UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

x

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2004

or

o

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)

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 þ  No o

      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. þ

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

      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 April 15, 2005: 1,000

      EL PASO CGP COMPANY MEETS THE CONDITIONS OF GENERAL INSTRUCTION I(1)(a) AND (b) TO FORM 10-K AND IS, THEREFORE, FILING THIS REPORT WITH A REDUCED DISCLOSURE FORMAT AS PERMITTED BY SUCH INSTRUCTION.

Documents Incorporated by Reference: None

EL PASO CGP COMPANY

TABLE OF CONTENTS

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

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

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

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 year ended December 31, 2004, we had both regulated and non-regulated operations conducted through four business segments — Pipelines, Production, Power and Field Services. Through these segments, we provided the following energy related services:

      During 2004, we also had discontinued operations related to a historical petroleum markets business and international natural gas and oil production operations, primarily in Canada.

      Below is a discussion of each of our business segments. Our business segments 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 15, which is incorporated herein by reference.

Regulated Business — Pipelines Segment

      Our Pipelines segment provides natural gas transmission, storage and related services. We own or have interests in approximately 17,600 miles of interstate natural gas pipelines in the United States that connect the nation’s principal natural gas supply regions to several large consuming regions in the United States. Our pipeline operations also include access to systems in Canada. We also own or have interests in approximately 270 Bcf of storage capacity used to provide a variety of flexible services to our customers.

      Our Pipelines segment conducts its business activities primarily through four wholly owned and a partially owned interstate transmission system, along with four underground natural gas storage entities. The tables below detail our wholly owned and partially owned interstate transmission systems:

     We also have several pipeline expansion projects underway as of December 31, 2004 that have been approved by the Federal Energy Regulatory Commission (FERC), the more significant of which are presented below:

     We also have a 50 percent interest in Wyco Development, L.L.C. Wyco owns the Front Range Pipeline, a state-regulated gas pipeline extending from the Cheyenne Hub to Public Service Company of Colorado’s (PSCo) Fort St. Vrain electric generation plant, and compression facilities on WIC’s Medicine Bow Lateral. These facilities are leased to PSCo and WIC, respectively, under long-term leases.

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

      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:

      • 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 usage charges based on the volume of gas actually transported, stored, injected or withdrawn. In 2004, approximately 90 percent of our transportation service and storage revenues were attributable to reservation charges paid by firm customers. The remaining 10 percent of our revenues were variable. Due to our regulated nature and the high percentage of our revenues attributable to reservation charges, our revenues have historically been relatively stable. However, our financial 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. We also experience volatility in our financial results when the amount of gas utilized in our operations differs from the amounts we receive for that purpose.

      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 these 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.

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

      Electric power generation is the fastest growing demand sector of the natural gas market. The growth and development of the electric power industry potentially benefits the natural gas industry by creating more demand for natural gas turbine generated electric power, but this effect is offset, in varying degrees, by increased generation efficiency, the more effective use of surplus electric capacity and increased natural gas prices. The increase in natural gas prices, driven in part by increased demand from the power sector, has diminished the demand for gas in the industrial sector. In addition, in several regions of the country, new additions in electric generating capacity have exceeded load growth and transmission capabilities out of those regions. These developments may inhibit owners of new power generation facilities from signing firm contracts with pipelines and may impair their creditworthiness.

      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, and in certain regions, 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 faced by each of our wholly owned pipeline systems as of December 31, 2004:

Non-Regulated Business — 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, in the United States and Brazil. In the United States, as of December 31, 2004, we controlled approximately one million net acres of leasehold acreage through our operations primarily in Texas, Utah, West Virginia and Wyoming, and through our offshore operations in federal and state waters in the Gulf of Mexico. During 2004, daily equivalent natural gas production averaged approximately 334 MMcfe/d, and our proved natural gas and oil reserves at December 31, 2004, were approximately 800 Bcfe.

      We will focus on developing production opportunities around our asset base in the United States and in Brazil. Our other international operations that are not part of our long-term strategy have been treated as discontinued operations as further discussed in Part II, Item 8, Financial Statements and Supplementary Data, Note 2.

      Our operations are divided into the following areas:

Natural Gas, Oil and Condensate and Natural Gas Liquids (NGL) Reserves

      The tables below detail our proved reserves at December 31, 2004. Information in these tables is based on our internal reserve report. Ryder Scott Company, an independent petroleum engineering firm, prepared an estimate of our natural gas and oil reserves for 82 percent of our properties by volume. The total estimate of proved reserved prepared by Ryder Scott was within one percent of our internally prepared estimates presented in these tables. 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. Ryder Scott was retained by and reports to the Audit Committee of El Paso’s Board of Directors. The properties reviewed by Ryder Scott represented 84 percent of our proved properties based on value. Our estimated net proved reserves as of December 31, 2004, and our 2004 production are as follows:

     The table below summarizes our estimated net proved producing reserves, proved non-producing reserves, and proved undeveloped reserves as of December 31, 2004:

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

      There are numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and projecting the 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 accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretations and judgment. All estimates of proved reserves are determined according to the rules prescribed by the SEC. These rules indicate that the standard of “reasonable certainty” be applied to proved reserve estimates. This concept of reasonable certainty implies that as more technical data becomes available, a positive, or upward, revision is more likely than a negative, or downward, revision. Estimates are subject to revision based upon a number of factors, including reservoir performance, prices, economic conditions and government restrictions. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of that estimate. Reserve estimates are often different from the quantities of natural gas and oil that are ultimately recovered. The meaningfulness of reserve estimates is highly dependent on the accuracy of the assumptions on which they were based. In general, the volume of production from natural gas and oil properties we own declines as reserves are depleted. Except to the extent we conduct successful exploration and development activities or acquire additional properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. For further discussion of our reserves, see Part II, Item 8, Financial Statements and Supplementary Data, under the heading Supplemental Natural Gas and Oil Operations.

      The following table details our gross and net interest in developed and undeveloped acreage at December 31, 2004. Any acreage in which our interest is limited to owned royalty, overriding royalty and other similar interests is excluded.

     Our United States net developed acreage is concentrated primarily in the Gulf of Mexico (48 percent), Utah (32 percent), and Texas (20 percent). Our United States net undeveloped acreage is concentrated primarily in Texas (31 percent), West Virginia (24 percent), Wyoming (20 percent), and the Gulf of Mexico (16 percent). Approximately 27 percent, 14 percent and 4 percent of our total United States net undeveloped acreage is held under leases that have minimum remaining primary terms expiring in 2005, 2006 and 2007.

      The following table details our working interests in natural gas and oil wells in the United States at December 31, 2004:

     We operated 922 of the 951 net productive wells as of December 31, 2004.

      The following table details our exploratory and development wells drilled during the years 2002 through 2004:

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

Net Production, Sales Prices, Transportation and Production Costs

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

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:

     We spent approximately $11 million in 2004, $50 million in 2003 and $88 million in 2002 to develop proved undeveloped reserves that were included in our reserve report as of January 1 of each year.

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 in which 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, water disposal rights, 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, El Paso maintains insurance on our behalf to limit exposure to potential losses from 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 property or injuries to people. 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 to limit exposure to potential losses resulting from these operating hazards.

Markets and Competition

      We primarily sell our natural gas and oil to third parties through our affiliates 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 Marketing 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 operations and individual producers or operators with varying scopes of operations and financial resources. Competitive factors include price, contract terms and our ability to access drilling and other equipment on a timely and cost effective basis. 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.

Non-regulated Business — Power Segment

      Our Power segment includes the ownership and operation of international and domestic power generation facilities as well as the management of restructured power contracts. As of December 31, 2004, we owned or had interests in 17 power facilities in eight countries with a total generating capacity of approximately 3,700 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. However, during 2004 and through the first quarter of 2005, we sold substantially all of our domestic power operations. We will continue to evaluate potential opportunities to sell or otherwise divest many of our remaining power assets.

      International Power. As of December 31, 2004, we owned or had a direct investment in the following international power plants:

     Domestic Power Plants. During 2004 and the first quarter of 2005, we sold substantially all of our domestic power assets. As of December 31, 2004, we owned or had a direct investment in the following domestic power facilities:

Regulatory Environment & Markets and Competition

      International. Our international power generation activities are regulated by numerous governmental agencies in the countries in which these projects are located. Many of these countries have recently developed or are developing new regulatory and legal structures to accommodate private and foreign-owned businesses. These regulatory and legal structures are subject to change (including differing interpretations) over time.

      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, competitive and political risks.

      Domestic. 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. Our cogeneration power production activities are regulated by the FERC under the Public Utility Regulatory Policies Act of 1987 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.

Non-regulated Business — Field Services Segment

      Our Field Services segment conducts our midstream activities, which include gathering and processing of natural gas for natural gas producers, primarily in the south Louisiana production area. We currently expect to sell many of these assets.

      Gathering and Processing Assets. As of December 31, 2004, our gathering systems consisted of 77 miles of pipeline with 25 MMcfe/d of throughput capacity. These systems had average throughput of 7 BBtue/d during 2004. Our processing facilities had operational capacity and volumes as follows:

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

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

      Markets and Competition. We compete with major interstate and intrastate pipeline companies in transporting natural gas and NGL. 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. 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 and production activity, customer service and access to favorable downstream markets.

Other Operations and Assets

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

      Our corporate operations include our general and administrative functions as well as our petroleum ship charter operations and various other contracts and assets, all of which were insignificant to our results in 2004.

      Our discontinued operations consist of our petroleum markets business and our international natural gas and oil production operations, primarily in Canada.

Environmental

      A description of our environmental activities is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 13, and is incorporated herein by reference.

Employees

      As of April 5, 2005, we had approximately 900 full-time employees, none of whom are subject to collective bargaining agreements.

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

      Details of the cases listed below, as well as a description of our legal proceedings are included in Part II, Item 8, Financial Statements and Supplementary Data, Note 13, and is incorporated herein by reference.

      Corpus Christi Refinery Air Violations. On March 18, 2004, the Texas Commission on Environmental Quality 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 filed a hearing request to protect our procedural rights. Pursuant to discussions on March 16, 2005, the parties have reached an agreement in principle to resolve the allegations for $272,097. The parties are drafting the final settlement document formalizing the agreement.

      Coastal Eagle Point Air Issues. Pursuant to the Environmental Protection Agency’s (EPA) Petroleum Refinery Initiative, our former Eagle Point refinery resolved certain claims of the U.S. and the State of New Jersey in a Consent Decree entered in December 2003. The Eagle Point refinery will invest an estimated $3 million 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 New Jersey Department of Environmental Protection 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, prior to the sale. We 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. 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 alleged reporting violations. We responded to the EPA’s demand, and we have fully resolved the alleged violations by paying a penalty of $50,345 and conducting a supplemental project costing $59,581.

      Natural Buttes. In May 2004, 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. We are in negotiations with the EPA as to the appropriate penalty and have reserved our anticipated settlement amount.

      None.

PART II

      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

      Item 6, Selected Financial Data, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

      The information required by this Item is presented in a reduced disclosure format permitted by General Instruction I to Form 10-K. The Notes to Consolidated Financial Statements contain information that is pertinent to the following analysis, including a discussion of our significant accounting policies.

Liquidity and Capital Resources

      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.

      Some of our subsidiaries are subsidiary guarantors of El Paso’s $3 billion credit agreement. In connection with these guarantees, El Paso pledged our ownership of ANR, ANR Storage, CIG, and WIC to collateralize the $3 billion credit agreement. Our ownership in the above mentioned companies is subject to change if there is an event of default under the $3 billion credit agreement and the lenders under the $3 billion credit agreement 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 could 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 some of 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 could adversely affect our liquidity position and, in turn, our financial condition.

      For a further discussion of our debt, other obligations and other commitments and obligations, see Item 8, Financial Statements and Supplementary Data, Notes 12 and 13.

Results of Operations

Overview

      As of December 31, 2004, our operating business segments were Pipelines, Production, Power and Field Services. These segments provide a variety of energy products and services. They are managed separately and each requires different technology and marketing strategies. Our businesses are divided into two primary business lines: regulated and non-regulated. Our regulated business includes our Pipelines segment, while our non-regulated business includes our Production, Power and Field Services segments.

      Our management, as well as El Paso’s management, uses EBIT to assess the operating results and effectiveness of our business segments. We define EBIT as net income (loss) adjusted for (i) items that do not impact our income (loss) from continuing operations, such as extraordinary items, discontinued operations and the impact of accounting changes, (ii) income taxes, (iii) interest and debt expense and (iv) distributions on preferred interests of consolidated subsidiaries. Our businesses consist of consolidated operations as well as investments in unconsolidated affiliates. We exclude interest and debt expense and distributions on preferred interests of consolidated subsidiaries so that investors may evaluate our operating results independently from our financing methods or capital structure. We believe EBIT is helpful to our investors because it allows them to more effectively evaluate the operating performance of both our consolidated businesses and our unconsolidated investments using the same performance measure analyzed internally by our management. EBIT may not be comparable to measurements used by other companies. Additionally, EBIT should be considered in conjunction with net income and other performance measures such as operating income or operating cash flow.

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

Individual Segment Results

Regulated Business — Pipelines Segment

      Our Pipelines segment consists of interstate natural gas transmission, storage and related services in the United States. We face varying degrees of competition in this segment from other pipelines and proposed LNG facilities, as well as from alternative energy sources used to generate electricity, such as hydroelectric power, nuclear, coal and fuel oil.

      The FERC regulates the rates we can charge our customers. These rates are a function of the cost of providing services to our customers, including a reasonable return on our invested capital. As a result, our revenues have historically been relatively stable. However, our financial results can be subject to volatility due to factors such as changes in natural gas prices and market conditions, regulatory actions, competition, the creditworthiness of our customers and weather. In 2004, approximately 90 percent of our transportation service and storage revenues were attributable to reservation charges paid by firm customers. The remaining 10 percent of our revenues were variable. We also experience earnings volatility when the amount of natural gas utilized in operations differs from the amounts we receive for that purpose.

      Historically, much of our business was conducted through long term contracts with customers. However, over the past several years some of our customers have shifted from a traditional dependence solely on long-term contracts to a portfolio approach which balances short-term opportunities with long-term commitments. This shift, which can increase the volatility of our revenues, is due to changes in market conditions and competition driven by state utility deregulation, local distribution company mergers, new supply sources, volatility in natural gas prices, demand for short-term capacity and new power plant markets.

      In addition, our ability to extend existing customer contracts or re-market expiring contracted capacity is dependent on the competitive alternatives, the regulatory environment at the federal, state and local levels and market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of

new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Subject to regulatory constraints, we attempt to re-contract or re-market our capacity at the maximum rates allowed under our tariffs, although, at times, we discount these rates to remain competitive. The level of discount varies for each of our pipeline systems. Our existing contracts mature at various times and in varying amounts of throughput capacity. We continue to manage our recontracting process to limit the risk of significant impacts on our revenues. The weighted average remaining contract term for active contracts is approximately 4 years as of December 31, 2004. Below is the expiration schedule for contracts executed as of December 31, 2004, including those whose terms begin in 2005 or later.

Operating Results

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

     The following contributed to our overall EBIT decrease in 2004 as compared to 2003:

     The following provides further discussion on the items listed above as well as an outlook on events that may affect our operations in the future.

      Contract Modifications/Terminations. Included in this item are (i) the renegotiation or restructuring of several contracts on our pipeline systems, including ANR’s contracts with We Energies which contributed to the decrease in revenues by $36 million in 2004 and (ii) the termination of the Dakota gasification facility contract on ANR’s system, which resulted in lower operating revenues and lower operating expenses during 2004, without a significant overall impact on operating income and EBIT.

      Guardian Pipeline, which is owned in part by We Energies, currently provides a portion of We Energies’ firm transportation requirements and, therefore, directly competes with ANR for a portion of the markets in Wisconsin. This could impact ANR’s existing customer contracts as well as future contractual negotiations with We Energies. In addition, ANR has entered into an agreement with a shipper to restructure one of its transportation contracts on its Southeast Leg as well as a related gathering contract. In March 2005, this restructuring was completed and ANR received approximately $26 million, which will be included in its earnings during the first quarter of 2005.

      Gas not used in Operations, Processing Revenues and Other Gas Sales. The financial impact of operational gas, net of gas used in operations is based on the amount of natural gas we are allowed to recover and dispose of according to our tariff, relative to the amounts of gas we use for operating purposes, and the price of natural gas. Gas not needed for operations results in revenues to us, which is driven by volumes and prices during the period. During 2004, we recovered, fairly consistently, volumes of natural gas that were not utilized for operations. These recoveries were and are based on factors such as system throughput, facility enhancements, gas processing margins and the ability to operate the systems in the most efficient and safe manner. Additionally, a steadily increasing natural gas price environment during this timeframe also resulted in favorable impacts on our operating results in 2004 versus 2003. We anticipate that this area of our business will continue to vary in the future and will be impacted by things such as rate actions, efficiency of our pipeline operations, natural gas prices and other factors.

      Expansions. During the two years ended December 31, 2004, we completed a number of expansion projects that have generated or will generate new sources of revenues, the more significant of which was our ANR WestLeg Expansion. Our expansions during these years added approximately 310 MMcf/d to our overall pipeline system.

      Our pipeline systems connect the principal gas supply regions to the largest consuming regions in the U.S. We are well-positioned to capture growth opportunities in the Rocky Mountains and deepwater Gulf of Mexico, and have an infrastructure that complements LNG growth. We are aggressively seeking to attach new supplies of natural gas to our systems in order to maintain an adequate supply of gas to serve our growing markets and to replace quantities lost due to the natural decline in production from wells currently attached to our system.

      Expansion projects currently in process include:

      Other Regulatory Matters. In November 2004, the FERC issued a proposed accounting release that may impact certain costs our interstate pipelines incur related to their pipeline integrity programs. If the release is enacted as written, we would be required to expense certain future pipeline integrity costs instead of capitalizing them as part of our property, plant and equipment. Although we continue to evaluate the impact of this potential accounting release, we currently estimate that if the release is enacted as written, we would be required to expense an additional amount of pipeline integrity expenditures in the range of approximately $6 million to $12 million annually over the next eight years.

      In 2003 we re-applied Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation, on our CIG and WIC systems, resulting in income from recording the regulatory assets of these systems. SFAS No. 71 allows a company to capitalize items that will be considered in future rate proceedings and $18 million in income resulted from the capitalization of those items that we believe will be considered in CIG’s and WIC’s future rate cases. At the same time CIG and WIC re-applied SFAS No. 71, they adopted the FERC depreciation rate for their regulated plant and equipment. This change resulted in an increase in depreciation expense of approximately $9 million in 2004, an increase which will continue in the future. As of December 31, 2004, ANR Storage Company re-applied SFAS No. 71 which had an immaterial impact and also adopted the FERC depreciation rate which will result in future depreciation expense increases of approximately $4 million annually.

      Our pipeline systems periodically file for changes in their rates which are subject to the approval of the FERC. Changes in rates and other tariff provisions resulting from these regulatory proceedings have the potential to negatively impact our profitability. CIG is required to file for new rates that would be effective October 2006. Our other pipelines have no requirements to file new rate cases and, absent any further regulatory action, expect to continue operating under their existing rates.

Non-regulated Businesses — Production Segment

      Our Production segment conducts our natural gas and oil exploration and production activities. Our operating results are driven by a variety of factors including the ability to locate and develop economic natural gas and oil reserves, extract those reserves with minimal production costs, sell the products at attractive prices and minimize our total administrative costs.

      Our long-term strategy includes developing our production opportunities primarily in the United States and Brazil, while prudently divesting of production properties outside of these regions. We emphasize strict capital discipline designed to improve capital efficiencies through the use of standardized risk analysis and a heightened focus on cost control. We also implemented a more rigorous process for booking proved natural gas and oil reserves, which includes multiple layers of reviews by personnel independent of the reserve estimation process. Our plan is to stabilize production by improving the production mix across our operating areas and to generate more predictable returns. We intend to improve our production mix by allocating more capital to long-life, slower decline projects and to develop projects in longer reserve life areas. This is being accomplished through our more rigorous capital review process and a more balanced allocation of our capital to development and exploration projects, supplemented by acquisition activities with low-risk development locations that provide operating synergies with our existing operations. In March 2005, we purchased the interests held by one of the parties under a net profits interest agreement for approximately $22 million. See Item 8, Financial Statements and Supplementary Data, under the heading Supplemental Natural Gas and Oil Operations for a further discussion of our net profits interest agreements.

Reserves, Production and Costs

      Our estimate of proved natural gas and oil reserves as of December 31, 2004, reflects 679 Bcfe of proved reserves in the United States and 125 Bcfe of proved reserves in Brazil. These estimates were prepared internally by us. Ryder Scott Company, an independent petroleum engineering firm, prepared an estimate of our natural gas and oil reserves for 82 percent of our properties by volume. The total estimate of proved reserves prepared by Ryder Scott is within one percent of our internally prepared estimates. Ryder Scott was retained by and reports to the Audit Committee of El Paso’s Board of Directors. The properties reviewed by Ryder Scott represented 84 percent of our properties based on value. For additional information on our estimated proved reserves and the processes by which they are developed, see Part I, Item 1, Business, Non-regulated Business — Production Segment, Item 7, Risk Factors, and Item 8, Financial Statements and Supplementary Data, under the heading Supplemental Natural Gas and Oil Operations.

      For 2004, our total equivalent production declined 55 Bcfe or 31 percent as compared to 2003. The decrease was due to production declines in our Texas Gulf Coast and offshore Gulf of Mexico regions and a significantly reduced capital expenditure program in 2004 compared to 2003.

      Our depletion rate is determined under the full cost method of accounting. Due to disappointing drilling performance in 2004 that resulted in higher finding and development costs, we expect our domestic unit of production depletion rate to increase from $2.68/Mcfe in the fourth quarter of 2004 to $2.73/Mcfe in the first quarter of 2005. Our future trends in production and depletion rates will be dependent upon the amount of capital allocated to our Production segment, the level of success in our drilling programs and any future sale or acquisition activities relating to our proved reserves.

      Our relatively high historical finding and development costs and disappointing drilling performance increase the likelihood of future ceiling test charges if natural gas and oil prices decline or if we experience negative reserve revisions.

      As part of our overall strategy, we hedge our natural gas and oil production to stabilize cash flows, reduce the risk of downward commodity price movements on our sales and to protect the economic assumptions associated with our capital investment programs. We conduct our hedging activities through natural gas and oil derivatives on our natural gas and oil production. Because this hedging strategy only partially reduces our exposure to downward movements in commodity prices, our reported results of operations, financial position and cash flows can be impacted significantly by movements in commodity prices from period to period. At December 31, 2004, our hedging position included 12,750 BBtu of our anticipated natural gas production for each quarter in 2005 at a hedged price of $3.31 per MMBtu.

      In December 2004, we replaced our existing hedges on approximately 51 TBtu of natural gas with new hedge transactions at the same volume and over the same time period. The combination of our original hedges and the new transactions will not change the average price at which we are hedged and will not have an impact on our realized prices. As a result, these transactions will have the same impact on our accumulated other comprehensive income balances, cash flow and income statements as our original derivative positions that existed prior to December 1, 2004. However, these transactions “locked in” a loss of approximately $180 million in accumulated other comprehensive income that will be recognized in earnings as our original hedged transactions settle in 2005. We have entered into a service agreement with El Paso that provides for a reimbursement of 2.5 cents per MMBtu in 2005 for our expected administrative costs associated with these transactions.

Operational Factors Affecting the Year Ended December 31, 2004

      During 2004, our Production segment experienced the following:

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