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 1-2700

El Paso Natural Gas 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 stock 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 March 29, 2005: 1,000

     EL PASO NATURAL GAS 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 NATURAL GAS 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 cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.

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

PART I

ITEM 1. BUSINESS

General

      We are a Delaware corporation incorporated in 1928, and an indirect wholly owned subsidiary of El Paso Corporation (El Paso). Our primary business is the interstate transportation of natural gas. We conduct our business activities through two pipeline systems, each of which is discussed below.

      The EPNG system. The El Paso Natural Gas system consists of approximately 11,000 miles of pipeline with a winter sustainable west-flow capacity of 4,850 MMcf/d and approximately 800 MMcf/d of east-end deliverability. During 2004, 2003 and 2002, average throughput on the EPNG system was 4,074 BBtu/d, 3,874 BBtu/d and 3,799 BBtu/d. This system delivers natural gas from the San Juan, Permian and Anadarko basins to California, which is our single largest market, as well as markets in Arizona, Nevada, New Mexico, Oklahoma, Texas and northern Mexico.

      The Mojave system. The Mojave Pipeline Company (Mojave) system consists of approximately 400 miles of pipeline with a design capacity of approximately 400 MMcf/d. During 2004, 2003 and 2002, average throughput on the Mojave system was 161 BBtu/d, 192 BBtu/d and 266 BBtu/d. This system connects with the EPNG and Transwestern transmission systems at Topock, Arizona, the Kern River Gas Transmission Company transmission system in California and extends to customers in the vicinity of Bakersfield, California.

Regulatory Environment

      Our interstate natural gas transmission systems are regulated by the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Our pipeline systems operate 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;

      • certification and construction of new facilities;

      • extension or abandonment of services and facilities;

      • maintenance of accounts and records;

      • relationships between pipeline and energy affiliates;

      • terms and conditions of services;

      • 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 service to our customers, and include provisions for a reasonable return on our invested capital. Approximately 93 percent of our 2004 transportation services revenue is attributable to reservation charges paid by firm customers. Firm customers are those who are obligated to pay a monthly reservation charge, regardless of the amount of natural gas they transport, for the term of their contracts. The remaining seven percent of our transportation services revenue is 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 changes in natural gas prices and market conditions, regulatory actions, competition, weather and the creditworthiness of our customers. We also experience volatility in our financial results when the amounts of natural gas utilized in operations differ from the amounts we receive for that purpose.

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

      We are subject to regulation over the safety requirements in the design, construction, operation and maintenance of our interstate natural gas transmission systems by the U.S. Department of Transportation. Our operations on U.S. government land are regulated by the U.S. Department of the Interior.

      A discussion of significant rate and regulatory matters is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 6, and is incorporated herein by reference.

Markets and Competition

      Our markets consist of distribution and industrial companies, electric generation companies, natural gas producers, other natural gas pipelines, and natural gas marketing and trading companies. We provide transportation services in both our natural gas supply and market areas. Our pipeline systems connect with multiple pipelines that provide our customers with access to diverse sources of supply and various natural gas markets serviced by these pipelines.

      A number of large natural gas consumers are electric utility companies who use natural gas to fuel electric power generation facilities. Electric power generation is the fastest growing demand sector of the natural gas market. The growth and development of the electric power industry potentially benefit the natural gas industry by creating more demand for natural gas turbine generated electric power, but this effect is offset, in varying degrees, by increased electric generation efficiency, the more effective use of surplus electric capacity as well as 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 natural gas in the industrial sector. In addition, in several regions of the country, new additions in electric generation capacity have exceeded electric load growth and transmission capabilities out of those regions. These developments may inhibit owners of new power generation facilities from signing firm contracts with us.

      We serve major markets in the southwestern United States and California as well as northern Mexico. These have recently been among the fastest growing regions in the U.S. and Mexico; therefore the market demand for natural gas distribution as well as gas-fired electric generation capacity has experienced considerable growth. This demand growth has slowed moderately from the levels in 2000-2001, and we expect it to continue at a slower rate. The combined capacity of all pipeline companies serving the California market is approximately 8.5 Bcf/d and we provide approximately 39 percent of this capacity. In 2004, the demand for interstate pipeline capacity to California averaged 5.2 Bcf/d, equivalent to approximately 61 percent of the total interstate pipeline capacity serving that state. Natural gas shipped to California across our system represented approximately 26 percent of the natural gas consumed in the state in 2004.

      Our existing transportation contracts mature at various times and in varying amounts of throughput capacity. Our ability to extend our existing contracts or remarket expiring capacity at maximum rates is dependent on competitive alternatives, access to capital, 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. While we are allowed to negotiate contracts at the maximum rates allowed under our tariffs, we must, at times, discount our contracts to remain competitive.

      The following table details the markets we serve and the competition on our pipeline systems as of December 31, 2004:

Environmental

      A description of our environmental activities is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 6, and is incorporated herein by reference.

Employees

      As of March 24, 2005, we had approximately 770 full-time employees, none of whom are subject to collective bargaining arrangements.

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 is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 6, and is incorporated herein by reference.

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

      Item 4, Submission of Matters to a Vote of Security Holders, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

PART II

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

      We pay dividends on our common stock from time to time from legally available funds that have been approved for payment by our Board of Directors. In 2002, we declared and paid to El Paso a non-cash dividend of non-regulated assets in the amount of $19 million. There were no common stock dividends declared during 2004 and 2003.

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 pursuant to General Instruction I to Form 10-K. The notes to our consolidated financial statements contain information that is pertinent to the following analysis, including a discussion of our significant accounting policies.

Overview

      Our business consists of interstate natural gas transportation services. Our interstate natural gas transportation systems face varying degrees of competition from other pipelines, as well as from alternative energy sources used to generate electricity, such as hydroelectric power, nuclear, coal and fuel oil.

      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, weather and the creditworthiness of our customers. We also experience volatility in our financial results when the amounts of natural gas utilized in operations differ from the amounts we receive for that purpose. In 2004, 93 percent of our transportation services revenues were attributable to reservation charges paid by firm customers. The remaining seven percent was variable.

      Our ability to extend existing customer contracts or remarket expiring contracted capacity is dependent on the competitive alternatives, the regulatory environment at the federal, state and local levels and the 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 recontract or remarket our capacity at the maximum rates allowed under our tariffs, although, at times, we discount these rates to remain competitive. Our existing contracts mature at various times and in varying amounts of throughput capacity. We continue to manage our recontracting process to mitigate the risk of significant impacts on our revenues. The weighted average remaining contract term for active and extended contracts is approximately five years as of December 31, 2004. Approximately 1,564 MMcf/d currently under contract is subject to early termination in August 2006 (and other subsequent dates) provided customers give timely notice of an intent to terminate. If all of these rights were exercised, the weighted average remaining contract term would decrease to approximately three years and would expire as follows:

Results of Operations

      Our management, as well as El Paso’s management, uses earnings before interest expense and income taxes (EBIT) to assess the operating results and effectiveness of our business. We define EBIT as net income adjusted for (i) items that do not impact our income from continuing operations, (ii) income taxes, (iii) interest and debt expense and (iv) affiliated interest income. We exclude interest and debt expense from this measure so that our management can evaluate our operating results without regard to our financing methods. We believe the discussion of our results of operations based on EBIT is useful to our investors because it allows them to more effectively evaluate the operating performance of our business 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.

      The following is a reconciliation of EBIT to net income for the years ended December 31:

      The following items contributed to our overall EBIT increase of $101 million for the year ended December 31, 2004 as compared to 2003:

      The following provides further discussions on some of the significant items listed above as well as events that may affect our operations in the future.

      Risk sharing provision. Our risk sharing provision, which provided revenue net of our sharing obligations, expired at the end of 2003 and continued to impact our comparative EBIT for 2004.

      Gas Not Used in Operations. 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 tariffs, 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 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.

      Western Energy Settlement. In 2003, El Paso entered into the Western Energy Settlement. We were a party to that settlement and recorded a charge to our 2002 operating expenses of $412 million for our share of the expected settlement amounts. This charge represented the value of El Paso stock and cash that we paid to the settling parties. In the second quarter of 2003, the settlement was finalized and we recorded an additional net pretax charge of $127 million. Also, during 2003, accretion expense and other miscellaneous charges of $13 million were recorded and included in operating expenses.

      Expansions. In order to meet increased demand in our markets and comply with FERC orders, we completed Phases I, II, and III of our EPNG Line 2000 Power-up project in 2004, which increased the capacity of that line by 320 MMcf/d. In addition, we expect to complete the EPNG Cadiz to Ehrenberg project by the end of 2005, which will increase our north-to-south capacity by 372 MMcf/d. We expect to earn revenues associated with these expansions beginning in January 2006, the effective date of EPNG’s next rate filing.

      Significant growth opportunities exist in Arizona, California, and northern Mexico. Potential new competition for this growth may emerge through proposed LNG facilities and pipeline projects proposed by competitor pipelines.

      Recontracting. We entered into an agreement to extend 750 MMcf/d of capacity, effective September 1, 2006, on our EPNG pipeline system with Southern California Gas Company (SoCal). This precedent agreement is subject to FERC approval and the successful awarding of the capacity to SoCal following the post and bid process required by EPNG’s tariff. The new service agreements will have primary terms of three to five years to serve SoCal’s core customers at rates that are, on average, less than our current maximum rates. SoCal is currently contracted on our EPNG system for approximately 1.3 Bcf/d of capacity. We continue in our efforts to market the remaining capacity, including marketing efforts to serve, directly or indirectly, SoCal’s non-core customers or to serve new markets. At this time, we are uncertain whether this remaining capacity will be recontracted.

      Navajo Nation. Nearly 900 looped pipeline miles of the north mainline of our EPNG pipeline system are located on property inside the Navajo Nation. We currently pay approximately $2 million per year for the real property interests, such as easements, leases and rights-of-way, located on Navajo Nation trust lands. These real property interests are scheduled to expire in October 2005. We are in negotiations with the Navajo Nation to renew these interests, but the Navajo Nation has made a demand of more than ten times the existing fee. We will continue to negotiate in order to reach an agreement on a renewal, but we are also exploring other options including potentially developing collaborative projects to benefit the Navajo Nation in lieu of cash payments. The outcome of this process is uncertain, but we may incur higher future costs arising from potential litigation or increased right-of-way fees.

      Regulatory Matters. In November 2004, the FERC issued a proposed accounting release that may impact certain costs we incur related to our pipeline integrity program. 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 that this potential accounting release will have on our consolidated financial statements, we currently estimate that we would be required to expense an additional amount of pipeline integrity expenditures in the range of approximately $5 million to $11 million annually over the next eight years.

      In November 2004, the FERC issued a Notice of Inquiry(NOI) seeking comments on its policy regarding selective discounting by natural gas pipelines. The FERC seeks comments regarding whether its practice of permitting pipelines to adjust their ratemaking throughput downward in rate cases to reflect discounts given by pipelines for competitive reasons is appropriate when the discount is given to meet competition from another natural gas pipeline. We, along with several of our affiliated pipelines, filed comments on the NOI in March 2005. The final outcome of this inquiry cannot be predicted with certainty, nor can we predict the impact that the final rule will have on us.

      We periodically file for changes in our 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. EPNG is required to file for new rates to be effective in January 2006. Mojave is required to file for new rates to be effective in March 2007.

Income Taxes

      Our effective tax rate for 2004 was lower than the statutory rate of 35 percent primarily due to a state income tax valuation adjustment related to the Western Energy Settlement discussed below and other deferred tax matters, including deferred taxes related to the Mojave pipeline system. Our effective tax rate for 2003 was higher than the statutory rate of 35 percent primarily due to the effect of state income taxes.

      As of December 31, 2003, we maintained a valuation allowance on deferred tax assets related to our ability to realize state tax benefits from the deduction of the charge we took related to the Western Energy Settlement. During the first quarter of 2004, we evaluated this allowance and now believe, based on our current estimates, that these state tax benefits will be fully realized. Consequently, we reversed this valuation allowance. Net of federal taxes, this benefit totaled approximately $6 million.

      In 2004, Congress proposed but failed to enact legislation that would disallow deductions for certain settlements made to or on behalf of governmental entities. It is possible Congress will reintroduce similar legislation in 2005. If enacted, this tax legislation could impact the deductibility of the Western Energy Settlement and could result in a write-off of some or all of the associated tax benefits. In such event, our tax expense would increase. Our total tax benefits related to the Western Energy Settlement were approximately $205 million as of December 31, 2004.

      For a reconciliation of the statutory rate to the effective rates, see Item 8, Financial Statements and Supplementary Data, Note 2.

Liquidity

      Our liquidity needs have been provided by cash flow from operating activities and the use of El Paso’s cash management program. Under El Paso’s cash management 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 provided cash advances to El Paso, and we reflect these advances as investing activities in our statement of cash flows. At December 31, 2004, we had a cash advance receivable from El Paso of $730 million as a result of this program. This receivable is due upon demand; however, we do not anticipate settlement of the entire amount in the next twelve months. At December 31, 2004, we have classified $28 million of this receivable as current affiliate receivables and $702 million as non-current notes receivable from affiliates. In addition to El Paso’s cash management program, we are also eligible to borrow amounts available under El Paso’s $3 billion credit agreement, under which we and our interest in Mojave are pledged

as collateral. We believe that cash flows from operating activities, along with the current notes receivable from El Paso under its cash management program, will be adequate to meet our short-term capital requirements for existing operations.

Capital Expenditures

      Our capital expenditures for the years ended December 31 are as follows:

      We have relatively high maintenance capital requirements over the next three years due, in part, to the requirements of the 2002 Pipeline Integrity Act and our continued commitment to improve the total integrity of our pipeline system. Under our current plan, we expect to spend between approximately $117 million and $125 million in each of the next three years for capital expenditures to maintain the integrity of our pipelines and ensure the safe and reliable delivery of natural gas to our customers. Included in these amounts are pipeline integrity supplemental program expenditures that range from approximately $33 million to $37 million in each of the next three years. In addition, we have budgeted to spend between approximately $3 million and $99 million in each of the next three years to expand the capacity of our pipeline systems contingent, in part, upon customer commitments to the projects. The primary drivers of these capacity additions are the 2005 Phoenix area lateral projects and the Cadiz to Ehrenberg (Line 1903) project, which is subject to FERC approval. We expect to fund our maintenance and expansion capital expenditures using a combination of internally generated funds and/or by recovering some of the amounts advanced to El Paso under its cash management program.

Commitments and Contingencies

      For a discussion of our commitments and contingencies, see Item 8, Financial Statements and Supplementary Data, Note 6, which is incorporated herein by reference.

New Accounting Pronouncements Issued But Not Yet Adopted

      As of December 31, 2004, there were a number of accounting standards and interpretations that had been issued, but not yet adopted by us. Based on our assessment of those standards, we do not believe there are any that could have a material impact on us.

RISK FACTORS AND CAUTIONARY STATEMENT FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

      This report contains or incorporates by reference forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Where any forward-looking statement includes a statement of the assumptions or bases underlying the forward-looking statement, we caution that, while we believe these assumptions or bases to be reasonable and in good faith, assumed facts or bases almost always vary from the actual results, and the differences between assumed facts or bases and actual results can be material, depending upon the circumstances. Where, in any forward-looking statement, we or our management express an expectation or belief as to future results, that expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the statement of expectation or belief will result or be achieved or accomplished. The words “believe,” “expect,” “estimate,” “anticipate” and similar expressions will generally identify forward-looking statements. Our forward-looking statements, whether written or oral, are expressly qualified by these cautionary statements and any other cautionary statements that may accompany those statements. In addition, we disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report.

      With this in mind, you should consider the risks discussed elsewhere in this report and other documents we file with the Securities and Exchange Commission (SEC) from time to time and the following important factors that could cause actual results to differ materially from those expressed in any forward-looking statement made by us or on our behalf.

Risks Related to Our Business

Our success depends on factors beyond our control.

      Our business is the transportation of natural gas for third parties. As a result, the volume of natural gas involved in these activities depends on the actions of those third parties, and is beyond our control. Further, the following factors, most of which are beyond our control, may unfavorably impact our ability to maintain or increase current throughput and rates, to renegotiate existing contracts as they expire, or to remarket unsubscribed capacity:

The revenues of our pipeline businesses are generated under contracts that must be renegotiated periodically, some of which are for a substantial portion of our firm transportation capacity.

      For 2004, our contracts with SoCal were substantial. SoCal recently renewed its contracts with us for 750 MMcf/d at rates that are, on average, less than our current maximum rates. We are continuing in our efforts to remarket their remaining capacity. For additional information on our contracts with SoCal, see Part I, Item 1, Business — Markets and Competition and Item 8, Financial Statements and Supplementary Data, Note 10. The loss of this customer or a decline in its creditworthiness could adversely affect our results of operations, financial position and cash flow.

      Our revenues are generated under transportation services contracts that expire periodically and must be renegotiated and extended or replaced. Although we actively pursue the renegotiation, extension and/or replacement of these contracts, we cannot assure that we will be able to extend or replace these contracts when they expire or that the terms of any renegotiated contracts will be as favorable as the existing contracts.

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

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

Fluctuations in energy commodity prices could adversely affect our business.

      Revenues generated by our transportation services contracts depend on volumes and rates, both of which can be affected by the prices of natural gas. Increased natural gas prices could result in a reduction of the volumes transported by our customers, such as power companies who, depending on the price of fuel, may not dispatch gas-fired power plants. Increased prices could also result from industrial plant shutdowns or load losses to competitive fuels and local distribution companies’ loss of customer base. We also experience volatility in our financial results when the amounts of natural gas utilized in operations differ from the amounts we receive for that purpose. The success of our operations is subject to continued development of additional oil and natural gas reserves in the vicinity of our facilities and our ability to access additional suppliers from interconnecting pipelines to offset the natural decline from existing wells connected to our systems. A decline in energy prices could precipitate a decrease in these development activities and could cause a decrease in the volume of reserves available for transmission on our system. If natural gas prices in the supply basins connected to our pipeline system are higher than prices in other natural gas producing regions, our ability to compete with other transporters may be negatively impacted. Fluctuations in energy prices are caused by a number of factors, including:

The agencies that regulate us and our customers affect our profitability.

      Our pipeline businesses are regulated by the FERC, the U.S. Department of Transportation, and various state and local regulatory agencies. Regulatory actions taken by these agencies have the potential to adversely affect our profitability. In particular, the FERC regulates the rates we are permitted to charge our customers for our services. In setting authorized rates of return in a few recent FERC decisions, the FERC has utilized a proxy group of companies that includes local distribution companies that are not faced with as much competition or risk as interstate pipelines. The inclusion of these companies may create downward pressure on tariff rates when subjected to review at the FERC.

      If our tariff rates were reduced in a future rate proceeding, if our volume of business under our currently permitted rates was decreased significantly or if we were required to substantially discount the rates for our services because of competition, our profitability and liquidity could be reduced.

      Further, state agencies and local governments that regulate our local distribution company customers could impose requirements that could impact demand for our services.

Costs of environmental liabilities, regulations and litigation could exceed our estimates.

      Our operations are subject to various environmental laws and regulations. These laws and regulations obligate us to install and maintain pollution controls and to clean up various sites at which regulated materials may have been disposed of or released. We are also party to legal proceedings involving environmental matters pending in various courts and agencies.

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

      Although we believe we have established appropriate reserves for liabilities, including clean up costs, we could be required to set aside additional reserves in the future due to these uncertainties, and these amounts could be material. For additional information, see Item 8, Financial Statements and Supplementary Data, Note 6.

Our operations are subject to operational hazards and uninsured risks.

      Our operations are subject to the inherent risks normally associated with those operations, including pipeline ruptures, explosions, pollution, release of toxic substances, fires and adverse weather conditions, and other hazards, each of which could result in damage to or destruction of our facilities or damages or injuries to persons. In addition, our operations face possible risks associated with acts of aggression on our assets. If any of these events were to occur, we could suffer substantial losses.

      While we maintain insurance against many of these risks to the extent and in amounts that we believe are reasonable, our financial condition and operations could be adversely affected if a significant event occurs that is not fully covered by insurance.

Cost of litigation could exceed our estimates.

      We have been named a party in various lawsuits. Although we believe we established appropriate reserves for these liabilities, we could be required to set aside additional reserves in the future and these amounts could

have a significant impact on our financial position, results of operations and cash flows in the specific period the respective matter transpires. For additional information concerning our litigation matters see Item 8, Financial Statements and Supplementary Data, Note 6.

Risks Related to Our Affiliation with El Paso

      El Paso files reports, proxy statements and other information with the SEC under the Securities Exchange Act of 1934, as amended. Each prospective investor should consider this information and the matters disclosed therein in addition to the matters described in this report. Such information is not incorporated by reference herein.

Our relationship with El Paso and its financial condition subjects us to potential risks that are beyond our control.

      Due to our relationship with El Paso, adverse developments or announcements concerning El Paso could adversely affect our financial condition, even if we have not suffered any similar development. The ratings assigned to El Paso’s senior unsecured indebtedness are below investment grade, currently rated Caa1 by Moody’s Investor Service and CCC+ by Standard & Poor’s. The ratings assigned to our senior unsecured indebtedness are currently rated B1 by Moody’s Investor Service and B- by Standard & Poor’s. Further downgrades of our credit rating could increase our cost of capital and collateral requirements, and could impede our access to capital markets. El Paso continues its efforts to execute its Long Range Plan that established certain financial and other objectives, including significant debt reduction. An inability to meet these objectives could adversely affect El Paso’s liquidity position, and in turn affect our financial condition.

      Pursuant to El Paso’s cash management program, surplus cash is made available to El Paso in exchange for an affiliated receivable. In addition, we conduct commercial transactions with some of our affiliates. El Paso provides cash management and other corporate services for us. If El Paso is unable to meet its liquidity needs, there can be no assurance that we will be able to access cash under the cash management program, or that our affiliates would pay their obligations to us. However, we might still be required to satisfy affiliated company payables. Our inability to recover any affiliated receivables owed to us could adversely affect our ability to repay our outstanding indebtedness. For a further discussion of these matters, see Item 8, Financial Statements and Supplementary Data, Note 9.

      In 2004, El Paso restated its 2003 and prior financial statements and the financial statements of certain of its subsidiaries for the same periods due to revisions to their natural gas and oil reserves and for adjustments related to the manner in which they historically accounted for hedges of their natural gas production. As a result of its reserve revisions, several class action lawsuits have been filed against El Paso and several of its subsidiaries, but not against us. The reserve revisions have also become the subject of investigations by the SEC and U.S. Attorney. These investigations and lawsuits may further negatively impact El Paso’s credit ratings and place further demands on its liquidity.

      We are required to maintain an effective system of internal control over financial reporting. As a result of our efforts to comply with this requirement, we determined that as of December 31, 2004, we did not maintain effective internal control over financial reporting. As more fully discussed in Item 9A, we identified several deficiencies in internal control over financial reporting, one of which management has concluded constituted a material weakness. Although we have taken steps to remediate some of these deficiencies, additional steps must be taken to remediate the remaining control deficiencies. If we are unable to remediate our identified internal control deficiencies over financial reporting, or we identify additional deficiencies in our internal controls over financial reporting, we could be subjected to additional regulatory scrutiny, future delays in filing our financial statements and suffer a loss of public confidence in the reliability of our financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, which could have a negative impact on our liquidity, access to capital markets and our financial condition.

      In addition to the risk of not completing the remediation of all deficiencies in our internal controls over financial reporting, we do not expect that our disclosure controls and procedures or our internal controls over financial reporting will prevent all mistakes, errors and fraud. Any system of internal controls, no matter how well designed or implemented, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. The design of a control system must reflect the fact that the benefits of controls must be considered relative to their costs. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Therefore, any system of internal controls is subject to inherent limitations, including the possibility that controls may be circumvented or overridden, that judgments in decision-making can be faulty, and that misstatements due to mistakes, errors or fraud may occur and may not be detected. Also, while we document our assumptions and review financial disclosures, the regulations and literature governing our disclosures are complex and reasonable persons may disagree as to their application to a particular situation or set of facts. In addition, the applicable regulations and literature are relatively new. As a result, they are potentially subject to change in the future, which could include changes in the interpretation of the existing regulations and literature as well as the issuance of more detailed rules and procedures.

We may be subject to a change of control under certain circumstances.

      One of our subsidiaries, Sabine River Investor V, L.L.C. (Sabine V), is one of many subsidiary guarantors of El Paso’s $3 billion credit agreement. In connection with its guarantee of the agreement, Sabine V pledged its ownership of Mojave Pipeline, its sole asset, as collateral. In addition, in connection with the guarantee of El Paso’s credit agreement, our direct parent, El Paso EPNG Investments, L.L.C., pledged its equity interests in us as collateral. As a result, our ownership is subject to change if there is an event of default under the credit agreement and El Paso’s lenders under its credit agreement exercise rights over their collateral.

A default under El Paso’s $3 billion credit agreement by any party could accelerate our future borrowings, if any, under the credit agreement and our long-term debt, which could adversely affect our liquidity position.

      We are a party to El Paso’s $3 billion credit agreement. We are only liable, however, for our borrowings under the agreement, which were zero as of December 31, 2004. Under the agreement, a default by El Paso, or any other party, could result in the acceleration of all outstanding borrowings under the credit agreement, including the borrowings of any non-defaulting party. The acceleration of our future borrowings, if any, under the credit agreement, or the inability to borrow under the credit agreement, could adversely affect our liquidity position and, in turn, our financial condition.

      Furthermore, the indentures governing our long-term debt contain cross-acceleration provisions. Therefore, if we borrow $25 million or more under the credit agreement and such borrowings are accelerated for any reason, including the default of another party under the credit agreement, our long-term debt could also be accelerated. The acceleration of our long-term debt could also adversely affect our liquidity position and, in turn, our financial condition.

We could be substantively consolidated with El Paso if El Paso were forced to seek protection from its creditors in bankruptcy.

      If El Paso were the subject of 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. The equitable doctrine of substantive consolidation permits a bankruptcy court to disregard the separateness of related entities and to consolidate and pool the entities’ assets and liabilities and treat them as though held and incurred by one entity where the interrelationship between the entities warrants such consolidation. We believe that any effort to substantively consolidate us with El Paso and/or its other subsidiaries would be without merit. However, we cannot assure you that El Paso and/or its other subsidiaries or their respective creditors would not attempt to

advance such claims in a bankruptcy proceeding or, if advanced, how a bankruptcy court would resolve the issue. If a bankruptcy court were to substantively consolidate us with El Paso and/or its other subsidiaries, there could be a material adverse effect on our financial condition and liquidity.

We are an indirect subsidiary of El Paso.

      As an indirect subsidiary of El Paso, El Paso has substantial control over:

      El Paso may exercise such control in its interests and not necessarily in the interests of us or the holders of our long-term debt.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

      Our primary market risk is exposure to changing interest rates. The table below shows the carrying value and related weighted average effective interest rates of our interest bearing securities, by expected maturity dates, and the fair value of those securities. The carrying amounts of short-term borrowings are representative of fair values because of the short-term maturity of these instruments. At December 31, 2004, the fair values of our fixed rate long-term debt securities have been estimated based on quoted market prices for the same or similar issues.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

EL PASO NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(In millions)

See accompanying notes.

EL PASO NATURAL GAS COMPANY

CONSOLIDATED BALANCE SHEETS

(In millions, except share amounts)

See accompanying notes.

EL PASO NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

See accompanying notes.

EL PASO NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY

(In millions, except share amounts)

See accompanying notes.

EL PASO NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

  Basis of Presentation and Principles of Consolidation

      Our consolidated financial statements include the accounts of all majority-owned and controlled subsidiaries after the elimination of all significant intercompany accounts and transactions. We consolidate entities when we either (i) have the ability to control the operating and financial decisions and policies of that entity or (ii) are allocated a majority of the entity’s losses and/or returns through our variable interests in that entity. The determination of our ability to control or exert significant influence over an entity and whether we are allocated a majority of the entity’s losses and/or returns involves the use of judgment. Our financial statements for prior periods include reclassifications that were made to conform to the current year presentation. Those reclassifications had no impact on reported net income or stockholder’s equity.

  Use of Estimates

      The preparation of financial statements in conformity with accounting principles generally accepted in the U.S. requires the use of estimates and assumptions that affect the amounts we report as assets, liabilities, revenues and expenses and our disclosures in these financial statements. Actual results can, and often do, differ from those estimates.

     Regulated Operations

      Our natural gas systems are subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, and we currently apply the provisions of Statements of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Type of Regulation. We perform an annual study to assess the ongoing applicability of SFAS No. 71. The accounting required by SFAS No. 71 differs from the accounting required for businesses that do not apply its provisions. Transactions that are generally recorded differently as a result of applying regulatory accounting requirements include capitalizing an equity return component on regulated capital projects, postretirement employee benefit plans, and other costs included in, or expected to be included in, future rates.

  Cash and Cash Equivalents

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

  Allowance for Doubtful Accounts

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

  Materials and Supplies

      We value materials and supplies at the lower of cost or market value with cost determined using the average cost method.

  Natural Gas Imbalances

      Natural gas imbalances occur when the actual amount of natural gas delivered from or received by a pipeline system differs from the contractual amount of natural gas delivered or received. We value these

imbalances due to or from shippers and operators at an actual or appropriate index price. Imbalances are settled in cash or made up in kind, subject to the terms of settlement.

      Imbalances due from others are reported in our balance sheet as either accounts receivable from customers or accounts receivable from affiliates. Imbalances owed to others are reported on the balance sheet as either trade accounts payable or accounts payable to affiliates. In addition, we classify all imbalances as current.

  Property, Plant and Equipment

      Our property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at either the fair value of the assets acquired or the cost to the entity that first placed the asset in service. For assets we construct, we capitalize direct costs, such as labor and materials, and indirect costs, such as overhead, interest and an equity return component for our regulated business as allowed by the FERC. We capitalize the major units of property replacements or improvements and expense minor items.

      We use the composite (group) method to depreciate regulated property, plant and equipment. Under this method, assets with similar lives and other characteristics are grouped and depreciated as one asset. We apply the FERC-accepted depreciation rate to the total cost of the group until its net book value equals its salvage value. For all other property, plant and equipment we depreciate the asset to zero. Currently, our depreciation rates vary from two to 33 percent. Using these rates, the remaining depreciable lives of these assets range from two to 43 years. We re-evaluate depreciation rates each time we file with the FERC for a change in our transportation services rates.

      When we retire property, plant and equipment, we charge accumulated depreciation and amortization for the original cost, plus the cost to remove, sell or dispose, less its salvage value. We do not recognize a gain or loss unless we sell an entire operating unit. We include gains or losses on dispositions of operating units in income.

      Included in our pipeline property balances are additional acquisition costs of $151 million which represent the excess of allocated purchase costs over historical costs of these facilities. These costs are amortized on a straight-line basis over 36 years, and we do not recover these excess costs in our rates. At December 31, 2004, we had unamortized additional acquisition costs of $67 million.

      At December 31, 2004 and 2003, we had approximately $104 million and $218 million of construction work in progress included in our property, plant and equipment.

      We capitalize a carrying cost (an allowance for funds used during construction) on funds invested in our construction of long-lived assets. This carrying cost consists of a return on the investment financed by debt and a return on the investment financed by equity. The debt portion is calculated based on our average cost of debt. Debt amounts capitalized during the years ended December 31, 2004, 2003 and 2002, were $3 million, $3 million and $6 million. These amounts are included as a reduction to interest expense in our income statement. The equity portion is calculated using the most recent FERC approved equity rate of return. The equity amount capitalized during the years ended December 31, 2004 and 2003, was $4 million (exclusive of any tax related impacts). Equity amounts capitalized for the year ended December 31, 2002 were immaterial. These amounts are included as other non-operating income on our income statement. Capitalized carrying costs for debt and equity financed construction are reflected as an increase in the cost of the asset on our balance sheet.

  Asset Impairments

      We apply the provisions of SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, to account for asset impairments. Under this standard, we evaluate an asset for impairment when events or circumstances indicate that its carrying value may not be recovered. These events include market declines, changes in the manner in which we intend to use an asset, decisions to sell an asset and adverse changes in the legal or business environment such as adverse actions by regulators. When an event occurs, we evaluate the recoverability of the asset’s carrying value based on its ability to generate future cash flows on an

undiscounted basis. If an impairment is indicated or if we decide to exit or sell a long-lived asset or group of assets, we adjust the carrying value of these assets downward, if necessary, to their estimated fair value, less costs to sell. Our fair value estimates are generally based on market data obtained through the sales process and an analysis of expected discounted cash flows. The magnitude of any impairment is impacted by a number of factors, including the nature of the assets to be sold and our established time frame for completing the sales, among other factors.

  Revenue Recognition

      Our revenues consist primarily of demand and throughput-based transportation services. We recognize demand revenues on firm contracted capacity monthly over the contract period regardless of the amount of capacity that is actually used. For throughput-based services, we record revenues when physical deliveries of natural gas are made at the agreed upon delivery point. Revenues are generally based on the thermal quantity of gas delivered or subscribed at a price specified in the contract. We are subject to FERC regulations and, as a result, revenues we collect may possibly be refunded in a final order of a pending rate proceeding or as a result of a rate settlement. We establish reserves for these potential refunds.

  Environmental Costs and Other Contingencies

      We record environmental liabilities when our environmental assessments indicate that remediation efforts are probable, and the costs can be reasonably estimated. We recognize a current period expense for the liability when clean-up efforts do not benefit future periods. We capitalize costs that benefit more than one accounting period, except in instances where separate agreements or legal and regulatory guidelines dictate otherwise. Estimates of our liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into account the likely effects of inflation and other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the Environmental Protection Agency (EPA) or other organizations. These estimates are subject to revision in future periods based on actual costs or new circumstances and are included in our balance sheet in other current and long-term liabilities at their undiscounted amounts. We evaluate recoveries from insurance coverage, rate recovery, government sponsored and other programs separately from our liability and, when recovery is assured, we record and report an asset separately from the associated liability in our financial statements.

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

  Income Taxes

      El Paso maintains a tax accrual policy to record both regular and alternative minimum taxes for companies included in its consolidated federal and state income tax returns. The policy provides, among other things, that (i) each company in a taxable income position will accrue a current expense equivalent to its federal and state income taxes, and (ii) each company in a tax loss position will accrue a benefit to the extent its deductions, including general business credits, can be utilized in the consolidated returns. El Paso pays all consolidated U.S. federal and state income taxes directly to the appropriate taxing jurisdictions and, under a separate tax billing agreement, El Paso may bill or refund its subsidiaries for their portion of these income tax payments.

      Pursuant to El Paso’s Policy, we report current income taxes based on our taxable income and we provide for deferred income taxes to reflect estimated future tax payments or receipts. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. We account for tax credits under the flow-through method, which reduces the provision for income taxes in the year the tax credits first become available. We reduce deferred tax assets by a valuation

allowance when, based on our estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The estimates utilized in the recognition of deferred tax assets are subject to revision, either up or down, in future periods based on new facts or circumstances.

2. Income Taxes

      The following table reflects the components of income taxes included in net income for each of the three years ended December 31:

      Our income taxes differ from the amount computed by applying the statutory federal income tax rate of 35 percent for the following reasons for each of the three years ended December 31:

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

      In 2004, Congress proposed but failed to enact legislation which would disallow deductions for certain settlements made to or on behalf of governmental entities. It is possible Congress will reintroduce similar

legislation in 2005. If enacted, this tax legislation could impact the deductibility of the Western Energy Settlement and could result in a write-off of some or all of the associated tax benefits. In such event, our tax expense would increase. Our total tax benefits related to the Western Energy Settlement were approximately $205 million as of December 31, 2004.

      As of December 31, 2003, we maintained a valuation allowance on deferred tax assets related to our ability to realize state tax benefits from the deduction of the charge we took related to the Western Energy Settlement. During the first quarter of 2004, we evaluated this allowance and now believe, based on our current estimates, that these state tax benefits will be fully realized. Consequently, we reversed this valuation allowance. Net of federal taxes, this benefit totaled approximately $6 million.

      As of December 31, 2004, we had approximately $17 million of alternative minimum tax credits that carryover indefinitely.

      The following are the components of our net operating loss carryovers as of December 31, 2004:

     Usage of these carryovers is subject to the limitations provided under Sections 382 and 383 of the Internal Revenue Code as well as the separate return limitation year rules of IRS regulations.

      Under El Paso’s tax accrual policy, we are allocated the tax effects associated with our employees’ non-qualified dispositions of employee stock purchase plan stock, the exercise of non-qualified stock options and the vesting of restricted stock as well as restricted stock dividends. This allocation did not have a material effect in 2004; however, it increased taxes payable by $1 million in 2003 and reduced taxes payable by $1 million in 2002. These tax effects are included in additional paid-in capital in our balance sheet. For a discussion of the components of current taxes receivable and payable at December 31, 2004 and 2003, see Note 9.

3. Financial Instruments

      The carrying amounts and estimated fair values of our financial instruments are as follows at December 31:

     As of December 31, 2004 and 2003, the carrying amounts of cash and cash equivalents, short-term borrowings, and trade receivables and payables are representative of fair value because of the short-term maturity of these instruments.

4. Regulatory Assets and Liabilities

      Below are the details of our regulatory assets and regulatory liabilities at December 31:

5. Debt and Other Credit Facilities

      Our long-term debt outstanding consisted of the following at December 31:

      In July 2003, we issued $355 million of senior unsecured notes with an annual interest rate of 7.625% due 2010. Net proceeds were approximately $347 million. In November 2003, we retired $200 million of 6.75% notes due 2003.

      In June 2002, we issued $300 million of senior unsecured notes with an annual interest rate of 8.375% due 2032. Net proceeds were approximately $296 million.

      In 2001, we issued $3 million of letters of credit for an unconsolidated affiliate. At December 31, 2004, only one letter of credit was still outstanding. In January 2005, the final letter of credit was cancelled.

      In November 2004, El Paso replaced its previous $3 billion revolving credit facility with a new $3 billion credit agreement under which we continue to be an eligible borrower. The credit agreement consists of a $1.25 billion term loan facility, a $750 million letter of credit facility, and a $1 billion revolving credit facility. The letter of credit facility provides El Paso the ability to issue letters of credit or borrow any unused capacity as revolving loans. We are only liable for amounts we directly borrow under the credit agreement. At December 31, 2004, El Paso had $1.25 billion outstanding under the term loan facility and utilized approximately all of the $750 million letter of credit facility and approximately $0.4 billion of the $1 billion revolving credit facility to issue letters of credit, none of which were borrowed by or issued on behalf of us.

Additionally, El Paso’s interest in us and our interest in Mojave, and several of our affiliates continue to be pledged as collateral under the credit agreement.

      Under the $3 billion credit agreement and our indentures, we are subject to a number of restrictions and covenants. The most restrictive of these include (i) limitations on the incurrence of additional debt, based on a ratio of debt to EBITDA (as defined in the agreements) the most restrictive of which shall not exceed 5 to 1; (ii) limitations on the use of proceeds from borrowings; (iii) limitations, in some cases, on transactions with our affiliates; (iv) limitations on the incurrence of liens; (v) potential limitations on our ability to declare and pay dividends; (vi) potential limitations on our ability to participate in the El Paso cash management program discussed in Note 9 and (vii) limitation on our ability to prepay debt. For the year ended December 31, 2004, we were in compliance with all of our debt related covenants.

      Our long-term debt contains cross-acceleration provisions, the most restrictive of which is a $25 million cross-acceleration clause. If triggered, repayment of our long-term debt could be accelerated.

6. Commitments and Contingencies

  Legal Proceedings

      Western Energy Settlement. In June 2004, our master settlement agreement, along with other separate settlement agreements, became effective with a number of public and private claimants, including the states of California, Washington, Oregon and Nevada. These agreements resolved the principal litigation, investigations, claims and regulatory proceedings arising out of the sale or delivery of natural gas and/or electricity to the western U.S. (the Western Energy Settlement). As part of the Western Energy Settlement, we admitted no wrongdoing but agreed, among other things, to make various cash payments and modify an existing power supply contract. We also entered into a Joint Settlement Agreement or JSA where we agreed, subject to limitations in the JSA, to (1) make 3.29 Bcf/d of capacity available to California to the extent shippers sign firm contracts for that capacity, (2) maintain facilities sufficient to physically deliver 3.29 Bcf/d to California; (3) construct facilities, which we completed in 2004, (4) clarify certain shippers’ recall rights on the system and (5) with limited exceptions, bar any of our affiliated companies from obtaining additional firm capacity on our pipeline system during a five year period from the effective date of the settlement.

      In June 2003, El Paso, the California Public Utilities Commission (CPUC), Pacific Gas and Electric Company, Southern California Edison Company, and the City of Los Angeles filed the JSA described above with the FERC. In November 2003, the FERC approved the JSA with minor modifications. Our east of California shippers filed requests for rehearing, which were denied by the FERC on March 30, 2004. Certain shippers have appealed the FERC’s ruling to the U.S. Court of Appeals for the District of Columbia, where this matter is pending. We expect this appeal to be fully briefed by the summer of 2005.

      During the fourth quarter of 2002, we recorded a $412 million pretax charge related to the Western Energy Settlement. During 2003, we recorded additional pretax charges of $127 million based upon reaching definitive settlement agreements. We also recorded accretion and other charges of $13 million in 2003. Charges and expenses associated with the Western Energy Settlement are included in operations and maintenance expense in our consolidated statements of income. When the settlement became effective in June 2004, El Paso released $602 million to the settling parties. Of the amount released, $568 million had been previously held in an escrow account, including $73 million of proceeds from the issuance of El Paso’s common stock which were contributed to us by El Paso in January 2004, pending final approval of the settlement. We also paid an additional $22 million, the total of which satisfied our $538 million obligation under the Western Energy Settlement. The release of these restricted funds by El Paso on our behalf from the escrow account is reflected as an increase in our cash flows from investing activities. The release of funds to satisfy our Western Energy Settlement liability has been reflected as a reduction of our cash flow from operating activities. We are a guarantor for El Paso’s remaining obligation which, as of December 31, 2004, consists of a discounted 20-year cash payment obligation of $395 million and a price reduction under a power supply contract. In connection with the Western Energy Settlement, El Paso also provided collateral in the form of natural gas and oil properties to secure its remaining cash payment obligation. The collateral

requirement is being reduced as payments under the 20 year obligation are made. For an issue regarding the potential tax deductibility of our Western Energy Settlement charges, see Note 2.

      Sierra Pacific Resources and Nevada Power Company v. El Paso et al. In April 2003, Sierra Pacific Resources and Nevada Power Company filed a suit in U.S. District Court for the District of Nevada against us, our affiliates and unrelated third parties. The allegations are similar to those in the California cases. In January 2004, the court dismissed the lawsuit. Plaintiffs subsequently amended the complaint, which was dismissed again in November 2004. Plaintiffs have appealed from that dismissal to the US Court of Appeals for the Ninth Circuit. We expect this appeal to be fully briefed by the beginning of summer 2005. Our costs and legal exposure related to this lawsuit are not currently determinable.

      IMC Chemicals v. E1 Paso Marketing (EPM), et al. In January 2003, IMC Chemicals filed a lawsuit in California state court against us and our affiliates. The suit arose out of a gas supply contract between IMC Chemicals (IMCC) and EPM and sought to void the Gas Purchase Agreement between IMCC and EPM for gas purchases until December 2003. IMCC contended that EPM and its affiliates manipulated market prices for natural gas and, as part of that manipulation, induced IMCC to enter into the contract. In furtherance of its attempt to void the contract, IMCC repeated the allegations and claims of the California lawsuits described above. EPM intends to enforce the terms of the contract and has filed a counterclaim for contract damages in excess of $5 million. IMCC’s claim is undeterminable but appears to be in excess of $20 million. Our costs and legal exposure related to this lawsuit are not currently determinable.

      State of Arizona v. El Paso et. al. In December 2004, we and our affiliates entered into a settlement agreement with the Attorney General for the State of Arizona acting on behalf of the citizens, residents and consumers of Arizona dismissing the lawsuit filed against us in March 2003. Similar to the California cases, that lawsuit asserted that the defendants had conspired to artificially inflate prices of natural gas and electricity during 2000 and 2001. Under the settlement, we admitted no wrongdoing, but agreed to:

      The settlement provides that we may seek recovery in our FERC-approved rates of the costs associated with the pipeline enhancements, accelerated pipeline integrity program expenditures, and the water conservation initiative.

      Phelps Dodge vs. EPNG. In February, 2004, one of our customers, Phelps Dodge, and a number of its affiliates filed a lawsuit against us in the state court of Arizona. Plaintiffs claim we violated Arizona anti-trust statutes and allege that during 2000-2001, we unlawfully manipulated and inflated gas prices. We removed this lawsuit to the U.S. District Court for the District of Arizona. Plaintiffs have filed a motion to remand the matter to state court which the district court granted in March 2005. Our costs and legal exposure related to this lawsuit are not currently determinable.

      Shareholder Class Action Suit. In November 2002, we and certain of our affiliates were named as a defendant in a shareholder derivative suit titled Marilyn Clark v. Byron Allumbaugh, David A. Arledge,

John M. Bissell, Juan Carlos Braniff, James F. Gibbons, Anthony W. Hall, Ronald L. Kuehn, J. Carleton MacNeil, Thomas McDade, Malcolm Wallop, William Wise, Joe B. Wyatt, El Paso Natural Gas Company and El Paso Merchant Energy Company filed in state court in Houston. This shareholder derivative suit generally alleges that manipulation of California gas supply and gas prices exposed our parent, El Paso, to claims of antitrust conspiracy, FERC penalties and erosion of share value. The plaintiffs have not asked for any relief with regard to us. Our costs and legal exposure related to this proceeding are not currently determinable.

      Carlsbad. In August 2000, a main transmission line owned and operated by us ruptured at the crossing of the Pecos River near Carlsbad, New Mexico. Twelve individuals at the site were fatally injured. As a result, the U.S. Department of Transportation’s Office of Pipeline Safety issued a Notice of Probable Violation and Proposed Civil Penalty to us proposing a fine of $2.5 million. We have fully accrued for these fines. In October 2001, we filed a response with the Office of Pipeline Safety disputing each of the alleged violations. In December 2003, the matter was referred to the Department of Justice.

      After a public hearing conducted by the National Transportation Safety Board (NTSB) on its investigation of the Carlsbad rupture, the NTSB published its final report in April 2003. The NTSB stated that it had determined that the probable cause of the August 2000 rupture was a significant reduction in pipe wall thickness due to severe internal corrosion, which occurred because our corrosion control program “failed to prevent, detect, or control internal corrosion” in the pipeline. The NTSB also determined that ineffective federal pre-accident inspections contributed to the accident by not identifying deficiencies in our internal corrosion control program.

      In November 2002, we received a federal grand jury subpoena for documents relating to the rupture and we cooperated fully in responding to the subpoena. That subpoena has since expired. In December 2003 and January 2004, eight current and former employees were served with testimonial subpoenas issued by the grand jury. Six individuals testified in March 2004. In April 2004, we and El Paso received a new federal grand jury subpoena requesting additional documents. We have responded fully to this subpoena. Two additional employees testified before the grand jury in June 2004. Additional testimonial and documentary subpoenas may be issued by the grand jury.

      In addition, a lawsuit entitled Baldonado et al. vs. EPNG was filed in June 2003, in state court in Eddy County, New Mexico, on behalf of 23 firemen and EMS personnel who responded to the fire and who allegedly have suffered psychological trauma. This case was dismissed by the trial court, but has been appealed to the New Mexico Court of Appeals. The appeal is currently being briefed. Our costs and legal exposure related to the Baldonado lawsuit are currently not determinable, however, we believe these matters will be fully covered by insurance. All other personal injury suits related to the rupture have been settled.

      Grynberg. In 1997, we and a number of our affiliates were named defendants in actions brought by Jack Grynberg on behalf of the U.S. Government under the False Claims Act. Generally, these complaints allege an industry-wide conspiracy to underreport the heating value as well as the volumes of the natural gas produced from federal and Native American lands, which deprived the U.S. Government of royalties. The plaintiff in this case seeks royalties that he contends the government should have received had the volume and heating value been differently measured, analyzed, calculated and reported, together with interest, treble damages, civil penalties, expenses and future injunctive relief to require the defendants to adopt allegedly appropriate gas measurement practices. No monetary relief has been specified in this case. These matters have been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District of Wyoming, filed June 1997). Motions to dismiss have been filed on behalf of all dependants. Our costs and legal exposure related to these lawsuits and claims are not currently determinable.

      Will Price (formerly Quinque). We and a number of our affiliates are named defendants in Will Price, et al. v. Gas Pipelines and Their Predecessors, et al., filed in 1999 in the District Court of Stevens County, Kansas. Plaintiffs allege that the defendants mismeasured natural gas volumes and heating content of natural gas on non-federal and non-Native American lands and seek to recover royalties that they contend they should have received had the volume and heating value of natural gas produced from their properties been differently measured, analyzed, calculated and reported, together with prejudgment and post judgment interest, punitive

damages, treble damages, attorneys’ fees, costs and expenses, and future injunctive relief to require the defendants to adopt allegedly appropriate gas measurement practices. No monetary relief has been specified in this case. Plaintiffs’ motion for class certification of a nationwide class of natural gas working interest owners and natural gas royalty owners was denied in April 2003. Plaintiffs were granted leave to file a Fourth Amended Petition, which narrows the proposed class to royalty owners in wells in Kansas, Wyoming and Colorado, and removes claims as to heating content. A second class action petition has since been filed as to the heating content claims. Plaintiffs have filed motions for class certification in both proceedings, and dependants have filed briefs in opposition thereto. Our costs and legal exposure related to these lawsuits and claims are not currently determinable.

      Bank of America. We are a named defendant, along with Burlington Resources, Inc., in two class action lawsuits styled as Bank of America, et al. v. El Paso Natural Gas Company, et al., and Deane W. Moore, et al. v. Burlington Northern, Inc., et al., each filed in 1997 in the District Court of Washita County, State of Oklahoma and subsequently consolidated by the court. The plaintiffs seek an accounting and damages for alleged royalty underpayments from 1982 to the present on natural gas produced from specified wells in Oklahoma, plus interest from the time such amounts were allegedly due, as well as punitive damages. The court has certified the plaintiff classes of royalty and overriding royalty interest owners, and the parties have completed discovery. The plaintiffs have filed expert reports alleging damages in excess of $1 billion. Pursuant to a recent summary judgment decision, the court ruled that claims previously released by the settlement of Altheide v. Meridian, a nation-wide royalty class action against Burlington and its affiliates are barred from being reasserted in this action. We believe that this ruling eliminates a material, but yet unquantified portion of the alleged class damages. A third action, styled Bank of America, et al. v. El Paso Natural Gas and Burlington Resources Oil and Gas Company, was filed in October 2003 in the District Court of Kiowa County, Oklahoma asserting similar claims as to specified shallow wells in Oklahoma, Texas and New Mexico. Defendants succeeded in transferring this action to Washita County. A class has not been certified. While Burlington accepted our tender of the defense of these cases in 1997, pursuant to the spin-off agreement entered into in 1992 between us and Burlington Resources, Inc., and had been defending the matter since that time, at the end of 2003 it asserted contractual claims for indemnity against us. We have filed an action styled El Paso Natural Gas Company v. Burlington Resources, Inc. and Burlington Resources Oil and Gas Company, L.P. against Burlington in state court in Harris County relating to the indemnity issues between Burlington and us. That action is currently stayed. We believe we have substantial defenses to the plaintiffs’ claims as well as to the claims for indemnity by Burlington. Our costs and legal exposure related to these lawsuits and claims are not currently determinable.

      In addition to the above matters, we and our subsidiaries and affiliates are named defendants in numerous lawsuits and governmental proceedings that arise in the ordinary course of our business.

      For each of our outstanding legal matters, we evaluate the merits of the case, our exposure in the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. As this information becomes available, or other relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our current reserves are adequate. At December 31, 2004, we had accrued approximately $3 million for our outstanding legal matters.

  Environmental Matters

      We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. At December 31, 2004, we had accrued approximately $32 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and for related environmental legal costs. This accrual includes $25 million for environmental contingencies related to properties we previously owned. Our accrual was based on the most

likely outcome that can be reasonably estimated; however, our exposure could be as high as $60 million. Below is a reconciliation of our accrued liability at December 31, 2004 (in millions).

      In addition, we expect to make capital expenditures for environmental matters of approximately $1 million in the aggregate for the years 2005 through 2009. These expenditures primarily relate to compliance with clean air regulations. For 2005, we estimate that our total remediation expenditures will be approximately $7 million, which will be expended under government directed clean-up plans.

      CERCLA Matters. We have received notice that we could be designated, or have been asked for information to determine whether we could be designated, as a Potentially Responsible Party (PRP) with respect to three active sites under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or state equivalents. We have sought to resolve our liability as a PRP at these sites through indemnification by third parties and settlements which provide for payment of our allocable share of remediation costs. As of December 31, 2004, we have estimated our share of the remediation costs at these sites to be between $12 million and $19 million. Since the clean-up costs are estimates and are subject to revision as more information becomes available about the extent of remediation required, and because in some cases we have asserted a defense to any liability, our estimates could change. Moreover, liability under the federal CERCLA statute is joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. Our understanding of the financial strength of other PRPs has been considered, where appropriate, in estimating our liabilities. Accruals for these matters are included in the environmental reserve discussed above.

      New Mexico Ambient Air Quality Standards. In October 2004, the State of New Mexico’s Environmental Department proposed a new rule that would impose an eight-hour ambient air quality standard on all New Mexico industrial facilities that are currently under the federal Title 5 program. We filed a notice of intent to provide testimony in opposition to this rule at an upcoming hearing. In January 2005, we reached an agreement in principle with the state on an alternative to the proposed rule that could reduce compliance costs and help achieve some of the Department’s goals. The rulemaking procedure has been suspended while we negotiate the definitive agreement with the State. The outcome of this proposed rule is not determinable at this time.

      State of Arizona Chromium Review. In April 2004, the State of Arizona’s Department of Environmental Quality requested information from us regarding the historical use of chromium in our operations. By June 2004, we had responded fully to the request. We are currently working with the State of Arizona on this matter and have committed to undertake a study of our facilities in Arizona to determine if there are any issues concerning the usage of chromium. We will also study our facilities on tribal lands in Arizona and New Mexico and our facility at El Paso Station in El Paso, Texas. Our costs related to this matter are not currently determinable.

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

  Rates and Regulatory Matters

      CPUC Complaint Proceeding. In April 2000, the CPUC filed a complaint under Section 5 of the Natural Gas Act (NGA) with the FERC alleging that our sale of approximately 1.2 Bcf/d of capacity to our affiliate, EPM, raised issues of market power and violation of the FERC’s marketing affiliate regulations and asked that the contracts be voided. In the spring and summer of 2001, two hearings were held before an Administrative Law Judge (ALJ) to address the market power issue and the affiliate issue. In November 2003, in approving the JSA, which is part of the Western Energy Settlement, the FERC also vacated both of the ALJ’s Initial Decisions. That decision was upheld by the FERC in a rehearing order issued in March 2004. Certain shippers have appealed from both FERC orders to the U.S. Court of Appeals for the District of Columbia, where the matter is pending.

      Systemwide Capacity Allocation Proceeding. In July 2001, several of our customers filed complaints against us at the FERC claiming that we had failed to provide appropriate service on our pipeline. As a result of the FERC’s many orders in these proceedings: (i) full requirements (FR) shippers under Rate Schedule FT-1 were required to convert from full requirements to contract demand service in September 2003; (ii) firm customers were assigned specific receipt point rights in lieu of systemwide receipt point rights; (iii) reservation charges will be credited to all firm customers if we fail to schedule confirmed volumes except in cases of force majeure; in such force majeure cases, the reservation charge credits will be limited to the return and associated tax portion of our reservation rate; (iv) no new firm contracts can be executed unless we can demonstrate there is adequate capacity on the system available to provide the service; (v) capacity turned-back to us from contracts that terminated or expired between May 31, 2002 and May 1, 2003, could not be remarketed because it was included in the volumes allocated to the FR shippers; and (vi) a backhaul service was established from our California delivery points for existing and new shippers. We also received certificate authority to add compression to our Line 2000 to increase our system capacity by 320 MMcf/d without receiving cost coverage for the expansion until our next rate case in January 2006.

      After the FERC upheld its decision, certain shippers took an appeal to the US. Court of Appeals for the District of Columbia (No. 03-1206.) In December 2004, the appeals panel affirmed the FERC’s decision in its entirety, endorsed the FERC’s conclusion that El Paso operated its dynamic pipeline system at reasonable levels of capacity, and rejected the claim that El Paso improperly withheld capacity.

      Rate Settlement. Our current rate settlement establishes our base rates through December 31, 2005. The settlement has certain requirements applicable to the Post-Settlement Period. These requirements include a provision which limits the rates to be charged to a portion of our contracted portfolio to a level equal to the inflation-escalated rate from the 1996 rate settlement. We are currently reviewing the definition and applicability of this future capped-rate requirement given, among other things, the customer and contract changes required by the capacity allocation proceeding discussed above. We have the right to increase or decrease our base rates if changes in laws or regulations result in increased or decreased costs in excess of $10 million a year. Our settlement included both the risk and revenue sharing provisions which expired at the end of 2003. We refunded $12 million in the first quarter of 2004 related to these expiring provisions.

      Rate Case. The rate settlement reached in RP95-363, et al. requires EPNG to file a rate case to be effective January 2006. We are preparing for such filing and also meeting with our customers to attempt to develop a settlement. At this juncture, we anticipate the cost of service, the rate design, rate allocation, along with the rate cap issues described above, to be contentious absent a settlement agreement with our customers.

      FERC Order 2004 Audit. In February 2005, we were notified that the FERC’s Office of Market Oversight and Investigations had selected us to undergo an audit of its FERC Order 2004 compliance efforts. In conjunction with the notice, we received voluminous data requests. The notice also informed us that the auditors will conduct an on-site visit. We are cooperating fully with the auditors and have provided initial responses to the data requests. The final outcome of this audit can not be predicted with certainty, nor can its impact on us or our affiliated pipelines be determined at this time.

      CPUC’s OIR Proceeding. The CPUC initiated an Order Instituting Rulemaking (OIR) in Docket No. R04-01-025 addressing California’s utilities’ energy supply plans for the period of 2006 and beyond. The

proceeding is broken into two phases, with the first focusing on issues that need to be addressed more immediately such as interstate capacity and utility access to liquified natural gas supplies. In September 2004, the CPUC issued its decision on these Phase I issues that is generally favorable to us. However, it authorizes the California utilities to issue notices of termination of their contracts with us in order to permit them to negotiate reduced contract levels and diversify their supply portfolios. This means, for instance, that our largest customer, SoCal, had the CPUC’s permission to terminate its contract to transport over 1.3 Bcf/d of gas on our system by giving notice by the end of February 2005. In December 2004, we entered into an agreement with SoCal subject to FERC approval and tariff procedures, providing that SoCal will recontract approximately 750 MMcf/d on our system under several contracts with terms variously extending from 2009 to 2011. We are focusing on pursuing recontracting of the remaining, expiring capacity on the EPNG system. Depending upon the actions of the CPUC in Phase II of the OIR proceeding and the actions of the California utilities, we could have capacity formerly held by SoCal to remarket in 2006. The outcome of this process is not determinable at this time.

      Accounting for Pipeline Integrity Costs. In November 2004, the FERC issued a proposed accounting release that may impact certain costs we incur related to our pipeline integrity program. 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 that this potential accounting release will have on our consolidated financial statements, we currently estimate that we would be required to expense an additional amount of pipeline integrity expenditures in the range of approximately $5 million to $11 million annually over the next eight years.

      Inquiry Regarding Income Tax Allowances. In December 2004, the FERC issued a Notice of Inquiry (NOI) in response to a recent D.C. Circuit decision that held the FERC had not adequately justified its policy of providing a certain oil pipeline limited partnership with an income tax allowance equal to the proportion of its limited partnership interests owned by corporate partners. The FERC sought comments on whether the court’s reasoning should be applied to other partnerships or other ownership structures. Our wholly owned pipeline, Mojave, could be affected by this ruling; however, we cannot predict the impact of this inquiry at this time.

      Selective Discounting Notice of Inquiry. In November 2004, the FERC issued a NOI seeking comments on its policy regarding selective discounting by natural gas pipelines. The FERC seeks comments regarding whether its practice of permitting pipelines to adjust their ratemaking throughput downward in rate cases to reflect discounts given by pipelines for competitive reasons is appropriate when the discount is given to meet competition from another natural gas pipeline. We, along with several of our affiliated pipelines, filed comments on the NOI in March 2005. The final outcome of this inquiry cannot be predicted with certainty, nor can we predict the impact that the final rule will have on us.

      While the outcome of our outstanding rates and regulatory matters cannot be predicted with certainty, based on current information, we do not expect the ultimate resolution of these matters to have a material adverse effect on our financial position, operating results or cash flows. However, it is possible that new information or future developments could require us to reassess our potential exposure related to these matters, which could have a material effect on our results of operations, our financial position, and our cash flows.

      Enron Bankruptcy. In December 2001, Enron Corp. (Enron), and a number of its subsidiaries, including Enron North America Corp. ENA and Enron Power Marketing, Inc., filed for Chapter 11 bankruptcy protection in the United States Bankruptcy Court for the Southern District of New York. ENA had transportation contracts on our system. The transportation contracts have now been rejected and we have filed a proof of claim in the amount of approximately $128 million, which included $18 million for amounts due for services provided through the date the contracts were rejected and $110 million for damage claims arising from the rejection of its transportation contracts. We anticipate that Enron will vigorously oppose these claims. Given the uncertainties of the bankruptcy actions, we have fully reserved for all amounts due from

Enron through the date the contracts were rejected, and we have not recognized any amounts under these contracts since the rejection date.

      While the outcome of these matters cannot be predicted with certainty, based on current information, we do not expect the ultimate resolution of these matters to have a material adverse effect on our financial position, operating results or cash flows. However, it is possible that new information or future developments could require us to reassess our potential exposure related to these matters. The impact of these changes may have a material effect on our results of operations, our financial position, and our cash flows in the periods these events occur.

  Capital Commitments

      At December 31, 2004, we had capital and investment commitments of approximately $73 million primarily related to ongoing capital projects and commitments made with the State of Arizona in settlement of its lawsuit filed against us in March 2003. Our other planned capital and investment projects are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures.

  Operating Leases

      We lease property, facilities and equipment under various operating leases. Minimum future annual rental commitments on operating leases as of December 31, 2004, were as follows:

     Our minimum future rental commitments have not been reduced by minimum sublease rentals of approximately $4 million due to us in the future under noncancelable subleases.

      Rental expense on our operating leases for each of the years ended December 31, 2004, 2003 and 2002 was $3 million. These amounts include our share of rent allocated to us from El Paso.

     Guarantees

      We are involved in various joint ventures and other ownership arrangements that sometimes require additional financial support that results in the issuance of financial and performance guarantees. In a financial guarantee, we are obligated to make payments if the guaranteed party fails to make payments under, or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, we are required to perform on their behalf. As of December 31, 2004, we had approximately $16 million of financial and performance guarantees not otherwise reflected in our financial statements.

7. Retirement Benefits

  Pension and Retirement Benefits

      Prior to January 1, 1997, El Paso maintained a defined benefit pension plan covering substantially all of our employees. Pension benefits were based on years of credited service and final five year average compensation, subject to maximum limitations as defined in the pension plan. Effective January 1, 1997, the plan was amended to provide benefits determined by a cash balance formula. Employees who were pension

plan participants on December 31, 1996, receive the greater of cash balance benefits or prior plan benefits accrued through December 31, 2001.

      In addition, El Paso maintains a defined contribution plan covering its U.S. employees, including our employees. Prior to May 1, 2002, El Paso matched 75 percent of participant basic contributions up to 6 percent, with the matching contributions being made to the plan’s stock fund, which participants could diversify at any time. After May 1, 2002, the plan was amended to allow for company matching contributions to be invested in the same manner as that of participant contributions. Effective March 1, 2003, El Paso suspended the matching contribution but reinstituted it again at a rate of 50 percent of participant basic contributions up to 6 percent on July 1, 2003. Effective July 1, 2004, El Paso increased the matching contributions to 75 percent of participant basic contribution up to 6 percent. El Paso is responsible for benefits accrued under its plans and allocates the related costs to its affiliates.

  Other Postretirement Benefits

      We provide postretirement medical benefits for a closed group of employees who retired on or before March 1, 1986, and limited postretirement life insurance for employees who retired after January 1, 1985. As such, our obligation to accrue for other postretirement employee benefits (OPEB) is primarily limited to the fixed population of retirees who retired on or before March 1, 1986. The medical plan is pre-funded to the extent employer contributions are recoverable through rates. To the extent actual OPEB costs differ from amounts recovered in rates, a regulatory asset or liability is recorded. We expect to contribute $11 million to our other postretirement benefit plan in 2005.

      In 2004, we adopted FASB Staff Position (FSP) No. 106-2. Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. This pronouncement required us to record the impact of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 on our postretirement benefit plans that provide drug benefits that are covered by that legislation. The adoption of FSP No. 106-2 decreased our accumulated postretirement benefit obligation by $21 million, which is deferred as an actuarial gain in our postretirement benefit liabilities as of December 31, 2004. We expect that the adoption of this guidance will reduce our postretirement benefit expense by $3 million in 2005.

      The following table presents the change in projected benefit obligation, change in plan assets and reconciliation of funded status for our other postretirement benefit plan. Our benefits are presented and computed as of and for the twelve months ended September 30 (the plan reporting date):

      Future benefits expected to be paid on our other postretirement plan as of December 31, 2004, are as follows (in millions):

      Our postretirement benefit costs recorded in operating expenses include the following components for the years ended December 31,:

      Projected benefit obligations and net benefit costs are based on actuarial estimates and assumptions. The following table details the weighted average actuarial assumptions used for our other postretirement plan for 2004, 2003 and 2002:

     Actuarial estimates for our postretirement benefits plan assumed a weighted average annual rate of increase in the per capita costs of covered health care benefits of 10.0 percent in 2004, gradually decreasing to 5.5 percent by the year 2009. Assumed health care cost trends can have a significant effect on the amounts reported for our postretirement benefit plan. A one-percentage point change in our assumed health care cost trends would have the following effects as of September 30:

     Other Postretirement Plan Assets

      The following table provides the actual asset allocations in our postretirement plan as of September 30:

      The primary investment objective of our plan is to ensure, that over the long-term life of the plan, an adequate pool of sufficiently liquid assets exists to support the benefit obligation to participants, retirees and beneficiaries. In meeting this objective, the plan seeks to achieve a high level of investment return consistent with a prudent level of portfolio risk. Investment objectives are long-term in nature covering typical market cycles of three to five years. Any shortfall in investment performance compared to investment objectives is the result of general economic and capital market conditions.

      The target allocation for the invested assets is 65 percent equity and 35 percent fixed income. In 2003, we modified our target asset allocations for our postretirement benefit plan to increase our equity allocation to 65 percent of total plan assets. Other assets are held in cash for payment of benefits upon presentment. Any El Paso stock held by the plan is held indirectly through investments in mutual funds.

8. Preferred Stock

      On April 3, 2003, El Paso contributed its 500,000 shares of our 8% preferred stock to us, including accrued dividends of $9 million. The total contribution was approximately $359 million and is reflected as additional paid in capital in our stockholder’s equity. During the year ended December 31, 2002, we paid $28 million in dividends on our preferred stock.

9. Transactions with Affiliates

      Cash Management Program. We participate in El Paso’s cash management program which matches short-term cash surpluses and needs of participating affiliates, thus minimizing total borrowings from outside sources. As of December 31, 2004 and 2003, we had advanced to El Paso $730 million and $779 million. The rate of interest at December 31, 2004 and 2003, was 2.0% and 2.8%. This receivable is due upon demand; however, we do not anticipate settlement of the entire amount in the next twelve months. At December 31, 2004, we have classified $28 million of this receivable as current accounts receivable from affiliates. In addition, at December 31, 2004 and 2003, we have classified $702 million and $779 million of this receivable as non-current note receivables from affiliates.

      Affiliate Receivables and Payables. At December 31, 2004 and 2003, we had other accounts receivable from affiliates of $10 million and $4 million. In addition, we had accounts payable to affiliates of $16 million at December 31, 2004, and $13 million at December 31, 2003. These balances arose in the normal course of business.

      We also maintained $6 million as of December 31, 2004 and 2003 as a contractual deposit related to an affiliate’s transportation contract on our EPNG system.

      We are a party to a tax accrual policy with El Paso whereby El Paso files U.S. and certain state tax returns on our behalf. In certain states, we file and pay directly to the state taxing authorities. We have income taxes receivable of $102 million at December 31, 2004. We have income taxes payable of $9 million and $102 million at December 31, 2004 and 2003, included in taxes payable on our balance sheet. The majority of these balances will become payable to or receivable from El Paso under the tax accrual policy. See Note 1 for a discussion of our tax accrual policy.

      Other. In January 2004, El Paso contributed to us $73 million in proceeds from the issuance of its common stock. The proceeds were placed in escrow and released to the Western Energy Settlement parties in June 2004. See Note 6 for further discussion. In addition we acquired assets from an affiliate with a net book value of $6 million in the third quarter of 2004.

      During 2002, we distributed assets with net book values of $19 million to our parent through a dividend.

      Affiliate Revenues and Expenses. We provided EPM transportation services for the years ended 2004, 2003 and 2002. We recognized revenues of $18 million, $18 million and $46 million for these periods. We entered into these transactions in the ordinary course of business and the services were based on the same terms as non-affiliates.

      El Paso allocates a portion of its general and administrative expenses to us. The allocation is based on the estimated level of effort devoted to our operations and the relative size of our EBIT, gross property and payroll. For the years ended December 31, 2004, 2003 and 2002, the annual charges were $40 million, $52 million and $49 million. Tennessee Gas Pipeline Company allocates payroll to us and other expenses associated with our shared pipeline services. The allocated expenses are based on the estimated level of staff and their expenses to provide the services. For the years ended 2004, 2003 and 2002, the annual charges were $13 million, $8 million and $6 million. El Paso Field Services allocates payroll and other expenses to us and during each of the three years ended December 31, 2004, 2003 and 2002 those amounts were $9 million. In addition, we performed operational, financial, accounting and administrative services for an affiliate, Colorado Interstate Gas Company. The amounts received for these services are recorded as reimbursement of operating expenses and for 2004, 2003 and 2002 were $14 million, $13 million and $12 million. We believe all the allocation methods are reasonable.

      The following table shows revenues and charges from our affiliates:

10. Transactions with Major Customer

      The following table shows revenues from our major customer for the years ended December 31:

11. Supplemental Cash Flow Information

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

12. Supplemental Selected Quarterly Financial Information (Unaudited)

      Financial information by quarter is summarized below:

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

El Paso Natural Gas Company:

      In our opinion, the consolidated financial statements listed in the Index appearing under Item 15(a) (1) present fairly, in all material respects, the consolidated financial position of El Paso Natural Gas Company and its subsidiaries (the “Company”) at December 31, 2004 and 2003, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the Index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and the financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 29, 2005

SCHEDULE II

EL PASO NATURAL GAS COMPANY

VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 2004, 2003 and 2002

(In millions)