10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

þ

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

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2005

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)

Delaware	74-0608280
(State or Other Jurisdiction of	(I.R.S. Employer
Incorporation or Organization)	Identification No.)
El Paso Building 1001 Louisiana Street Houston, Texas (Address of Principal Executive Offices)	77002 (Zip Code)

Telephone Number: (713) 420-2600

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act: None

    Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes  o  No  þ

    Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes  þ  No  o

    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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o Accelerated filer o Non-accelerated filer þ

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange 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 3, 2006: 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

	Caption	Page
PART I
Item 1.	Business		1
Item 1A.	Risk Factors		5
	Cautionary Statement for Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995
Item 1B.	Unresolved Staff Comments		10
Item 2.	Properties		10
Item 3.	Legal Proceedings		10
Item 4.	Submission of Matters to a Vote of Security Holders		*
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		11
Item 6.	Selected Financial Data		*
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		12
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		17
Item 8.	Financial Statements and Supplementary Data		18
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		40
Item 9A.	Controls and Procedures		40
Item 9B.	Other Information		40
PART III
Item 10.	Directors and Executive Officers of the Registrant		*
Item 11.	Executive Compensation		*
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		*
Item 13.	Certain Relationships and Related Transactions		*
Item 14.	Principal Accountant Fees and Services		40
PART IV
Item 15.	Exhibits and Financial Statement Schedules		41
	Signatures		44
Certification of CEO pursuant to Section 302
Certification of CFO pursuant to Section 302
Certification of CEO pursuant to 18 U.S.C Section 1350
Certification of CFO pursuant to 18 U.S.C Section 1350

*  We have not included a response to this item in this document since no response is required pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

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

/d	= per day	LNG	= liquefied natural gas
BBtu	= billion British thermal units	MDth	= thousand dekatherm
Bcf	= billion cubic feet	MMcf	= million cubic feet

      When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.

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

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PART I

ITEM 1. BUSINESS

Overview and Strategy

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

      Each of our pipeline systems and our storage facility operates under tariffs approved by the Federal Energy Regulatory Commission (FERC) that establish rates, cost recovery mechanisms, terms and conditions of service to our customers. The fees or rates established under our tariffs are a function of our costs of providing services to our customers, including a reasonable return on our invested capital. Our revenues from transportation services consist of two types of revenues:

      Reservation revenues. Reservation revenues are from customers (referred to as firm customers) that reserve capacity on our pipeline systems. These firm customers are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport, for the term of their contracts.

      Usage revenues. Usage revenues are from both firm customers and interruptible customers (those without reserved capacity) that pay usage charges based on the volume of gas actually transported.

      In 2005, approximately 92 percent of our revenues were attributable to reservation charges paid by firm customers. The remaining eight percent of our revenues were variable. Because of 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, the creditworthiness of our customers and weather. Through 2005, we also experienced volatility in our financial results when the amounts of natural gas utilized in our operations differed from the amounts we recovered from our customers for that purpose. We do not anticipate that this will significantly impact our financial results going forward as we have adopted a tracking mechanism beginning in 2006.

      Our strategic business plan is as follows:

•  Favorably resolve our open EPNG rate case;

•  Successfully recontract transportation capacity;

•  Develop storage to serve our market area;

•  Focus on cost efficiencies, especially fuel use;

•  Successfully complete expansion projects; and

•  Attract new supply and transport to new markets.

      Below is a further discussion of our pipeline systems and storage facility.

      The EPNG System. The El Paso Natural Gas system consists of approximately 10,700 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 2005, 2004 and 2003, average throughput was 4,053 BBtu/d, 4,074 BBtu/d and 3,874 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.

      Beginning in 2006, we began offering interruptible storage services from our Washington Ranch underground storage facility located in New Mexico which has up to approximately 44 Bcf of underground working natural gas storage capacity. In previous years, we utilized this facility to manage our system transportation needs.

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      The Mojave System. The Mojave system consists of approximately 400 miles of pipeline with a design capacity of approximately 407 MMcf/d. During 2005, 2004 and 2003, average throughput was 161 BBtu/d, 161 BBtu/d and 192 BBtu/d. This system connects with the EPNG system near Cadiz, California, the EPNG and Transwestern systems at Topock, Arizona and the Kern River Gas Transmission Company system in California. This system also extends to customers in the vicinity of Bakersfield, California.

Markets and Competition

      Our customers consist of natural gas 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.

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

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

      We provide transportation services in the southwestern U.S. with connections to pipelines serving northern Mexico. These have recently been among the fastest growing regions in the U.S. and in Mexico; therefore, the market demand for natural gas distribution as well as gas-fired electric generation capacity has experienced considerable growth in these areas. The combined capacity of all pipeline companies serving California is approximately 8.5 Bcf/d and we provide approximately 39 percent of this capacity. In 2005, the demand for interstate pipeline capacity to California averaged 4.8 Bcf/d, equivalent to approximately 57 percent of the total interstate pipeline capacity serving that state. Natural gas shipped to California on our system represented approximately 27 percent of the natural gas consumed in that state in 2005.

      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 is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Subject to regulatory requirements, we attempt to recontract or remarket our capacity at the rates allowed under our tariffs, although at times, we discount these rates to remain competitive.

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      The following table details the markets we serve and the competition on our pipeline systems as of December 31, 2005:

Pipeline
System	Customer Information	Contract Information	Competition
EPNG	Approximately 163 firm and interruptible customers	Approximately 251 firm transportation contracts. Weighted average remaining contract term of approximately four years.(1)	EPNG faces competition in the west and southwest from other existing and proposed pipelines, from California storage facilities, and alternative energy sources that are used to generate electricity such as hydroelectric power, nuclear, coal and fuel oil. In addition, initiatives to bring LNG into California and northern Mexico are underway.
	Major Customers: Southern California Gas   Company(SoCal)
	(453 BBtu/d)	Contract term expires in 2006.
	(93 BBtu/d)	Contract term expires in 2007.
	(768 BBtu/d)	Contract terms expire in 2009-2011.
	Southwest Gas Corporation
	(12 BBtu/d)	Contract term expires in 2006.
	(470 BBtu/d)	Contract term expires in 2011.
	(74 BBtu/d)	Contract term expires in 2015.
Mojave	Approximately 13 firm and interruptible customers	Approximately six firm transportation contracts. Weighted average remaining contract term of approximately eight years.(2)	Mojave faces competition from other existing and proposed pipelines and alternative energy sources that are used to generate electricity such as hydroelectric power, nuclear, coal and fuel oil. In addition, initiatives to bring LNG into California and northern Mexico are underway.
	Major Customers:
	EPNG
	(312 BBtu/d)	Contract term expires in 2015.
	Los Angeles Department of Water and Power
	(50 BBtu/d)	Contract term expires in 2007.

(1)	Reflects the impact of 507 BBtu/d of contracts that will be terminated in August 2006. This capacity will be available for new contracts or utilized to provide new services. Additionally, we are in the process of recontracting an additional 436 BBtu/d of capacity that is also subject to early termination in August 2006.
(2)	In December 2005, EPNG placed in service its Line 1903 project. EPNG holds approximately 312 BBtu/d of Mojave system capacity to fulfill its long-term obligations under the project.

Regulatory Environment

      Our interstate natural gas transmission systems and storage operations are regulated by the FERC under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. We operate under tariffs approved by the FERC that establish rates, terms and conditions of service 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;

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      • depreciation and amortization policies;

      • acquisition and disposition of facilities; and

      • initiation and discontinuation of services.

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

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

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 February 27, 2006, we had approximately 770 full-time employees, none of whom are subject to a collective bargaining arrangement.

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ITEM  1A.  RISK FACTORS

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

      This report contains 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 to be made 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, to renegotiate existing contracts as they expire or to remarket unsubscribed capacity:

•  service area competition;

•  expiration or turn back of significant contracts;

•  changes in regulation and actions of regulatory bodies;

•  future weather conditions;

•  price competition;

•  drilling activity and availability of natural gas;

•  decreased availability of conventional gas supply sources and the availability and timing of other gas supply sources, such as LNG;

•  decreased natural gas demand due to various factors, including increases in prices and the increased availability or popularity of alternative energy sources such as hydroelectric power, nuclear, coal and fuel oil;

•  increased costs of capital;

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•  opposition to energy infrastructure development, especially in environmentally sensitive areas;

•  adverse general economic conditions;

•  expiration or renewal of existing interests in real property including real property on Native American lands; and

•  unfavorable movements in natural gas prices in supply and demand areas.

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.

      Our revenues are generated under transportation contracts that expire periodically and must be renegotiated and extended or replaced. Although we actively pursue the renegotiation, extension 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 or replace transportation contracts could be adversely affected by factors we cannot control, including:

•  competition by other pipelines, including the proposed construction by other companies of additional pipeline capacity or LNG terminals, such as those proposed in Baja California, in markets served by us;

•  changes in state regulation of local distribution companies, which may cause them to negotiate short-term contracts or turn back their capacity when their contracts expire;

•  reduced demand and market conditions in the areas we serve;

•  the availability of alternative energy sources or gas supply points; and

•  regulatory actions.

      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.

      During 2005, SoCal successfully acquired approximately 768 BBtu/d of capacity on our EPNG system under new contracts which have been executed with various terms extending from 2009 to 2011 commencing September 2006. However, effective September 2006, approximately 453 BBtu/d of capacity formerly held by SoCal to serve its non-core customers will be available for recontracting. In addition, we have 1,142 BBtu/d of capacity that will, or potentially will, terminate in 2006 and 1,384 BBtu/d of capacity that will expire in 2007. We are remarketing the expiring capacity to serve either existing customers, SoCal’s non-core customers or to serve new customers. We are also pursuing the option of using some or all of this capacity to provide new services to existing customers. At this time, we are uncertain how much of the expiring capacity will be recontracted, and if so at what rates. For additional information on our contracts with our major customers, see Item 1, Business — Markets and Competition and Part II, Item 8, Financial Statements and Supplementary Data, Note 9. The loss of these customers or a decline in their creditworthiness could adversely affect our results of operations, financial position and cash flow.

Fluctuations in energy commodity prices could adversely affect our business.

      Revenues generated by our transportation 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 in industrial plant shutdowns or load losses to competitive fuels as well as local distribution companies’ loss of customer base. The success of our transmission operations is subject to continued development of additional natural gas reserves and our ability to access additional supplies from interconnecting pipelines to offset the natural decline from existing wells connected to our systems. A decline in energy prices could cause a decrease in these development activities and could cause a decrease in the volume of natural gas available for transmission through our systems.

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Pricing volatility may, in some cases, impact the value of under or over recoveries of retained gas, as well as imbalances and system encroachments. If natural gas prices in the supply basins connected to our pipeline systems are higher than prices in other natural gas producing regions, our ability to compete with other transporters may be negatively impacted. Furthermore, fluctuations in pricing between supply sources and market areas could negatively impact our transportation revenues. Fluctuations in energy prices are caused by a number of factors, including:

•  regional, domestic and international supply and demand;

•  availability and adequacy of transportation facilities;

•  energy legislation;

•  federal and state taxes, if any, on the transportation and storage of natural gas;

•  abundance of supplies of alternative energy sources; and

•  political unrest among oil producing countries.

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

      Our pipeline business is regulated by the FERC, the U.S. Department of Transportation, the U.S. Department of Interior 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 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 risks as interstate pipelines. The inclusion of these companies may create downward pressure on tariff rates that are submitted for approval. If our tariff rates were reduced or redesigned in a future rate proceeding, if our volume of business under our currently permitted rates were 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.

      In addition, increased regulatory requirements relating to the integrity of our pipelines requires additional spending in order to maintain compliance with these requirements. Any additional requirements that are enacted could significantly increase the amount of these expenditures.

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

Environmental compliance and remediation costs and the costs of environmental liabilities could exceed our estimates.

      Our operations are subject to various environmental laws and regulations regarding compliance and remediation obligations. Compliance obligations can result in significant costs to install and maintain pollution controls, fines and penalties resulting from any failure to comply and potential limitations on our operations. Remediation obligations can result in significant costs associated with the investigation and remediation or clean-up of contaminated properties (some of which have been designated as Superfund sites by the Environmental Protection Agency (EPA) under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA)), as well as damage claims arising out of the contamination of properties or impact on natural resources. It is not possible for us to estimate exactly the amount and timing of all future expenditures related to environmental matters because of:

•  The uncertainties in estimating pollution control and clean up costs, including sites where preliminary site investigation or assessments have been completed;

•  The discovery of new sites or additional information at existing sites;

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•  The uncertainty in quantifying liability under environmental laws that impose joint and several liability on all potentially responsible parties; and

•  The nature of environmental laws and regulations, including the interpretation and enforcement thereof.

      Currently, various legislative and regulatory measures to address greenhouse gas (GHG) emissions (including carbon dioxide and methane) are in various phases of discussion or implementation. These include the Kyoto Protocol, proposed federal legislation and state actions to develop statewide or regional programs, each of which have imposed or would impose reductions in GHG emissions. These actions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any GHG emissions program. These actions could also impact the consumption of natural gas, thereby affecting our operations.

      Although we believe we have established appropriate reserves for our environmental liabilities, we could be required to set aside additional amounts due to these uncertainties which could significantly impact our future consolidated results of operations, cash flows or financial position. For additional information concerning our environmental matters, see Part II, 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 pipeline operations, including pipeline ruptures, explosions, pollution, release of toxic substances, fires, 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 and assets face possible risks associated with acts of aggression. 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 we believe are reasonable, this insurance does not cover all risks. Many of our insurance coverages have material deductibles and self insurance levels, as well as limits on our maximum recovery. As a result, our financial condition and operations could be adversely affected if a significant event occurs that is not fully covered by insurance.

The expansion of our business by constructing new facilities subjects us to construction and other risks that may adversely affect our financial results.

      We may expand the capacity of our existing pipelines and our storage facilities by constructing additional facilities. Construction of these facilities is subject to various regulatory, development and operational risks, including:

•  our ability to obtain all necessary approvals and permits by regulatory agencies on a timely basis on terms that are acceptable to us;

•  potential changes of federal, state and local statutes and regulations, including environmental requirements that prevent a project from proceeding or increase the anticipated cost of the expansion project;

•  impediments on our ability to acquire rights-of-ways or land rights on a timely basis within our anticipated costs;

•  our ability to construct projects within anticipated costs, including the risk that we may incur cost overruns resulting from inflation or increased costs of equipment, materials or labor, or other factors beyond our control, that may be material;

•  anticipated future growth in natural gas supply does not materialize; and

•  lack of transportation, storage or throughput commitments that result in write-offs of development costs.

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      Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs. As a result, new facilities may not achieve our expected investment return, which could adversely affect our financial position or results of operations.

Cost of litigation could exceed our estimates.

      We have been named a party in various lawsuits. Although we believe we have 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 Part II, 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 into this report.

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 B- 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. Downgrades of our credit rating could increase our cost of capital collateral requirements, and could impede our access to capital markets.

      El Paso provides cash management and other corporate services for us. 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. 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 Part II, Item 8, Financial Statements and Supplementary Data, Note 11.

Our system of internal controls is designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes. A loss of public confidence in the quality of our internal controls or disclosures could have a negative impact on us.

      Our system of internal controls is designed to provide reasonable assurance that the objectives of the control system are met. However, any system of internal controls is subject to inherent limitations and the design of our controls may not provide absolute assurances that all of our objectives will be entirely met. This includes the possibility that controls may be inappropriately circumvented or overridden, that judgments in decision-making can be faulty and that misstatements due to errors or fraud may not be prevented or detected.

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

      We are pledged as collateral under El Paso’s $3 billion credit agreement. In addition, one of our subsidiaries, Sabine River Investor V, L.L.C. pledged its ownership of Mojave, its sole asset, as collateral. As a result, our ownership is subject to change if there is an event of default under the credit agreement, regardless

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if we have any borrowings outstanding under the credit agreement, and El Paso’s lenders 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, 2005. Under the credit agreement, a default by El Paso, or any other borrower could result in the acceleration of all outstanding borrowings, including the borrowings of any non-defaulting party. The acceleration of our future borrowings, if any, 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 some of our long-term debt contain cross-acceleration provisions, the most restrictive of which is $25 million. Therefore, if we borrow $25 million or more under El Paso’s $3 billion credit agreement and such borrowings are accelerated for any reason, including the default of another party under the credit agreement, our long-term debt that contains these provisions 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 are an indirect subsidiary of El Paso.

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

•  our payment of dividends;

•  decisions on our financings and our capital raising activities;

•  mergers or other business combinations;

•  our acquisitions or dispositions of assets; and

•  our participation in El Paso’s cash management program.

      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 1B. UNRESOLVED STAFF COMMENTS

      None.

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 business. 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.

      Arizona Pipe-Coating. In September 2005, the Arizona Department of Environmental Quality (ADEQ) issued a Notice of Violation (NOV) for alleged regulatory violations related to our handling of asbestos-containing asphaltic pipe coating. This matter has been referred to the Office of the Attorney General for the State of Arizona, who has informed us of its intent to assess a civil penalty and require preventive

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actions by us to resolve the NOV. Although the likely penalty and costs associated with any preventive actions are unknown at this time, the ADEQ proposed a fine of less than $1 million. We are in discussions with the state in an effort to resolve this matter.

      Tucson Waste Management. In September 2004, we received a NOV from the ADEQ for alleged failure to comply with waste management regulations at our Tucson compressor station. We fulfilled their request for information and documentation related to the alleged noncompliance. This matter has been referred to the Office of the Attorney General for the State of Arizona, who has informed us of its intent to require a civil penalty to resolve the NOV. The amount of the penalty is unknown at this time, but we are in discussions with the state in an effort to resolve this matter.

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

ITEM  5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

      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. No common stock dividends were declared or paid in 2005, 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.

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

      The information required by this Item is presented in a reduced disclosure format pursuant to General Instruction I to Form 10-K. Our Management’s Discussion and Analysis includes forward-looking statements that are subject to risks and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are in Part I, Item 1A, Risk Factors.

Overview

      Our business consists of interstate natural gas transmission services which face varying degrees of competition from existing and proposed 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 and financial results have historically been relatively stable. However, our financial results can be subject to volatility due to factors such as changes in natural gas prices and market conditions, regulatory actions, competition, the creditworthiness of our customers and weather. In 2005, 92 percent of our revenues were attributable to reservation charges paid by firm customers. Reservation charges are paid regardless of volumes transported. The remaining eight percent were variable. Through 2005, we also experienced volatility in our financial results when the amounts of natural gas utilized in operations differed from the amounts we recovered from our customers for that purpose. We do not anticipate that this will impact our future results as we have filed with the FERC to adopt a fuel tracking mechanism beginning in 2006.

      Our ability to extend existing customer contracts or remarket expiring contracted capacity is dependent on 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 requirements, we attempt to recontract or remarket our capacity at the 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 our contracts is approximately four years as of December 31, 2005.

      Below is the contract expiration portfolio for our firm transportation contracts as of December 31, 2005, including those whose terms begin in 2006 or later.

			Percent of Total
	BBtu/d(1)		Contracted Capacity
2006		1,595		26
2007		1,384		22
2008		483		8
2009 and beyond		2,779		44

⁽¹⁾  Includes EPNG capacity on the Mojave system.

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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 and (iii) interest, which includes interest and debt expense and affiliated interest income. We exclude interest from this measure so that our investors may evaluate our operating results without regard to our financing methods. We believe 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 flows. The following is a reconciliation of EBIT to net income for the years ended December 31:

		2005			2004
		(In millions, except
		volume amounts)
Operating revenues		$	497		$	508
Operating expenses			(335	)		(266	)
	Operating income		162			242
Other income, net			8			7
	EBIT		170			249
Interest and debt expense			(92	)		(92	)
Affiliated interest income, net			32			19
Income taxes			(46	)		(58	)
	Net income	$	64		$	118
Total throughput (BBtu/d)			4,214			4,235

      The following items contributed to our overall EBIT decrease of $79 million for the year ended December 31, 2005 as compared to 2004:

										EBIT
		Revenue			Expense			Other		Impact
		Favorable/(Unfavorable)
		(In millions)
Higher litigation accruals		$	—		$	(42	)	$	—	$	(42	)
Gas not used in operations and revaluations			(15	)		(9	)		—		(24	)
Higher general and administrative expenses			—			(15	)		—		(15	)
Other(1)			4			(3	)		1		2
	Total impact on EBIT	$	(11	)	$	(69	)	$	1	$	(79	)

⁽¹⁾  Consists of individually insignificant items.

     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.

      Higher Litigation Accruals. During the year ended December 31, 2005, our litigation accrual was higher than in 2004 due to the settlement and continuing negotiations of several of our outstanding legal claims. We believe our current accruals for our remaining legal matters are adequate. However, the ultimate outcome of the remaining claims could adversely affect our financial results. For further discussion of our pending legal matters, see Item 8, Financial Statements and Supplementary Data, Note 6.

      Gas Not Used in Operations and Revaluations. The financial impact of operational gas is based on the amount of natural gas we are allowed to retain, relative to the amounts of natural gas we use for operating purposes and the price of natural gas. Gas not needed for operations results in revenues to us, which are impacted by volumes and prices during a given period and by factors such as system throughput, facility enhancements and the ability to operate the systems in the most efficient and safe manner. Revenues from gas not used in operations are recognized at the time volumes are retained. Accordingly, we experienced

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variability in our results based on the volumes and changing prices of these retained volumes. We also experienced variability in our operating results from revaluations of net natural gas imbalances owed to customers and from encroachments against our system gas. These volumetric obligations were recognized as they occurred and were impacted by changing prices each period.

      During 2004, we retained, fairly consistently, volumes of natural gas that were not used in operations. During 2005, we experienced a net usage of natural gas in excess of amounts we retained under our tariff. This, along with a steadily increasing natural gas price environment during this timeframe, resulted in unfavorable impacts on our operating results in 2005 versus 2004.

      On January 1, 2006, we adopted a fuel tracker related to the actual costs of fuel lost and unaccounted for and other gas balancing costs, such as encroachments against our system gas supply and imbalance cash out price adjustments, with a true-up mechanism for amounts over or under retained. We believe this fuel tracker will reduce the future financial impacts of gas not used in our operations.

      Higher General and Administrative Expenses. During the year ended December 31, 2005, our general and administrative expenses were higher than in 2004, primarily due to an increase in benefits accrued under retirement plans, higher insurance and professional fees. We were also allocated higher costs from Tennessee Gas Pipeline Company (TGP), our affiliate, associated with our shared pipeline services. In addition, we allocate certain costs to Colorado Interstate Gas Company (CIG), also our affiliate.

      Recontracting. During 2005, SoCal successfully acquired approximately 768 BBtu/d of capacity on our EPNG system under new contracts which have been executed with various terms extending from 2009 to 2011 commencing September 2006. However, effective September 2006, approximately 453 BBtu/d of capacity formerly held by SoCal to serve its non-core customers will be available for recontracting. In addition, we have 1,142 BBtu/d of capacity that will, or potentially will, terminate in 2006 and 1,384 BBtu/d of capacity that will expire in 2007. We are remarketing the expiring capacity to serve either existing customers, SoCal’s non-core customers or to serve new customers. We are also pursuing the option of using some or all of this capacity to provide new services to existing customers. At this time, we are uncertain how much of the expiring capacity will be recontracted, and if so at what rates.

      Accounting for Pipeline Integrity Costs. In December 2005, we adopted the provisions of a FERC accounting release that requires us to expense certain pipeline integrity costs instead of our previous practice of capitalizing them as part of our property, plant and equipment. The adoption of the release did not have a material impact to our income statement for the year ended December 31, 2005, however, we currently estimate that we will be required to expense additional costs in the range of approximately $8 million to $16 million annually.

      Regulatory Matter. In June 2005, we filed a rate case with the FERC proposing an increase in revenues of 10.6 percent or $56 million over current tariff rates, and also proposing new services and revisions to certain terms and conditions of existing services, including the adoption of a fuel tracking mechanism. On January 1, 2006, the rates, which are subject to refund, and the fuel tracking mechanism became effective. In addition, the reduced tariff rates previously provided under the terms of our FERC-approved systemwide capacity allocation proceeding terminated. The combined effect of the proposed increase in tariff rates and the expiration of the lower rates is estimated to increase our revenues by approximately $138 million annually. The FERC accepted a delay in the effective date of the proposed new services and certain other provisions until April 1, 2006. At this time, the outcome of the rate case cannot be predicted with certainty. See Item 8, Financial Statements and Supplementary Data, Note 6, for a further discussion of this matter.

      As part of our rate case, we sought recovery, through a tracking mechanism, of costs associated with renewing our rights-of-way on Navajo Nation lands, which is discussed in Item 8, Financial Statements and Supplementary Data, Note 6. The FERC initially rejected our request, but invited us to seek a waiver of their regulations to permit the cost of the rights-of-way renewal to be included in our pending rate case if the final cost becomes known and measurable within a reasonable time after the close of the test period, which occurred on December 31, 2005. The timing or extent of recovery could impact our future financial results.

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      We periodically file for changes in our rates subject to the approval of the FERC. Changes in rates and other tariff provisions resulting from these regulatory proceedings have the potential to positively or negatively impact our profitability. In addition, Mojave is required to file for new rates to be effective in March 2007.

Affiliated Interest Income, Net

      Affiliated interest income, net for the year ended December 31, 2005, was $13 million higher than in 2004 due primarily to higher average short-term interest rates and slightly higher average advances to El Paso under its cash management program. The average short-term interest rate increased from 2.4% in 2004 to 4.2% in 2005. In addition, the average advances due from El Paso of $778 million in 2004 increased to $779 million in 2005.

Income Taxes

	Year Ended
	December 31,
	2005			2004
	(In millions,
	except for rates)
Income taxes	$	46		$	58
Effective tax rate		42	%		33	%

      Our effective tax rate for 2005 was different than the statutory rate of 35 percent primarily due to the effect of state income taxes and non-deductible expenses. Our effective tax rate for 2004 was lower than the statutory rate of 35 percent due to a state income tax adjustment related to the Western Energy Settlement and an adjustment to consolidated deferred taxes related to the Mojave pipeline system. 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 2004, we evaluated this allowance and determined that these state tax benefits would be fully realized. Consequently, we reversed this valuation allowance. Net of federal taxes, this benefit totaled approximately $6 million. For a reconciliation of the statutory rate to the effective rates, see Item 8, Financial Statements and Supplementary Data, Note 2.

Liquidity and Capital Expenditures

Liquidity Overview

      Our liquidity needs are provided by cash flows from operating activities. In addition, we participate in 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 in exchange for an affiliated note receivable or payable. 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, 2005, we had notes receivable from El Paso of $872 million that are due upon demand. However, we do not anticipate settlement within the next twelve months and therefore, classified this receivable as non-current on our balance sheet. See Item 8, Financial Statements and Supplementary Data, Note 11, for a further discussion of El Paso’s cash management program.

      In addition to the cash management program, we are also eligible to borrow amounts available under El Paso’s $3 billion credit agreement, under which our common stock, our ownership in Mojave and several of our affiliates are pledged as collateral. At December 31, 2005, El Paso had $1.2 billion outstanding as a term loan and $1.7 billion of letters of credit issued under the credit agreement. We have no borrowings or letter of credit obligations under this facility. We believe that cash flows from operating activities and amounts available under El Paso’s cash management program, if necessary, will be adequate to meet our short-term capital requirements for our existing operations.

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Capital Expenditures

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

		2005		2004
		(In millions)
Maintenance		$	106	$	107
Expansion/Other			34		41
	Total	$	140	$	148

      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 systems. Under our current plan, we expect to spend between approximately $120 million and $136 million in each of the next three years for capital expenditures to maintain the integrity of our pipelines, to comply with clean air regulations and to 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 $35 million. In addition, we have budgeted to spend between approximately $28 million and $52 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 Phoenix area lateral and storage projects. We expect to fund our capital expenditures through a combination of internally generated funds or by recovering some of the amounts advanced to El Paso under its cash management program, if necessary.

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, 2005, 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.

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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. At December 31, 2005, 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.

			December 31, 2005										December 31, 2004
			Expected Fiscal Year of
			Maturity of Carrying Amounts
											Fair		Carrying
			2010			Thereafter			Total		Value		Amount		Fair Value
			(In millions, except for rates)
Liabilities:
	Long-term debt — fixed rate		$	352		$	758		$	1,110	$	1,220	$	1,110	$	1,240
		Average interest rate		7.9	%		8.3	%

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

EL PASO NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(In millions)

		Year Ended December 31,
		2005			2004			2003
Operating revenues		$	497		$	508		$	526
Operating expenses
	Operation and maintenance		232			166			163
	Western Energy Settlement		—			—			127
	Depreciation, depletion and amortization		74			72			66
	Taxes, other than income taxes		29			28			29
			335			266			385
Operating income			162			242			141
Other income, net			8			7			7
Interest and debt expense			(92	)		(92	)		(90	)
Affiliated interest income, net			32			19			20
Income before income taxes			110			176			78
Income taxes			46			58			31
Net income		$	64		$	118		$	47

See accompanying notes.

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EL PASO NATURAL GAS COMPANY

CONSOLIDATED BALANCE SHEETS

(In millions, except share amounts)

				December 31,
				2005		2004
ASSETS
Current assets
	Cash and cash equivalents			$	—	$	1
	Accounts and notes receivable
		Customer, net of allowance of $18 in 2005 and 2004			114		73
		Affiliates			4		38
		Other			—		3
	Taxes receivable				—		102
	Materials and supplies				41		41
	Deferred income taxes				14		27
	Restricted cash				17		—
	Other				3		19
			Total current assets		193		304
Property, plant and equipment, at cost					3,417		3,355
	Less accumulated depreciation, depletion and amortization				1,193		1,222
			Total property, plant and equipment, net		2,224		2,133
Other assets
	Note receivable from affiliate				872		702
	Other				89		86
					961		788
			Total assets	$	3,378	$	3,225
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
	Accounts payable
		Trade		$	84	$	36
		Affiliates			6		16
		Other			17		4
	Short-term borrowings				—		7
	Taxes payable				27		29
	Accrued interest				25		25
	Accrued liabilities				50		10
	Other				12		12
			Total current liabilities		221		139
Long-term debt					1,110		1,110
Other liabilities
	Deferred income taxes				364		359
	Other				105		104
					469		463
Commitments and contingencies
Stockholder’s equity
	Common stock, par value $1 per share; 1,000 shares authorized, issued and outstanding				—		—
	Additional paid-in capital				1,268		1,267
	Retained earnings				310		246
			Total stockholder’s equity		1,578		1,513
			Total liabilities and stockholder’s equity	$	3,378	$	3,225

See accompanying notes.

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EL PASO NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

						Year Ended December 31,
						2005			2004			2003
Cash flows from operating activities
Net income						$	64		$	118		$	47
	Adjustments to reconcile net income to net cash from operating activities
		Depreciation, depletion and amortization					74			72			66
		Deferred income taxes					7			155			(12	)
		Western Energy Settlement					—			—			117
		Other non-cash income items					—			—			(36	)
		Asset and liabilities changes
			Western Energy Settlement liability				—			(538	)		—
			Accounts receivable				(34	)		(5	)		18
			Accounts payable				41			4			(33	)
			Taxes receivable				102			(102	)		—
			Taxes payable				16			(93	)		(9	)
			Other asset and liability changes
				Assets			8			—			(4	)
				Liabilities			26			(47	)		3
					Net cash provided by (used in) operating activities		304			(436	)		157
Cash flows from investing activities
	Additions to property, plant and equipment						(141	)		(148	)		(225	)
	Proceeds from the sale of assets						2			1			38
	Net change in restricted cash						(17	)		443			(443	)
	Net change in affiliate advances						(142	)		49			221
	Other						—			(7	)		—
					Net cash provided by (used in) investing activities		(298	)		338			(409	)
Cash flows from financing activities
	Net proceeds from the issuance of debt						—			—			354
	Payments to retire debt						(7	)		—			(200	)
	Capital contributions						—			73			121
					Net cash provided by (used in) financing activities		(7	)		73			275
Net change in cash and cash equivalents							(1	)		(25	)		23
Cash and cash equivalents
	Beginning of period						1			26			3
	End of period					$	—		$	1		$	26

See accompanying notes.

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EL PASO NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY

(In millions, except share amounts)

		8%			Common stock				Additional						Total
		Preferred							paid-in			Retained			stockholder’s
		stock			Shares		Amount		capital			earnings			equity
January 1, 2003		$	350			1,000	$	—	$	715		$	88		$	1,153
	Net income												47			47
	Preferred stock dividends												(7	)		(7	)
	Redemption of preferred stock		(350	)						359						9
	Western Energy Settlement contribution									121						121
	Allocated tax expense of El Paso equity plans									(1	)					(1	)
December 31, 2003			—			1,000		—		1,194			128			1,322
	Net income												118			118
	Western Energy Settlement contribution									73						73
December 31, 2004			—			1,000		—		1,267			246			1,513
	Net income												64			64
	Allocated tax benefit of El Paso equity plans									1						1
December 31, 2005		$	—			1,000	$	—	$	1,268		$	310		$	1,578

See accompanying notes.

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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 transmission systems are subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978, and the Energy Policy Act of 2005, and we currently apply the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types 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 postretirement employee benefit plan costs, capitalizing an equity return component on regulated capital projects and certain 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.

      We maintain cash on deposit with banks that is pledged for a particular use or restricted to support a potential liability. We classify these balances as restricted cash in other current or non-current assets in our balance sheet based on when we expect this cash to be used.

  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.

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  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 current index prices. Imbalances are settled in cash or made up in kind, subject to the terms of our tariff.

      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 in our balance sheet as either trade accounts payable or accounts payable to affiliates. In addition, we classify all imbalances as current as we expect to settle them within a year.

  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 and an interest and an equity return component, 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 property, plant and equipment. Under this method, assets with similar lives and 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 percent to 33 percent per year. Using these rates, the remaining depreciable lives of these assets range from three to 63 years. We re-evaluate depreciation rates each time we file with the FERC for a change in our transportation services rates. In our current rate filing, we have proposed depreciation rates ranging from two percent to 20 percent per year. We will use these rates, subject to refund, beginning in 2006.

      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 operating income.

      Included in our property, plant and equipment balances are additional acquisition costs of $151 million which represent the excess of allocated purchase costs over the 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, 2005 and 2004, we had unamortized additional acquisition costs of $64 million and $67 million.

      At December 31, 2005 and 2004, we had approximately $82 million and $104 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, 2005, 2004 and 2003 were $3 million. These debt amounts are included as a reduction to interest expense in our income statement. The equity portion of capitalized costs is calculated using the most recent FERC-approved equity rate of return. The equity amounts capitalized during the years ended December 31, 2005, 2004 and 2003, were $5 million, $4 million and $4 million (exclusive of any tax related impacts). These equity 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.

      In December 2005, we adopted the provisions of a FERC accounting release that impacts certain costs we incur related to our pipeline integrity programs. Under the release, we are required to prospectively expense certain pipeline integrity costs instead of capitalizing them as a part of our property, plant and equipment. The adoption of the provisions of this release did not have a material impact to our income statement for the year

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ended December 31, 2005; however, we currently estimate that we will be required to expense an additional amount of pipeline integrity costs under the release in the range of approximately $8 million to $16 million annually.

  Asset Impairments

      We evaluate our assets for impairment when events or circumstances indicate that their carrying values 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 our assets’ carrying values based on their ability to generate future cash flows on an undiscounted basis. If an impairment is indicated or if we decide to 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 or an analysis of expected discounted cash flows. The magnitude of any impairments are impacted by a number of factors, including the nature of the assets being sold and our established time frame for completing the sales, among other factors.

  Revenue Recognition

      Our revenues are primarily generated from natural gas transportation services. For our transportation services, we recognize reservation revenues on firm contracted capacity over the contract period regardless of the amount of natural gas that is transported. For interruptible or volumetric-based services, we record revenues when physical deliveries of natural gas are made at the agreed upon delivery point. Gas not used in operations is based on the volumes of natural gas we are allowed to retain relative to the amounts we use for operating purposes. We recognize revenue on gas not used in operations when the volumes are retained under our tariff. 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 be subject to refund in a rate proceeding.

  Environmental Costs and Other Contingencies

      We record liabilities at their undiscounted amounts in our balance sheet in other current and long-term liabilities when our environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the EPA or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and we recognize a current period expense when clean-up efforts do not benefit future periods.

      We evaluate separately from our liability any amounts paid directly or reimbursed by government sponsored programs and potential recoveries or reimbursements of remediation costs from third parties including insurance coverage. When recovery is assured after an evaluation of their creditworthiness or solvency, we record and report an asset separately from the associated liability on our balance sheet.

      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 the associated 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

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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 record 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.

Accounting for Asset Retirement Obligations

      On January 1, 2003, we adopted SFAS No. 143, Accounting for Asset Retirement Obligations, which requires that we record a liability for retirement and removal costs of long-lived assets used in our business when the timing and/or amount of the settlement of those costs are relatively certain. On December 31, 2005, we adopted the provisions of FASB Interpretation (FIN) No. 47, Accounting for Conditional Asset Retirement Obligations, which requires that we record a liability for those retirement and removal costs in which the timing and/or amount of the settlement of the costs are uncertain.

      We have legal obligations associated with our natural gas pipelines and related transmission facilities and storage wells. We have obligations to plug storage wells when we no longer plan to use them and when we abandon them. Our legal obligations associated with our natural gas transmission facilities relate primarily to purging and sealing the pipelines if they are abandoned. We also have obligations to remove hazardous materials associated with our natural gas transmission facilities if they are replaced. We accrue a liability on those legal obligations when we can estimate the timing and amount of their settlement. These obligations include those where we have plans to or otherwise will be legally required to replace, remove or retire the associated assets. Substantially all of our natural gas pipelines can be maintained indefinitely and, as a result, we have not accrued a liability associated with purging and sealing them. Our net asset retirement liability as of December 31, 2005 and 2004, is not material to our financial statements.

2. Income Taxes

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

			2005		2004			2003
			(In millions)
Current
	Federal		$	35	$	(99	)	$	37
	State			4		2			6
				39		(97	)		43
Deferred
	Federal			5		159			(11	)
	State			2		(4	)		(1	)
				7		155			(12	)
		Total income taxes	$	46	$	58		$	31

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      Effective Tax Rate Reconciliation. 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:

		2005			2004			2003
		(In millions, except for rates)
Income taxes at the statutory federal rate of 35%		$	39		$	62		$	27
Increase (decrease)
	State income taxes, net of federal income tax effect		4			6			3
	State tax valuation allowance — Western Energy Settlement		—			(6	)		—
	Deferred tax adjustments, including Mojave		—			(3	)		—
	Non-deductible expenses		3			—			—
	Other		—			(1	)		1
Income taxes		$	46		$	58		$	31
Effective tax rate			42	%		33	%		40	%

      Deferred Tax Assets and Liabilities. The following are the components of our net deferred tax liability at December 31:

			2005		2004
			(In millions)
Deferred tax liabilities
	Property, plant and equipment		$	427	$	389
	Employee benefits and deferred compensation obligations			27		26
	Regulatory and other assets			45		73
		Total deferred tax liability		499		488
Deferred tax assets
	U.S. net operating loss and tax credit carryovers			81		69
	State net operating loss carryovers			—		21
	Other liabilities			68		66
		Total deferred tax asset		149		156
Net deferred tax liability			$	350	$	332

      As of December 31, 2005, we had approximately $17 million of alternative minimum tax credits that carryover indefinitely.

      Net Operating Loss Carryovers. The table below presents the details of our net operating loss carryover period as of December 31, 2005:

Carryover	Amount		Expiration Year
	(In millions)
U.S. federal net operating loss(1)	$	184		2019-2024

⁽¹⁾  Less than $1 million of this amount expires in 2019, $1 million in 2021 and $183 million in 2024.

     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.

      Valuation Allowances. 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 2004, we evaluated this allowance and determined that these state tax benefits would be fully realized. Consequently, we reversed this valuation allowance. Net of federal taxes, this benefit totaled approximately $6 million.

      Other Tax Matters. Under El Paso’s tax accrual policy, we are allocated the tax effects associated with our employees’ nonqualified dispositions of El Paso stock under its employee stock purchase plan, the exercise of stock options and the vesting of restricted stock as well as restricted stock dividends. This allocation reduced

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taxes payable by $1 million in 2005, was not significant in 2004 and increased taxes payable by $1 million in 2003. These tax effects are included in additional paid-in capital in our balance sheets.

3. Financial Instruments

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

		2005				2004
		Carrying				Carrying
		Amount		Fair Value		Amount		Fair Value
		(In millions)
Balance sheet financial instruments:
	Long-term debt(1)	$	1,110	$	1,220	$	1,110	$	1,240

⁽¹⁾  We estimated the fair value of debt with fixed interest rates based on quoted market prices for the same or similar issues.

     As of December 31, 2005 and 2004, 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 liabilities at December 31:

Description			2005		2004
			(In millions)
Non-current regulatory assets
	Unamortized loss on reacquired debt		$	18	$	21
	Deferred taxes on capitalized funds used during construction			19		17
	Postretirement benefits			9		11
	Under-collected state income taxes			7		7
	Other			3		—
		Total non-current regulatory assets(1)	$	56	$	56
Current regulatory liabilities			$	1	$	—
Non-current regulatory liabilities
	Property and plant depreciation			41		35
	Excess deferred federal income taxes			2		3
		Total regulatory liabilities(1)	$	44	$	38

⁽¹⁾  Amounts are included as other non-current assets and other current and non-current liabilities in our balance sheet.

5. Debt and Credit Facilities

Debt

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

		2005		2004
		(In millions)
7.625% Notes due 2010		$	355	$	355
8.625% Debentures due 2022			260		260
7.50%   Debentures due 2026			200		200
8.375% Notes due 2032			300		300
			1,115		1,115
Less: Unamortized discount			5		5
	Total long-term debt	$	1,110	$	1,110

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      In July 2003, we issued $355 million of 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.

      We have the ability to call $655 million of our notes due in 2010 and 2032 at any time prior to their stated maturity date. If we were to exercise our option to call these notes, we would be obligated to pay principal, accrued interest and potentially a make-whole premium to redeem the debt. At this time, we have no intent to call this debt.

Credit Facilities

      El Paso maintains a $3 billion credit agreement. We are an eligible borrower under the credit agreement and are only liable for amounts we directly borrow. Additionally, our common stock, our interest in Mojave, and several of our affiliates continue to be pledged as collateral under the agreement. At December 31, 2005, El Paso had $1.2 billion outstanding as a term loan and $1.7 billion of letters of credit issued under the credit agreement. We have no borrowings or letter of credit obligations under this facility.

      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 11; and (vii) limitations on our ability to prepay debt. For the year ended December 31, 2005, 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 that contain these provisions could be accelerated.

6. Commitments and Contingencies

  Legal Proceedings

      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, alleging that the defendants conspired to manipulate prices and supplies of natural gas in the California-Arizona border market from 1996 to 2001. In January 2004, the court dismissed the lawsuit. Plaintiffs subsequently amended the complaint, which was dismissed again in late 2004. Plaintiffs have appealed that dismissal to the U.S. Court of Appeals for the Ninth Circuit. The appeal has been fully briefed. Our costs and legal exposure related to this lawsuit are not currently determinable.

      IMC Chemicals (IMCC) v. El Paso Marketing, L.P. (EPM), et al. In January 2003, IMCC filed a lawsuit in California state court against us and our affiliates seeking to void a gas purchase agreement between IMCC and EPM. 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. IMCC’s total claim appeared to be in excess of $20 million. IMCC alternatively sought $5.5 million as damages it maintained it was entitled to as of the termination date of the contract which was December 2003. EPM’s counterclaim sought in excess of $5 million in damages. This matter was settled in November 2005 and there was no impact to our financial statements.

      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 withheld capacity and thereby manipulated and inflated gas prices. The case was dismissed by the Maricopa County Superior Court in August 2005, however

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the dismissal has been appealed. 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.

      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. In June 2001, the U.S. Department of Transportation’s (DOT) Office of Pipeline Safety issued a Notice of Probable Violation and Proposed Civil Penalty to us. The Notice alleged violations of DOT regulations, proposed fines totaling $2.5 million and proposed corrective actions. In April 2003, the National Transportation Safety Board issued its final report on the rupture, finding that the rupture was probably caused by internal corrosion that was not detected by our corrosion control program. In December 2003, this matter was referred by the DOT to the Department of Justice (DOJ). We entered into a tolling agreement with the DOJ and have recently extended that agreement. As a result of the referral to the DOJ, the amount of the proposed fine may increase substantially from the DOT’s proposed fine of $2.5 million and may also involve implementation of additional operational and safety measures.

      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 emergency medical service 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. 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 due to the alleged mismeasurement. The plaintiff seeks royalties, along with interest, expenses, and punitive damages. The plaintiff also seeks injunctive relief with regard to future 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 were argued before a representative appointed by the court. In May 2005, the representative issued a recommendation, which if adopted by the district court judge, will result in the dismissal on jurisdictional grounds of the suit against us. If the district court judge adopts the representative’s recommendation, an appeal by the plaintiff of the district court’s order is likely. 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

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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. Motions for class certification have been briefed and argued in both proceedings, and the parties are awaiting the court’s ruling. 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. (Burlington), 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 consolidated class action has been settled pursuant to a settlement agreement executed in January 2006. 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. All the claims in this action have also been settled as part of the January 2006 settlement. The settlement of all these claims is subject to court approval, after a fairness hearing anticipated in the spring of 2006. We 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, Texas relating to indemnity issues between Burlington and us. That action was stayed by agreement of the parties and settled in November 2005, subject to the underlying class settlements being finalized and approved by the court. Upon final court approval of these settlements, our contribution will be approximately $30 million plus interest, which has been accrued as of December 31, 2005.

      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 to 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 further information becomes available, or other relevant developments occur, we 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, 2005, we had accrued approximately $45 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, 2005, we had accrued approximately $29 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and for related environmental legal costs. This accrual includes $24 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 $54 million. Our environmental remediation projects are in various stages of completion. The liabilities we have recorded reflect our current estimates of amounts we will expend to remediate these sites. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As additional assessments occur or remediation efforts continue, we may incur additional liabilities.

      Below is a reconciliation of our accrued liability from January 1, 2005 to December 31, 2005 (in millions):

Balance at January 1, 2005	$	32
Additions/adjustments for remediation activities		1
Payments for remediation activities		(4	)
Balance at December 31, 2005	$	29

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      For 2006, we estimate that our total remediation expenditures will be approximately $5 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 four active sites under 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, 2005, we have estimated our share of the remediation costs at these sites to be between $12 million and $17 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.

      State of Arizona Chromium Review. In April 2004, the ADEQ 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 commenced 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 the 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 related 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

      Rate Case. In June 2005, we filed a rate case with the FERC proposing an increase in revenues of 10.6 percent or $56 million over current tariff rates, and also proposing new services and revisions to certain terms and conditions of existing services, including the adoption of a fuel tracking mechanism. On January 1, 2006, the rates, which are subject to refund, and the fuel tracking mechanism became effective. In addition, the reduced tariff rates previously provided under the terms of our FERC-approved systemwide capacity allocation proceeding terminated. The combined effect of the proposed increase in tariff rates and the expiration of the lower rates is estimated to increase our revenues by approximately $138 million annually. The FERC accepted a delay in the effective date of the proposed new services and certain other provisions until April 1, 2006. We are continuing settlement discussions with our customers. At this time, the outcome of this rate case cannot be predicted with certainty.

      Rate Settlement. Our prior rate settlement established our base rates through December 31, 2005. The prior settlement has certain requirements applicable to the post-settlement period that includes 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 our 1996 rate settlement. In our rate case filed in June 2005, we proposed that the rate limitation should no longer apply. The FERC could issue an order concerning the continued viability of the capped-rate provision of the 1996 rate settlement in early 2006.

      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 December 2005, the auditors gave us the results of their report citing us with two classes of unintentional

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errors and requiring us to improve certain detection procedures. Based on this information it is unlikely that the final outcome will be material to us or to our affiliated pipelines.

      California Public Utilities Commission (CPUC)’s OIR Proceeding. In 2005, 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 such as interstate capacity and utility access to LNG supplies. The CPUC has issued decisions on these issues that are generally favorable to us. However, the CPUC authorized 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, which they have done. The staff of the CPUC has issued a report recommending that the California utilities consider acquiring firm interstate pipeline capacity to serve base loaded generation plants, which are non-core customers. Although we have successfully recontracted with SoCal for 768 BBtu/d of capacity for various terms extending through 2011, we will have approximately 453 BBtu/d of capacity formerly held by SoCal for its use in serving its non-core customers available for recontracting, effective September 2006. We are continuing in our efforts to remarket this remaining expiring capacity to serve either SoCal’s non-core customers or to serve new customers. We are also pursuing the option of using some or all of this capacity to provide new services to existing customers. At this time, we are uncertain how much of the remaining capacity formerly held by SoCal will be recontracted and, if so, at what rates.

      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.

Other Matter

      Navajo Nation. Nearly 900 looped pipeline miles of the north mainline of our EPNG pipeline system are located on lands held in trust by the United States for the benefit of the Navajo Nation. Our rights-of-way, on lands crossing the Navajo Nation expired in October 2005. Under an interim agreement reached in January 2006, the Navajo Nation consented to our continued use and enjoyment of our existing rights-of-way through the end of 2006. Under the interim agreement, we will make quarterly payments to the Navajo Nation, subject to a two-way adjustment if the parties reach final agreement on a long term right-of-way agreement prior to the end of 2006. Negotiations on the terms of the long-term agreement are continuing. Although the Navajo Nation has at times demanded more than ten times the $2 million annual fee that existed prior to the execution of the interim agreement, El Paso continues to offer a combination of cash and non-cash consideration, including collaborative projects to benefit the Nation. In addition, we continue to preserve our other legal and regulatory alternatives, which include continuing to pursue our application with the Department of the Interior for renewal of our rights-of-way on Navajo Nation lands. We also continue to press for public policy intervention by Congress in this area. The Energy Policy Act of 2005 commissioned a comprehensive study of energy infrastructure rights-of-way on tribal lands. The study, to be conducted jointly by the Department of Energy and the Department of Interior must be submitted to Congress by August 2006. It is uncertain whether our negotiation, public policy or litigation efforts will be successful, or if successful, what will be the ultimate cost of obtaining the rights-of-way or whether we will be able to recover those costs in our rate case.

      While the outcome of this matter cannot be predicted with certainty, based on current information and our existing accruals, we do not expect the ultimate resolution of this matter to have a material adverse effect on our financial position, operating results or cash flows. It is possible that new information or future developments could require us to reassess our potential exposure related to this matter, and adjust our accruals accordingly. 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.

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  Capital Commitments

      At December 31, 2005, we had capital and investment commitments of approximately $71 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, 2005, were as follows:

Year Ending
December 31,		Operating Leases
		(In millions)
2006		$	16
2007			8
2008			2
2009			1
	Total	$	27

      Our minimum future rental commitments have not been reduced by minimum sublease rentals of approximately $2 million due to us in the future under noncancelable subleases.

      Included in our minimum future rental commitments above is our remaining obligation under a terminated lease agreement. Rental expense on our operating leases for each of the years ended December 31, 2005, 2004 and 2003 was $6 million, $3 million and $3 million. These amounts include our share of rent allocated to us from El Paso.

     Other Commercial Commitments

      We also hold cancelable easements or rights-of-way arrangements from landowners permitting the use of land for the construction and operation of our pipeline systems. Currently, our obligation under these easements is not material to the results of our operations except for Navajo Nation discussed above.

     Guarantees

      We are or have been 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, 2005, we had approximately $16 million of financial and performance guarantees not otherwise reflected in our financial statements.

7. Retirement Benefits

  Pension and Retirement Benefits

      El Paso maintains a pension plan to provide benefits determined under a cash balance formula. El Paso also maintains a defined contribution plan covering its U.S. employees, including our employees. El Paso matches 75 percent of participant basic contributions up to 6 percent of eligible compensation and can make additional discretionary matching contributions. El Paso is responsible for benefits accrued under its plans and allocates the related costs to its affiliates.

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  Postretirement Benefits

      We provide 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 make no contributions to our postretirement benefit plan in 2006.

      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 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. We also reduced 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 postretirement benefit plan. Our benefits are presented and computed as of and for the twelve months ended September 30 (the plan reporting date):

		2005			2004
		(In millions)
Change in benefit obligation:
	Projected benefit obligation at beginning of period	$	85		$	107
	Interest cost		4			6
	Actuarial (gain) loss		10			(22	)
	Benefits paid		(6	)		(6	)
	Projected benefit obligation at end of period	$	93		$	85
Change in plan assets:
	Fair value of plan assets at beginning period	$	77		$	70
	Actual return on plan assets		8			2
	Employer contributions		11			11
	Benefits paid		(6	)		(6	)
	Fair value of plan assets at end of period	$	90		$	77
Reconciliation of funded status:
	Under funded status as of September 30	$	(3	)	$	(8	)
	Fourth quarter contributions		3			3
	Unrecognized net actuarial loss		15			9
	Unrecognized net transition obligation		—			8
	Prepaid benefit cost at December 31	$	15		$	12

      Future benefits expected to be paid on our postretirement plan as of December 31, 2005, are as follows (in millions):

Year Ending
December 31,
2006		$	8
2007			8
2008			8
2009			7
2010			8
2011-2015			40
	Total	$	79

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

	2005			2004			2003
	(In millions)
Interest cost	$	4		$	6		$	7
Expected return on plan assets		(5	)		(5	)		(4	)
Amortization of net actuarial gain		—			2			1
Amortization of transition obligation		8			8			8
Net postretirement benefit cost	$	7		$	11		$	12

      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 postretirement plan for 2005, 2004 and 2003:

		2005		2004		2003
		(Percent)
Assumptions related to benefit obligations at September 30:
	Discount rate		5.25		5.75
Assumptions related to benefit costs at December 31:
	Discount rate		5.75		6.00		6.75
	Expected return on plan assets(1)		7.50		7.50		7.50

⁽¹⁾  The expected return on plan assets is a pre-tax rate (before a tax rate of 15 percent on postretirement benefits) that is primarily based on an expected risk-free investment return, adjusted for historical risk premiums and specific risk adjustments associated with our debt and equity securities. These expected returns were then weighted based on the target asset allocations of our investment portfolio.

     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 10.9 percent, gradually decreasing to 5.0 percent by the year 2015. 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:

		2005			2004
		(In millions)
One percentage point increase:
	Aggregate of service cost and interest cost	$	—		$	—
	Accumulated postretirement benefit obligation	$	7		$	6
One percentage point decrease:
	Aggregate of service cost and interest cost	$	—		$	—
	Accumulated postretirement benefit obligation	$	(6	)	$	(5	)

     Postretirement Plan Assets

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

		Actual		Actual
Asset Category		2005		2004
		(Percent)
Equity securities			65		65
Debt securities			34		35
Other			1		—
	Total		100		100

      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

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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. 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

      In April 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.

9. Transactions with Major Customers

      The following table shows revenues from our major customers for each of the three years ended December 31:

	2005		2004		2003
	(In millions)
SoCal	$	156	$	157	$	154
Southwest Gas Corporation		51		51		50

10. Supplemental Cash Flow Information

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

	2005			2004		2003
	(In millions)
Interest paid, net of capitalized interest	$	93		$	92	$	74
Income tax payments (refunds)		(93	)		98		51

11. 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. We have historically provided cash to El Paso in exchange for an affiliated note receivable that is due upon demand. However, at December 31, 2005, we do not anticipate settlement within the next twelve months and therefore, classified this receivable as non-current on our balance sheet. At December 31, 2005 and 2004, we had notes receivable from El Paso of $872 million and $730 million. We classified $28 million of this receivable as current at December 31, 2004. The interest rate at December 31, 2005 and 2004, was 5.0% and 2.0%.

      Taxes. 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 had income taxes receivable of $102 million at December 31, 2004 which we collected as of December 31, 2005. We also had income taxes payable of $26 million and $9 million at December 31, 2005 and 2004, included in taxes payable on our balance sheets. In addition, we had income tax assets of $21 million at December 31, 2004 included in non-current deferred income taxes on our balance sheet that were paid to us by El Paso in 2005. The majority of these balances will become payable to or receivable from El Paso. See Note 1 for a discussion of our tax accrual policy.

      Capital Contributions. In 2004 and 2003, El Paso contributed to us $73 million and $121 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.

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      Other Affiliate Balances. At December 31, 2005 and 2004, we had contractual deposits with our affiliates arising in the ordinary course of business of $6 million.

      In 2004, we acquired assets from our affiliate with a net book value of $6 million.

      Affiliate Revenues and Expenses. We provide transportation services to EPM. We entered into these transactions in the normal course of business and the services were based on the same terms as non-affiliates.

      El Paso bills us directly for certain general and administrative costs and allocates a portion of its general and administrative costs to us. This allocation is based on the estimated level of effort devoted to our operations and the relative size of our EBIT, gross property and payroll. In addition to allocations from El Paso, we are also allocated costs from TGP associated with our pipeline services. We also allocate costs to CIG for its share of pipeline services. El Paso currently bills us directly for compensation expense related to certain stock-based compensation awards granted directly to our employees as well as allocates to us our proportionate share of El Paso’s corporate compensation expense. On January 1, 2006, El Paso adopted SFAS No. 123(R), Share-Based Payment, which requires that companies measure all employee stock-based compensation awards at fair value on the date they are granted to employees and recognize compensation costs in its financial statements over the requisite service period. As a result, beginning in 2006, we will record additional expense for all stock-based compensation awards (including stock options) granted directly to our employees as well as our allocable share of El Paso’s corporate stock-based compensation expense.

      The following table shows revenues and charges from our affiliates for each of the three years ended December 31:

	2005		2004		2003
	(In millions)
Revenues from affiliates	$	17	$	18	$	18
Operation and maintenance expenses from affiliates		67		62		69
Reimbursements of operating expenses charged to affiliates		16		14		13

12. Supplemental Selected Quarterly Financial Information (Unaudited)

      Financial information by quarter is summarized below:

		Quarters Ended
		March 31		June 30		September 30		December 31		Total
		(In millions)
2005
	Operating revenues	$	123	$	123	$	125	$	126	$	497
	Operating income		47		57		19		39		162
	Net income		19		27		5		13		64
2004
	Operating revenues	$	124	$	130	$	130	$	124	$	508
	Operating income		60		69		59		54		242
	Net income		34		32		32		20		118

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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, 2005 and 2004, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 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

February 28, 2006

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SCHEDULE II

EL PASO NATURAL GAS COMPANY

VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 2005, 2004 and 2003

(In millions)

		Balance at		Charged to						Charged to		Balance
		Beginning		Costs and						Other		at End
Description		of Period		Expenses			Deductions			Accounts		of Period
2005
	Allowance for doubtful accounts	$	18	$	—		$	—		$	—	$	18
	Legal reserves		3		42	(1)		—			—		45
	Environmental reserves		32		1			(4	)		—		29
2004
	Allowance for doubtful accounts	$	18	$	—		$	—		$	—	$	18
	Valuation allowance on deferred tax assets		6		—			(6	)		—		—
	Legal reserves		541		—			(538	)(2)		—		3
	Environmental reserves		28		7			(3	)		—		32
2003
	Allowance for doubtful accounts	$	18	$	—		$	—		$	—	$	18
	Valuation allowance on deferred tax assets		6		—			—			—		6
	Legal reserves		415		136	(3)		(10	)(2)		—		541
	Environmental reserves		29		1			(2	)		—		28

(1)	For a discussion of our legal matters, see Item 8, Financial Statements and Supplementary Data, Note 6.
(2)	Relates to payments made pursuant to the Western Energy Settlement.
(3)	Reflects charges for the Western Energy Settlement.

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

      None.

ITEM 9A.  CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

      As of December 31, 2005, we carried out an evaluation under the supervision and with the participation of our management, including our President and Chief Financial Officer, as to the effectiveness, design and operation of our disclosure controls and procedures, as defined by the Securities Exchange Act of 1934, as amended. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports we file or submit under the Exchange Act is accurate, complete and timely.

      Based on the results of this evaluation, our President and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2005.

Changes in Internal Control Over Financial Reporting

      There were no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting during the fourth quarter 2005.

ITEM 9B. OTHER INFORMATION

      None.

PART III

      Item 10, “Directors and Executive Officers of the Registrant;” Item 11, “Executive Compensation;” Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters;” and Item 13, “Certain Relationships and Related Transactions,” have been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit Fees

      The audit fees for the years ended December 31, 2005 and 2004 of $800,000 and $925,000 were for professional services rendered by PricewaterhouseCoopers LLP for the audits of the consolidated financial statements of El Paso Natural Gas Company.

All Other Fees

      No other audit-related, tax or other services were provided by our independent registered public accounting firm for the years ended December 31, 2005 and 2004.

Policy for Approval of Audit and Non-Audit Fees

      We are an indirect wholly owned subsidiary of El Paso and do not have a separate audit committee. El Paso’s Audit Committee has adopted a pre-approval policy for audit and non-audit services. For a description of El Paso’s pre-approval policies for audit and non-audit related services, see El Paso Corporation’s proxy statement for its 2006 Annual Meeting of Stockholders.

40

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

      (a) The following documents are filed as a part of this report:

      1. Financial statements.

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

		Page
	Consolidated Statements of Income		18
	Consolidated Balance Sheets		19
	Consolidated Statements of Cash Flows		20
	Consolidated Statements of Stockholder’s Equity		21
	Notes to Consolidated Financial Statements		22
	Report of Independent Registered Public Accounting Firm		38
2. Financial statement schedules.
	Schedule II — Valuation and Qualifying Accounts		39
	All other schedules are omitted because they are not applicable, or the required information is disclosed in the financial statements or accompanying notes.
3. Exhibit list			42

41

EL PASO NATURAL GAS COMPANY

EXHIBIT LIST

December 31, 2005

      Each exhibit identified below is a part of this Report. Exhibits filed with this Report are designated by “*”. All exhibits not so designated are incorporated herein by reference to a prior filing as indicated.

Exhibit
Number		Description
	3.A	Restated Certificate of Incorporation dated April 8, 2003 (Exhibit 3.A to our 2003 Second Quarter Form 10-Q).
	3.B	By-laws dated June 24, 2002 (Exhibit 3.B to our 2002 Form 10-K).
	4.A	Indenture dated as of January 1, 1992, between El Paso Natural Gas Company and Wilmington Trust Company (as successor to Citibank, N.A.), as Trustee, (Exhibit 4.A to our 2004 Form 10-K).
	4.B	Indenture dated as of November 13, 1996, between El Paso Natural Gas Company and Wilmington Trust Company (as successor to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as Trustee, (Exhibit 4.B to our 2004 Form 10-K).
	4.C	Indenture dated as of July 21, 2003, between El Paso Natural Gas Company and Wilmington Trust Company, as Trustee, (Exhibit 4.1 to our Form 8-K filed July 23, 2003).
	10.A	Amended and Restated Credit Agreement dated as of November 23, 2004, among El Paso Corporation, ANR Pipeline Company, Colorado Interstate Gas Company, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the several banks and other financial institutions from time to time parties thereto and JPMorgan Chase Bank, N.A., as administrative agent and as collateral agent (Exhibit 10.A to our Form 8-K filed November 29, 2004); Amended and Restated Subsidiary Guarantee Agreement dated as of November 23, 2004, made by each of the Subsidiary Guarantors in favor of JPMorgan Chase Bank, N.A., as Collateral Agent (Exhibit 10.C to our Form 8-K filed November 29, 2004).
	10.B	Amended and Restated Security Agreement dated as of November 23, 2004, among El Paso Corporation, ANR Pipeline Company, Colorado Interstate Gas Company, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the Subsidiary Grantors and certain other credit parties thereto and JPMorgan Chase Bank, N.A., not in its individual capacity, but solely as collateral agent for the Secured Parties and as the depository bank (Exhibit 10.B to our Form 8-K filed November 29, 2004).

42

Exhibit
Number		Description
	10.C	Master Settlement Agreement dated as of June 24, 2003, by and between, on the one hand, El Paso Corporation, El Paso Natural Gas Company, and El Paso Merchant Energy, L.P.; and, on the other hand, the Attorney General of the State of California, the Governor of the State of California, the California Public Utilities Commission, the California Department of Water Resources, the California Energy Oversight Board, the Attorney General of the State of Washington, the Attorney General of the State of Oregon, the Attorney General of the State of Nevada, Pacific Gas & Electric Company, Southern California Edison Company, the City of Los Angeles, the City of Long Beach, and classes consisting of all individuals and entities in California that purchased natural gas and/or electricity for use and not for resale or generation of electricity for the purpose of resale, between September 1, 1996 and March 20, 2003, inclusive, represented by class representatives Continental Forge Company, Andrew Berg, Andrea Berg, Gerald J. Marcil, United Church Retirement Homes of Long Beach, Inc., doing business as Plymouth West, Long Beach Brethren Manor, Robert Lamond, Douglas Welch, Valerie Welch, William Patrick Bower, Thomas L. French, Frank Stella, Kathleen Stella, John Clement Molony, SierraPine, Ltd., John Frazee and Jennifer Frazee, John W.H.K. Phillip, and Cruz Bustamante (Exhibit 10.HH to our second quarter 2003 Form 10-Q).
	10.D	Joint Settlement Agreement submitted and entered into by El Paso Natural Gas Company, El Paso Merchant Energy Company, El Paso Merchant Energy-Gas, L.P., the Public Utilities Commission of the State of California, Pacific Gas & Electric Company, Southern California Edison Company and the City of Los Angeles (Exhibit 10.II to our 2003 second quarter Form 10-Q).
	21	Omitted pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
	*31.A	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	*31.B	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	*32.A	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	*32.B	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Undertaking

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

43

SIGNATURES

      Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, El Paso Natural Gas Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 3rd day of March 2006.

EL PASO NATURAL GAS COMPANY

By:  /s/ James J. Cleary

James J. Cleary

Chairman of the Board and President

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

Signature	Title	Date
/s/ James J. Cleary James J. Cleary	Chairman of the Board and President (Principal Executive Officer)	March 3, 2006
/s/ John R. Sult John R. Sult	Senior Vice President, Chief Financial Officer and Controller (Principal Accounting and Financial Officer)	March 3, 2006
/s/ Daniel B. Martin Daniel B. Martin	Senior Vice President and Director	March 3, 2006
/s/ Thomas L. Price Thomas L. Price	Vice President and Director	March 3, 2006

44

EL PASO NATURAL GAS COMPANY

EXHIBIT INDEX

December 31, 2005

      Each exhibit identified below is a part of this Report. Exhibits filed with this Report are designated by “*”. All exhibits not so designated are incorporated herein by reference to a prior filing as indicated.

Exhibit
Number		Description
	3.A	Restated Certificate of Incorporation dated April 8, 2003 (Exhibit 3.A to our 2003 Second Quarter Form 10-Q).
	3.B	By-laws dated June 24, 2002 (Exhibit 3.B to our 2002 Form 10-K).
	4.A	Indenture dated as of January 1, 1992, between El Paso Natural Gas Company and Wilmington Trust Company (as successor to Citibank, N.A.), as Trustee, (Exhibit 4.A to our 2004 Form 10-K).
	4.B	Indenture dated as of November 13, 1996, between El Paso Natural Gas Company and Wilmington Trust Company (as successor to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as Trustee, (Exhibit 4.B to our 2004 Form 10-K).
	4.C	Indenture dated as of July 21, 2003, between El Paso Natural Gas Company and Wilmington Trust Company, as Trustee, (Exhibit 4.1 to our Form 8-K filed July 23, 2003).
	10.A	Amended and Restated Credit Agreement dated as of November 23, 2004, among El Paso Corporation, ANR Pipeline Company, Colorado Interstate Gas Company, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the several banks and other financial institutions from time to time parties thereto and JPMorgan Chase Bank, N.A., as administrative agent and as collateral agent (Exhibit 10.A to our Form 8-K filed November 29, 2004); Amended and Restated Subsidiary Guarantee Agreement dated as of November 23, 2004, made by each of the Subsidiary Guarantors in favor of JPMorgan Chase Bank, N.A., as Collateral Agent (Exhibit 10.C to our Form 8-K filed November 29, 2004).
	10.B	Amended and Restated Security Agreement dated as of November 23, 2004, among El Paso Corporation, ANR Pipeline Company, Colorado Interstate Gas Company, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the Subsidiary Grantors and certain other credit parties thereto and JPMorgan Chase Bank, N.A., not in its individual capacity, but solely as collateral agent for the Secured Parties and as the depository bank (Exhibit 10.B to our Form 8-K filed November 29, 2004).

Exhibit
Number		Description
	10.C	Master Settlement Agreement dated as of June 24, 2003, by and between, on the one hand, El Paso Corporation, El Paso Natural Gas Company, and El Paso Merchant Energy, L.P.; and, on the other hand, the Attorney General of the State of California, the Governor of the State of California, the California Public Utilities Commission, the California Department of Water Resources, the California Energy Oversight Board, the Attorney General of the State of Washington, the Attorney General of the State of Oregon, the Attorney General of the State of Nevada, Pacific Gas & Electric Company, Southern California Edison Company, the City of Los Angeles, the City of Long Beach, and classes consisting of all individuals and entities in California that purchased natural gas and/or electricity for use and not for resale or generation of electricity for the purpose of resale, between September 1, 1996 and March 20, 2003, inclusive, represented by class representatives Continental Forge Company, Andrew Berg, Andrea Berg, Gerald J. Marcil, United Church Retirement Homes of Long Beach, Inc., doing business as Plymouth West, Long Beach Brethren Manor, Robert Lamond, Douglas Welch, Valerie Welch, William Patrick Bower, Thomas L. French, Frank Stella, Kathleen Stella, John Clement Molony, SierraPine, Ltd., John Frazee and Jennifer Frazee, John W.H.K. Phillip, and Cruz Bustamante (Exhibit 10.HH to our second quarter 2003 Form 10-Q).
	10.D	Joint Settlement Agreement submitted and entered into by El Paso Natural Gas Company, El Paso Merchant Energy Company, El Paso Merchant Energy-Gas, L.P., the Public Utilities Commission of the State of California, Pacific Gas & Electric Company, Southern California Edison Company and the City of Los Angeles (Exhibit 10.II to our 2003 second quarter Form 10-Q).
	21	Omitted pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
	*31.A	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	*31.B	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	*32.A	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	*32.B	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

EX-31.A

EXHIBIT 31.A

CERTIFICATION

I, James J. Cleary, certify that:

1. I have reviewed this Annual Report on Form 10-K of El Paso Natural Gas Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 3, 2006

/s/ James J. Cleary  

James J. Cleary 

Chairman of the Board and President
(Principal Executive Officer)
El Paso Natural Gas Company 

EX-31.B

EXHIBIT 31.B

CERTIFICATION

I, John R. Sult, certify that:

1. I have reviewed this Annual Report on Form 10-K of El Paso Natural Gas Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 3, 2006

/s/ John R. Sult  

John R. Sult 

Senior Vice President, Chief Financial Officer and Controller
(Principal Financial and Accounting Officer)
El Paso Natural Gas Company 

EX-32.A

EXHIBIT 32.A

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002

     In connection with the Annual Report on Form 10-K for the period ending December 31, 2005, of El Paso Natural Gas Company (the “Company”) as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, James J. Cleary, Chairman of the Board and President, certify (i) that the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ James J. Cleary  

James J. Cleary 

Chairman of the Board and President
(Principal Executive Officer)
El Paso Natural Gas Company

March 3, 2006 

A signed original of this written statement required by Section 906 has been provided to El Paso Natural Gas Company and will be retained by El Paso Natural Gas Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.B

EXHIBIT 32.B

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002

     In connection with the Annual Report on Form 10-K for the period ending December 31, 2005, of El Paso Natural Gas Company (the “Company”) as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John R. Sult, Senior Vice President, Chief Financial Officer and Controller, certify (i) that the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ John R. Sult  

John R. Sult 

Senior Vice President, Chief Financial Officer and Controller
(Principal Financial and Accounting Officer)
El Paso Natural Gas Company

March 3, 2006 

A signed original of this written statement required by Section 906 has been provided to El Paso Natural Gas Company and will be retained by El Paso Natural Gas Company and furnished to the Securities and Exchange Commission or its staff upon request.