues, discounted at 10 percent, plus the lower of cost or fair market value
of unproved properties. During the third quarter of 2001, capitalized costs
exceeded this ceiling limit by $135 million, including $87 million for our
Canadian full cost pool, $28 million for our Brazilian full cost pool and $20
million for other international production operations, primarily in Turkey.
These charges were based on the November 1, 2001 daily posted oil and natural
gas sales prices. During 1999, we incurred charges related to our U.S. full cost
pool of $352 million based on end of period natural gas and oil prices. The
natural gas and oil prices used in both periods were adjusted for oilfield or
gas gathering hub and wellhead price differences as appropriate. These non-cash
write-downs are included in our income statement as ceiling test charges.

We use financial instruments to hedge against volatility of natural gas and
oil prices. The impact of these hedges was considered in the determination of
our ceiling test charge during 2001, and will be factored into future ceiling
test calculations. Had the impact of our hedges not been included in calculating
our 2001 ceiling test charge, the charge would not have materially changed since
we do not significantly hedge our international production activities.

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Also as mentioned above, our 2001 charge was computed based on daily posted
prices on November 1, 2001. Had we computed this charge based on the daily oil
and natural gas prices as of September 30, 2001, the charge would have been
approximately $275 million, including approximately $227 million for our
Canadian full cost pool and $48 million for our Brazilian and other
international production operations, including the impact on future cash flows
of our hedging program. Had the impact of our hedging program been excluded, the
charges would have been approximately the same for our international full costs
pools and production operations, but we would have incurred an additional charge
of approximately $576 million related to our U.S. full cost pool.

6. INCOME TAXES

Pretax income before extraordinary items and cumulative effect of
accounting change are composed of the following for each of the three years
ended December 31:

The following table reflects the components of income tax expense included
in income before extraordinary items and cumulative effect of accounting change
for each of the three years ended December 31:

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Our tax expense, included in income before extraordinary items and
cumulative effect of accounting change, differs from the amount computed by
applying the statutory federal income tax rate of 35 percent for the following
reasons for each of the three years ended December 31:

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

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At December 31, 2001, the portion of the cumulative undistributed earnings
of our foreign subsidiaries and foreign corporate joint ventures on which we
have not recorded U.S. income taxes was approximately $975 million. Since these
earnings have been or are intended to be indefinitely reinvested in foreign
operations, no provision has been made for any U.S. taxes or foreign withholding
taxes that may be applicable upon actual or deemed repatriation. If a
distribution of these earnings were to be made, we might be subject to both
foreign withholding taxes and U.S. income taxes, net of any allowable foreign
tax credits or deductions. However, an estimate of these taxes is not
practicable. For these same reasons, we have not recorded a provision for U.S.
income taxes on the foreign currency translation adjustment recorded in other
comprehensive income.

The tax benefit associated with the exercise of non-qualified stock options
and the vesting of restricted stock, as well as restricted stock dividends,
reduced taxes payable by $31 million in 2001, $60 million in 2000 and $19
million in 1999. These benefits are included in additional paid-in capital in
our balance sheets.

As of December 31, 2001, we have charitable contribution carryovers of $24
million for which the carryover periods end as follows: $1 million in 2002, $1
million in 2003 and $22 million in 2004; alternative minimum tax credits of $225
million that carryover indefinitely; and $2 million of general business credit
carryovers for which the carryover periods end at various times in the years
2006 through 2020. Usage of these carryovers is subject to the limitations
provided under Sections 382 and 383 of the Internal Revenue Code as well as the
separate return limitation year rules of IRS regulations. The table below
presents the details of our net operating loss carryover periods.

We recorded a valuation allowance to reflect the estimated amount of
deferred tax assets which we may not realize due to the expiration of net
operating loss and tax credit carryovers. As of December 31, 2001 and 2000,
approximately $1 million of the valuation allowance relates to net operating
loss carryovers of an acquired company. The remaining $2 million of the
allowance relates to general business credit carryovers.

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7. EARNINGS PER SHARE

We calculated basic and diluted earnings per share amounts as follows for
each of the three years ended December 31:

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(1) Due to its antidilutive effect on earnings per share, approximately 7
million shares related to our convertible debentures were excluded from 2001
diluted shares, and approximately 8 million shares related to our trust
preferred securities were excluded in 2001 and 1999.

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8. FINANCIAL INSTRUMENTS AND PRICE RISK MANAGEMENT ACTIVITIES

Fair Value of Financial Instruments

Following are the carrying amounts and estimated fair values of our
financial instruments as of December 31:

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(1) Excludes all physical contracts including transportation capacity, tolling
agreements and natural gas in storage held for trading purposes since these
do not constitute financial instruments.
(2) On January 1, 2001, we adopted SFAS No. 133. Under SFAS No. 133, all
derivative instruments are recorded at their fair value in our financial
statements.

As of December 31, 2001 and 2000, our carrying amounts of cash and cash
equivalents, short-term borrowings, and trade receivables and payables are
representative of fair value because of the short-term nature of these
instruments. The fair value of long-term debt with variable interest rates
approximates its carrying value because of the market-based nature of the debt's
interest rates. We estimated the fair value of debt with fixed interest rates
based on quoted market prices for the same or similar issues. We estimated the
fair value of all derivative financial instruments based on quoted market
prices, current market conditions, estimates we obtained from third-party
brokers or dealers, or amounts derived using valuation models.

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Trading and Non-Trading Price Risk Management Activities

The following table summarizes the carrying value of our trading and
non-trading price risk management assets and liabilities as of December 31:

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(1) Physical contracts include transportation capacity, tolling agreements and
natural gas in storage held for trading purposes.

Commodity Trading Activities

We recognized gross margins from our trading activities of $690 million and
$418 million for the year ended December 31, 2001 and 2000. The fair value of
commodity and energy related contracts entered into for trading purposes as of
December 31, 2001 and 2000, and the average fair value of those instruments are
set forth below:

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(1) Computed using the net asset (liability) balance at the end of each month.

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Notional Amounts and Terms of Trading Price Risk Management Activities

The notional amounts and terms of our energy commodity financial
instruments at December 31, 2001 and 2000, are set forth below:

The notional amounts included in the table above reflect the contracted
notional volumes multiplied by the number of delivery periods remaining under
the related contracts. These notional amounts are not indicative of future cash
flows as we may decide to sell the contracts into the commodity markets in the
future.

The notional amount and terms of foreign currency forward purchases and
sales and interest rate swaps and futures at December 31, 2001 and 2000, were as
follows:

The weighted average maturity of our entire portfolio of price risk
management activities was approximately four years as of December 31, 2001, and
two years as of December 31, 2000.

Market and Credit Risks

We serve a diverse group of customers that require a wide variety of
financial structures, products and terms. This diversity requires us to manage,
on a portfolio basis, the resulting market risks inherent in these transactions
subject to parameters established by our risk management committee. We monitor
market risks through a risk control committee operating independently from the
units that create or actively manage these risk exposures to ensure compliance
with our stated risk management policies.

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We measure and adjust the risk in our portfolio in accordance with
mark-to-market and other risk management methodologies which utilize forward
price curves in the energy markets to estimate the size and probability of
future potential exposure.

Credit risk relates to the risk of loss that we would incur as a result of
non-performance by counterparties pursuant to the terms of their contractual
obligations. We maintain credit policies with regard to our counterparties to
minimize overall credit risk. These policies require an evaluation of potential
counterparties' financial condition (including credit rating), collateral
requirements under certain circumstances (including cash in advance, letters of
credit, and guarantees), and the use of standardized agreements that allow for
the netting of positive and negative exposures associated with a single
counterparty. The counterparties associated with our assets from trading price
risk management activities are summarized as follows:

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(1)"Investment Grade" and "Below Investment Grade" are primarily determined
using publicly available credit ratings, or if a counterparty is not publicly
rated, a minimum implied credit rating through internal credit analysis.
"Investment Grade" includes counterparties with a minimum Standard & Poor's
rating of BBB- or Moody's rating of Baa3. "Below Investment Grade" includes
counterparties with a credit rating that do not meet the criteria of
"Investment Grade".

(2)As of December 31, 2001, we required collateral, which encompasses margins,
standby letters of credit, and parent company guarantees, for $375 million of
the $486 million, or 77%, from counterparties included in "Below Investment
Grade".

(3)We had one customer that comprised greater than 5 percent of assets from
price risk management activities as of December 31, 2001. Although this
customer was considered below investment grade, our position with this
counterparty was fully collateralized through margins and standby letters of
credit. We had one customer that comprised greater than 5 percent of assets
from price risk management activities as of December 31, 2000. The customer
was considered investment grade.

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(4)Counterparty total does not include natural gas in storage or marketable
securities held for trading purposes of $196 million at December 31, 2001.

This concentration of counterparties may impact our overall exposure to
credit risk, either positively or negatively, in that the counterparties may be
similarly affected by changes in economic, regulatory or other conditions.

Non-Trading Price Risk Management Activities

We also utilize derivative financial instruments for non-trading activities
to mitigate market price risk associated with significant physical transactions.
Non-trading commodity activities are accounted for using hedge accounting
provided they meet hedge accounting criteria. Non-trading activities are
conducted through exchange traded futures contracts, swaps, and forward
agreements with third parties.

The notional amounts and terms of contracts held for purposes other than
trading were as follows at December 31:

In March 2001, we issued E550 million (approximately $510 million) of euro
notes at 5.75% due 2006. To reduce our exposure to foreign currency risk, we
entered into a swap transaction exchanging the euro note for a $510 million U.S.
dollar denominated obligation with a fixed interest rate of 6.61% for the
five-year term of the note. The fair value of our liability related to this swap
was $33 million as of December 31, 2001.

As of December 31, 2001, we had an interest rate swap transaction with a
notional amount of $240 million exchanging LIBOR, a variable interest rate, for
a fixed rate of 3.07%. This swap was entered into as a hedge of the variable
interest rates on a loan with a principal amount of $240 million that matures in
March 2004. The swap converts the variable interest payments on the loan to a
fixed rate of 4.49% until the swap terminates in June 2003. The fair value of
this swap was immaterial as of December 31, 2001.

We also face credit risk with respect to our non-trading activities, and
take similar measures as in our trading activities to mitigate this risk. Based
upon our policies and risk exposure, we do not anticipate a material effect on
our financial position, operating results or cash flows resulting from
counterparty non-performance.

9. ACCOUNTING FOR HEDGING ACTIVITIES

On January 1, 2001, we adopted the provisions of SFAS No. 133 and recorded
a cumulative-effect adjustment of $1,280 million, net of income taxes, in
accumulated other comprehensive income to recognize the fair value of all
derivatives designated as hedging instruments. The majority of the initial
charge related to hedging cash flows from anticipated sales of natural gas for
2001 and 2002. During the year ended December 31, 2001, $1,063 million, net of
income taxes, of this initial transition adjustment was reclassified to earnings
as a result of hedged sales and purchases during the year. A discussion of our
hedging activities is as follows:

Fair Value Hedges. We have crude oil and refined products inventories that
change in value daily due to changes in the commodity markets. We use futures
and swaps to protect the value of these inventories. For the year ended December
31, 2001, the financial statement impact of our hedges of the fair value of
these inventories was immaterial.

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Cash Flow Hedges. A majority of our commodity sales and purchases are at
spot market or forward market prices. We use futures, forward contracts and
swaps to limit our exposure to fluctuations in the commodity markets and allow
for a fixed cash flow stream from these activities. As of December 31, 2001, the
value of cash flow hedges included in accumulated other comprehensive income was
a net unrealized gain of $256 million, net of income taxes. We estimate that
unrealized gains of $272 million, net of income taxes, will be reclassified from
accumulated other comprehensive income over the next 12 months.
Reclassifications occur upon physical delivery of the hedge commodity and the
corresponding expiration of the hedge. The maximum term of our cash flow hedges
is 12 years; however, most of our cash flow hedges expire within the next 24
months.

Our accumulated other comprehensive income also includes a loss of $23
million, net of income taxes, representing our proportionate share of amounts
recorded in other comprehensive income by our unconsolidated affiliates who use
derivatives as cash flow hedges. Included in this loss is a $10 million loss
that we estimate will be reclassified from accumulated other comprehensive
income over the next 12 months. The maximum term of these cash flow hedges is
two years, excluding hedges related to interest rates on variable debt.

For the year ended December 31, 2001, we recognized a net gain of $3
million, net of income taxes, related to the ineffective portion of all cash
flow hedges.

Foreign Currency Hedges. In our international activities, we have fixed
rate foreign currency denominated debt that exposes us to changes in exchange
rates between the foreign currency and U.S. dollar. In 2001, we used a currency
swap to effectively convert the fixed amounts of foreign currency due under
foreign currency denominated debt to fixed U.S. dollar amounts.

10. INVENTORY

Our inventory consisted of the following at December 31:

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11. PROPERTY, PLANT AND EQUIPMENT

At December 31, 2001 and 2000, we had approximately $2,271 million and
$2,367 million construction work in progress included in our property, plant and
equipment.

In June 2001, we entered into a 20-year lease agreement related to our
Corpus Christi refinery and related assets with Valero Energy Corporation. Under
the lease, Valero pays us a quarterly amount that increases after the second
year of the lease. For the year ended December 31, 2001, we recorded $11 million
in lease income related to this lease. In addition, Valero has the option to
purchase the plant and related assets in 2003 for approximately $294 million,
and a similar option each year thereafter at an annually increasing amount. The
net book value of the plant and related assets was approximately $225 million at
December 31, 2001. Based on the terms, the lease qualified as an operating lease
with total minimum lease payments of $811 million with future minimum lease
payments totaling $797 million; $19 million in 2002; $37 million in 2003; $43
million in each of 2004, 2005 and 2006; and a total of $612 million thereafter.

12. DEBT, OTHER FINANCING OBLIGATIONS AND OTHER CREDIT FACILITIES

At December 31, 2001, our weighted average interest rate on our commercial
paper and short-term credit facilities was 3.2%, and at December 31, 2000, it
was 7.4%. We had the following short-term borrowings and other financing
obligations, at December 31:

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Credit Facilities

We use commercial paper programs to manage our short-term cash
requirements. Under our programs we can borrow up to $3 billion through a
combination of individual corporate, TGP and EPNG commercial paper programs of
$1 billion each.

We maintain a 3-year, $1 billion, revolving credit and competitive advance
facility under which we can conduct short-term borrowings and other commercial
credit transactions. This facility expires in 2003 and El Paso CGP (formerly
Coastal), EPNG and TGP are designated borrowers under the facility. In June
2001, we replaced an existing 364-day revolving credit facility with a renewable
$3 billion, 364-day revolving credit and competitive advance facility. EPNG and
TGP are also designated borrowers under this new facility. The interest rate on
these facilities varies and was based on LIBOR plus 50 basis points at December
31, 2001. No amounts were outstanding under these facilities at December 31,
2001.

In connection with our acquisition of PG&E's Texas Midstream operations in
December 2000, we established a $700 million short-term credit facility, under
which $455 million was outstanding on December 31, 2000. In February 2001, we
borrowed an additional $245 million under the facility. In two separate payments
in March and June 2001, we repaid the outstanding balance of the credit
facility, and the facility was terminated.

We also supplement our commercial paper program with other smaller
short-term credit facilities, some of which were used by Coastal prior to our
merger and which were terminated during the year.

In April 2001, we filed a shelf registration statement with the Securities
and Exchange Commission to sell, from time to time, up to a total of $3 billion
in debt securities, preferred and common stock, medium term notes, or trust
securities. At December 31, 2001, we had approximately $920 million remaining
from this shelf registration statement under which we issued additional
securities in January 2002.

As of December 31, 2001, TGP had $200 million, and SNG had $100 million
under shelf registration statements on file with the Securities and Exchange
Commission.

The availability of borrowings under our credit and borrowing agreements is
subject to specified conditions, which we believe we currently meet. These
conditions include compliance with the financial covenants and ratios required
by such agreements, absence of default under such agreements, and continued
accuracy of the representations and warranties contained in such agreements. Our
senior unsecured debt issues have been given investment grade ratings by S&P and
Moody's.

2002 Activities

In January 2002, we increased our shelf registration statement from $920
million to $1.10 billion and issued $1.10 billion aggregate principal amount of
7.75% medium term notes due 2032. Net proceeds of approximately $1.08 billion,
net of issuance costs, were used to repay short-term borrowings and for general
corporate purposes. This issuance used up the remaining capacity on our previous
shelf registration statement. In February 2002, we filed a new shelf
registration statement with the Securities and Exchange Commission that allows
us to issue up to $3 billion. Under this registration statement we can issue a
combination of debt, equity and other instruments, including trust preferred
securities of El Paso Capital Trust II and El Paso Capital Trust III, trusts
wholly owned by us. If we issue securities from these trusts, we will be
required to issue full and unconditional guarantees on these securities.

Also in January 2002, we retired $100 million aggregate principal amount
7.85% notes and $215 million aggregate principal amount 7.75% notes. In March
2002, we retired $400 million of floating rate notes.

In January 2002, SNG filed a shelf registration statement increasing the
amount of debt it can issue from $100 million to $300 million. In February 2002,
SNG issued $300 million aggregate principal amount of 8.0% notes due 2032. Net
proceeds of approximately $297 million, net of issuance costs, were used for
general corporate purposes. This issuance used the remaining capacity on SNG's
shelf registration statement.

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Our long-term debt and other financing obligations outstanding consisted of
the following at December 31:

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Aggregate maturities of the principal amounts of long-term debt and other
financing obligations for the next 5 years and in total thereafter are as
follows (in millions):

2002........................................................ $ 1,799
2003........................................................ 586
2004........................................................ 1,027
2005........................................................ 561
2006........................................................ 1,276
Thereafter.................................................. 9,441
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Total long-term debt and other financing
obligations, including current maturities........ $14,690
=======

Our zero coupon convertible debentures have a maturity value of $1.8
billion, are due 2021 and have a yield to maturity of 4%. These debentures are
convertible into 8,456,589 shares of our common stock, which is based on a
conversion rate of 4.7872 shares per $1,000 principal amount at maturity. This
rate is equal to a conversion price of $94.604 per share of our common stock.

In October 2001, we borrowed $240 million due in 2004 under a loan
agreement. The loan is collateralized by the lease payments from Valero under
their lease of our Corpus Christi refinery.

In 1999, we issued a total of 18,400,000 FELINE PRIDES(sm) consisting of
17,000,000 Income PRIDES with a stated value of $25 and 1,400,000 Growth PRIDES
with a stated value of $25. The Income PRIDES consist of a unit comprised of a
Senior Debenture and a purchase contract under which the holder is obligated to
purchase from us by no later than August 16, 2002 for $25 (the stated price) a
number of shares of our common stock. The Growth PRIDES consist of a unit
comprised of a purchase contract under which the holder is obligated to purchase
from us by no later than August 16, 2002 for $25 (the stated price) a number of
shares of our common stock and a 2.5% undivided beneficial interest in a
three-year Treasury security having a principal amount at maturity equal to
$1,000. Under the terms of the purchase contract in effect prior to our merger
with Coastal, the number of shares of common stock the holder of a PRIDE
received varied between 0.5384 and 0.6568 shares, depending on the price of
Coastal's common stock.

As a result of our merger with Coastal, and under the terms of the purchase
contract, the number of shares the holder of a PRIDE is entitled and required to
receive upon settlement became fixed at 0.6622 shares of El Paso common stock.
This will result in the issuance of approximately 12.2 million shares of El Paso
common stock.

Our other financing obligations consist of crude oil prepayments received
from third parties in exchange for our agreement to deliver a fixed quantity of
crude oil to a specified delivery point in the future and a production payment
received in exchange for delivery of a fixed quantity of natural gas from our
future production. These agreements, by their terms, can only be settled through
the delivery of the commodity. We have entered into commodity swaps to
effectively lock-in the value of these commitments to the third party upon
delivery of the commodity. We will continue to deliver natural gas under the
production payment agreement according to its terms, but consider these
agreements to be financing arrangements. The carrying cost of the prepayments
and the production payment are recognized as interest expense in our income
statement.

13. SECURITIES OF SUBSIDIARIES AND MINORITY INTERESTS

Over the past three years, we have entered into a number of transactions to
finance our consolidated subsidiaries. In most cases, these have been
accomplished through the sale of preferred interests in these entities, or
through structured financial transactions that are collateralized by the assets
of these subsidiaries. Total amounts outstanding under these programs at
December 31, 2001, were as follows (in millions):

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Consolidated trusts(1)...................................... $ 925
Trinity River............................................... 980
Clydesdale.................................................. 1,000
Preferred stock of subsidiaries............................. 465
Gemstone.................................................... 300
Consolidated partnership.................................... 285
Other....................................................... 58
------
$4,013
======

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

(1) The consolidated trusts are composed of Capital Trust I, Coastal Finance I
and Capital Trust IV.

Capital Trust I. In March 1998, we formed El Paso Energy Capital Trust I
which issued 6.5 million of 4 3/4% trust convertible preferred securities for
$325 million. We own all of the Common Securities of Trust I. Trust I exists for
the sole purpose of issuing preferred securities and investing the proceeds in
4 3/4% convertible subordinated debentures due 2028, their sole asset. We
provide a full and unconditional guarantee of Trust I's preferred securities.
Trust I's preferred securities are reflected as company-obligated preferred
securities of consolidated trusts in our balance sheet. Distributions paid on
the preferred securities are included as minority interest in our income
statement.

Trust I's preferred securities are non-voting (except in limited
circumstances), pay quarterly distributions at an annual rate of 4 3/4%, carry a
liquidation value of $50 per security plus accrued and unpaid distributions and
are convertible into our common shares at any time prior to the close of
business on March 31, 2028, at the option of the holder at a rate of 1.2022
common shares for each Trust I Preferred Security (equivalent to a conversion
price of $41.59 per common share). As of December 31, 2001, we had approximately
6.5 million Trust I preferred securities outstanding.

Coastal Finance I. In May 1998, Coastal completed a public offering of 12
million mandatory redemption preferred securities on Coastal Finance I, a
business trust, for $300 million. Coastal Finance I holds debt securities of
ours purchased with the proceeds of the preferred securities offering.
Cumulative quarterly distributions are being paid on the preferred securities at
an annual rate of 8.375% of the liquidation amount of $25 per preferred
security. The preferred securities are mandatorily redeemable on the maturity
date, May 13, 2038, and may be redeemed at our option on or after May 13, 2003,
or earlier if various events occur. The redemption price to be paid is $25 per
preferred security, plus accrued and unpaid distributions to the date of
redemption.

Capital Trust IV. In May 2000, we formed El Paso Energy Capital Trust IV
which issued $300 million of preferred securities to a third party investor.
These preferred securities pay cash distributions at a floating rate equal to
the three-month LIBOR plus 75 basis points. As of December 31, 2001, the
floating rate was 2.83%. These preferred securities must be redeemed by Trust IV
no later than November 30, 2003. Proceeds from the sale of the securities were
used by Trust IV to purchase a series of our floating rate senior debentures
whose yield and maturity terms mirror those of Trust IV's preferred securities.
The sole assets of Trust IV are these floating rate senior debentures. We
provide a full and unconditional guarantee of all obligations of Trust IV
related to its preferred securities. At the time Trust IV issued the preferred
securities, we also agreed to issue $300 million of equity securities,
including, but not limited to, our common stock in one or more public offerings
prior to May 31, 2003.

Trinity River (also known as Red River). During 1999, we formed a series
of companies that we refer to as Trinity River. Trinity River was formed to
provide financing to invest in various capital projects and other assets. A
third-party investor contributed cash of $980 million into Trinity River during
1999 in exchange for the preferred securities of one of our consolidated
subsidiaries. The third party is entitled to an adjustable preferred return
derived from Trinity River's net income. The preferred interest is
collateralized by a combination of notes payable from us and various fixed
assets, including our Mojave pipeline, Bear Creek Storage, various natural gas
and oil production properties and some of our El Paso Energy Partners common
units. We have the option to acquire the third-party's interest in Trinity River
at any time prior to June 2004.

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If we do not exercise this option or if the agreement is not extended, we could
be required to liquidate the assets supporting this transaction. We account for
the investor's preferred interest in our consolidated subsidiary as a minority
interest in our balance sheet and the preferred return as minority interest
expense in our income statement. The assets, liabilities and operations of
Trinity River are included in our financial statements. If our credit ratings
are downgraded to below investment grade by both S&P and Moody's, we could be
required to liquidate the assets supporting the transaction.

Clydesdale (also known as Mustang). During 2000, we formed a series of
companies that we refer to as Clydesdale. Clydesdale was formed to provide
financing to invest in various capital projects and other assets. A third-party
investor contributed cash of $1 billion into Clydesdale in exchange for the
preferred securities of one of our consolidated subsidiaries. The third party is
entitled to an adjustable preferred return derived from Clydesdale's net income.
The preferred interest is collateralized by a combination of notes payable from
us and various fixed assets, including our Colorado Interstate Gas transmission
system and natural gas and oil properties. We have the option to acquire the
third-party's interest in Clydesdale at any time prior to May 2005. If we do not
exercise this option or if the agreement is not extended, we could be required
to liquidate the assets supporting this transaction. We account for the
investor's preferred interest in our consolidated subsidiary as a minority
interest in our balance sheet and the preferred return as minority interest
expense in our income statement. The assets, liabilities, and operations of
Clydesdale are included in our financial statements. If our credit ratings are
downgraded to below investment grade by both S&P and Moody's, we could be
required to liquidate the assets supporting the transaction.

El Paso Tennessee Preferred Stock. In 1996, El Paso Tennessee Pipeline
Co., our subsidiary, issued 6 million shares of publicly registered 8.25%
cumulative preferred stock with a par value of $50 per share for $300 million.
The preferred stock is redeemable, at the option of El Paso Tennessee, at a
redemption price equal to $50 per share, plus accrued and unpaid dividends, at
any time after January 2002. During the three years ended December 31, 2001,
dividends of approximately $25 million were paid each year on the preferred
stock.

Coastal Securities Company Preferred Stock. In 1996, Coastal Securities
Company Limited, our wholly owned subsidiary, issued 4 million shares of
preferred stock for $100 million. Quarterly cash dividends are being paid on the
preferred stock at a rate based on LIBOR. The preferred shareholders are also
entitled to participating dividends based on various refining margins. Coastal
Securities may redeem the preferred stock for cash at the liquidation price plus
accrued and unpaid dividends.

Coastal Oil & Gas Resources Preferred Stock. In 1999, Coastal Oil & Gas
Resources, Inc., our wholly owned subsidiary, issued 50,000 shares of preferred
stock for $50 million. The preferred shareholders are entitled to quarterly cash
dividends at a rate based on LIBOR. The dividend rate is subject to
renegotiation in 2004 and on each fifth anniversary thereafter. In the event
Coastal Oil & Gas Resources and the preferred shareholders are unable to agree
to a new rate, Coastal Oil & Gas Resources must redeem the shares at $1,000 per
share plus any accrued and unpaid dividends, or cause the preferred stock to be
registered with the Securities and Exchange Commission and remarketed. Coastal
Oil & Gas Resources also has the option to redeem all shares on any dividend
rate reset date for $1,000 per share plus any accrued and unpaid preferred
dividends.

Coastal Limited Ventures Preferred Stock. In 1999, Coastal Limited
Ventures, Inc., our wholly owned subsidiary, issued 150,000 shares of preferred
stock for $15 million. The preferred shareholders are entitled to quarterly cash
dividends at an annual rate of 6%. The dividend rate is subject to renegotiation
in 2004 and on each fifth anniversary thereafter. In the event Coastal Limited
and the preferred shareholders are unable to agree to a new rate, the preferred
shareholders may call for redemption of all of the preferred shares. The
redemption price is $100 per share plus any accrued and unpaid preferred
dividends thereon. Coastal Limited also has the option to redeem all shares on
any rate reset date for $100 per share plus any accrued and unpaid preferred
dividends.

Gemstone. As part of the Gemstone transaction, our wholly owned subsidiary,
Topaz Investors, L.L.C., issued a minority member interest to the third party
investor of Gemstone for $300 million. The third party investor is entitled to a
cumulative preferred return of 8.03% on its interest. The agreements underlying
this
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transaction expire in 2004, or earlier if we sell the international power assets
owned indirectly by Topaz. The minority member interest is redeemable at
liquidation value plus accrued and unpaid dividends.

Consolidated Partnership. In December 1999, Coastal Limited contributed
assets to a limited partnership in exchange for a controlling general
partnership interest. Limited interests in the partnership were issued to
unaffiliated investors for $285 million. The limited partners are entitled to a
cumulative priority return based on LIBOR. The return is subject to
renegotiation in 2004 and on each fifth anniversary thereafter. The partnership
has a maximum life of 20 years, but may be terminated sooner subject to certain
conditions, including failure to agree to a new rate. Coastal Limited may
terminate the partnership at any time by repayment of the limited partners'
outstanding capital plus any unpaid priority returns.

14. COMMITMENTS AND CONTINGENCIES

Legal Proceedings

We and several of our subsidiaries were named defendants in eleven
purported class action, municipal or individual lawsuits, and in one shareholder
derivative lawsuit, filed in the California state courts. The eleven suits
contend that our entities acted improperly to limit the construction of new
pipeline capacity to California and/or to manipulate the price of natural gas
sold into the California marketplace. The shareholder derivative suit contends
that we, through our directors, failed to prevent the conduct alleged in several
of these underlying cases. We have consolidated nine of the eleven suits into a
single San Diego court proceeding, and expect to consolidate the remaining two
suits in the near future. In March 2002, the derivative lawsuit was dismissed in
California, to be refiled in a state court in Houston, Texas. A listing of these
cases is included under the heading Cases below.

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

On August 19, 2000, a main transmission line owned and operated by EPNG
ruptured at the crossing of the Pecos River near Carlsbad, New Mexico. Twelve
individuals at the site were fatally injured. On June 20, 2001, the U.S.
Department of Transportation's Office of Pipeline Safety issued a Notice of
Proposed Violation to EPNG. The Notice alleged five probable violations of its
regulations, proposed fines totaling $2.5 million and proposed corrective
actions. On October 15, 2001, EPNG filed a detailed response with the Office of
Pipeline Safety disputing each of the alleged violations. The alleged five
probable violations of the regulations of the Department of Transportation's
Office of Pipeline Safety are: 1) failure to perform appropriate tasks to
prevent corrosion, with an associated proposed fine of $500,000; 2) failure to
investigate and minimize internal corrosion, with an associated proposed fine of
$1,000,000; 3) failure to consider unusual operating and maintenance conditions
and respond appropriately, with an associated proposed fine of $500,000; 4)
failure to follow company procedure, with an associated proposed fine of
$500,000; and 5) failure to maintain topographical diagrams, with an associated
proposed fine of $25,000. We are cooperating with the National Transportation
Safety Board in an investigation into the facts and circumstances concerning the
possible causes of the rupture. If we are required to pay the proposed fines, it
will not have a material adverse effect on our financial position, operating
results or cash flows. In addition, a number of personal injury and wrongful
death lawsuits were filed against us in connection with the rupture. Several of
these suits have been settled, with payments fully covered by insurance. Seven
Carlsbad lawsuits remain, with one of those seven having reached a contingent
settlement within insurance coverage. A listing of these cases is included under
the heading Cases below.

In May 1999, one of our subsidiaries was named as a defendant in a suit
filed in the 319th Judicial District Court, Nueces County, Texas by an
individual employed by one of our contractors (Rolando Lopez and Rosanna Barton
v. Coastal Refining & Marketing, Inc. and The Coastal Corporation). The suit
sought damages for injuries sustained at the time of an explosion at one of our
refining plants, and was settled in August 2000 for a total payment of $7
million, of which $5 million was covered by insurance. Three of the refinery
employees intervened in the suit and sought damages for injuries sustained in
the explosion. Those claims were tried in August 2000, resulting in a $122
million verdict, for which there is insurance coverage.

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The case has been appealed to the Thirteenth Court of Appeals of Texas, and all
appellate briefing in that court has been completed. Even if the verdict is
upheld on appeal, it will not have a material adverse effect on our financial
position, operating results or cash flows.

In 1997, a number of our subsidiaries were named defendants in actions
brought by Jack Grynberg on behalf of the U.S. Government under the False Claims
Act. Generally, these complaints allege an industry-wide conspiracy to under
report the heating value as well as the volumes of the natural gas produced from
federal and Native American lands, which deprived the U.S. Government of
royalties. These matters have been consolidated for pretrial purposes (In re:
natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District
of Wyoming, filed June 1997). In May 2001, the court denied the defendants'
motions to dismiss.

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

In October 1992, several property owners in McAllen, Texas, filed suit in
the 93rd Judicial District Court, Hidalgo County, Texas, against, among others,
one of our subsidiaries (Timely Adventures, Inc., et al, v. Phillips Properties,
Inc., et al and Garza v. Coastal Mart, Inc.). The suit sought damages for the
alleged diminution of property value and damages related to the exposure to
hazardous chemicals arising from the operation of service stations and storage
facilities. In July 2000, the trial court entered a judgment for approximately
$1.2 million in actual damages for property diminution and approximately $100
million in punitive damages. The judgment was appealed. An agreement in
principle to settle this case has been reached, and we expect the settlement to
be concluded in March 2002. We have established accruals that we believe are
sufficient to provide for the settlement. The settlement will not have a
material adverse effect on our financial position, operating results or cash
flows.

In compliance with the 1990 amendments to the Clean Air Act (CAA), we use
the gasoline additive, methyl tertiary-butyl ether (MTBE), in some of our
gasoline. We also produce, buy, sell and distribute MTBE. A number of lawsuits
have been filed throughout the U.S. regarding MTBE's potential impact on water
supplies. We are currently one of several defendants in five such lawsuits in
New York. Our costs and legal exposure related to these lawsuits and claims are
not currently determinable.

In addition, we and our subsidiaries and affiliates are named defendants in
numerous lawsuits and governmental proceedings that arise in the ordinary course
of our business. For each of these matters, we evaluate the merits of the case,
our exposure to the matter and possible legal or settlement strategies and the
likelihood of an unfavorable outcome. If we determine that an unfavorable
outcome is probable and can be estimated, we make the necessary accruals. As new
information becomes available, our estimates may change. The impact of these
changes may have a material effect on our results of operations. As of December
31, 2001, we had reserves totaling $187 million for all outstanding legal
matters.

While the outcome of the matters discussed above cannot be predicted with
certainty, based on information known to date and our existing accruals, we do
not expect the ultimate resolution of these matters will have a material adverse
effect on our financial position, operating results or cash flows.

Environmental Matters

We are subject to extensive federal, state, and local laws and regulations
governing environmental quality and pollution control. These laws and
regulations require us to remove or remedy the effect on the environment of the
disposal or release of specified substances at current and former operating
sites. As of December 31, 2001, we had a reserve of approximately $555 million
for expected remediation costs, including approximately $526 million for
associated onsite, offsite and groundwater technical studies, and approximately
$29 million for other costs which we anticipate incurring through 2027. In
addition, we expect to make capital

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expenditures for environmental matters of approximately $333 million in the
aggregate for the years 2002 through 2006. These expenditures primarily relate
to compliance with clean air regulations. Our accrued amounts as of December 31,
2001 include a change in our estimated environmental remediation liabilities as
a result of several events that occurred during 2001 and an evaluation of our
operations following the Coastal merger. See a discussion of this change in
estimate under Changes in Accounting Estimates.

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 polychlorinated biphenyls (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 agreed orders with the agency
to resolve many of the issues raised in the complaint and received water
discharge permits from the agency for its Kentucky compressor stations. The
relevant Kentucky compressor stations are being characterized and remediated
under a 1994 consent order with the Environmental Protection Agency (EPA).
Despite these remediation efforts, the agency may raise additional technical
issues or require additional remediation work in the future.

From May 1999 to March 2001, our Coastal Eagle Point Oil Company received
several Administrative Orders and Notices of Civil Administrative Penalty
Assessment from the New Jersey Department of Environmental Protection. All of
the assessments are related to alleged noncompliance with the New Jersey Air
Pollution Control Act pertaining to excess emissions from the first quarter 1998
through the fourth quarter 2000 reported by our Eagle Point refinery in
Westville, New Jersey. The New Jersey Department of Environmental Protection has
assessed penalties totaling approximately $1.1 million for these alleged
violations. Our Eagle Point refinery has been granted an administrative hearing
on issues raised by the assessments and, concurrently, is in negotiations to
settle these assessments.

In February 2002, we received a Notice of Violation from the EPA alleging
noncompliance with the EPA's fuel regulations from 1996 to 1998. The notice
proposes a penalty of $165,000 for these alleged violations. We are
investigating the allegations and are preparing a response.

Since 1988, TGP has been engaged in an internal project to identify and
deal with the presence of PCBs and other substances, including those on the EPA
List of Hazardous Substances, at compressor stations and other facilities it
operates. While conducting this project, TGP has been in frequent contact with
federal and state regulatory agencies, both through informal negotiation and
formal entry of consent orders, to ensure that its efforts meet regulatory
requirements.

In May 1995, following negotiations with its customers, TGP filed a
stipulation and agreement with FERC that established a mechanism for recovering
a substantial portion of the environmental costs identified in its internal
project. The stipulation and agreement was effective July 1, 1995. Refunds may
be required to the extent actual eligible expenditures are less than amounts
collected.

TGP is a party in proceedings involving federal and state authorities
regarding the past use of PCBs in its starting air systems. TGP executed a
consent order in 1994 with the EPA governing the remediation of the relevant
compressor stations and is working with the EPA and the relevant states
regarding those remediation activities. TGP is also working with the
Pennsylvania and New York environmental agencies regarding remediation and
post-remediation activities at the Pennsylvania and New York stations.

We have been designated, have received notice that we could be designated
or have been asked for information to determine whether we could be designated,
as a Potentially Responsible Party (PRP) with respect to 57 active sites under
CERCLA or state equivalents. We have sought to resolve our liability as a PRP at
these CERCLA sites, as appropriate, through indemnification by third parties and
settlements which provide for payment of our allocable share of remediation
costs. As of December 31, 2001, we have estimated our share of the remediation
costs at these sites to be between $66 million and $205 million and have
provided reserves that we believe are adequate for such costs. Since the
clean-up costs are estimates and are subject to revision as more information
becomes available about the extent of remediation required, and because in some
cases we have asserted a defense to any liability, our estimates could change.
Moreover, liability under the federal CERCLA statute is joint and several,
meaning that we could be required to pay in excess of our pro rata share of
remediation costs. Our understanding of the financial strength of other PRPs has
been

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considered, where appropriate, in the determination of our estimated
liabilities. We presently believe that based on our existing reserves, and
information known to date, the impact of the costs associated with these CERCLA
sites will not have a material adverse effect on our financial position,
operating results or cash flows.

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

Rates and Regulatory Matters

In April 2000, the California Public Utilities Commission (CPUC) filed a
complaint with FERC alleging that the sale of approximately 1.2 Bcf/d of
California capacity by EPNG to El Paso Merchant Energy Company, both of whom are
our wholly-owned subsidiaries, was anti-competitive and an abuse of the
affiliate relationship under FERC's policies. Other parties in the proceeding
requested that the original complaint be set for hearing and that Merchant
Energy pay back any profits it earned under the contract. In March 2001, FERC
established a hearing, before an administrative law judge, to address the issue
of whether EPNG and/or Merchant Energy had market power and, if so, had
exercised it. In October 2001, the administrative law judge issued a proposed
decision finding that El Paso did not exercise market power and that the market
power portion of the CPUC's complaint should be dismissed. The decision further
found that El Paso had violated FERC's marketing affiliate regulations. The
judge's proposed decision has been briefed to, and will be effective only if
approved by, the FERC. On October 30, 2001, the Market Oversight and Enforcement
(MOE) section of the FERC's office of the General Counsel filed comments in this
proceeding stating that record development at the trial was inadequate to
conclude that EPNG complied with FERC's regulation. We filed a motion to strike
the MOE's pleading, but in December 2001, the FERC denied our motion and
remanded the proceeding to the administrative law judge for a supplemental
hearing on the availability of capacity at El Paso's California delivery points.
The hearing is set to commence on March 20, 2002.

Two groups of EPNG's customers, those within California and those east of
California, have filed complaints against EPNG with FERC. On July 13, 2001,
twelve parties composed of California customers, natural gas producers and
natural gas marketers, filed a complaint alleging that EPNG's full requirements
contracts with its customers east of California should be converted to contracts
with specific volumetric entitlements, that EPNG should be required to expand
its interstate pipeline system and that firm shippers who experience reductions
in their nominated gas volumes should be awarded demand charge credits. Also, on
July 17, 2001, ten parties, most of which are east of California
full-requirement contract customers, filed a complaint against EPNG with FERC,
alleging that EPNG violated the Natural Gas Act of 1938 and breached its
contractual obligations by failing to expand its system in order to serve the
needs of the full-requirement contract shippers. The complainants have requested
that FERC require EPNG to show cause why it should not be required to augment
its system capacity. On September 10, 2001, the July 17, 2001 complainants filed
a motion for partial summary disposition of their complaint, to which EPNG
responded on September 25, 2001. In addition, on November 13, 2001, one of the
July 17, 2001, complainants submitted a type of settlement proposal that we and
most other parties have opposed. At its March 13, 2002 public meeting, the FERC
Staff made a presentation to the FERC Commissioners recommending that FERC
address the capacity allocation issues raised in these and other related EPNG
proceedings by, among other things, eliminating the full requirements provisions
from all of EPNG's contracts except those in a small customer category and
converting them to contracts with specific volumetric entitlements. The Staff
also recommended scheduling a technical conference. FERC authorized its Staff to
provide notice of a technical conference to be attended by the Commissioners. It
is expected that this conference will be held no later than the spring of this
year.

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In June 2001, the Western Australia regulators issued a draft rate decision
at lower than expected levels for the Dampier-to-Bunbury pipeline owned by EPIC
Energy Australia Trust, in which we have a 33 percent ownership interest and a
total investment, including financial guarantees, of approximately $182 million.
EPIC Energy Australia has appealed a variety of issues related to the draft
decision to the Western Australia Supreme Court. The appeal was heard at the
Western Australia Supreme Court in November 2001 and a decision from the court
is expected in the middle of 2002. If the draft decision rates are implemented,
the new rates will adversely impact future operating results, liquidity and debt
capacity, possibly reducing the value of our investment by up to $122 million.

In September 2001, FERC issued a Notice of Proposed Rulemaking (NOPR). The
NOPR proposes to apply the standards of conduct governing the relationship
between interstate pipelines and marketing affiliates to all energy affiliates.
The proposed regulations, if adopted by FERC, would dictate how all our energy
affiliates conduct business and interact with our interstate pipelines. In
December 2001, we filed comments with the FERC addressing our concerns with the
proposed rules. We cannot predict the outcome of the NOPR, but adoption of the
regulations in substantially the form proposed would, at a minimum, place
additional administrative and operational burdens on us.

While we cannot predict with certainty the final outcome or the timing of
the resolution of all of our rates and regulatory matters, we believe the
ultimate resolution of these issues, based on information known to date, will
not have a material adverse effect on our financial position, results of
operations or cash flows.

Other Matters

In December 2001, Enron Corp. and a number of its subsidiaries, including
Enron North America Corp. and Enron Power Marketing, Inc., filed for Chapter 11
bankruptcy protection in the United States Bankruptcy Court for the Southern
District of New York. We had contracts with Enron North America, Enron Power
Marketing and other Enron subsidiaries for, among other things, the
transportation of natural gas and natural gas liquids, the trading of physical
gas, power, petroleum and financial derivatives. We established reserves for
potential losses related to the receivables from our transportation contracts,
as well as the positions and receivables under our marketing and trading
contracts that we believe are adequate. In addition, we have terminated most of
our trading related contracts as a result of Enron's bankruptcy filings, and are
analyzing our damage claims arising from the Enron bankruptcy proceedings.

Affiliates of Enron hold both short-term and long-term capacity on several
of our pipeline systems. As a result of Enron's bankruptcy filing, we are
uncertain as to their intent to maintain or release this capacity and also as to
their ability to honor the terms of their contracts. Future revenue related to
these capacity contracts will depend upon the outcome of Enron's bankruptcy
proceedings and our ability to re-market any subsequently released pipeline
capacity. While we expect to re-market any such capacity on favorable terms, we
cannot at this time predict that we will be successful in this effort, or that
the rates we will receive will be as high as those we currently earn.

Our foreign investments are subject to risks and unforeseen obstacles that,
in many cases are beyond our control or ability to manage. We attempt to manage
or limit these risks through our due diligence and partner selection processes,
through the denomination of foreign transactions, where possible, in U.S.
dollars, and by maintaining insurance coverage, whenever economical and
obtainable.

We currently have three power plants in Pakistan, with a total investment,
including financial guarantees on these projects, of approximately $271 million.
While we are aware of no specific threats or actions against these power plants,
events in that region, including possible retaliation for American military
actions, could impact these projects and our related investments. At this time,
we believe that through a combination of commercial insurance, political
insurance and rights under contractual obligations, our financial exposure in
Pakistan from acts of war, hostility, terrorism or political instability is not
material. It is possible, however, that new information, future developments in
the region, or the inability of a party or parties to fulfill their contractual
obligations could cause us to reassess our potential exposure.

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We also have investments in oil and natural gas, power and pipeline
projects in Argentina with an aggregate investment, including financial
guarantees, of approximately $381 million. Economic conditions in Argentina have
significantly deteriorated during 2001, and the Argentine government has
recently defaulted on its public debt obligations. In addition, the government
has imposed several changes in law in the first quarter of 2002, including: (i)
repeal of the one-to-one exchange rate for the Argentine Peso with U.S. dollar;
(ii) a mandate that all contracts and obligations previously denominated in U.S.
dollars be re-negotiated and denominated in Argentine Pesos; and (iii) a tax
imposed on hydrocarbon and potentially on electric power exports. The Argentine
Peso devaluation, combined with the new law changes, effectively convert our
projects' contracts from U.S. dollars to Argentine Pesos and will result in a
significant reduction in the value of our investments in Argentina. We are
monitoring the situation closely and will pursue all options available to us
under our political risk insurance policies and under the international
arbitration provisions of the United States -- Argentina Bilateral Investment
Treaty. Despite the current actions by project management and the options
available to us that may mitigate our exposure, we may be required to write down
our investment by a substantial amount in the first quarter of 2002.

Cases

The California cases discussed above are: five filed in the Superior Court
of Los Angeles County (Continental Forge Company. et al v. Southern California
Gas Company, et al, filed September 25, 2000; Berg v. Southern California Gas
Company, et al; filed December 18, 2000; County of Los Angeles v Southern
California Gas Company, et al, filed January 8, 2002; The City of Los Angeles,
et al v. Southern California Gas Company, et al and The City of Long Beach, et
al v. Southern California Gas Company, et al, both filed March 20, 2001); two
filed in the Superior Court of San Diego County (John W.H.K. Phillip v. El Paso
Merchant Energy; and John Phillip v. El Paso Merchant Energy, both filed
December 13, 2000); three filed in the Superior Court of San Francisco County
(Sweetie's et al v. El Paso Corporation, et al, filed March 22, 2001; Philip
Hackett, et al v. El Paso Corporation, et al, filed May 9, 2001; and California
Dairies, Inc., et al v. El Paso Corporation, et al, filed May 21, 2001); and one
filed in the Superior Court of the State of California, County of Alameda (Dry
Creek Corporation v. El Paso Natural Gas Company, et al, filed December 10,
2001). The shareholder derivative suit now dismissed was styled Clark, et al v.
Allumbaugh, et al, Superior Court of Orange County, filed August 23, 2001.

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

Capital Commitments, Purchase and other Obligations

At December 31, 2001, we had capital and investment commitments of $2.4
billion primarily relating to our production, pipeline, and international power
activities. Our other planned capital and investment projects are discretionary
in nature, with no substantial capital commitments made in advance of the actual
expenditures. Our pipelines have entered into unconditional purchase obligations
for products and services totaling $346 million at December 31, 2001. The annual
obligations under these agreements are $34 million for 2002, $32 million for
2003, $34 million for each of the years 2004, 2005 and 2006, and $178 million in
total thereafter.

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Operating Leases

We maintain operating leases in the ordinary course of our business
activities. These leases include those for office space and operating facilities
and office and operating equipment, and the terms of the agreements vary from
2002 until 2053. As of December 31, 2001, our total commitments under operating
leases were approximately $677 million.

Under several of our leases, we have provided residual value guarantees to
the lessor. Under these guarantees, we can either choose to purchase the asset
at the end of the lease term for a specified amount, which is typically equal to
the outstanding loan amounts owed by the lessor, or we can choose to assist in
the sale of the leased asset to a third party. Should the asset not be sold for
a price that equals or exceeds the amount of the guarantee, we would be
obligated for the shortfall. The levels of our residual value guarantees range
from 86.0 percent to 89.9 percent of the original cost of the leased assets. For
the total outstanding residual value guarantees on our operating leases at
December 31, 2001, see Residual Value Guarantees below.

Minimum annual rental commitments at December 31, 2001, were as follows:

Aggregate minimum commitments have not been reduced by minimum sublease
rentals of approximately $16 million due in the future under noncancelable
subleases.

Rental expense on our operating leases for the years ended December 31,
2001, 2000, and 1999 was $147 million, $198 million, and $157 million.

Lines of Credit

We have a commitment to loan Mesquite, a subsidiary of Chaparral and our
affiliate, up to $725 million. As of December 31, 2001, Mesquite had borrowed
$552 million under this facility, resulting in undrawn commitment of $173
million. The interest rate on the facility is based on LIBOR plus a margin, and
was 2.64% at December 31, 2001.

Letters of Credit

We enter into letters of credit in the ordinary course of our operating
activities. As of December 31, 2001, we had outstanding letters of credit of
$465 million related to our marketing and trading activities, our domestic power
development and other operating activities.

Guarantees

Our involvement in joint ventures and project level construction and
finance results in the issuance of financial and non-financial guarantees in our
business activities. We also guarantee performance and contractual commitments
of companies within our consolidated group. There are various events and
circumstances that may require us to perform under our guarantees, including:

- non-payment by the guaranteed party;

- non-compliance with the covenants of the transactions by the guaranteed
party;

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- non-compliance by us with the provision of guarantees; and

- cross-acceleration with other transactions.

As of December 31, 2001, we had approximately $1.5 billion of guarantees in
connection with our international development and operating activities not
consolidated on our balance sheet and approximately $1.9 billion of guarantees
in connection with domestic development and operating activities not
consolidated on our balance sheet. Of these amounts, approximately $950 million
relates to our Gemstone investment and $1.0 billion relates to our Chaparral
investment.

Residual Value Guarantees

As of December 31, 2001, we have $738 million of residual value guarantees
supporting our operating leases. These leases expire in 2002 and 2006.

Other Commercial Commitments

From May to October 2001, we entered into agreements to time charter four
separate ships to secure transportation for our developing liquefied natural gas
business. The agreements provide for deliveries of vessels between 2003 to 2005.
Each time charter has a 20-year term commencing when the vessels are delivered
with the possibility of two 5-year extensions. The total commitment under the
four time charter agreements is $1.8 billion.

15. RETIREMENT BENEFITS

Pension Benefits

We maintain a defined benefit pension plan that covers substantially all of
our U.S. employees and provides benefits under a cash balance formula. Employees
who were participating in El Paso's defined benefit pension plan on December 31,
1996 receive the greater of cash balance benefits or prior plan benefits accrued
through December 31, 2001. Effective January 1, 2000, Sonat's pension plan was
merged into our pension plan. Sonat employees who were participants in the Sonat
pension plan on December 31, 1999 receive the greater of cash balance benefits
or the Sonat plan benefits accrued through December 31, 2004.

Prior to our merger with Coastal, Coastal provided non-contributory pension
plans covering substantially all of its U.S. employees. On April 1, 2001,
Coastal's primary plan was merged into our existing plan. Coastal employees who
were participants in Coastal's primary plan on March 31, 2001 receive the
greater of cash balance benefits or the Coastal plan benefits accrued through
March 31, 2006.

Following our mergers with Coastal and Sonat, we offered an early
retirement incentive program for eligible employees of these organizations.
These programs offered enhanced pension benefits to individuals who elected
early retirement. Charges incurred in connection with the Sonat program were $8
million and those in connection with the Coastal program were $152 million.

Plan assets of Coastal's pension plan included Coastal's common stock and
Class A common stock, amounting to a total of 8.9 million shares, after
conversion, at December 31, 2000 and 1999. In addition to Coastal's primary
pension plan, separate plans were provided to employees of our coal and
convenience store operations. We also participate in several multi-employer
pension plans for the benefit of our employees who are union members. Our
contributions to these plans were not material for 2001 or 2000.

Retirement Savings Plan

We maintain a defined contribution plan covering all of our U.S. employees.
We match 75 percent of participant basic contributions of up to 6 percent, with
the matching contribution being made to the plan's stock fund. Participants can
elect to move the matching contribution at any time into any of the seven
remaining funds or leave them in the stock fund. Prior to our merger, Coastal
matched 100 percent of basic contributions of up to 8 percent with matching
contributions made in Coastal stock. Amounts expensed under

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these combined plans were approximately $30 million, $35 million and $36 million
for the years ended December 31, 2001, 2000 and 1999.

Other Postretirement Benefits

We provide postretirement medical benefits for ANR Coal and closed groups
of retired employees of EPNG, El Paso Tennessee, Sonat, and Coastal, and limited
postretirement life insurance benefits for current and retired employees. Other
postretirement employee benefits (OPEB) are prefunded to the extent such costs
are recoverable through rates. To the extent actual OPEB costs for TGP, EPNG or
SNG differ from the amounts recovered in rates, a regulatory asset or liability
is recorded.

Under our early retirement incentive program for Coastal employees,
participating eligible employees were allowed to keep postretirement medical and
life benefits commencing at the later of age 50 or retirement. Total charges
associated with the Coastal incentive program and the elimination of retiree
benefits for future retirees were $65 million. Under our early retirement
incentive program for employees of PG&E's Texas Midstream operations,
participating eligible employees were allowed to keep postretirement medical and
life benefits commencing at the later of age 55 or retirement. The total
liabilities for this incentive program were $8 million.

Medical benefits for these closed groups of retirees may be subject to
deductibles, co-payment provisions, and other limitations and dollar caps on the
amount of employer costs. We reserve the right to change these benefits.

The following table sets forth the change in benefit obligation, change in
plan assets, reconciliation of funded status and components of net periodic
benefit cost for pension benefits and other postretirement benefits. Our
benefits are presented and computed as of and for the twelve months ended
September 30. Coastal's 2000 and 2001 disclosure information was determined as
of and for the twelve months ended December 31, 2000 and September 30, 2001.

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Included in the above information are plans in which the projected benefit
obligation and accumulated benefit obligation for pension plans with accumulated
benefit obligations in excess of plan assets were $51 million and $47 million as
of December 31, 2001, and $50 million and $41 million as of December 31, 2000.
Accrued benefit costs related to these plans for the years ended December 31,
2001 and 2000 were $61 million and $51 million.

The current liability portion of the postretirement benefits was $46
million as of December 31, 2001 and 2000. Benefit obligations are based upon
actuarial estimates as described below. Where these assumptions differed,
average rates have been presented.

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Actuarial estimates for our postretirement benefits plans assumed a
weighted average annual rate of increase in the per capita costs of covered
health care benefits of 9.5 percent in 2001, gradually decreasing to 6 percent
by the year 2008. Assumed health care cost trends have a significant effect on
the amounts reported for other postretirement benefit plans. A one-percentage
point change in assumed health care cost trends would have the following
effects:

16. CAPITAL STOCK

In December 2001, we issued 20.3 million shares of common stock for
approximately $863 million (net of issuance costs).

We have 50,000,000 shares of authorized preferred stock, par value $0.01
per share, of which 7,500,000 shares have been designated as Series A Junior
Participating Preferred Stock and reserved for issuance pursuant to our
preferred stock purchase rights plan. In March 2000, we issued 200,000 shares of
El Paso Series B Mandatorily Convertible Single Reset Preferred Stock in
connection with the issuance of the Chaparral third party notes. In November
2001, we also issued 190,000 shares of El Paso Series C Mandatorily Convertible
Single Reset Preferred Stock in connection with the issuance of the Gemstone
third party notes. Each of the Chaparral and Gemstone preferred stock issuances
were to separate share trusts that we own and, therefore, are not reflected as
preferred stock issuances in our financial statements.

17. STOCK-BASED COMPENSATION

We grant stock awards under various stock option plans. We account for our
stock option plans using Accounting Principles Board Opinion No. 25 and its
related interpretations. Under our employee plans, we may issue incentive stock
options on our common stock (intended to qualify under Section 422 of the
Internal Revenue Code), non-qualified stock options, restricted stock, stock
appreciation rights (SARs), phantom stock options, and performance units. Under
our non-employee director plans, we may issue non-qualified stock options and
deferred shares of common stock. We have reserved approximately 74 million
shares of common stock for existing and future stock awards. As of December 31,
2001, approximately 26 million shares remained unissued.

Non-qualified Stock Options

We granted non-qualified stock options to our employees in 2001, 2000, and
1999. Our stock options have contractual terms of 10 years and generally vest
after completion of one to five years of continuous employment from the grant
date. We also granted options to non-employee members of the Board of Directors

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at fair market value on the grant date that are exercisable immediately. A
summary of our stock options and stock options outstanding as of December 31,
2001, 2000, and 1999 is presented below:

The fair value of each stock option granted is estimated on the date of
grant using the Black-Scholes option-pricing model with the following
weighted-average assumptions:

The Black-Scholes weighted average fair value of options granted during
2001, 2000 and 1999 was $15.75, $10.16, and $11.42.

Pro Forma Net Income and Net Income Per Common Share

Had the compensation expense for our stock-based compensation plans been
determined applying the provisions of SFAS No. 123, our net income and net
income per common share for 2001, 2000 and 1999 would approximate the pro forma
amounts below:

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The effects of applying SFAS No. 123 in this pro forma disclosure are not
indicative of future amounts. SFAS No. 123 does not apply to awards granted
prior to the 1995 fiscal year.

Restricted Stock

Under our stock-based compensation plans, a limited number of shares of
restricted common stock may be granted to our officers and employees. These
shares carry voting and dividend rights; however, sale or transfer of the shares
is restricted. These restricted stock awards vest over a specific period of time
and/or if we achieve established performance targets. Restricted stock awards
representing 2.3 million, 0.4 million, and 1.4 million shares were granted
during 2001, 2000 and 1999 with a weighted average grant date fair value of
$62.10, $34.82 and $35.10 per share. At December 31, 2001, 4.3 million shares of
restricted stock were outstanding. The value of restricted shares subject to
performance vesting is determined based on the fair market value on the date
performance targets are achieved, and this value is charged to compensation
expense ratably over the required service or restriction period. The value of
time vested restricted shares is determined at their issuance date and this cost
is amortized to compensation expense over the period of service. For 2001, 2000,
and 1999, these charges totaled $144 million, $13 million, and $69 million.
Included in deferred compensation at December 31, 2000, is $69 million related
to options that will be converted automatically into common stock at the end of
their vesting period. These options met all performance targets in December
2000.

Performance Units and Phantom Stock Options

We award eligible employees phantom stock options that are payable in cash.
We also award eligible employees and officers performance units that are payable
in cash or stock at the end of the vesting period. The final value of the
performance units may vary according to the plan under which they are granted,
but is usually based on our common stock price at the end of the vesting period
or total shareholder return during the vesting period. The value of the
performance units is charged ratably to compensation expense over the vesting
period with periodic adjustments to account for the fluctuation in the market
price of our stock or changes in expected total shareholder return. Amounts
charged to compensation expense in 2001, 2000 and 1999 were $64 million, $25
million and $30 million. Our 2001 expense includes a $51 million charge to pay
out all of our outstanding phantom stock options. Included in the 1999 amount is
$22 million related to the accelerated vesting of the performance units due to
the change in control resulting from the merger with Sonat.

Employee Stock Purchase Program

In October 1999, we implemented an employee stock purchase plan under
Section 423 of the Internal Revenue Code. The plan allows participating
employees the right to purchase common stock on a quarterly basis at 85 percent
of the lower of the market price at the beginning of the plan period or at the
end of each calendar quarter. Two million shares of common stock are authorized
for issuance under this plan.

The following table presents the number of shares issued and the price per
share by quarter for the year ended December 31:

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(1) Since many employees reached the maximum contribution that is imposed by
Section 423 of the Internal Revenue Code in the third quarter of 2001, they
were excluded from participating in the fourth quarter of 2001.

Funds we receive under this program may be used for general corporate
purposes. However, we record a liability for the withholdings not yet applied
towards the purchase of common stock. We bear all expenses associated with
administering the plan, except for costs, including any applicable taxes,
associated with the participants' sale of common stock.

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18. SEGMENT INFORMATION

Our business activities are segregated into four segments: Pipelines,
Merchant Energy, Production, and Field Services. These segments are strategic
business units that offer a variety of different energy products and services.
We manage each segment separately as each business requires different technology
and marketing strategies.

Our Pipelines segment provides natural gas transmission services in the
U.S. and internationally. We conduct our activities through seven wholly owned
and eight partially owned interstate transmission systems along with six
underground natural gas storage facilities and a LNG terminalling facility. Our
pipeline operations also 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 Merchant Energy segment is involved in a broad range of energy-related
activities, including asset ownership, customer origination, marketing and
trading and financial services. We buy, sell and trade natural gas, power, crude
oil, refined products, coal and other energy commodities throughout the world,
and own or have interests in 95 power generation plants in 20 countries.

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. Production has onshore and coal seam
operations and properties in 19 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.

Our Field Services segment provides wellhead-to-mainline services,
including natural gas gathering, products extraction, fractionation,
dehydration, purification, compression and transportation of natural gas and
natural gas liquids. Field Services' assets are located in the San Juan Basin,
the Rocky Mountains, east and south Texas, the Mid-Continent, Permian Basin, the
Gulf of Mexico and Louisiana.

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The accounting policies of the individual segments are the same as those
described in Note 1. Since earnings on equity investments can be a significant
component of earnings in several of our segments, we have chosen to evaluate
segment performance based on earnings before interest and taxes (EBIT) instead
of operating income. To the extent practicable, results of operations for the
years ended December 31, 2000 and 1999 have been reclassified to conform to the
current business segment presentation, although such results are not necessarily
indicative of the results which would have been achieved had the revised
business segment structure been in effect during that period.

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(1) Includes Corporate and Other and eliminations as well as retail operations
through June 2001 and telecommunications operations which has not had
significant activity. We sold a majority of our retail operations in 2001.

(2) The increase in intersegment revenue from 2000 to 2001 for our Production
segment is primarily due to the consolidation of Engage in September 2000.

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(1) Includes Corporate and Other and eliminations as well as retail operations
and telecommunications operations which has not had significant activity.

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

(1) Includes Corporate and Other and eliminations as well as retail operations.

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The reconciliations of EBIT to income before extraordinary items and the
cumulative effect of accounting change are presented below for each of the three
years ended December 31:

We had no customers whose revenues exceeded 10 percent of our total
revenues in 2001, 2000 and 1999.

19. SUPPLEMENTAL CASH FLOW INFORMATION

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

See Note 2 for a discussion of the non-cash investing transactions related
to our acquisitions.

20. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES

We hold investments in various unconsolidated affiliates which are
accounted for using the equity method of accounting. Our principal equity method
investees are international pipelines, interstate pipelines, power generation
plants, and gathering systems. Our investment balance includes unamortized
purchase price differences of $393 million and $402 million as of December 31,
2001 and 2000 that are being amortized over the remaining life of the
unconsolidated affiliate's underlying assets. Our net ownership interest,
investments in and advances to our unconsolidated affiliates are as follows as
of December 31:

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(1) Mesquite Investors, LLC is included in Chaparral.
(2) Citrus corporation owns 100 percent of Florida Gas Transmission System.
(3) Our ownership interest consists of a one percent general partner interest,
26 percent of the partnership's common units and preferred units with $143
million liquidation value.
(4) Denotes investments less than $50 million.
(5) Contributed to Gemstone in 2001.

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Earnings from our unconsolidated affiliates are as follows for each of the
three years ended December 31:

As discussed in Note 2, we have divested our ownership interest in the
Empire State, Iroquois, Stingray, and U-T offshore pipeline systems.

In October 2000, we terminated the Engage joint venture that was formed in
1997. As a result, the operations were divided into separate entities that are
owned and operated independently by each former joint venture partner.

Summarized financial information of our proportionate share of
unconsolidated affiliates below includes affiliates in which we hold a less than
50 percent interest as well as those in which we hold a greater than 50 percent
interest. Our proportional shares of the unconsolidated affiliates in which we
hold a greater than 50 percent interest had net income of $38 million and $48
million for December 31, 2001 and 2000 and total assets of $766 million and $589
million for December 31, 2001 and 2000.

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The following table shows revenues and charges from our unconsolidated
affiliates:

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(1) The decrease in 2001 affiliated revenue and cost of sales is due primarily
to the consolidation of Engage in September 2000.

Chaparral

During 1999, we formed a series of companies with a third-party financial
investor that we refer to as Chaparral. Chaparral (also known as Electron) was
formed to obtain low cost financing to fund the growth of our unregulated
domestic power generation and related businesses. Chaparral has acquired and
currently owns equity interests in 39 natural gas-fired generation facilities in
Arizona, California, Colorado, Connecticut, Florida, Massachusetts, Nevada, New
Jersey, New York, Pennsylvania and Rhode Island. Chaparral also owns several
operating companies that provide the services required to operate and maintain
these facilities and a natural gas service company that provides fuel
procurement services to eight of Chaparral's natural gas-fired generation
facilities in California.

Total third party capital in Chaparral was $1.15 billion, including $0.12
billion contributed in 1999 and $1.03 billion contributed in 2000, of which $1.0
billion was debt raised in 2000 by the third party investor through a note
issuance that matures in March 2003.

We have entered into various financing transactions with Chaparral and its
subsidiaries each year, which include capital contributions, debt issuances and
advances.

The following table summarizes the presentation of these transactions on
our balance sheet at December 31 (in millions):

We account for our equity investment in Chaparral using the equity method
of accounting since we do not have the ability to exercise control over the
entity. The debt securities, notes payable and receivable,

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revolving credit facility, and contingent interest promissory notes are included
in current and long-term receivables and payables from unconsolidated
affiliates, as appropriate, with the related interest as interest income or
expense in our income statement.

The debt securities payable to Chaparral are payable on demand and carry a
fixed interest rate of 7.443%. The notes payable and receivable from Chaparral
are payable on demand and carry various fixed interest rates. The credit
facility was established in 1999 and allows Chaparral to borrow up to $725
million from us at a variable interest rate, which was 2.6% at December 31,
2001.

The contingent interest promissory notes carry a variable interest rate not
to exceed 12.75% and mature in 2019 through 2021. The interest payments are
contingent on cash flow distributions from five power plant investments we own,
with the principal repayment being guaranteed by us. If we sell these
investments, the maturity date of the notes may be accelerated.

Chaparral has used our funds and the funds raised from the third-party
financial investors to acquire the domestic power generation and related
businesses described above. In some cases, Chaparral acquired these power
generation assets from us. Chaparral acquired power generation assets from us
with a value of $276 million and $659 million in 2001 and 2000, which we
determined to be a fair and reasonable amount. We did not recognize any gains or
losses on those transactions.

In addition to the financing transactions described above, we have also
entered into various contractual agreements with Chaparral related to management
and trading activities.

We serve as manager of Chaparral under a management agreement that expires
in 2006. We are compensated for the services we provide through an annual
performance-based management fee, which amounted to $147 million in 2001 and $80
million in 2000. This performance-based management fee is calculated based on
the value of Chaparral's assets as determined using cash flow techniques. We
also receive a fixed fee reimbursement for out-of-pocket and third-party
expenses we incurred on behalf of Chaparral, which was $20 million for 2001 and
2000.

Our Merchant Energy segment also enters into various contractual agreements
with Chaparral and its operating subsidiaries in conjunction with Chaparral's
operations. These include agreements to (i) supply natural gas or other fuels to
power Chaparral's facilities; (ii) purchase all or a portion of the power
produced by Chaparral's facilities; (iii) provide some or all of the power
supply that Chaparral is obligated to provide to fulfill agreements it has with
third parties; (iv) purchase tolling rights; and (v) provide other services to
Chaparral related to its operations. We account for these agreements as trading
price risk management activities and recognized revenues of $266 million and
$119 million in 2001 and 2000 and costs of sales of $121 million and $42 million
in 2001 and 2000 related to these transactions.

As additional credit support for Chaparral's notes, we issued mandatorily
convertible preferred stock with an aggregate liquidation preference of $1
billion to a share trust we control. Upon the occurrence of negative events,
including a decline in our stock price below $27.07 for ten consecutive trading
days coupled with downgrades in our credit ratings to below investment grade, we
could be required to remarket our preferred stock on terms that are designed to
generate a sufficient amount of cash to repay the third party investor's debt.

Gemstone

In November 2001, we formed with a third-party financial investor a series
of companies that we refer to as Gemstone. Gemstone was formed to provide a
financing vehicle through which we fund the development and growth of our power
generation, merchant energy, and related businesses in Brazil.

The third party financial investor contributed into Gemstone $50 million in
capital and raised an additional $950 million through a note issuance that
matures in October 2004. The proceeds were used by Gemstone to acquire a
Brazilian power investment, invest $300 million in preferred securities of one
of our consolidated subsidiaries and temporarily invest excess proceeds of $462
million in short-term notes from us. Our debt securities had an outstanding
balance of $346 million at December 31, 2001, are payable on demand

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and carry a fixed interest rate of 5.25%. The preferred securities of our
subsidiary entitle Gemstone to a preferred return of 8.03%.

We contributed $280 million in cash as well as several Brazilian
investments with a total value of $274 million in exchange for our interest in
Gemstone. Through Gemstone, we received approximately $762 million in cash
through the issuance of our debt securities and preferred securities to Gemstone
from which were used to acquire an interest in electric generation assets in
Brazil and for general corporate purposes.

Our investment in Gemstone as of December 31, 2001, is $555 million, and we
account for our investment using the equity method of accounting since we do not
have the ability to exercise control over the entity. The short-term notes we
issued are included in short-term borrowings in our balance sheet, with the
related interest as interest expense in our income statement. We account for the
investor's preferred interest in our consolidated subsidiary as a minority
interest in our balance sheet and the preferred return as minority interest
expense in our income statement.

Under our management agreement with Gemstone, we earn a cost-based
management fee. This fee was not significant in 2001. We have also entered into
a participation agreement with one of Gemstone's power generation interests
whereby we earn a fee for managing, constructing, and operating the related
facilities and marketing and distributing the energy produced by these
facilities. This fee was not significant in 2001.

As additional credit support for Gemstone's notes, we issued mandatorily
convertible preferred stock with an aggregate liquidation preference of $950
million to a share trust we control. Upon the occurrence of negative events,
including a decline in our stock price below $36.16 for ten consecutive trading
days coupled with downgrades in our credit ratings to below investment grade, we
could be required to remarket our preferred stock on terms that are designed to
generate a sufficient amount of cash to repay the third party investor's debt.

Photon

During 2000, we contributed $44 million of equity capital and assets to a
series of companies we refer to as Photon. Photon acquired and held
telecommunications assets. A third party financial investor contributed $60
million to Photon and earned a preferred return. We had a subordinated
promissory note receivable from Photon and a demand note payable to Photon with
a net receivable balance of approximately $33 million at December 31, 2000 that
was paid in 2001.

During 2001, we acquired the third-party interest for a fair value of $63
million. We accounted for this acquisition as a purchase reflecting the carrying
amount of Photon's assets and liabilities in our consolidated financial
statements.

El Paso Energy Partners

During the third quarter of 2000, El Paso Energy Partners completed a
public offering of 4.6 million common units. The offering reduced our common
units ownership interest from 32.5 percent to 27.8 percent. This transaction had
no effect on our general partner interest or our non-managing member interest.
Also, in the third quarter, we received $170 million of Series B preference
units in exchange for the sale of the natural gas storage businesses of Crystal
Gas Storage, Inc., our wholly owned subsidiary, to El Paso Energy Partners.
These preference units accrue dividends at a rate of 10% on a cumulative basis,
and are redeemable at the option of El Paso Energy Partners.

In 2001, as a result of our merger with Coastal, El Paso Energy Partners
sold its interest in several offshore assets including seven natural gas
pipeline systems, a dehydration facility and two offshore platforms. Proceeds
from these sales were approximately $135 million and resulted in a loss to the
partnership of approximately $25 million. As consideration for these sales, we
committed to pay El Paso Energy Partners a series of payments totaling $29
million, and were required to contribute $40 million to a trust related to one
of the assets sold by El Paso Energy Partners. These payments have been recorded
as merger-related costs.

120

In March 2001, El Paso Energy Partners issued 2.3 million common units
reducing our ownership interest in the common units to 26 percent. In October
2001, the partnership issued 5.6 million common units, of which we purchased 1.5
million units maintaining our common unit ownership interest at 26 percent.
Also, in October 2001, the partnership redeemed $50 million liquidation value of
the Series B preference units we received in the Crystal transaction. At
December 31, 2001, the liquidation value of the remaining Series B preference
units was $143 million.

As the general partner, we perform substantially all of the daily
operations and provide strategic direction for El Paso Energy Partners. We have
a management agreement and other operating agreements with El Paso Energy
Partners that provide for the reimbursement of various operational, financial,
accounting and administrative services that we perform for the partnership. The
management agreement expires on June 30, 2002, and may be terminated thereafter
upon a 90-day notice by either party. We recorded total reimbursements of $34
million and $22 million in 2001 and 2000.

In addition to the activities described above, we enter into transactions
with El Paso Energy Partners in the normal course of business for the sale of
natural gas and for services such as transportation and fractionation, storage,
processing and other types of operational services. These activities are based
on the same terms as our non-affiliates. We recognized revenues of $34 million
and $17 million in 2001 and 2000 and cost of sales of $56 million and $26
million in 2001 and 2000.

21. SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Financial information by quarter is summarized below:

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

(1) Adjustments were made to conform the accounting presentation of Coastal to
our presentation and include reclassifications to conform to our current
presentation. These reclassifications had no impact on our net income or
retained earnings.

22. SUPPLEMENTAL NATURAL GAS AND OIL OPERATIONS (UNAUDITED)

At December 31, 2001, we had interests in natural gas and oil properties in
19 states and offshore operations and properties in federal and state waters in
the Gulf of Mexico. Internationally, we have a limited number of natural gas and
oil properties in Brazil, Canada and Indonesia as well as exploration and
production rights in Australia, Bolivia, Brazil, Canada, Hungary, Indonesia and
Turkey.

For purposes of the Supplemental Natural Gas and Oil Operations disclosure,
we have presented reserves, standardized measure of discounted future net cash
flows and the related changes in standardized measure separately for natural gas
systems operations which includes the regulated natural gas and oil properties
owned by Colorado Interstate Gas Company and its subsidiaries. The Supplemental
Natural Gas and Oil Operations disclosure does not include any value for natural
gas systems storage gas and liquids volumes managed by our pipeline segment.

122

Capitalized costs relating to natural gas and oil producing activities and
related accumulated depreciation, depletion and amortization were as follows at
December 31 (in millions):

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

(1) Includes international operations in Brazil and Indonesia.

Costs incurred in natural gas and oil producing activities, whether
capitalized or expensed, were as follows at December 31 (in millions):

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

(1) Includes international operations in Brazil and Indonesia.

Presented below is an analysis of the capitalized costs of natural gas and
oil properties by year of expenditure that are not being amortized as of
December 31, 2001, pending determination of proved reserves.

123

Capitalized interest of $51 million, $25 million, and $2 million for the years
ended December 31, 2001, 2000 and 1999 is included in the presentation below (in
millions):

Projects presently excluded from amortization are in various stages of
evaluation. The majority of these costs are expected to be included in the
amortization calculation in the years 2002 through 2005. Total amortization
expense per Mcfe, including ceiling test charges, was $1.22, $1.00, and $1.64 in
2001, 2000, and 1999. Excluding ceiling test charges, amortization expense would
have been $1.04 and $0.91 per Mcfe in 2001 and 1999. Depreciation, depletion,
and amortization excludes provisions for the impairment of international
projects of $15 million in 2000 and $10 million in 1999.

All of our proved properties, with the exception of the proved reserves in
Brazil and Indonesia, are located in North America (U.S. and Canada).

124

Net quantities of proved developed and undeveloped reserves of natural gas
and liquids, including condensate and crude oil, and changes in these reserves
are presented below. These reserves include 124,158, 197,782 and 259,342 MMcfe
of production delivery commitments under financing arrangements that extend
through 2005. Total proved reserves on the fields with this dedicated production
were 1,981,239 MMcfe. In addition, this table excludes Production's 50 percent
interest in UnoPaso (Pescada in Brazil), Merchant Energy's 50 percent equity
interest in Sengkang in Indonesia, Merchant Energy's 45 percent and 24.75
percent equity interest in CAPSA and CAPEX in Argentina, and Field Services' 27
percent equity interest in El Paso Energy Partners. Combined proved reserve
balances for these equity interests include natural gas reserves of 361,997 MMcf
and liquids reserves of 44,711 MBbls, both net of our ownership interests.

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

(1) Includes international operations in Brazil and Indonesia.

(2) Includes natural gas and oil properties owned by Colorado Interstate Gas
Company and its subsidiaries.

(3) 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.

125

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

(1) Includes oil, condensate, and natural gas liquids.

(2) Includes international operations in Brazil and Indonesia.

(3) Includes natural gas and oil properties owned by Colorado Interstate Gas
Company and its subsidiaries.

(4) 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.

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 our 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 significant changes to reserves, other than purchases, sales or
production, are due to reservoir performance in existing fields and from
drilling additional wells in existing fields. There have been no major
discoveries or other events, favorable or adverse, that may be considered to
have caused a significant change in the estimated proved reserves since December
31, 2001.

126

Results of operations from producing activities by fiscal year were as
follows at December 31 (in millions):

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

(1) Includes international operations in Brazil and Indonesia.

127

The standardized measure of discounted future net cash flows relating to
proved natural gas and oil reserves follows at December 31 (in millions):

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

(1) Includes international operations in Brazil and Indonesia.

(2) Includes natural gas and oil properties owned by Colorado Interstate Gas
Company and its subsidiaries.

For the calculations in the preceding table, estimated future cash inflows
from estimated future production of proved reserves were computed using year-end
market natural gas and oil prices. We may receive amounts different than the
standardized measure of discounted cash flow for a number of reasons, including
price changes and the effects of our hedging activities.

We do not rely upon the standardized measure when making investment and
operating decisions. These decisions are based on various factors including
probable and proved reserves, different price and cost assumptions, actual
economic conditions and corporate investment criteria.

128

The following are the principal sources of change in the standardized
measure of discounted future net cash flows (in millions):

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

(1) Includes operations in the United States, Canada, Brazil and Indonesia.

(2) Includes natural gas and oil properties owned by Colorado Interstate Gas
Company and its subsidiaries.

129

REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Stockholders of
El Paso Corporation:

In our opinion, based upon our audits and the report of other auditors, the
consolidated financial statements listed in the Index under Item 14(a)(1)
present fairly, in all material respects, the financial position of El Paso
Corporation and its subsidiaries at December 31, 2001 and 2000, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 2001 in conformity with accounting principles
generally accepted in the United States of America. In addition, in our opinion,
based on our audits and the report of other auditors, the financial statement
schedule listed in the Index under Item 14(a)(2) presents fairly, in all
material respects, the information set forth therein when read in conjunction
with the related consolidated financial statements. These financial statements
and financial statement schedule are the responsibility of the Company's
management; our responsibility is to express an opinion on these financial
statements and financial statement schedule based on our audits. The
consolidated financial statements and financial statement schedule give
retroactive effect to the merger of El Paso CGP Company (formerly The Coastal
Corporation) on January 29, 2001 in a transaction accounted for as a pooling of
interests, as described in Note 2 to the consolidated financial statements. We
did not audit the financial statements and financial statement schedule of El
Paso CGP Company as of December 31, 2000 and for each of the two years in the
period then ended, which statements reflect total assets of $19,066 million as
of December 31, 2000, and total revenues of $26,936 million and $16,596 million
for each of the two years in the period ended December 31, 2000. Those
statements were audited by other auditors whose report thereon has been
furnished to us, and our opinion expressed herein, insofar as it relates to the
amounts included for El Paso CGP Company as of December 31, 2000 and for each of
the two years then ended, is based solely on the report of the other auditors.
We conducted our audits of these statements in accordance with auditing
standards generally accepted in the United States of America, which require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall financial
statement presentation. We believe that our audits and the report of other
auditors provide a reasonable basis for our opinion.

As described in Notes 1 and 9, the Company adopted Statement of Financial
Accounting Standards, No. 133, Accounting for Derivatives and Hedging
Activities, on January 1, 2001.

/s/ PricewaterhouseCoopers LLP

Houston, Texas
March 6, 2002

130

SCHEDULE II

EL PASO CORPORATION
VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DECEMBER 31, 2001, 2000, AND 1999
(IN MILLIONS)

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

(1)Primarily accounts written off.

(2)In 2001, we finalized our purchase price adjustment for the legal reserves
related to our PG&E acquisition.

(3)Of this amount, $232 million relates to additional environmental remediation
liabilities recorded in connection with the events described in Note 14.

(4)We accrued $23 million in 2001 and reversed $24 million of reserves for the
Corpus Christi refinery leased to Valero in June.

(5)Of this amount, $53 million was the legal reserve we acquired in connection
with our purchase of PG&E's Texas Midstream operations. We recorded an
additional $159 million for legal reserves related to purchase price
adjustments on our PG&E acquisition.

131

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

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information under the captions "Proposal No. 1 -- Election of
Directors" and "Section 16(a) Beneficial Ownership Reporting Compliance" in our
proxy statement for the 2002 Annual Meeting of Stockholders is incorporated
herein by reference. Information regarding our executive officers is presented
in Part I, Item 1, Business, of this Form 10-K under the caption "Executive
Officers of the Registrant."

As a result of recent clarifications in the insider trading rules, and in
particular, the promulgation of Rule 10b5-1, we have revised our insider trading
policy to allow certain officers and directors to establish pre-established
trading plans. Rule 10b5-1 allows certain officers and directors to establish
written programs that permit an independent person who is not aware of inside
information at the time of the trade to execute pre-established trades of our
securities for the officer or director according to fixed parameters. As of
March 1, 2002, no officer or director has established a trading plan. However,
we intend to disclose the name of any officer or director who establishes a
trading plan in compliance with Rule 10b5-1 in future filings with the
Securities and Exchange Commission.

ITEM 11. EXECUTIVE COMPENSATION

Information appearing under the caption "Executive Compensation" in our
proxy statement for the 2002 Annual Meeting of Stockholders is incorporated
herein by reference.

ITEM 12. SECURITY OWNERSHIP OF MANAGEMENT

Information appearing under the caption "Security Ownership of Management"
in our proxy statement for the 2002 Annual Meeting of Stockholders is
incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

We own a one percent general partner interest in El Paso Energy Partners, a
publicly traded master limited partnership and 26 percent of the partnership's
common units. In addition, we own preferred units with $143 million liquidation
value. Some of our directors, officers and other personnel who provide services
for us also provide services for El Paso Energy Partners. These shared personnel
own and are awarded units, or options to purchase units, in El Paso Energy
Partners from time to time, and their personal financial interests may not
always be completely aligned with ours.

A discussion of certain agreements, arrangements and transactions between
us and El Paso Energy Partners is summarized in Part II, Item 7, Management's
Discussion and Analysis of Financial Condition and Results of Operations, under
the heading "Field Services". Also see Part II, Item 8, Financial Statements and
Supplementary Data, Note 20.

Information appearing under the caption "Certain Relationships and Related
Transactions" in our proxy statement for the 2002 Annual Meeting of Stockholders
is incorporated herein by reference.

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

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

1. Financial statements.

132

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

(b) REPORTS ON FORM 8-K:

- We filed a current report on Form 8-K, dated December 14, 2001 announcing
El Paso's balance sheet enhancement plan.

- We filed a current report on Form 8-K, dated December 26, 2001 filing
exhibits in connection with the filing by El Paso of a Shelf Registration
Statement and the offering of 20,294,118 shares of El Paso's common stock
pursuant to a Registration Statement on Form S-3.

- We filed a current report on Form 8-K, dated January 4, 2002 reporting
Computation of the Ratio of Earnings to Fixed Charges for the five years
ended December 31, 2000 and for the nine months ended September 30, 2000
and 2001.

- We filed an amended current report on Form 8-K/A, dated January 8, 2002
correcting a typographical error appearing in the January 4, 2002 report
on Form 8-K.

- We filed a current report on Form 8-K dated January 11, 2002 filing
exhibits in connection with the offering of medium-term notes pursuant to
a Registration Statement on Form S-3.

133

EL PASO CORPORATION

EXHIBIT LIST
DECEMBER 31, 2001

Each exhibit identified below is filed as a part of this report. Exhibits
not incorporated by reference to a prior filing are designated by an asterisk;
all exhibits not so designated are incorporated herein by reference to a prior
filing as indicated. Exhibits designated with a "+" constitute a management
contract or compensatory plan or arrangement required to be filed as an exhibit
to this report pursuant to Item 14(c) of Form 10-K.

134

135

136

UNDERTAKING

We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph
(4)(iii), to furnish to the Securities and Exchange Commission upon request all
constituent instruments defining the rights of holders of our long-term debt and
our consolidated subsidiaries not filed herewith for the reason that the total
amount of securities authorized under any of such instruments does not exceed 10
percent of our total consolidated assets.

137

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, as amended, El Paso Corporation has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly authorized
on the 15th day of March 2002.

EL PASO CORPORATION
Registrant

By /s/ WILLIAM A. WISE
-----------------------------------
William A. Wise
Chairman of the Board,
President and Chief Executive
Officer

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

138

139

EXHIBIT INDEX

Each exhibit identified below is filed as a part of this report. Exhibits
not incorporated by reference to a prior filing are designated by an asterisk;
all exhibits not so designated are incorporated herein by reference to a prior
filing as indicated. Exhibits designated with a "+" constitute a management
contract or compensatory plan or arrangement required to be filed as an exhibit
to this report pursuant to Item 14(c) of Form 10-K.