EL PASO CGP CO - 10-K Annual Report

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

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FORM 10-K

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

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003

OR

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

FOR THE TRANSITION PERIOD FROM TO

COMMISSION FILE NUMBER 1-7176

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

DELAWARE 74-1734212
(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

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

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

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

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

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

STATE THE AGGREGATE MARKET VALUE OF THE VOTING AND NON-VOTING COMMON EQUITY
HELD BY NON-AFFILIATES OF THE REGISTRANT: NONE

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

Common Stock, par value $1 per share. Shares outstanding on October 11,
2004: 1,000

DOCUMENTS INCORPORATED BY REFERENCE: NONE

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EL PASO CGP COMPANY

TABLE OF CONTENTS

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

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

When we refer to natural gas and oil in "equivalents," we are doing so to
compare quantities of oil with quantities of natural gas or to express these
different commodities in a common unit. In calculating equivalents, we use a
generally recognized standard in which one Bbl of oil is equal to six Mcf of
natural gas. Oil includes natural gas liquids unless otherwise specified. Also,
when we refer to cubic feet measurements, all measurements are at a pressure of
14.73 pounds per square inch.

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

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RESTATEMENT OF HISTORICAL FINANCIAL INFORMATION

In February 2004, we completed the December 31, 2003 reserve estimation
process for the proved natural gas and oil reserves in our Production segment.
The results of this process indicated that a significant downward revision to
our proved reserve estimates was needed. After an investigation into the factors
that caused this revision, we determined that a material portion of the downward
reserve revisions should be reflected in historical periods. Accordingly, we
restated our historical financial information for the years from 1999 to 2002
and for the first nine months of 2003. The investigation determined that certain
personnel used aggressive, and at times, unsupportable methods to book proved
reserves. In some instances, certain personnel provided historical proved
reserve estimates that they knew or should have known were incorrect at the time
they were reported. The investigation also found that we did not, in some cases,
maintain adequate documentation and records to support historically booked
proved natural gas and oil reserves.

As a result of these conclusions, we restated our historical proved natural
gas and oil reserve estimates and the financial information derived from these
estimates for the periods from 1999 to 2002 and for the first nine months of
2003. The total cumulative impact of the restatement was a reduction of our
previously reported stockholder's equity as of September 30, 2003 of
approximately $1.1 billion. The restatement had no impact on our overall cash
flows during these periods. These restated amounts have been reflected only in
this Annual Report on Form 10-K, and we did not revise our historically filed
reports for the impacts of this restatement. Consequently, you should not rely
on historical information contained in those prior filings since this filing
replaces and revises those historically reported amounts.

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

PART I

ITEM 1. BUSINESS

GENERAL

We are a Delaware corporation originally founded in 1955. In January 2001,
we became a wholly owned subsidiary of El Paso Corporation (El Paso) through our
merger with a wholly owned El Paso subsidiary.

BUSINESS SEGMENTS

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

Interstate Natural Gas
Transmission
and Storage Services We own or have interests in approximately
17,300 miles of pipeline and approximately 280
Bcf of storage capacity. We provide customers
with interstate natural gas transmission and
storage services from a diverse group of supply
regions to major markets in the Midwest and
western United States.

Production We own or have interests in approximately 3.9
million net developed and undeveloped acres,
and had over 1.0 Tcfe of proved natural gas and
oil reserves worldwide at the end of 2003.
During 2003, our production averaged
approximately 530 MMcfe/d. During the first
eight months of 2004, production averaged 367
MMcfe/d.

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Midstream Services Our midstream businesses provide gathering and
processing services primarily in south
Louisiana.

Power Generation and Supply Our power business owns or manages over 4,000
MW of gross generating capacity in 8 countries.
Our plants serve customers under long-term and
market-based contracts or sell to the open
market in spot market transactions. This
business also manages power supply arrangements
with electric utility customers to meet their
peak electricity requirements. We have sold or
expect to sell substantially all of our
domestic power business in 2004.

In addition to our operating segments, we also have discontinued
operations. These discontinued operations include our petroleum markets
business, which owned and operated refineries in the northeastern U.S. and in
Aruba, with a capacity to refine over 430,000 Bbls of oil per day. We completed
the sale of substantially all of this business in early 2004.

Below is a description of each of our existing business segments. Our
current business 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 additional
discussion of our business segments, see Part II, Item 7, Management's
Discussion and Analysis of Financial Condition and Results of Operations. For
our segment operating results and identifiable assets, see Part II, Item 8,
Financial Statements and Supplementary Data, Note 21, which is incorporated
herein by reference.

PIPELINES SEGMENT

Our Pipelines segment provides natural gas transmission, storage and
related services and owns or has interests in approximately 17,300 miles of
interstate natural gas pipelines in the U.S. Our systems connect several of the
nation's principal natural gas supply regions to several large consuming regions
in the U.S. and include access between our U.S. based systems and Canada. In
addition, we own or have interests in approximately 280 Bcf of storage capacity
used to provide a variety of flexible services to our customers. We conduct our
activities primarily through three wholly owned and one partially owned
interstate transmission systems along with four underground natural gas storage
entities. 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.

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

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

Partially Owned Interstate Transmission System

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(1) This system is accounted for as an equity investment.
(2) Volumes represent the system's total design capacity and average throughput
and are not adjusted for our ownership interest.

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

Underground Natural Gas Storage Entities

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(1) Includes a total of 75 Bcf contracted to affiliates. Storage capacity is
under long-term contracts and is not adjusted for our ownership interest.
(2) These systems are accounted for as equity investments as of December 31,
2003.

In addition to these interests in interstate natural gas transmission and
storage facilities, we have a 50 percent interest in Wyco Development, L.L.C.
(Wyco). Wyco owns the Front Range Pipeline, a state-regulated gas pipeline
extending from the Cheyenne Hub to Public Service Company of Colorado's (PSCo)

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Fort St. Vrain electric generation plant, and also owns compression facilities
on WIC's Medicine Bow Lateral. These facilities are leased to PSCo and WIC,
respectively, under long-term leases. Our equity investment in Wyco is
approximately $24 million.

Regulatory Environment

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

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

- certification and construction of new facilities;

- extension or abandonment of facilities;

- maintenance of accounts and records;

- relationships between pipeline and energy affiliates;

- terms and conditions of service;

- depreciation and amortization policies;

- acquisition and disposition of facilities; and

- initiation and discontinuation of services.

The fees or rates established under our tariffs are a function of our costs
of providing services to our customers, including a reasonable return on our
invested capital. Our revenues from transportation, storage and related services
(transportation services revenues) consist of reservation revenues and usage
revenues. Reservation revenues are from customers (referred to as firm
customers) whose contracts (which are for varying terms) reserve capacity on our
pipeline systems or storage facilities. These firm customers are obligated to
pay a monthly reservation or demand charge, regardless of the amount of natural
gas they transport or store, for the term of their contracts. Usage revenues are
from both firm customers and interruptible customers (those without reserved
capacity) who pay charges based on the volume of gas actually transported,
stored, injected or withdrawn. In 2003, approximately 90 percent of our
transportation services revenues were attributable to charges paid by firm
customers. The remaining 10 percent of our transportation services revenue was
attributable to usage charges paid by both firm and interruptible customers. Due
to our regulated nature, our financial results have historically been relatively
stable. However, these results can be subject to volatility due to factors such
as weather, changes in natural gas prices and market conditions, regulatory
actions, competition and the creditworthiness of our customers.

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

Markets and Competition

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

Other Matters Impacting Our Markets

Electric power generation is the fastest growing demand sector of the
natural gas market. The potential consequences of proposed and ongoing
restructuring and deregulation of the electric power industry are currently
unclear. Restructuring and deregulation potentially benefit the natural gas
industry by creating more

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

Our existing contracts mature at various times and in varying amounts of
throughput capacity. As our pipeline contracts expire, our ability to extend our
existing contracts or re-market expiring contracted capacity is dependent on the
competitive alternatives, the regulatory environment at the federal, state and
local levels and market supply and demand factors at the relevant dates these
contracts are extended or expire. The duration of new or re-negotiated contracts
will be affected by current prices, competitive conditions and judgments
concerning future market trends and volatility. Subject to regulatory
constraints, we attempt to re-contract or re-market our capacity at the maximum
rates allowed under our tariffs, although we, at times, discount these rates to
remain competitive. The level of discount varies for each of our pipeline
systems.

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

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. as of December 31, 2003, we
controlled over 1 million net acres of leasehold through our onshore operations
in 10 states, including Texas, Utah, West Virginia, and Wyoming, and through our
offshore operations in federal and state waters in the Gulf of Mexico. We also
have international exploration and production rights in Australia, Bolivia,
Brazil, Canada, Hungary and Indonesia. During 2003, daily production averaged
approximately 530 MMcfe/d, and our proved natural gas and oil reserves at
December 31, 2003, were approximately 1.1 Tcfe.

In February 2004, we completed estimates of our December 31, 2003 proved
reserves. The results of this process indicated that a 1.0 Tcfe downward
revision to our proved natural gas and oil reserves was needed. Following an
investigation into the factors that caused this significant revision, we
determined that a material portion of these revisions should be reflected in
prior years and, as a result, we restated our historical proved reserve
estimates and our historical financial information derived from these proved
reserve estimates. See Part II, Item 6, Selected Financial Data and Item 8,
Financial Statements and Supplementary Data, Note 1 for a further discussion of
this restatement.

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

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

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

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In Brazil, our operations are concentrated in the Camamu and Santos Basins.
We have been successful with our drilling programs in the Santos and Camamu
Basins and are seeking a strategic partner with a strong interest in Brazil to
contribute near-term development capital in these two basins.

Natural Gas and Oil Reserves

The tables below provide information about our proved reserves at December
31, 2003. Reserve information in these tables is based on the reserve report
dated January 1, 2004, prepared internally by us. Ryder Scott Company and
Huddleston & Co., Inc., independent petroleum engineering firms, performed
independent reserve estimates for 84 percent and 16 percent of our properties,
respectively. The total estimate of proved reserves prepared independently by
Ryder Scott Company and Huddleston & Co., Inc. was within five percent of our
internally prepared estimates. This information is consistent with estimates of
reserves filed with other federal agencies except for differences of less than
five percent resulting from actual production, acquisitions, property sales,
necessary reserve revisions and additions to reflect actual experience.

The table below summarizes our estimated proved reserves as of December 31,
2003, and our 2003 production, by area.

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(1) Net proved reserves exclude royalties and interests owned by others
(including net profits interest) and reflects contractual arrangements and
royalty obligations in effect at the time of the estimate.
(2) Includes oil, condensate and natural gas liquids.
(3) As of September 2004, we have sold our production operations in Canada.
(4) Includes international operations in Hungary and Indonesia. As of September
30, 2004, we have sold substantially all of our operations in Indonesia.

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

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drilling or acquire additional properties containing proved reserves, or both,
our proved reserves will decline as reserves are produced.

In addition, during 2003 we sold reserves totaling approximately 173 Bcfe
to various third parties. The reserves sold were primarily located in New
Mexico, the Gulf of Mexico and western Canada. See Part II, Item 8, Financial
Statements and Supplementary Data, Note 24, for a further discussion of our
reserves.

Acreage and Wells

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

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

The U.S. net developed acreage is concentrated primarily in the Gulf of
Mexico (45 percent), Utah (35 percent), and Texas (18 percent). The domestic net
undeveloped acreage is concentrated primarily in Texas (30 percent), Gulf of
Mexico (26 percent), West Virginia (19 percent) and Wyoming (15 percent).
Approximately 23 percent, 21 percent and 10 percent of our total U.S. net
undeveloped acreage is held under leases that have minimum remaining primary
terms expiring in 2004, 2005 and 2006, respectively. During 2003, we sold
approximately 658,424 net acres primarily located in New Mexico, the Gulf of
Mexico and western Canada.

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

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

During 2003, we sold approximately 265 net productive wells located
primarily in New Mexico, the Gulf of Mexico and western Canada. At December 31,
2003, we operated 990 of the 1,030 net productive wells.

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

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(1) Net interest is the aggregate of the fractional working interest that we
have in our gross wells drilled.
(2) As of September 2004, we have sold our production operations in Canada.

(3) Includes international operations in Australia, Hungary and Indonesia. As of
September 30, 2004, we have sold substantially all of our operations in
Indonesia.

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

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Net Production, Sales Prices, Transportation and Production Costs

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

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(1) As of September 2004, we have sold our production operations in Canada.
(2) Prices are stated before transportation costs.
(3) Production costs include lease operating costs and production related taxes
(including ad valorem and severance taxes).

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Acquisition, Development and Exploration Expenditures

The following table details information regarding the costs incurred in our
acquisition, development and exploration activities for each of the three years
ended December 31, 2003. As a result of the restatement of our proved natural
gas and oil reserves, some costs that were previously reported as development
costs have been reclassified as exploratory drilling costs for the years 2002
and 2001. See Part II, Item 8, Financial Statements and Supplementary Data, Note
1 for a further discussion of this restatement.

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

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

Regulatory and Operating Environment

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

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

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

Markets and Competition

We primarily sell our natural gas and oil to third parties through El Paso
Merchant Energy L.P. (El Paso Merchant Energy), a wholly owned subsidiary of El
Paso, at spot market prices, subject to customary adjustments. We sell our
natural gas liquids at market prices under monthly or long-term contracts,
subject to customary adjustments. We also engage in hedging activities with El
Paso Merchant Energy on a portion of our natural gas and oil production to
stabilize our cash flows and reduce the risk of downward commodity price
movements on sales of our production.

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

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FIELD SERVICES SEGMENT

Our Field Services segment conducts our midstream activities which includes
gathering and processing of natural gas. For the majority of 2003, our assets
principally consisted of our consolidated processing assets in south Louisiana.

Processing and Gathering Operations

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

Regulatory Environment

We are subject to the Natural Gas Pipeline Safety Act of 1968, the
Hazardous Liquid Pipeline Safety Act of 1979 and various environmental statutes
and regulations. Each of our pipelines has continuing programs designed to keep
the facilities in compliance with pipeline safety and environmental
requirements, and we believe that these systems are in material compliance with
the applicable requirements.

Markets and Competition

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

MERCHANT ENERGY SEGMENT

Our Merchant Energy segment includes the ownership and operation of
domestic and international power generation facilities as well as the management
of restructured power contracts. As of December 31, 2003, we owned or had
interests in 19 power plants in 8 countries with a total generating capacity of
4,281 gross MW. Our commercial focus has historically been either to develop
projects in which new long-term power purchase agreements allow for an
acceptable return on capital, or to acquire projects with existing above-market
power purchase agreements. El Paso's Board of Directors authorized a plan in
December 2003 that included the sale of four of our six domestic power
generation plants. As of September 2004, we have sold two plants with a total
generating capacity of 582 gross MW. See Part II, Item 8, Financial Statements
and Supplementary Data, Note 4. El Paso continues to seek opportunities to sell
or otherwise divest of our remaining domestic power plants and our international
assets.

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

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(1) These power facilities are reflected as investments in unconsolidated
affiliates in our financial statements.
(2) These power facilities (referred to as merchant plants) do not have
long-term power purchase agreements and, as a result, sell the power they
generate into the wholesale power market.
(3) In December 2003, El Paso's Board approved a plan for selling these power
facilities.
(4) We completed the sale of these assets in 2004.
(5) This power facility is currently being leased to a third party who has an
option to purchase in 2005.

In addition to our power plants above, we were involved in activities in
2001 and 2002 that we have referred to as our power restructuring business.
These activities involved restructuring above-market, long-term power purchase
agreements with utilities that were originally tied to older power plants built
under the Public Utility Regulatory Policies Act of 1978 (PURPA). These PURPA
facilities were typically less efficient and more costly than newer power
generation facilities. Our power restructuring activities included restructuring
the contracts held by our consolidated Eagle Point and CDECCA power facilities.
In the restructuring, the contracts were amended so that the power sold to the
utilities did not have to be provided from the specific power plant, but could
be obtained in the wholesale power market. While we are no longer actively
seeking to restructure additional power purchase contracts, we continue to
manage the physical purchase and sale of electricity as required under the
restructured power contracts. As of December 31, 2003, our only significant
remaining restructured power contract is held by our wholly owned subsidiary,
Utility Contract Funding, L.L.C. (UCF). Morgan Stanley supplies the fuel under
this contract and PSEG is obligated to purchase a minimum annual volume of 1,666
MMwh under this contract through 2016. We sold our interest in UCF in June 2004.

Regulatory Environment

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

15

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

Markets and Competition

The domestic power generation industry continues to evolve and regulatory
initiatives have been adopted at the federal and state level aimed at increasing
competition in the power generation business. As a result, our domestic
facilities are required to compete in the marketplace in which operating
efficiency and other economic factors will determine success. We are likely to
face intense competition from generation companies as well as from the wholesale
power markets.

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

DISCONTINUED OPERATIONS

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

Petroleum Markets. In 2003, El Paso announced its intent to sell our
petroleum markets business since it was not core to El Paso's primary natural
gas business. During 2003 and 2004, El Paso sold substantially all of our
petroleum markets assets. As of December 31, 2003, our petroleum markets
business owned or had interests in two crude oil refineries and two chemical
production facilities and had petroleum terminalling and related marketing
operations. Our refineries operated at 74 percent of their combined daily
capacity in 2003, at 66 percent in 2002 and at 71 percent in 2001. The aggregate
sales volumes at our wholly owned refineries were approximately 118 MMBbls in
2003, 110 MMBbls in 2002 and 131 MMBbls in 2001. Of our total refinery sales in
2003, 24 percent was gasoline, 38 percent was middle distillates, such as jet
fuel, diesel fuel and home heating oil, and 38 percent was heavy industrial
fuels and other products. The following table presents information on our
wholly-owned refineries as of and for the years ended December 31:

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

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

16

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

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

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

(2) Removed from service in October 2003.

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

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

ENVIRONMENTAL

A description of our environmental activities is included in Part II, Item
8, Financial Statements and Supplementary Data, Note 18, and is incorporated
herein by reference.

EMPLOYEES

As of September 24, 2004, we had approximately 856 full-time employees,
none of whom are subject to collective bargaining agreements.

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EXECUTIVE OFFICERS OF THE REGISTRANT

Our executive officers as of October 11, 2004, are listed below. Prior to
August 1, 1998, all references to El Paso refer to positions held with El Paso
Natural Gas Company.

Douglas L. Foshee has served as our Chairman of the Board, President and
CEO since January 2004. Mr. Foshee has been President, Chief Executive Officer,
and a Director of El Paso since September 2003. Mr. Foshee became Executive Vice
President and Chief Operating Officer of Halliburton Company in 2003, having
joined that company in 2001 as Executive Vice President and Chief Financial
Officer. In December 2003, several subsidiaries of Halliburton, including DII
Industries and Kellogg Brown & Root, filed for bankruptcy protection whereby the
subsidiaries will jointly resolve their asbestos claims. Prior to that, Mr.
Foshee was President, Chief Executive Officer, and Chairman of the Board at
Nuevo Energy Company. From 1993 to 1997, Mr. Foshee served Torch Energy Advisors
Inc. in various capacities, including Chief Operating Officer and Chief
Executive Officer. He held various positions in finance and new business
ventures with ARCO International Oil and Gas Company and spent seven years in
commercial banking, primarily as an energy lender.

D. Dwight Scott has served as our Executive Vice President, Chief Financial
Officer and as a Director since January 2004. Mr. Scott has been Executive Vice
President and Chief Financial Officer of El Paso since October 2002. Mr. Scott
served as Senior Vice President of Finance and Planning for El Paso from July
2002 to September 2002. Mr. Scott was Executive Vice President of Power for El
Paso Merchant Energy from December 2001 to June 2002, and he served as Chief
Financial Officer of El Paso Global Networks from October 2000 to November 2001.
From January 1999 to October 2000, he served as a managing director in the
energy investment banking practice of Donaldson, Lufkin and Jenrette.

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

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ITEM 2. PROPERTIES

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

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

ITEM 3. LEGAL PROCEEDINGS

A description of our legal proceedings are included in Part II, Item 8,
Financial Statements and Supplementary Data, Note 18, and is incorporated herein
by reference.

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

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

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

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

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

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

None.

PART II

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

All of our common stock, par value $1 per share, is owned by El Paso and,
accordingly, our common stock is not publicly traded.

ITEM 6. SELECTED FINANCIAL DATA

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

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(1) In February 2004, we completed an assessment of our December 31, 2003 proved
natural gas and oil reserve estimates. The assessment indicated a downward
revision to our proved reserve estimates of 1.0 Tcfe was needed. Upon
completion of an investigation into the factors that caused this revision,
we determined that a material portion of the revision should be reflected in
all of the historical periods included in this Annual Report on Form 10-K.
As a result, we restated our historical financial statements for all periods
to reflect the impacts of the revised reserve estimates on the financial
statement amounts. The cumulative impact of the restatement on total
stockholder's equity as of September 30, 2003 (the most recent balance sheet
filed) was a reduction of approximately $1.1 billion, which includes the
reduction to beginning stockholder's equity as of January 1, 2001 of
approximately $1.1 billion. See Item 8, Financial Statements and
Supplementary Data, Note 1, for a further discussion of our restatement
process as well as the financial impacts of the restatement on 2001, 2002
and 2003. The financial impacts on 1999 and 2000 of the restatement were as
follows:

The restated stockholder's equity at December 31, 1999 includes a decrease
in 1999 income of $80 million, net of tax, due to an increased ceiling test
charge, partially offset by lower depletion expense, as well as a reduction
to beginning retained earnings of $1 billion for charges that would have
occurred in periods prior to January 1, 1999 as a result of our revised
reserve levels. As discussed in Item 8, Financial Statements and
Supplementary Data, Note 1, we revised our reserves for the periods from
December 31, 2000 to September 30, 2003 using a reserve reconstruction
approach. For each quarter from December 31, 1998 through the third quarter
of 2000, we estimated reserves using an approach that involved the use of a
"reserve over production ratio" based on the reconstructed December 31, 2000
reserve estimates. The reserve over production ratio provided the estimated
life of reserves based on production levels. We applied that ratio to the
actual historical period production levels to calculate estimated historical
reserves for each period. In determining the reserve over production ratio
to use for each period, historical prices at the end of each quarter were
considered, since at different pricing levels, more or less reserves are
economical to produce, which also impacts capital cost, operating cost and
revenue assumptions in determining cash flows that will be derived from
reserves. These overall quarterly reserve levels were then used to
recalculate the associated net future cash flows for each quarter during
those periods. Ceiling test charges and depreciation, depletion and
amortization rates were then determined based on these restated estimated
reserve levels and related net future cash flows. Finally, we assessed the
reasonableness of our initial adjustment as of December 31, 1998 based on
historical prices and our historical capitalized costs prior to that time.
Based on that assessment, we believe the amount recorded as a retained
earnings adjustment on January 1, 1999 reasonably reflects the financial
statement impact of our restated reserve levels that would have occurred
prior to that time. We believe the approach used to reconstruct our
historical reserve estimates was reasonable in light of the information
available to us and the circumstances surrounding our restatement. See Item
8, Financial Statements and Supplementary Data, Note 1, for a further
discussion of the methodologies used to restate our natural gas and oil
reserves and the reasons for the differences in the methods used in
computing our restated reserves.

The "as reported" income from continuing operations differs from those
amounts originally included in our 2000 Form 10-K by $123 million for 2000
and $31 million for 1999 due to reclassifications associated with our
discontinued operations and other minor reclassifications which had no
impact on previously reported net income.

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

(3) During 2001, we merged with El Paso Corporation and incurred employee,
business and integration costs related to this merger.

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

Our Management's Discussion and Analysis includes forward-looking
statements that are subject to risks and uncertainties. Actual results may
differ substantially from the statements we make in this section due to a number
of factors that are discussed beginning on page 46. The historical financial
information in this section has been restated as further discussed in Item 8,
Financial Statements and Supplementary Data, Note 1. The information contained
in this discussion also presents our petroleum markets and our coal mining
businesses as discontinued operations for all periods.

LIQUIDITY AND CAPITAL RESOURCES

LIQUIDITY

We rely on cash generated from our internal operations and loans from El
Paso through its cash management program as our primary sources of liquidity, as
well as asset sales and capital contributions from El Paso. We expect that our
future funding for working capital needs, capital expenditures and debt service
will continue to be provided from some or all of these sources. Each of these
sources is impacted by factors that influence the overall amount of cash
generated by us and the capital available to us. For example, cash generated by
our business operations may be impacted by changes in commodity prices or
demands for our commodities or services due to weather patterns, competition
from other providers or alternative energy sources. Cash generated by future
asset sales may depend on the overall economic conditions of the industries
served by these assets, the condition and location of the assets and the number
of interested buyers.

El Paso is a significant source of liquidity to us, and we participate in
its cash management program. Under this program, depending on whether we have
short-term cash surpluses or requirements, we either provide cash to El Paso or
El Paso provides cash to us. We have historically and consistently borrowed cash
from El Paso under this program. Currently, one of our subsidiaries, CIG, is not
advancing funds to El Paso via the cash management program based on its expected
cash needs. On December 31, 2003, El Paso authorized a capital contribution of
$1.5 billion to us and as of December 31, 2003, we had a note payable to El Paso
of $906 million related to this program. This note is classified as a current
liability in our balance sheet because it is due upon demand. Our ability to
rely on advances from El Paso can be impacted by its credit standing, its
requirement to repay debt and other financing obligations, and the cash demands
from other parts of its business. If El Paso were unable to meet its liquidity
needs, we would not have access to this source of liquidity. Furthermore, we
would be required to repay affiliated company payables, if demanded. However, we
do not anticipate that El Paso will require us to repay these payables during
2004.

In February 2004, El Paso completed the December 31, 2003 reserve
estimation process for its proved natural gas and oil reserves which included
reserves in our Production segment. As a result of this review, El Paso
announced that it was significantly reducing its proved natural gas and oil
reserve estimates, including our estimates. Following the conclusion of an
independent investigation into this matter, El Paso announced that a restatement
of its historical financial statements, as well as ours, was required.

El Paso believes that a material restatement of its financial statements
would have constituted events of default under its $3 billion revolving credit
facility and various other financing transactions, specifically under the
provisions related to representations and warranties on the accuracy of its
historical financial statements and on El Paso's debt to capitalization ratio.
During 2004, El Paso received several waivers on its $3 billion revolving credit
facility and various other financing transaction to address the restatement.
These waivers continue to be effective. El Paso also received an extension of
time with various lenders until November 30, 2004 to file its first and second
quarter 2004 Forms 10-Q, which it expects to meet. If El Paso is unable to file
its Forms 10-Q by that date and it is not able to negotiate an additional
extension of the filing deadline, the $3 billion revolving credit facility and
various other financing transactions could be accelerated. As part of obtaining
its waivers, El Paso also amended various provisions of the $3 billion revolving
credit facility, including provisions related to events of default, and
limitations on the ability of El Paso and its subsidiaries to repay indebtedness
scheduled to mature after June 30, 2005. Although two of our subsidiaries

22

(ANR and CIG) are eligible to borrow under El Paso's $3 billion revolving credit
facility, they do not have any borrowings or letters of credit outstanding under
that facility. Based upon a review of the provisions of our indentures and the
financing agreements, we believe that a default on El Paso's $3 billion
revolving credit facility would not result in an event of default under our
other debt agreements unless such default resulted in the acceleration of El
Paso's $3 billion revolving credit facility or other transactions collateralized
by the same assets, and our subsidiaries failed to perform their obligations
under their guarantees of such debt.

Various other financing arrangements entered into by El Paso and its
subsidiaries, including us, include covenants that require us to file financial
statements within specified time periods. Non-compliance with these covenants
does not constitute an automatic event of default. Instead, such agreements are
subject to acceleration when the indenture trustee or the holders of at least 25
percent of the outstanding principal amount of any series of debt provides
notice to the issuer of non-compliance under the indenture. In that event, the
default can be cured by filing financial statements within specified periods of
time (between 30 and 90 days after receipt of notice depending on the particular
indenture) to avoid acceleration of repayment. The filing of our first and
second quarter 2004 Forms 10-Q will cure the events of non-compliance resulting
from our failure to file financial statements. We have not received a notice of
the default caused by our failure to file our financial statements. In the event
of an acceleration, we may be unable to meet our payment obligations with
respect to the related indebtedness.

If El Paso were subject to voluntary or involuntary bankruptcy proceedings,
El Paso and its other subsidiaries and their creditors could attempt to make
claims against us, including claims to substantively consolidate our assets and
liabilities with those of El Paso and its other subsidiaries. We believe that
claims to substantively consolidate us with El Paso and/or its other
subsidiaries would be without merit. However, there is no assurance that El Paso
and/or its other subsidiaries or their creditors would not advance such a claim
in a bankruptcy proceeding. If we were to be substantively consolidated in a
bankruptcy proceeding with El Paso and/or its other subsidiaries, there could be
a material adverse effect on our financial condition and our liquidity.

Some of our subsidiaries are subsidiary guarantors of El Paso's $3 billion
revolving credit facility and other financing transactions. In connection with
their guarantees, El Paso pledged our ownership of ANR, ANR Storage, CIG, and
WIC to collateralize the $3 billion revolving credit facility and approximately
$300 million of other financing arrangements including leases, letters of credit
and other facilities. Our ownership in the above mentioned companies is subject
to change if El Paso's lenders under these facilities exercise their rights over
the collateral. If this were to occur, it could have a material adverse effect
on our financial condition. In addition, one of our subsidiaries has pledged as
collateral a portion of its natural gas and oil properties to support the
obligations of some of our affiliates to make payments in connection with the
settlement of various lawsuits arising out of the Western Energy Crisis. If our
affiliates fail to make those payments, the properties that our subsidiary has
pledged would be subject to foreclosure, which could have a material adverse
effect on our financial position, results of operations and cash flows.

We have cross-acceleration provisions in our long-term debt-agreements
which, if triggered, could result in the acceleration of our debt. The most
restrictive indenture has a cross-acceleration threshold of $5 million. The
acceleration of our long-term debt would adversely affect our liquidity position
and, in turn, our financial condition.

We believe we will generate sufficient funds through our operations, asset
sales, financing activities and advances from El Paso to meet all of our cash
needs.

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Overview of Cash Flow Activities

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

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

(1) Cash flows from continuing operating, investing and financing activities
were restated. However, the overall cash flows for 2002 were unaffected.

Cash From Continuing Operating Activities

Net cash provided by operating activities were $1.2 billion in 2003 versus
$0.5 billion in 2002. In our operating activities, we experienced a $0.8 billion
decline in 2003 in cash generated from our operations, before asset and
liability changes, primarily as a result of sales of operating assets during
both 2002 and 2003 and the effects of lower capital spending in our Production
segment. In 2003, changes in operating assets and liabilities were a source of
cash of $0.3 billion as compared to a use of cash of $1.1 billion in 2002.

Cash From Continuing Investing Activities

Net cash used in investing activities in 2003 consisted primarily of $994
million in capital expenditures. Offsetting this use of cash was $384 million of
proceeds from the sale of assets and investments. Our 2003 capital expenditures
includes the following (in millions):