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, 2007

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

For the transition period from                to               .

El Paso Natural Gas Company

(Exact Name of Registrant as Specified in Its Charter)

Delaware (State or Other Jurisdiction of Incorporation or Organization)		74-0608280 (I.R.S. Employer Identification No.)

El Paso Building
1001 Louisiana Street
Houston, Texas		77002
(Address of Principal Executive Offices)		(Zip Code)

     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 o No þ

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

Large Accelerated filer o		Accelerated filer o		Non-accelerated filer þ		Smaller reporting company o
		(Do not check if a smaller reporting company)

     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 February 27, 2008: 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.

 

 

EL PASO NATURAL GAS COMPANY

TABLE OF CONTENTS

		Caption		Page
PART I
Item 1.		Business		1
Item 1A.		Risk Factors		5
Item 1B.		Unresolved Staff Comments		11
Item 2.		Properties		11
Item 3.		Legal Proceedings		11
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		12
Item 6.		Selected Financial Data		*
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations		13
Item 7A.		Quantitative and Qualitative Disclosures About Market Risk		18
Item 8.		Financial Statements and Supplementary Data		19
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		43
Item 9A.		Controls and Procedures		43
Item 9A(T).		Controls and Procedures		43
Item 9B.		Other Information		43
PART III
Item 10.		Directors, Executive Officers and Corporate Governance		*
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, and Director Independence		*
Item 14.		Principal Accountant Fees and Services		44
PART IV
Item 15.		Exhibits and Financial Statement Schedules		45
		Signatures		46

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

/d	=	per day
BBtu	=	billion British thermal units
Bcf	=	billion cubic feet
LNG	=	liquefied natural gas
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.

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 and a storage facility 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 and other terms and conditions of services 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 strategy is to enhance the value of our transportation and storage business by:

	•		Developing new growth projects in our market and supply areas;
	•		Successfully recontracting expiring transportation capacity;
	•		Focusing on efficiency and synergies across our system;
	•		Ensuring the safety of our pipeline systems and assets; and
	•		Providing outstanding customer service.

     The EPNG System. The EPNG system consists of approximately 10,200 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 2007, 2006 and 2005, average throughput was 4,189 BBtu/d, 4,179 BBtu/d and 4,053 BBtu/d. This system delivers natural gas from the San Juan, Permian, Anadarko basins and the Rocky Mountains via interconnects to markets in California, Arizona, Nevada, New Mexico, Oklahoma, Texas and northern Mexico.

     The Mojave Pipeline Company (Mojave) System. The Mojave system consists of approximately 400 miles of pipeline with an east to west flow design capacity of approximately 400 MMcf/d. During 2007, 2006 and 2005, average throughput was 458 BBtu/d, 461 BBtu/d and 161 BBtu/d. Our 2007 and 2006 throughput includes 431 BBtu/d and 385 BBtu/d transported volume for the EPNG system. The Mojave 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.

     Storage Facility. Prior to 2006, we utilized our Washington Ranch underground storage facility located in New Mexico, which has up to approximately 44 Bcf of underground working natural gas storage capacity to manage our transportation needs. In 2006, we also began using this facility to offer interruptible storage services.

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 service in our natural gas supply and market areas and provide storage services in our supply 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. LNG 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 potential benefit is offset, in varying degrees, by increased generation efficiency, the more effective use of surplus electric capacity, increased natural gas prices and the use and availability of other fuel sources for power generation. 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 natural gas transportation contracts with us.

     We provide transportation services in the southwestern U.S. and to the Mexican border through connections to other pipelines. 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, our largest market, is approximately 8.5 Bcf/d and we provide approximately 39 percent of this capacity. In 2007, the demand for interstate pipeline capacity to California averaged 5.4 Bcf/d, equivalent to approximately 65 percent of the total interstate pipeline capacity serving that state. Natural gas shipped to California on our systems represented approximately 27 percent of the natural gas consumed in that state in 2007.

     Our existing transportation and storage 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 can discount these rates to remain competitive.

     The following table details information related to our pipeline system, including the customers, contracts and the competition we face on our pipeline systems as of December 31, 2007. Firm customers reserve capacity on our pipeline systems and storage facilities and are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts. Interruptible customers are customers without reserved capacity that pay usage charges based on the volume of gas they request to transport, store, inject or withdraw.

Pipeline
System		Customer Information		Contract Information		Competition
EPNG		Approximately 140 firm and interruptible customers.		Approximately 190 firm transportation contracts. Weighted average remaining contract term of approximately four years.		EPNG faces competition in the west and southwest from other existing and proposed pipelines, from California storage facilities, and from alternative energy sources that are used to generate electricity such as hydroelectric power, nuclear energy, wind, solar, coal and fuel oil. In addition, construction of facilities to bring LNG into California and northern Mexico are underway.
		Major Customers:
		Southern California Gas    Company (SoCal)
		(187 BBtu/d)		Expires in 2009.
		(246 BBtu/d)		Expires in 2010.
		(323 BBtu/d)		Expires in 2011.
		Southwest Gas    Corporation
		(11 BBtu/d)		Expires in 2008.
		(603 BBtu/d)		Expire in 2011—2015.
Mojave		Approximately 20 firm and interruptible customers		Approximately five firm transportation contracts. Weighted average remaining contract term of approximately eight years.		Mojave faces competition from other existing and proposed pipelines and alternative energy sources that are used to generate electricity such as hydroelectric power, nuclear energy, wind, solar, coal and fuel oil. In addition, construction of facilities to bring LNG into California and northern Mexico are underway.
		Major Customer:
		EPNG
		(312 BBtu/d)		Expires in 2015.

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, cost recovery mechanisms and other terms and conditions of service to our customers. Generally, the FERC’s authority extends to:

	•		rates and charges for natural gas transportation and storage;
	•		certification and construction of new facilities;
	•		extension or abandonment of services and facilities;
	•		maintenance of accounts and records;
	•		relationships between pipelines and certain affiliates;
	•		terms and conditions of service;
	•		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 safety and environmental statutes and regulations of the U.S. Department of Transportation and the U.S. Department of Interior. We have ongoing inspection programs designed to keep our facilities in compliance with pipeline safety and environmental requirements and we believe that our systems are in material compliance with the applicable regulations.

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, 2008, we had approximately 860 full-time employees, none of whom are subject to a collective bargaining arrangement.

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. These forward-looking statements are based on assumptions or beliefs that we believe to be reasonable; however, assumed facts almost always vary from actual results, and differences between assumed facts and actual results can be material, depending upon the circumstances. Where, based on assumptions, 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 stated expectation or belief will occur, be achieved or accomplished. The words “believe,” “expect,” “estimate,” “anticipate,” and similar expressions will generally identify forward-looking statements. All of our forward-looking statements, whether written or oral, are expressly qualified by these cautionary statements and any other cautionary statements that may accompany such forward-looking statements. In addition, we disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report.

     With this in mind, you should consider the risks discussed elsewhere in this report and other documents we file with the 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 and storage of natural gas for third parties. The results of our transportation and storage operations are impacted by the volumes of natural gas we transport or store and the prices we are able to charge for doing so. The volume of natural gas we are able to transport and store depends on the actions of those third parties and is beyond our control. Further, the following factors, most of which are also beyond our control, may unfavorably impact our ability to maintain or increase current throughput, or to remarket unsubscribed capacity on our pipeline systems.

	•		service area competition;
	•		expiration or turn back of significant contracts;
	•		changes in regulation and action of regulatory bodies;
	•		weather conditions that impact throughput and storage levels;
	•		price competition;
	•		drilling activity and decreased availability of conventional gas supply sources and the availability and timing of other natural gas supply sources, such as LNG;
	•		decreased natural gas demand due to various factors, including increases in prices and the availability or increased demand of alternative energy sources such as hydroelectric power, nuclear energy, wind, solar, coal and fuel oil;
	•		continued development of additional sources of gas supply that can be accessed;
	•		availability and cost of capital to fund ongoing maintenance and growth projects;
	•		opposition to energy infrastructure development, especially in environmentally sensitive areas;
	•		adverse general economic conditions including prolonged recessionary periods that might negatively impact natural gas demand and the capital markets;

	•		expiration or renewal of existing interests in real property including real property on Native American lands; and
	•		unfavorable movements in natural gas prices in certain supply and demand areas.

     Our revenues 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 and storage contracts which expire periodically and must be renegotiated, extended or replaced. If we are unable to extend or replace these contracts when they expire or renegotiate contract terms as favorable as the existing contracts, we could suffer a material reduction in our revenues, earnings and cash flows. For additional information on the expiration of our contract portfolio, see Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations. In particular, our ability to extend and replace contracts could be adversely affected by factors we cannot control, including:

	•		competition by other pipelines, including the change in rates or upstream supply of existing pipeline competitors, as well as the proposed construction by other companies of additional pipeline capacity or LNG terminals in markets served by our interstate pipelines;
	•		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 natural gas supply points; and
	•		regulatory actions.

     For additional information on our contracts with our major customers, see Part II, Item 8, Financial Statements and Supplementary Data, Note 8. The loss of any one of these customers or a decline in their creditworthiness could adversely affect our results of operations, financial position and cash flows.

Fluctuations in energy commodity prices could adversely affect our business.

     Revenues generated by our transportation and storage contracts depend on volumes and rates, both of which can be affected by the price of natural gas. Increased prices could result in a reduction of the volumes transported by our customers, including power companies that may not dispatch natural gas-fired power plants if natural gas prices increase. 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 and storage operations is subject to continued development of additional gas supplies to offset the natural decline from existing wells connected to our systems, which requires the development of additional oil and natural gas reserves and obtaining additional supplies from interconnecting pipelines. A decline in energy prices could cause a decrease in these development activities and could cause a decrease in the volume of reserves available for transmission and storage through our systems.

     We retain a fixed percentage of natural gas transported as provided in our tariff. This retained natural gas is used as fuel and to replace lost and unaccounted for natural gas. 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 and our long-term recontracting activities 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 countries producing oil and LNG.

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

     Our 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 whose actions 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 and sets authorized rates of return. The FERC uses a discounted cash flow model that incorporates the use of proxy groups to develop a range of reasonable returns earned on equity interests in companies with corresponding risks. The FERC then assigns a rate of return on equity within that range to reflect specific risks of that pipeline when compared to the proxy group companies. The FERC had been using a proxy group of companies that included local distribution companies that are not faced with as much competition or risk as interstate pipelines. The inclusion of these lower risk companies could have created downward pressure on tariff rates when subjected to review by the FERC in future rate proceedings. Recently, the U.S. Court of Appeals for the DC Circuit issued a decision that would require the FERC, if it utilizes lower risk companies in the proxy group, to make upward adjustments to the return on equity to compensate for their lower level of risk. Pursuant to the FERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. A successful complaint or protest against our rates could have an adverse impact on our revenues. In addition, in July 2007, the FERC issued a proposed policy statement addressing the issue of the proxy groups it will use to decide the return on equity of natural gas pipelines. The proposed policy statement describes the FERC’s intention to allow the use of master limited partnerships in proxy groups, which we and other pipelines have advocated. However, the FERC also proposed certain restrictions that would reduce the overall benefit that pipelines would receive by use of master limited partnerships in the proxy group.

     Also, 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 or clean up of contaminated properties (some of which have been designated as Superfund sites by the Environmental Protection Agency under the Comprehensive Environmental Response, Compensation and Liability Act ), as well as damage claims arising out of the contamination of properties or impact on natural resources. Although we believe we have established appropriate reserves for our environmental liabilities, it is not possible for us to estimate the exact amount and timing of all future expenditures related to environmental matters and we could be required to set aside additional amounts which could significantly impact our future consolidated results of operations, cash flows or financial position. See Part II, Item 8, Financial Statements and Supplementary Data, Note 6.

     In estimating our environmental liabilities, we face uncertainties that include:

	•		estimating pollution control and clean up costs, including sites where preliminary site investigation or assessments have been completed;
	•		discovering new sites or additional information at existing sites;
	•		quantifying liability under environmental laws that impose joint and several liability on all potentially responsible parties;
	•		evaluating and understanding environmental laws and regulations, including their interpretation and enforcement; and.
	•		changing environmental laws and regulations that may increase our costs.

     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 and various United States federal legislative proposals which have been made over the last several years. It is difficult to predict the timing of enactment of any federal legislation, as well as the ultimate legislation that will be enacted. However, components of the legislation that have been proposed in the past could negatively impact our operations and financial results, including whether any of our facilities are designated as the point of regulation for GHG emissions, whether the federal legislation will expressly preempt the potentially conflicting state GHG legislation and how inter-fuel issues will be handled, including how allowances are granted and whether caps will be imposed on GHG charges.

     Legislation and regulation are also in various stages of proposal, enactment, and implementation in many of the states in which we operate. This includes various initiatives of individual and coalitions of states, including seven western states that are members of the Western Climate Initiative.

     Additionally, various governmental entities and environmental groups have filed lawsuits seeking to force the federal government to regulate GHG emissions and individual companies to reduce the GHG emissions from their operations. These and other suits may also result in decisions by federal agencies, state courts and other agencies that impact our operations and our ability to obtain certifications and permits to construct future projects.

     These legislative, regulatory, and judicial actions could also result in changes to our operations and to the consumption and demand for natural gas. Changes to our operations could include increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities, (iii) construct new facilities, (iv) acquire allowances to authorize our GHG emissions, (v) pay any taxes related to our GHG emissions and (vi) administer and manage a GHG emissions program.

     While we may be able to include some or all of any costs in the rates charged by us such recovery of costs is uncertain and may depend on events beyond our control including the outcome of future rate proceedings before the FERC and the provisions of any final legislation.

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 (such as flooding), terrorist activity or acts of aggression, and other hazards. Each of these risks could result in damage to or destruction of our facilities or damages or injuries to persons and property causing us to suffer substantial losses.

     While we maintain insurance against many of these risks to the extent and in amounts that we believe are reasonable, our insurance coverages have material deductibles as well as limits on our maximum recovery, and do not cover all risks. As a result, our results of operations, cash flows or financial condition 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 or our storage facility by constructing additional facilities. Construction of these facilities is subject to various regulatory, development and operational risks, including:

	•		our ability to obtain necessary approvals and permits by the FERC and other regulatory agencies on a timely basis and on terms that are acceptable to us;
	•		the ability to obtain continued access to sufficient capital to fund expansion projects;
	•		the availability of skilled labor, equipment, and materials to complete expansion projects;
	•		potential changes in federal, state and local statutes, regulations and orders, including environmental requirements that prevent a project from proceeding or increase the anticipated cost of the project;
	•		impediments on our ability to acquire rights-of-way or land rights on a timely basis or on terms that are acceptable to us;
	•		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, labor, lack of contractor productivity, or other factors beyond our control, that we may not be able to recover from our customers which may be material;
	•		the lack of future growth in natural gas supply; and
	•		the lack of transportation, storage or throughput commitments.

     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 results of operations, cash flows or financial position.

Our business requires the retention and recruitment of a skilled workforce and the loss of employees could result in the failure to implement our business plan.

     Our business requires the retention and recruitment of a skilled workforce. If we are unable to retain and recruit employees such as engineers and other technical personnel, our business could be negatively impacted.

Adverse changes in general domestic economic conditions could adversely affect our operating results, financial condition, or liquidity.

     We, El Paso, and its subsidiaries are subject to the risks arising from adverse changes in general domestic economic conditions including recession or economic slowdown. Recently, the direction and relative strength of the U.S. economy has been increasingly uncertain due to softness in the housing markets, rising oil prices, and difficulties in the financial services sector. If economic growth in the United States is slowed, demand growth from consumers for natural gas transported by us may decrease which could impact our planned growth capital. Additionally, our access to capital could be impeded. Any of these events, which are beyond our control, could negatively impact our business, results of operations, financial condition, and liquidity.

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 included herein or 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 or its other subsidiaries 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 Ba3 by Moody’s Investor Service, BB- by Standard & Poor’s and BB+ by Fitch Ratings. The ratings assigned to our senior unsecured indebtedness are currently investment grade, rated Baa3 by Moody’s Investor Service, BB by Standard & Poor’s and investment grade with a BBB- rating by Fitch Ratings. We and El Paso are (i) on a positive outlook with Moody’s Investor Service and Standard & Poor’s and (ii) on a stable outlook with Fitch Ratings. Downgrades of our or El Paso’s credit ratings could increase our cost of capital and 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, we transfer surplus cash to El Paso in exchange for an affiliated note receivable. In addition, we conduct commercial transactions with some of our affiliates. If El Paso or such affiliates are unable to meet their respective liquidity needs, we may not be able to access cash under the cash management program, or our affiliates may not be able to pay their obligations to us. However, we might still be required to satisfy affiliated payables. Our inability to recover any affiliated receivables owed to us could adversely affect our financial position. For a further discussion of these matters, see Part II, Item 8, Financial Statements and Supplementary Data, Note 10.

We may be subject to a change of control if an event of default occurs under El Paso’s credit agreement.

     Under El Paso’s $1.5 billion credit agreement, our common stock and the common stock of one of El Paso’s other subsidiaries are pledged as collateral. As a result, our ownership is subject to change if there is a default under the credit agreement and El Paso’s lenders exercise rights over their collateral, even if we do not have any borrowings outstanding under the credit agreement. For additional information concerning El Paso’s credit facility, see Part II, Item 8, Financial Statements and Supplementary Data, Note 5.

A default under El Paso’s $1.5 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 $1.5 billion credit agreement. We are only liable, however, for our borrowings under the credit agreement, which were zero at December 31, 2007. Under the credit agreement, a default by El Paso, or any other borrower could result in the acceleration of repayment of all outstanding borrowings, including the borrowings of any non-defaulting party. The acceleration of repayments of 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 $1.5 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 wholly owned subsidiary of El Paso.

     As an indirect wholly owned subsidiary of El Paso, subject to limitations in our credit agreements and indentures, El Paso has substantial control over:

	•		our payment of dividends;
	•		decisions on our financing and 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

     We have not included a response to this item since no response is required under Item 1B of Form 10-K.

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 business, 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.

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

     Information 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 2007 or 2006.

ITEM 6. SELECTED FINANCIAL DATA

     Information has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

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 (MD&A) should be read in conjunction with our consolidated financial statements and the accompanying footnotes. MD&A includes forward-looking statements that are subject to risks and uncertainties that may result in actual results differing from the statements we make. These risks and uncertainties are discussed further in Part I, Item 1A, Risk Factors.

Overview

     Our business primarily consists of interstate transportation and storage of natural gas. Each of these businesses faces varying degrees of competition from other existing and proposed pipelines and LNG facilities, as well as from alternative energy sources used to generate electricity, such as hydroelectric power, nuclear energy, wind, coal and fuel oil. Our revenues from transportation and storage services consist of the following types.

				Percent of Total
Type		Description		Revenues in 2007
Reservation		Reservation revenues are from customers (referred to as firm customers) that reserve capacity on our pipeline systems and storage facility. These firm customers are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts.			86
Usage and Other		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, stored, injected or withdrawn. We also earn revenue from other miscellaneous sources.			14

     The FERC regulates the rates we can charge our customers. These rates are generally a function of the cost of providing services to our customers, including a reasonable return on our invested capital. 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, market conditions, regulatory actions, competition, declines in the creditworthiness of our customers and weather. On January 1, 2006, we adopted a fuel tracker on our EPNG system 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. The fuel tracker reduced the financial impacts of our operational gas costs.

     We continue to manage our recontracting process to limit the risk of significant impacts on our revenues from expiring contracts. 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, we can discount these rates to remain competitive. Our existing contracts mature at various times and in varying amounts of throughput capacity. The weighted average remaining contract term for active contracts is approximately four years as of December 31, 2007.

     Listed below are the expiration of our contract portfolio and the associated revenue expirations for our firm transportation contracts as of December 31, 2007, including those with terms beginning in 2008 or later.

						Percent of Total								Percent of Total
		BBtu/d (1)				Contracted Capacity				Reservation Revenue				Reservation Revenue
										(In millions)
2008			1,112				19			$	18				4
2009			1,142				19				93				20
2010			562				10				58				13
2011			1,301				22				67				15
2012			637				11				84				18
2013 and beyond			1,085				19				139				30
Total			5,839				100			$	459				100

Results of Operations

     Our management uses earnings before interest expense and income taxes (EBIT) to assess the operating results and effectiveness of our business. We believe EBIT is useful to our investors because it allows them to more effectively evaluate our operating performance using the same performance measure analyzed internally by our management. We define EBIT as net income adjusted for (i) items that do not impact our income from continuing operations, (ii) income taxes, (iii) interest and debt expense and (iv) affiliated interest income. We exclude interest and debt expense from this measure so that investors may evaluate our operating results without regard to our financing methods. 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. Below is a reconciliation of our EBIT to net income, our throughput volumes and an analysis and discussion of our results for the year ended December 31, 2007 compared with 2006.

Operating Results:

		2007				2006
		(In millions,
		except volumes)
Operating revenues		$	557			$	588
Operating expenses			(319	)			(305	)
Operating income			238				283
Other income, net			4				3
EBIT			242				286
Interest and debt expense			(98	)			(95	)
Affiliated interest income, net			71				53
Income taxes			(83	)			(92	)
Net income		$	132			$	152
Throughput volumes (BBtu/d)(1)			4,216				4,255

EBIT Analysis:

														EBIT
		Revenue				Expense				Other				Impact
		Favorable/(Unfavorable)
		(In millions)
Reservation and other services revenues		$	(20	)		$	—			$	—			$	(20	)
Enron bankruptcy settlement			(10	)			(2	)			—				(12	)
Depreciation and amortization expense			—				10				—				10
Operating and general and administrative expenses			—				(10	)			—				(10	)
Impairment of East Valley Line lateral			—				(9	)			—				(9	)
Other(1)			(1	)			(3	)			1				(3	)
Total impact on EBIT		$	(31	)		$	(14	)		$	1			$	(44	)

     Reservation and Other Services Revenues. 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. Our reservation and other services revenues were lower for the year ended December 31, 2007 compared to 2006, primarily as a result of lower reservation revenues on our Mojave system due to a decrease in tariff rates under our rate case settlement and the expiration of certain firm contracts, both effective March 1, 2007. Capacity expiring on the EPNG system in 2006, was resold generally at lower rates. Our completed rate proceedings are further discussed below and in Item 8, Financial Statements and Supplementary Data, Note 6.

	•		EPNG — In August 2007, EPNG received approval of the settlement of its rate case from the FERC and began billing the settlement rates on October 1, 2007. The settlement provides benefits for both EPNG and its customers for a three year period ending December 31, 2008. Under the terms of the settlement, EPNG is required to file a new rate case to be effective January 1, 2009. In 2007 and 2006, EPNG recorded rate refund provisions of approximately $60 million and $65 million, inclusive of interest. In the fourth quarter of 2007, EPNG refunded $115 million including interest in rate refunds to its customers and refunded the remaining $10 million in January 2008.
	•		Mojave — In February 2007, as required by its prior rate case settlement, Mojave filed with the FERC a general rate case proposing a 33 percent decrease in its base tariff rates resulting from a variety of factors, including a decline in rate base and various changes in rate design since the last rate case. No new services were proposed. The new base rates were effective March 1, 2007. Mojave filed an offer of settlement to resolve all issues in the rate case in October 2007 and received FERC approval of this settlement in December 2007. Under the terms of this settlement, we have refund obligations of $4 million that will be paid in the first quarter of 2008 for a previously accrued regulatory obligation. Other refund obligations to third parties are minimal .

     Enron Bankruptcy Settlement. During 2007 and 2006, we recorded income of approximately $5 million and $17 million, net of amounts owed to certain customers as a result of the Enron bankruptcy settlement.

     Depreciation and Amortization Expense. During the year ended December 31, 2007, our depreciation and amortization expense was lower primarily as a result of changes to depreciation and amortization rates implemented in our Mojave and EPNG rate cases.

     Operating and General and Administrative Expenses. During the year ended December 31, 2007, our operating, general, and administrative expenses increased primarily as a result of higher repair and maintenance costs.

     Impairment of East Valley Line Lateral. During the fourth quarter of 2007, we recorded an impairment of approximately $9 million pursuant to a FERC order on our accounting treatment for the planned sale of certain transmission facilities. We sought a rehearing of the FERC’s determination, which the FERC denied in February 2008. We are evaluating the possibility of seeking appellate review of the FERC’s order on the rehearing.

Interest and Debt Expense

     Interest and debt expense for the year ended December 31, 2007, was $3 million higher than in 2006 primarily due to interest recorded in 2007 for EPNG’s rate refund provision, partially offset by lower average interest rates on outstanding debt.

Affiliated Interest Income, Net

     Affiliated interest income, net for the year ended December 31, 2007, was $18 million higher than in 2006 due to higher average short-term interest rates and higher average advances to El Paso under its cash management program. The average short-term interest rate increased from 5.7% in 2006 to 6.2% in 2007. In addition, the average advances due from El Paso of $947 million in 2006 increased to $1.2 billion in 2007.

Income Taxes

     Our effective tax rate of 39 percent and 38 percent for the years ended December 31, 2007 and 2006 was higher than the statutory rate of 35 percent in both periods primarily due to the effect of state income taxes. For a reconciliation of the statutory rate to the effective tax 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 and depending on whether we have short-term cash surpluses or requirements, we either advance cash to El Paso or El Paso advances cash to us in exchange for an affiliated note receivable or payable that is due upon demand. We have historically advanced cash to El Paso, which we reflect in investing activities in our statement of cash flows. At December 31, 2007, we had a note receivable from El Paso of approximately $1.1 billion. We do not intend to settle this note within the next twelve months and therefore have classified it as non-current on our balance sheet. In 2007, we settled with El Paso certain tax attributes previously reflected as deferred income taxes in our financial statements for $40 million. This settlement is reflected as operating activities in our statement of cash flows. See Item 8, Financial Statements and Supplementary Data, Note 10, for a further discussion of El Paso’s cash management program.

     In addition to the cash management program, in November 2007, El Paso entered into a $1.5 billion credit agreement, which amended and restated its existing $1.75 billion credit agreement. We continue to be an eligible borrower under El Paso’s $1.5 billion credit agreement and are only liable for amounts we directly borrow. As of December 31, 2007, El Paso had approximately $0.3 billion of letters of credit issued and $0.4 billion of debt outstanding under this facility, none of which was issued or borrowed by us. For a further discussion of this credit agreement, see Item 8, Financial Statements and Supplementary Data, Note 5.

     We believe that cash flows from operating activities combined with amounts available to us under El Paso’s cash management program and its credit agreement, if necessary, will be adequate to meet our capital requirements and our existing operating needs.

     Credit Profile. In March 2007, Moody’s Investor Services upgraded our senior unsecured debt rating to an investment grade rating of Baa3 and upgraded El Paso’s senior unsecured debt rating to Ba3 while maintaining a positive outlook. Additionally, in March 2007, (i) Standard and Poor’s upgraded our senior unsecured debt ratings to BB and upgraded El Paso’s senior unsecured debt rating to BB-, maintaining a positive outlook and (ii) Fitch Ratings initiated coverage on us and assigned an investment grade rating of BBB- on our senior unsecured debt and a rating of BB+ on El Paso’s senior unsecured debt. Our ratings affect the cost of capital that is available in third party markets, generally allowing for a lower cost of capital relative to non-investment grade companies.

     Additionally, in April 2007, we were able to reduce our average cost of debt by issuing $355 million of 5.95% senior notes due in April 2017 and using a portion of the net proceeds to repurchase approximately $301 million of 7.625% notes due in August 2010.

     Capital Expenditures. Our capital expenditures for the years ended December 31 were as follows:

		2007				2006
		(In millions)
Maintenance		$	99			$	94
Expansion/Other			21				49
Total		$	120			$	143

     Under our current plan, we have budgeted to spend approximately $150 million in 2008 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. In addition, we have budgeted to spend approximately $70 million in 2008 to expand the capacity and services of our pipeline and storage systems. We expect to fund our capital expenditures through a combination of internally generated funds and, if necessary, repayments by El Paso of amounts we advanced under its cash management program.

Commitments and Contingencies

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

New Accounting Pronouncements Issued But Not Yet Adopted

     See Item 8, Financial Statements and Supplementary Data, Note 1, under New Accounting Pronouncements Issued But Not Yet Adopted, which is incorporated herein by reference.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     Our primary market risk is exposure to changing interest rates. At December 31, 2007, we had a note receivable from El Paso of approximately $1.1 billion, with a variable interest rate of 6.5% that is due upon demand. While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of this note receivable approximates its carrying value due to the market-based nature of its interest rate. The table below shows the carrying value and related weighted average effective interest rates of our non-affiliated interest bearing securities by expected maturity dates and the fair value of those securities. At December 31, 2007, 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, 2007
		Expected Fiscal Year of Maturity of
		Carrying Amounts																December 31, 2006
														Fair				Carrying				Fair
		2010				Thereafter				Total				Value				Amount				Value
		(In millions, except for rates)
Liabilities:
Long-term debt — fixed rate		$	53			$	1,113			$	1,166			$	1,309			$	1,111			$	1,273
Average effective interest rate			5.1	%			7.5	%

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

     Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined by SEC rules adopted under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. It consists of policies and procedures that:

	•		Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
	•		Provide reasonable assurance that transactions are recorded as necessary to permit preparation of the financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and
	•		Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

     Under the supervision and with the participation of management, including the President and Chief Financial Officer, we made an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2007. In making this assessment, we used the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our evaluation, we concluded that our internal control over financial reporting was effective as of December 31, 2007.

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholder of El Paso Natural Gas Company:

We have audited the accompanying consolidated balance sheets of El Paso Natural Gas Company (the Company) as of December 31, 2007 and 2006, and the related consolidated statements of income, stockholder’s equity, and cash flows for each of the two years in the period ended December 31, 2007. Our audits also included the financial statement schedule listed in the Index at Item 15(a) for each of the two years in the period ended December 31, 2007. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits 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. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also 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.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of El Paso Natural Gas Company at December 31, 2007 and 2006, and the consolidated results of its operations and its cash flows for each of the two years in the period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, effective January 1, 2007, the Company adopted the provisions of Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes an interpretation of FASB Statement No. 109; effective December 31, 2006, the Company adopted the recognition provisions of Statement of Financial Accounting Standards No. 158, Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans — An Amendment of FASB Statements No. 87, 88, 106, and 132 (R); and effective December 1, 2005, the Company adopted the Federal Energy Regulatory Commission’s accounting release related to pipeline assessment costs.

Houston, Texas
February 25, 2008

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 statements of income, stockholder’s equity and cash flows for the year ended December 31, 2005 listed in the Index appearing under Item 15(a) (1), present fairly, in all material respects, the results of operations and cash flows of El Paso Natural Gas Company and its subsidiaries (the “Company”) for the year 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 for the year ended December 31, 2005 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 audit. We conducted our audit 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 audit provides a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas
February 28, 2006

EL PASO NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(In millions)

		Year Ended December 31,
		2007				2006				2005
Operating revenues		$	557			$	588			$	497
Operating expenses
Operation and maintenance			210				183				232
Depreciation and amortization			82				92				74
Taxes, other than income taxes			27				30				29
			319				305				335
Operating income			238				283				162
Other income, net			4				3				8
Interest and debt expense			(98	)			(95	)			(92	)
Affiliated interest income, net			71				53				32
Income before income taxes			215				244				110
Income taxes			83				92				46
Net income		$	132			$	152			$	64

See accompanying notes.

EL PASO NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
(In millions, except share amounts)

		December 31,
		2007				2006
ASSETS
Current assets
Cash and cash equivalents		$	—			$	—
Accounts and notes receivable
Customer, net of allowance of $4 in 2007 and $5 in 2006			73				81
Affiliates			6				5
Other			1				—
Materials and supplies			41				40
Deferred income taxes			7				42
Other			7				6
Total current assets			135				174
Property, plant and equipment, at cost			3,710				3,557
Less accumulated depreciation and amortization			1,298				1,251
Total property, plant and equipment, net			2,412				2,306
Other assets
Note receivable from affiliate			1,113				1,070
Other			133				81
			1,246				1,151
Total assets		$	3,793			$	3,631
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
Accounts payable
Trade		$	101			$	59
Affiliates			17				17
Other			33				9
Taxes payable			56				87
Accrued interest			20				27
Accrued liabilities			20				84
Regulatory liabilities			19				3
Other			13				18
Total current liabilities			279				304
Long-term debt			1,166				1,111
Other liabilities
Deferred income taxes			370				405
Other			116				85
			486				490
Commitments and contingencies (Note 6)
Stockholder’s equity
Common stock, par value $1 per share; 1,000 shares authorized, issued and outstanding			—				—
Additional paid-in capital			1,268				1,268
Retained earnings			594				462
Accumulated other comprehensive loss			—				(4	)
Total stockholder’s equity			1,862				1,726
Total liabilities and stockholder’s equity		$	3,793			$	3,631

See accompanying notes.

EL PASO NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)

		Year Ended December 31,
		2007				2006				2005
Cash flows from operating activities
Net income		$	132			$	152			$	64
Adjustments to reconcile net income to net cash from operating activities
Depreciation and amortization			82				92				74
Deferred income taxes			37				15				7
Other non-cash income items			8				(1	)			—
Asset and liability changes
Accounts receivable			9				35				(34	)
Accounts payable			65				(17	)			41
Taxes receivable			—				—				102
Taxes payable			(27	)			55				16
Other current assets			(5	)			—				16
Other current liabilities			(88	)			38				21
Non-current assets			(57	)			(30	)			(8	)
Non-current liabilities			(31	)			(17	)			5
Net cash provided by operating activities			125				322				304
Cash flows from investing activities
Additions to property, plant and equipment			(120	)			(143	)			(141	)
Net change in notes receivable from affiliate			(43	)			(198	)			(142	)
Net change in restricted cash			—				17				(17	)
Other			2				2				2
Net cash used in investing activities			(161	)			(322	)			(298	)
Cash flows from financing activities
Net proceeds from issuance of long-term debt			350				—				—
Payments to retire long-term debt			(314	)			—				(7	)
Net cash provided by (used in) financing activities			36				—				(7	)
Net change in cash and cash equivalents			—				—				(1	)
Cash and cash equivalents
Beginning of period			—				—				1
End of period		$	—			$	—			$	—

See accompanying notes.

EL PASO NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY
(In millions, except share amounts)

																		Accumulated
										Additional								other				Total
		Common stock								paid-in				Retained				comprehensive				stockholder’s
		Shares				Amount				capital				earnings				loss				equity
January 1, 2005			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
Net income															152								152
Adoption of SFAS No. 158, net of income taxes of $3																			(4	)			(4	)
December 31, 2006			1,000				—				1,268				462				(4	)			1,726
Net income															132								132
Reclassification to regulatory asset (See Note 7)																			4				4
December 31, 2007			1,000			$	—			$	1,268			$	594			$	—			$	1,862

See accompanying notes.

EL PASO NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

     Basis of Presentation and Principles of Consolidation

     We are a Delaware corporation incorporated in 1928, and an indirect wholly owned subsidiary of El Paso Corporation (El Paso). Our consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles (GAAP) and include the accounts of all majority owned and controlled subsidiaries after the elimination of 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.

     Use of Estimates

     The preparation of our financial statements 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 pipelines and storage operations are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. We follow the regulatory accounting principles prescribed under Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. Under SFAS No. 71, we record regulatory assets and liabilities that would not be recorded under GAAP for non-regulated entities. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate making process. Items to which we apply regulatory accounting requirements include certain postretirement employee benefit plan costs, 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.

     Allowance for Doubtful Accounts

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

     Materials and Supplies

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

     Natural Gas Imbalances

     Natural gas imbalances occur when the actual amount of natural gas delivered from or received by a pipeline system or storage facility differs from the contractual amount delivered or received. We value these imbalances due to or from shippers and operators utilizing current index prices. Imbalances are settled in cash or 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 on the balance sheet as either trade accounts payable or accounts payable to affiliates. 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 the fair value of the assets acquired. For assets we construct, we capitalize direct costs, such as labor and materials, and indirect costs, such as overhead, interest and an equity return component, as allowed by the FERC. We capitalize major units of property replacements or improvements and expense minor items. Prior to December 1, 2005, we capitalized certain costs incurred related to our pipeline integrity programs as part of our property, plant and equipment. Beginning December 1, 2005, we began expensing these costs based on a FERC accounting release. During the year ended December 31, 2007 and 2006, we expensed approximately $6 million and $5 million as a result of the adoption of this accounting release.

     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 certain general plant and rights-of-way, we depreciate the asset to zero. The majority of our property, plant and equipment are on our EPNG system which has depreciation rates ranging from one to 20 percent and the depreciable lives ranging from five to 92 years consistent with our rate settlements with the FERC. The depreciation rates on our Mojave Pipeline Company (Mojave) system range from two to 33 percent per year. We re-evaluate depreciation rates each time we file with the FERC for a change in our transportation and storage rates.

     When we retire property, plant and equipment, we charge accumulated depreciation and amortization for the original cost of the assets in addition to the cost to remove, sell or dispose of the assets, less their 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 balances are additional acquisition costs of $152 million which represent the excess of allocated purchase costs over the historical costs of the 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, 2007 and 2006, we had unamortized additional acquisition costs of $60 million and $63 million.

     At December 31, 2007 and 2006, we had $98 million and $89 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 debt and equity funds related to 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. Interest costs on debt amounts capitalized during the years ended December 31, 2007, 2006 and 2005 were $1 million, $1 million and $3 million. These debt amounts are included as a reduction to interest and debt expense on 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 (exclusive of any tax related impacts) during the years ended December 31, 2007, 2006 and 2005, were $2 million, $2 million and $5 million. These equity amounts are included as other non-operating income on our income statement.

     Asset Impairments

     We evaluate assets for impairment when events or circumstances indicate that their carrying values may not be recovered. These events include market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived 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 long-lived assets’ carrying values based on the long-lived asset’s 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 the asset downward, if necessary, to their estimated fair value. 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 impairment is impacted by a number of factors, including the nature of the assets being sold and our established time frame for completing the sale, among other factors.

     During the fourth quarter of 2007, we recorded an impairment of approximately $9 million pursuant to a FERC order on our accounting treatment for the planned sale of certain transmission facilities. We sought a rehearing of the FERC’s determination, which the FERC denied in February 2008. We are evaluating the possibility of seeking appellate review of the FERC’s order on the rehearing.

     Revenue Recognition

     Our revenues are primarily generated from natural gas transportation and storage services. Revenues for all services are based on the thermal quantity of gas delivered or subscribed at a price specified in the contract. For our transportation and storage services, we recognize reservation revenues on firm contracted capacity over the contract period regardless of the amount of natural gas that is transported or stored. For interruptible or volumetric-based services, we record revenues when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage facility. 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. Prior to January 1, 2006, we recognized revenue on gas not used in operations on our EPNG system when the volumes were retained under our tariff. Effective January 1, 2006, we adopted a fuel tracker with a true-up mechanism for amounts over or under retained. We are subject to FERC regulations and, as a result, revenues we collect may be subject to refund in a rate proceeding. We establish reserves for these potential refunds.

     Environmental Costs and Other Contingencies

     Environmental Costs. We record liabilities at their undiscounted amounts on our balance sheet as other current and long-term liabilities when 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 Environmental Protection Agency 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 charge in operation and maintenance expense when clean-up efforts do not benefit future periods.

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

     Other Contingencies. We recognize liabilities for other contingencies when we have an exposure that, when fully analyzed, indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the low end of the range is accrued.

     Income Taxes

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

     Pursuant to El Paso’s policy, we record current income taxes based on our taxable income and we provide for deferred income taxes to reflect estimated future tax payments and 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.

     Effective January 1, 2007, we adopted the provisions of Financial Accounting Standards Board (FASB) Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109. FIN No. 48 clarifies SFAS No. 109, Accounting for Income Taxes , and requires us to evaluate our tax positions for all jurisdictions and for all years where the statute of limitations has not expired. FIN No. 48 requires companies to meet a more-likely-than-not threshold (i.e. a greater than 50 percent likelihood of a tax position being sustained under examination) prior to recording a benefit for their tax positions. Additionally, for tax positions meeting this more-likely-than-not threshold, the amount of benefit is limited to the largest benefit that has a greater than 50 percent probability of being realized upon effective settlement. The adoption of FIN No. 48 did not have a material impact on our financial statements.

     Accounting for Asset Retirement Obligations

     We account for our asset retirement obligations in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations and FIN No. 47, Accounting for Conditional Asset Retirement Obligations. We record a liability for legal obligations associated with the replacement, removal or retirement of our long-lived assets. Our asset retirement liabilities are recorded at their estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the long-lived asset to which that liability relates. An ongoing expense is also recognized for changes in the value of the liability as a result of the passage of time, which we record as depreciation and amortization expense in our income statement. We have the ability to recover certain of these costs from our customers and have recorded an asset (rather than expense) associated with the depreciation of the property, plant and equipment and accretion of the liabilities described above.

     We have legal obligations associated with our natural gas pipeline 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 pipeline if it is abandoned. We also have obligations to remove hazardous materials associated with our natural gas transmission facilities if they are replaced. We accrue a liability for legal obligations based on an estimate of the timing and amount of their settlement.

     We are required to operate and maintain our natural gas pipeline and storage systems, and intend to do so as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, we believe that the substantial majority of our natural gas pipelines and storage system assets have indeterminate lives. Accordingly, our asset retirement liabilities as of December 31, 2007 and 2006, were not material to our financial statements. We continue to evaluate our asset retirement obligations and future developments could impact the amounts we record.

     Postretirement Benefits

     We maintain a postretirement benefit plan covering certain of our former employees. This plan requires us to make contributions to fund the benefits to be paid out under the plan. These contributions are invested until the benefits are paid out to plan participants. We record net benefit cost related to this plan in our income statement. This net benefit cost is a function of many factors including benefits earned during the year by plan participants (which is a function of the level of benefits provided under the plan, actuarial assumptions and the passage of time), expected returns on plan assets and amortization of certain deferred gains and losses. For a further discussion of our policies with respect to our postretirement plan, see Note 7.

     We use the recognition provisions of SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an Amendment of FASB Statements No. 87, 88, 106, and 132(R) to account for our plan. Under SFAS No. 158, we record an asset or liability for our postretirement benefit plan based on its overfunded or underfunded status. Any deferred amounts related to unrealized gains and losses or changes in actuarial assumptions are recorded either as a regulatory asset or liability. For a further discussion of our application of SFAS No. 158, see Note 7.

     New Accounting Pronouncements Issued But Not Yet Adopted

     As of December 31, 2007, the following accounting standards had not yet been adopted by us.

     Fair Value Measurements. In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements, which provides guidance on measuring the fair value of assets and liabilities in the financial statements. We will adopt the provisions of this standard for our financial assets and liabilities effective January 1, 2008. Adoption of the standard is not expected to have a material impact on our financial statements. The FASB provided a one year deferral of the adoption of SFAS No. 157 for certain non-financial assets and liabilities. We have elected to defer the adoption of the standard for certain of our non-financial asset and liabilities and are currently evaluating the impact, if any, that the deferred provisions of the standard will have on our financial statements.

     Measurement Date of Postretirement Benefits. In December 2006, we adopted the recognition provisions of SFAS No. 158. Beginning in 2008, this standard will also require us to change the measurement date of our postretirement benefit plan from September 30, the date we currently use, to December 31. Adoption of the measurement date provisions of this standard is not expected to have a material impact on our financial statements.

     Fair Value Option. In February 2007, the FASB issued SFAS No. 159, Fair Value Option for Financial Assets and Financial Liabilities — including an Amendment to FASB Statement No. 115, Accounting for Certain Investments in Debt and Equity Securities, which permits entities to choose to measure many financial instruments and certain other items at fair value. We will adopt the provisions of this standard effective January 1, 2008, and do not anticipate that it will have a material impact on our financial statements.

     Business Combinations. In December 2007, the FASB issued SFAS No. 141(R), Business Combinations, which provides revised guidance on the accounting for acquisitions of businesses. This standard changes the current guidance to require that all acquired assets, liabilities, minority interest and certain contingencies be measured at fair

value, and certain other acquisition-related costs be expensed rather than capitalized. SFAS No. 141(R) will apply to acquisitions that are effective after December 31, 2008, and application of the standard to acquisitions prior to that date is not permitted.

     Noncontrolling Interests. In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, which provides guidance on the presentation of minority interests in the financial statements. This standard requires that minority interest be presented as a component of equity rather than as a “mezzanine” item between liabilities and equity, and also requires that minority interest be presented as a separate caption in the income statement. This standard also requires all transactions with minority interest holders, including the issuance and repurchase of minority interests, be accounted for as equity transactions unless a change in control of the subsidiary occurs. SFAS No. 160 is effective for fiscal years beginning after December 15, 2008, and we are evaluating the impact that this standard will have on our financial statements.

2. Income Taxes

     El Paso files consolidated U.S. federal and certain state tax returns which include our taxable income. In certain states, we file and pay taxes directly to the state taxing authorities. With a few exceptions, we and El Paso are no longer subject to U.S. federal, state and local income tax examinations by tax authorities for years before 1999. Additionally, the Internal Revenue Service has completed an examination of El Paso’s U.S. income tax returns for 2003 and 2004, with a tentative settlement at the appellate level for all issues. For our open tax years, we have no unrecognized tax benefits (liabilities for uncertain tax matters).

     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:

		2007				2006				2005
		(In millions)
Current
Federal		$	40			$	66			$	35
State			6				11				4
			46				77				39
Deferred
Federal			32				13				5
State			5				2				2
			37				15				7
Total income taxes		$	83			$	92			$	46

     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:

		2007				2006				2005
		(In millions, except for rates)
Income taxes at the statutory federal rate of 35%		$	75			$	85			$	39
Increase (decrease)
State income taxes, net of federal income tax effect			7				8				4
Non-deductible expenses			1				—				3
Other			—				(1	)			—
Income taxes		$	83			$	92			$	46
Effective tax rate			39	%			38	%			42	%

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

		2007				2006
		(In millions)
Deferred tax liabilities
Property, plant and equipment		$	462			$	448
Regulatory and other assets			29				61
Total deferred tax liability			491				509
Deferred tax assets
U.S. net operating loss and tax credit carryovers			80				80
Other liabilities			48				66
Total deferred tax asset			128				146
Net deferred tax liability		$	363			$	363

     Tax Credits and Carryovers. As of December 31, 2007, we had approximately $18 million of alternative minimum tax credits that carryover indefinitely. We also have approximately $178 million of net operating loss carryovers that expire between 2021 and 2026. Usage of our 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.

3. Financial Instruments

     At December 31, 2007 and 2006, the carrying amounts of cash and cash equivalents and trade receivables and payables are representative of their fair value because of the short-term maturity of these instruments. The fair value of our note receivable from affiliate approximates its carrying value due to the market-based nature of its interest rate. The carrying amounts and estimated fair values of our long-term debt are based on quoted market prices for the same or similar issues and are as follows at December 31:

		2007								2006
		Carrying								Carrying
		Amount				Fair Value				Amount				Fair Value
		(In millions)
Long-term debt		$	1,166			$	1,309			$	1,111			$	1,273

4. Regulatory Assets and Liabilities

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

		2007				2006
		(In millions)
Non-current regulatory assets
Taxes on capitalized funds used during construction		$	21			$	20
Unamortized loss on reacquired debt			30				16
Postretirement benefits			8				9
Deferred fuel variance			6				6
Under-collected state income taxes			6				3
Other			3				4
Total non-current regulatory assets		$	74			$	58
Current regulatory liabilities
Property and plant depreciation		$	10			$	—
Other			9				3
			19				3
Non-current regulatory liabilities
Property and plant depreciation			47				47
Imbalance cashouts			8				4
Postretirement benefits			29				—
Excess deferred federal income taxes			2				2
Total regulatory liabilities		$	105			$	56

5. Debt and Credit Facilities

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

		2007				2006
		(In millions)
7.625% Notes due August 2010		$	54			$	355
5.95% Notes due April 2017			355				—
8.625% Debentures due January 2022			260				260
7.50% Debentures due November 2026			200				200
8.375% Notes due June 2032			300				300
			1,169				1,115
Less: Unamortized discount			3				4
Total long-term debt		$	1,166			$	1,111

     In April 2007, we issued $355 million of 5.95% senior notes using a portion of the net proceeds to repurchase approximately $301 million of our 7.625% notes.

     Credit Facilities. In November 2007, El Paso entered into a $1.5 billion credit agreement, which amended and restated its existing $1.75 billion credit agreement. We continue to be an eligible borrower under the $1.5 billion credit agreement and are only liable for amounts we directly borrow. As of December 31, 2007, El Paso had approximately $0.3 billion of letters of credit issued and $0.4 billion of debt outstanding under this facility, none of which was issued or borrowed by us. Our common stock and the common stock of another El Paso subsidiary are pledged as collateral under the credit agreement.

     Under El Paso’s $1.5 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), 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; and (vi) potential limitations on our ability to participate in the El Paso’s cash management program. Our long-term debt contains cross-acceleration provisions, the most restrictive of which is a $25 million cross-acceleration clause. For the year ended December 31, 2007, we were in compliance with our debt-related covenants.

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 the 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. The trial court twice dismissed the lawsuit. The U.S. Court of Appeals for the Ninth Circuit, however, reversed the dismissal and remanded the matter to the trial court. The defendants have filed a petition to request that the case be heard by the U.S. Supreme Court, and have also reasserted with the trial court, motions to dismiss on other grounds. Our costs and legal exposure related to this lawsuit are not currently determinable.

     Baldonado et al. v. EPNG. 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 2003, a lawsuit entitled Baldonado et al. v. EPNG was filed in state court in Eddy County, New Mexico, on behalf of 26 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 was appealed to the New Mexico Court of Appeals. In June 2006, the New Mexico Court of Appeals affirmed the dismissal of the plaintiff’s claims for negligent infliction of emotional distress, but reversed the dismissal of the claims for intentional infliction of emotional distress. In December 2007, the New Mexico Supreme Court issued an opinion which ruled that a trial on the merits could proceed on either the grounds of intentional or reckless infliction of emotional distress. EPNG moved to reconsider the decision and in January 2008, removed the case to federal court on the basis of the federal question created by the New Mexico Supreme Court’s decision. The plaintiffs have made a motion to remand this matter which, if successful, would move it back to state court. Our costs and legal exposure related to this lawsuit are currently not determinable; however, we believe this matter will be fully covered by insurance.

     Gas Measurement Cases. We and a number of our affiliates were named defendants in actions that generally allege mismeasurement of natural gas volumes and/or heating content resulting in the underpayment of royalties. The first set of cases was filed in 1997 by an individual under the False Claims Act, which have been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District of Wyoming). 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. In October 2006, the U.S. District Judge issued an order dismissing all claims against all defendants. An appeal has been filed.

     Similar allegations were filed in a second set of actions initiated in 1999 in Will Price, et al. v. Gas Pipelines and Their Predecessors, et al., in the District Court of Stevens County, Kansas. The plaintiffs currently seek certification of a class of royalty owners in wells on non-federal and non-Native American lands in Kansas, Wyoming and Colorado. Motions for class certification have been briefed and argued in the proceedings and the parties are awaiting the court’s ruling. The plaintiff seeks an unspecified amount of monetary damages in the form of additional royalty payments (along with interest, expenses and punitive damages) and injunctive relief with regard to future gas measurement practices. Our costs and legal exposure related to these lawsuits and claim are not currently determinable.

     Bank of America. We are a named defendant, along with Burlington Resources, Inc. (Burlington), now a subsidiary of ConocoPhillips, in a class action lawsuit styled Bank of America, et al. v. El Paso Natural Gas and Burlington Resources Oil and Gas Company, L.P., filed in October 2003 in the District Court of Kiowa County, Oklahoma asserting royalty underpayment claims related to specified shallow wells in Oklahoma, Texas and New Mexico. The Plaintiffs assert that royalties were underpaid starting in the 1980s when the purchase price of gas was lowered below the Natural Gas Policy Act maximum lawful prices. The Plaintiffs assert that royalties were further underpaid by Burlington as a result of post-production cost deductions taken starting in the late 1990s. This action was transferred to Washita County District Court in 2004. A tentative settlement reached in November 2005 was disapproved by the court in June 2007. A class certification hearing is scheduled for June 2008. A companion case styled Bank of America v. El Paso Natural Gas involving similar claims made as to certain wells in Oklahoma was settled in 2006.

     In addition to the above proceedings, we and our subsidiaries and affiliates are named defendants in numerous lawsuits and governmental proceedings that arise in the ordinary course of our business. For each of these matters, we evaluate the merits of the case, our exposure to the matter, 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. While the outcome of these matters, including those discussed above, cannot be predicted with certainty, and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we accrued approximately $4 million for our outstanding legal matters at December 31, 2007. It is possible that new information or future developments could require us to reassess our potential exposure related to these matters and adjust our accruals accordingly.

     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, 2007, we accrued approximately $25 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and for related environmental legal costs; however, we estimate that our exposure could be as high as $45 million. Our accrual includes $22 million for environmental contingencies related to properties we previously owned.

     Our accrual represents a combination of two estimation methodologies. First, where the most likely outcome can be reasonably estimated, that cost has been accrued. Second, where the most likely outcome cannot be estimated, a range of costs is established and if no one amount in that range is more likely than any other, the lower end of the expected range has been accrued. Our environmental remediation projects are in various stages of completion. Our recorded liabilities 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, 2007 to December 31, 2007 (in millions):

Balance at January 1, 2007		$	24
Additions/adjustments for remediation activities			6
Payments for remediation activities			(5	)
Balance at December 31, 2007		$	25

     For 2008, we estimate that our total remediation expenditures will be approximately $6 million, which will be expended under government directed clean-up plans.

     Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) Matters. We have received notice that we could be designated, or have been asked for information to determine whether we could be designated, as a Potentially Responsible Party (PRP) with respect to three active sites under the 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, 2007, we have estimated our share of the remediation costs at these sites to be between $12 million and $16 million. Because the clean-up costs are estimates and are subject to revision as more information becomes available about the extent of remediation required, and 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.

     Chromium Review. In April 2004, the State of Arizona’s Department of Environmental Quality (ADEQ) requested information regarding the historical use of chromium containing compounds in our operations. In June 2004, we responded fully to the request and began working with the ADEQ on this matter. We commenced a study of our facilities in Arizona, Texas and New Mexico, as well as on tribal lands in Arizona and New Mexico to determine if there were any issues concerning the usage of chromium. Of the 12 Arizona sites that were investigated, nine were found not to have chromium contamination above regulatory thresholds and no further action is required. Of the three remaining sites, one was already enrolled in Arizona’s Voluntary Remediation Program (VRP) and the second site has been entered in the VRP. We are further investigating the chromium levels at the third site. Additional work will be conducted at these three sites as directed by the ADEQ. We investigated eight Texas sites that previously used chromium of which two sites will require further investigation for chromium impacts to soil and groundwater. We investigated 13 New Mexico sites of which four sites will require further investigation. None of the sites on the tribal lands were determined to require further investigation. We will be coordinating the additional work at the Texas and New Mexico sites with the respective state environmental agencies.

     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 orders of regulatory agencies, as well as claims for damages to property and the environment or injuries to employees, and other persons 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

     EPNG. In August 2007, EPNG received approval of the settlement of its rate case from the FERC. The settlement provides benefits for both EPNG and its customers for a three year period ending December 31, 2008. Under the terms of the settlement, EPNG is required to file a new rate case to be effective January 1, 2009. EPNG received approval from the FERC to begin billing the settlement rates on October 1, 2007. Our financial statements reflect EPNG’s settled rates. Additionally, in 2007 and 2006, we recorded rate refund provisions of approximately $60 million and $65 million, inclusive of interest, which we reflected as accrued liabilities on our balance sheet. In the fourth quarter of 2007, EPNG refunded $115 million including interest in rate refunds to its customers and refunded the remaining $10 million in January 2008.

     Mojave Rate Case. In February 2007, as required by its prior rate case settlement, Mojave filed with the FERC a general rate case proposing a 33 percent decrease in its base tariff rates resulting from a variety of factors, including a decline in rate base and various changes in rate design since its last rate case. No new services were proposed. The new base rates were effective March 1, 2007. In October 2007, Mojave filed an offer of settlement to resolve all issues in the rate case and received FERC approval of this settlement in December 2007. Under the terms of this settlement, we have refund obligations of $4 million that will be paid in the first quarter of 2008 for a previously accrued regulatory obligation. Other refund obligations to third parties are minimal.

Other Matters

     Navajo Nation. Approximately 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 are the subject of a pending renewal application filed in 2005 with the Department of the Interior’s Bureau of Indian Affairs. An interim agreement with the Navajo Nation expired at the end of December 2006. Negotiations on the terms of the long-term agreement are continuing. In addition, we continue to preserve other legal, regulatory and legislative 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. It is uncertain whether our negotiation, or other alternatives, will be successful, or if successful, what the ultimate cost will be of obtaining the rights-of-way and whether we will be able to recover these costs in our rates.

     Tuba City Uranium Milling Facility. For a period of approximately ten years beginning in the mid to late 1950s, Rare Metals Corporation of America, a historical affiliate, conducted uranium mining and milling operations in the vicinity of Tuba City, Arizona, under a contract with the United States government as part of the Cold War nuclear program. The site of the Tuba City uranium mill, which is on land within the Navajo Indian Reservation, reverted to the Navajo Nation after the mill closed in 1966. The tailings at the mill site were encapsulated and a ground water remediation system was installed by the U.S. Department of Energy (DOE) under the Federal Uranium Mill Tailings Radiation Control Act of 1978. In May 2007, we filed suit against the DOE and other federal agencies requesting a judicial determination that the DOE was fully and legally responsible for any remediation of any waste associated with historical uranium production activity at two sites in the vicinity of the mill facilities near Tuba City, Arizona. We are also cooperating with the Navajo Nation in joint legislative efforts to achieve appropriations for the DOE to assess and remediate the sites. Pending the potential remedial response by the United States government, we are undertaking certain interim site control measures in coordination with the Navajo Nation.

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

     Capital Commitments and Other Matters

     Capital Commitments. At December 31, 2007, we had capital commitments of approximately $12 million. We have other planned capital projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures.

     Operating Leases and Other Commercial Commitments. We lease property, facilities and equipment under various operating leases. Minimum future annual rental commitments on operating leases as of December 31, 2007, were as follows:

Year Ending
December 31,		(In millions)
2008		$	2
2009			2
2010			1
Thereafter			1
Total		$	6

     Rental expense on our operating leases for each of the three years ended December 31, 2007, 2006 and 2005 was $20 million, $17 million and $6 million. These amounts include rent allocated to us from El Paso.

     We hold cancelable easements or rights-of-way arrangements from landowners permitting the use of land for the construction and operation of our pipeline systems. Our obligations under these easements are not material to our results of our operations.

     Guarantees. We are or have been involved in various ownership and other contractual arrangements that sometimes require us to provide 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, 2007, we had approximately $11 million of financial and performance guarantees not otherwise recorded in our financial statements.

7. Retirement Benefits

     Pension and Retirement Benefits. El Paso maintains a pension plan and a retirement savings plan covering substantially all of its U.S. employees, including our employees. The benefits under the pension plan are determined under a cash balance formula. Under its retirement savings plan, El Paso matches 75 percent of participant basic contributions up to six 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.

     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 do not expect to make any contributions to our postretirement benefit plan in 2008.

     In December 2006, we adopted the recognition provisions of SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an Amendment of FASB Statements No. 87, 88, 106, and 132(R), and began reflecting assets and liabilities related to our postretirement benefit plan based on its funded or unfunded status and reclassified all actuarial deferrals as a component of accumulated other comprehensive income. In March 2007, the FERC issued guidance requiring regulated pipeline companies to recognize a regulatory asset or liability for the amount that would otherwise be recorded in accumulated other comprehensive income under SFAS No. 158, if it is probable that amounts calculated on the same basis as SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions, would be included in our rates in future periods. Upon adoption of this FERC guidance, we reclassified approximately $4 million from the beginning balance of accumulated other comprehensive loss to a regulatory asset, which represented the amount we believe will be included in our future rates.

     Change in Accumulated Postretirement Benefit Obligation, Plan Assets and Funded Status. Our benefits are presented and computed as of and for the twelve months ended September 30:

		2007				2006
		(In millions)
Change in accumulated postretirement benefit obligation:
Accumulated postretirement benefit obligation at beginning of period		$	88			$	93
Interest cost			4				5
Actuarial gain			(24	)			(4	)
Benefits paid			(6	)			(6	)
Accumulated postretirement benefit obligation at end of period		$	62			$	88
Change in plan assets:
Fair value of plan assets at beginning period		$	96			$	90
Actual return on plan assets			14				9
Employer contributions			—				3
Benefits paid			(6	)			(6	)
Fair value of plan assets at end of period		$	104			$	96
Reconciliation of funded status:
Fair value of plan assets at September 30		$	104			$	96
Less: accumulated postretirement benefit obligation end of period			62				88
Funded status at September 30			42				8
Fourth quarter contributions			—				—
Net asset at December 31		$	42			$	8

     Expected Payment of Future Benefits. As of December 31, 2007, we expect the following payments (net of participant contributions and an expected subsidy related to the Medicare Prescription Drug Improvement and Modernization Act of 2003) under our plan (in millions):

Year Ending
December 31,
2008		$	7
2009			7
2010			7
2011			6
2012			6
2013 — 2017			27

     Components of Net Benefit Cost (Income). For each of the years ended December 31, the components of net benefit cost (income) are as follows:

		2007				2006				2005
		(In millions)
Interest cost		$	4			$	5			$	4
Expected return on plan assets			(6	)			(6	)			(5	)
Amortization of net actuarial loss			—				1				—
Amortization of transition obligation			—				—				8
Net postretirement benefit cost (income)		$	(2	)		$	—			$	7

     Actuarial Assumptions and Sensitivity Analysis. Accumulated postretirement benefit obligations and net benefit costs are based on actuarial estimates and assumptions. The following table details the weighted average actuarial assumptions used in determining our postretirement plan obligations for 2007, 2006 and 2005:

		2007				2006				2005
		(Percent)
Assumptions related to benefit obligations at September 30:
Discount rate			6.05				5.50
Assumptions related to benefit costs at December 31:
Discount rate			5.50				5.25				5.75
Expected return on plan assets(1)			8.00				8.00				7.50

     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 9.4 percent in 2007, 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 would not have had a significant effect on interest costs in 2007 or 2006. A one-percentage point change in assumed health care cost trends would have the following effect as of September 30:

		2007				2006
		(In millions)
One percentage point increase:
Accumulated postretirement benefit obligation		$	4			$	6
One percentage point decrease:
Accumulated postretirement benefit obligation		$	(4	)		$	(5	)

     Plan Assets. 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 to meet the benefit obligations to participants, retirees and beneficiaries exists. Investment objectives are long-term in nature covering typical market cycles of three to five years. Any shortfall of investment performance compared to investment objectives is the result of general economic and capital market conditions. The following table provides the target and actual asset allocations in our postretirement benefit plan as of September 30:

						Actual				Actual
Asset Category		Target				2007				2006
		(Percent)
Equity securities			65				63				65
Debt securities			35				33				35
Cash and cash equivalents			—				4				—
Total			100				100				100

8. Transactions with Major Customers

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

		2007				2006(2)				2005
		(In millions)
SoCal		$	87			$	145			$	156
Southwest Gas Corporation			54	(1)			66				51

9. Supplemental Cash Flow Information

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

		2007				2006				2005
		(In millions)
Interest paid, net of capitalized interest		$	106			$	93			$	93
Income tax payments (refunds)			112				22				(93	)

10. 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. El Paso uses the cash management program to settle intercompany transactions between participating affiliates. We have historically advanced cash to El Paso in exchange for an affiliated note receivable that is due upon demand. At December 31, 2007 and 2006, we had a note receivable from El Paso of approximately $1.1 billion. We do not intend to settle this note within the next twelve months and therefore have classified it as non-current on our balance sheets. The interest rate on this note at December 31, 2007 and 2006 was 6.5% and 5.3%.

      Income Taxes. El Paso files consolidated U.S. federal and certain state tax returns which include our taxable income. In certain states, we file and pay taxes directly to the state taxing authorities. At December 31, 2007 and 2006, we had income taxes payable of $54 million and $81 million. The majority of these balances, as well as our deferred income taxes, will become payable to El Paso. See Note 1 for a discussion of our income tax policy.

     During 2007, we amended our tax sharing agreement and intercompany tax billing policy with El Paso to clarify the billing of taxes and tax related items to El Paso’s subsidiaries. We also settled with El Paso certain tax attributes previously reflected as deferred income taxes in our financial statements for $40 million through our cash management program. This settlement is reflected as operating activities in our statement of cash flows.

     Other Affiliate Balances. At December 31, 2007 and 2006, we had contractual deposits from our affiliates of $8 million and $7 million, included in other current liabilities on our balance sheets.

     Affiliate Revenues and Expenses. We provide natural gas transportation services to an affiliate under long-term contracts. We entered into these contracts in the normal course of our business and the services are 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. In addition to allocations from El Paso, we are also allocated costs from Tennessee Gas Pipeline Company (TGP) associated with our pipeline services. We also allocate costs to Colorado Interstate Gas Company for its share of our pipeline services. The allocations from El Paso and TGP are based on the estimated level of effort devoted to our operations and the relative size of our EBIT, gross property and payroll.

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

		2007				2006				2005
		(In millions)
Revenues from affiliates		$	19			$	17			$	17
Operation and maintenance expenses from affiliates			53				52				67
Reimbursements of operating expenses charged to affiliates			17				16				16

11. Supplemental Selected Quarterly Financial Information (Unaudited)

     Our financial information by quarter is summarized below. Due to the seasonal nature of our business, information for interim periods may not be indicative of our results of operations for the entire year.

		Quarters Ended
		March 31				June 30				September 30				December 31				Total
		(In millions)
2007
Operating revenues		$	145			$	136			$	136			$	140			$	557
Operating income			70				56				54				58				238
Net income			39				31				30				32				132
2006
Operating revenues		$	153			$	142			$	155			$	138			$	588
Operating income			72				62				80				69				283
Net income			38				33				45				36				152

SCHEDULE II

EL PASO NATURAL GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 2007, 2006 and 2005
(In millions)

		Balance at				Charged to
		Beginning				Costs and								Balance at
Description		of Period				Expenses				Deductions				End of Period
2007
Allowance for doubtful accounts		$	5			$	(1	)		$	—			$	4
Legal reserves			16				4				(16	)			4
Environmental reserves			24				6				(5	)			25
Regulatory reserves(1)			65				60				(115	)			10
2006
Allowance for doubtful accounts		$	18			$	(4	)		$	(9	)		$	5
Legal reserves			45				1				(30	)			16
Environmental reserves			29				(1	)			(4	)			24
Regulatory reserves(1)			—				65				—				65
2005
Allowance for doubtful accounts		$	18			$	—			$	—			$	18
Legal reserves			3				42				—				45
Environmental reserves			32				1				(4	)			29